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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] 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 0-31095
DUKE ENERGY FIELD SERVICES, LLC
(Exact name of registrant as specified in its charter)
DELAWARE 76-0632293
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
370 17TH STREET, SUITE 900
DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code
303-595-3331
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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None Not Applicable
Securities registered pursuant to Section 12(g) of the Act:
LIMITED LIABILITY COMPANY MEMBER INTERESTS
(Title of class)
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 [X] No [ ]
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 registrant's 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. [X]
As of March 22, 2001, 69.7% of the registrant's outstanding member interests is
beneficially owned by Duke Energy Corporation and 30.3% is beneficially owned by
Phillips Petroleum Company. The aggregate market value of the voting member
interests held by non-affiliates of the Registrant as of March 22, 2001 was $0.
Documents incorporated by reference:
NONE
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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2000
TABLE OF CONTENTS
ITEM PAGE
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PART I.
1. Business.................................................... 1
Our Business................................................ 1
Our Business Strategy....................................... 2
Natural Gas Gathering, Processing, Transportation, Marketing
and Storage................................................. 3
Natural Gas Liquids Transportation, Fractionation and
Marketing................................................... 10
TEPPCO...................................................... 11
Natural Gas Suppliers....................................... 13
Competition................................................. 13
Regulation.................................................. 14
Environmental Matters....................................... 16
Employees................................................... 17
2. Properties.................................................. 17
3. Legal Proceedings........................................... 17
4. Submission of Matters to a Vote of Security Holders......... 17
PART II.
Market for Registrant's Common Equity and Related
5. Stockholder Matters......................................... 17
6. Selected Financial Data..................................... 18
Management's Discussion and Analysis of Financial Condition
7. and Results of Operations................................... 20
Quantitative and Qualitative Disclosures About Market
7A. Risk........................................................ 29
8. Financial Statements and Supplementary Data................. 32
Changes in and Disagreements with Accountants on Accounting
9. and Financial Disclosure.................................... 60
PART III.
10. Directors and Executive Officers of the Registrant.......... 60
11. Executive Compensation...................................... 62
Security Ownership of Certain Beneficial Owners and
12. Management.................................................. 66
13. Certain Relationships and Related Transactions.............. 66
PART IV.
Exhibits, Financial Statement Schedules, and Reports on Form
14. 8-K......................................................... 68
Signatures.................................................. 69
Exhibit Index............................................... 70
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our reports, filings and other public announcements may from time to time
contain statements that do not directly or exclusively relate to historical
facts. Such statements are "forward-looking statements" within the meaning of
the Private Securities Litigation Reform Act of 1995. You can typically identify
forward-looking statements by the use of forward-looking words, such as "may,"
"could," "project," "believe," "anticipate," "expect," "estimate," "potential,"
"plan," "forecast" and other similar words.
All of such statements other than statements of historical facts, including
statements regarding our future financial position, business strategy, budgets,
projected costs and plans and objectives of management for future operations,
are forward-looking statements.
These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors, many of which are outside our control.
Important factors that could cause actual results to differ materially from the
expectations expressed or implied in the forward-looking statements include
known and unknown risks. Known risks include, but are not limited to, the
following:
- our ability to access the debt and equity markets, which will depend on
general market conditions and the credit ratings for our debt
obligations;
- our use of derivative financial instruments to hedge commodity and
interest rate risks;
- changes in laws and regulations, particularly with regard to taxes,
safety and protection of the environment or the increased regulation of
the gathering and processing industry;
- the timing and extent of changes in commodity prices, interest rates and
demand for our services;
- weather and other natural phenomena;
- industry changes, including the impact of consolidations, and changes in
competition;
- our ability to obtain required approvals for construction or
modernization of gathering and processing facilities, and the timing of
production from such facilities, which are dependent on the issuance by
federal, state and municipal governments, or agencies thereof, of
building, environmental and other permits, the availability of
specialized contractors and work force and prices of and demand for
products; and
- the effect of accounting policies issued periodically by accounting
standard-setting bodies.
In light of these risks, uncertainties and assumptions, the events
described in the forward-looking statements might not occur or might occur to a
different extent or at a different time than we have described.
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PART I.
ITEM 1. BUSINESS.
Duke Energy Field Services, LLC is a new company that holds the combined
North American midstream natural gas gathering, processing, marketing and
natural gas liquids ("NGL") business of Duke Energy Corporation ("Duke Energy")
and Phillips Petroleum Company ("Phillips"). The transaction in which those
businesses were combined is referred to in this Form 10-K as the "Combination."
Our limited liability company agreement limits the scope of our business to the
midstream natural gas industry in the United States and Canada, the marketing of
NGLs in Mexico and the transportation, marketing and storage of other petroleum
products, unless approved by our Board of Directors.
Unless the context otherwise requires, descriptions of assets, operations
and results in this Form 10-K give effect to the Combination and related
transactions, the transfer to us of additional midstream natural gas assets
acquired by Duke Energy or Phillips prior to the Combination and the transfer to
us of the general partner of TEPPCO Partners, L.P., all of which are described
in more detail under "Management's Discussion and Analysis of Financial
Condition and Results of Operations." In this Form 10-K, the terms "the
Company," "we," "us" and "our" refer to Duke Energy Field Services, LLC and our
subsidiaries, giving effect to the Combination and related transactions.
From a financial reporting perspective, we are the successor to Duke
Energy's North American midstream natural gas business. The subsidiaries of Duke
Energy that conducted this business were contributed to us immediately prior to
the Combination. For periods prior to the Combination, Duke Energy Field
Services and these subsidiaries of Duke Energy are collectively referred to
herein as the "Predecessor Company."
We are a Delaware limited liability company, and we were formed on December
15, 1999. Our principal executive offices are located at 370 17th Street, Suite
900, Denver, Colorado 80202. Our telephone number is 303-595-3331.
OUR BUSINESS
The midstream natural gas industry is the link between exploration and
production of raw natural gas and the delivery of its components to end-use
markets. We operate in the two principal segments of the midstream natural gas
industry:
- natural gas gathering, processing, transportation, marketing and storage;
and
- NGL fractionation, transportation, marketing and trading.
We believe that we are one of the largest gatherers of raw natural gas,
based on wellhead volume, in North America. We are the largest producer, and we
believe that we are one of the largest marketers, of NGLs in North America. In
2000:
- we gathered and/or transported an average of approximately 7.6 trillion
British thermal units (Btus) per day of raw natural gas;
- we produced an average of approximately 360,000 barrels per day of NGLs;
and
- we marketed and traded an average of approximately 505,000 barrels per
day of NGLs.
We gather raw natural gas through gathering systems located in seven major
natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin
Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of
Mexico and Western Canada. Our gathering systems consist of approximately 57,000
miles of gathering pipe, with approximately 35,000 active receipt points.
Our natural gas processing operations involve the separation of raw natural
gas gathered both by our gathering systems and by third-party systems into NGLs
and residue gas. We process the raw natural gas at our 68 owned and operated
plants and at 11 third-party operated facilities in which we hold an equity
interest.
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The NGLs separated from the raw natural gas by our processing operations
are either sold and transported as NGL raw mix or further separated through a
process known as fractionation into their individual components (ethane,
propane, butanes and natural gasoline) and then sold as components. We
fractionate NGL raw mix at our 12 owned and operated processing facilities and
at two third-party operated fractionators located on the Gulf Coast in which we
hold an equity interest.
We sell NGLs to a variety of customers ranging from large, multi-national
petrochemical and refining companies to small regional retail propane
distributors. Substantially all of our NGL sales are made at market-based
prices, including approximately 40% of our NGL production that is committed to
Phillips and Chevron Phillips Chemical Company LLC under an existing contract
which expires December 31, 2014.
The residue gas that results from our processing is sold at market-based
prices to marketers or end-users, including large industrial customers and
natural gas and electric utilities serving individual consumers. We market
residue gas through our wholly owned gas marketing company. We also store
residue gas at our 8.5 billion cubic foot natural gas storage facility.
On March 31, 2000, we combined the gas gathering, processing, marketing and
NGLs businesses of Duke Energy and Phillips. In connection with the Combination,
Duke Energy and Phillips transferred all of their respective interests in their
subsidiaries that conducted their midstream natural gas business to us. In
connection with the Combination, Duke Energy and Phillips also transferred to us
additional midstream natural gas assets acquired by Duke Energy or Phillips
prior to consummation of the Combination, including the Mid-Continent gathering
and processing assets of Conoco and Mitchell Energy. The acquisition of the
Conoco/Mitchell assets is significant in that the assets acquired lie adjacent
to and between our current assets, providing significant integration
opportunities.
Concurrently with the Combination, on March 31, 2000, we obtained by
transfer from Duke Energy the general partner of TEPPCO Partners, L.P.
("TEPPCO"), a publicly traded limited partnership which owns and operates a
network of pipelines for refined products and crude oil. The general partner is
responsible for the management and operations of TEPPCO. We believe that our
ownership of the general partner of TEPPCO improves our business position in the
transportation sector of the midstream natural gas industry and provides
additional flexibility in pursuing our disciplined acquisition strategy by
providing an alternative acquisition vehicle. It also provides us with an
opportunity to sell appropriate assets currently held by our company to TEPPCO.
A discussion of the current business and operations of each of our segments
follows. For further discussion of these segments, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations." For financial
information concerning our business segments, see Note 17 "Business Segments" of
the Notes to Consolidated Financial Statements.
OUR BUSINESS STRATEGY
We believe that we are one of the largest gatherers of raw natural gas,
based on wellhead volume, in North America. We are the largest producer, and we
believe that we are one of the largest marketers, of NGLs in North America. Our
limited liability company agreement limits the scope of our business to the
midstream natural gas industry in the United States and Canada, the marketing of
NGLs in Mexico, and the transportation, marketing and storage of other petroleum
products, unless otherwise approved by our board of directors. We have
significant midstream natural gas operations in five of the largest natural gas
producing regions in North America. To take advantage of the anticipated growth
in natural gas demand in North America, we are pursuing the following
strategies:
- Capitalize on the size and focus of our existing operations. We intend
to use the size, scope and concentration of our assets in our regions of
operation to take advantage of growth opportunities and to acquire
additional supplies of raw natural gas. Our significant market presence
and asset base generally provide us with a competitive advantage in
capturing new supplies of raw natural gas because of our resulting lower
costs of connection to new wells and of processing additional raw natural
gas. In
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addition, we believe our size and geographic diversity allow us to benefit from
the growth of natural gas production in multiple regions while mitigating the
adverse effects from a downturn in any one region.
- Increase our presence in each aspect of the midstream business. We are
active in each significant aspect of the midstream natural gas value
chain, including raw natural gas gathering, processing, and
transportation, NGL fractionation and NGL and residue gas transportation
and marketing. Each link in the value chain provides us with an
opportunity to earn incremental income from the raw natural gas that we
gather and from the NGLs and residue gas that we produce. We intend to
grow our significant NGL market presence by investing in additional NGL
infrastructure, including pipelines, fractionators and terminals.
- Increase our presence in high growth production areas. According to the
Energy Information Administration's report "Annual Energy Outlook 2000"
(the "EIA Report"), production from areas such as Western Canada, Onshore
Gulf of Mexico, Rocky Mountains and Offshore Gulf of Mexico is expected
to increase significantly to meet anticipated increases in demand for
natural gas in North America. We intend to use our strategic asset base
in these growth areas and our leading position in the midstream natural
gas industry as a platform for future growth in these areas. We plan to
increase our operations in these areas by following a disciplined
acquisition strategy, and by expanding existing infrastructure and
constructing new gathering lines and processing facilities.
- Capitalize on proven acquisition skills in a consolidating industry. In
addition to pursuing internal growth by attracting new raw natural gas
supplies, we intend to use our substantial acquisition and integration
skills to continue to participate selectively in the consolidation of the
midstream natural gas industry. We have pursued a disciplined acquisition
strategy focused on acquiring complementary assets during periods of
relatively low commodity prices and integrating the acquired assets into
our operations. Since 1996, we have completed over 20 acquisitions,
increasing our raw natural gas processing capacity by over 275%. These
acquisitions demonstrate our ability to successfully identify, acquire
and integrate attractive midstream natural gas operations.
- Further streamline our low-cost structure. Our economies of scale,
operating efficiency and resulting low cost structure enhance our ability
to attract new raw natural gas supplies and generate current income. The
low-cost provider in any region can more readily attract new raw natural
gas volumes by offering more competitive terms to producers. We believe
the Combination provides us with a complementary base of assets from
which to further extract operating efficiencies and cost reductions,
while continuing to provide superior customer service.
NATURAL GAS GATHERING, PROCESSING, TRANSPORTATION, MARKETING AND STORAGE
Overview
At December 31, 2000, our raw natural gas gathering and processing
operations consisted of:
- approximately 57,000 miles of gathering pipe, with connections to
approximately 35,000 active receipt points; and
- 68 owned and operated processing plants and ownership interests in 11
additional third-party operated plants, with a combined processing
capacity of approximately 8.0 billion cubic feet per day.
In 2000, we gathered, processed and/or transported approximately 7.6
trillion Btus per day of raw natural gas. During 2000, our natural gas
gathering, processing, transportation, marketing and storage activities produced
$1,169.3 million of gross margin.
Our raw natural gas gathering and processing operations are located in 11
contiguous states in the United States and two provinces in Western Canada. We
provide services in the following key North American natural gas and oil
producing regions: Permian Basin, Mid-Continent, East Texas-Austin Chalk-North
Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and
Western Canada. We have a significant presence in the first five of these
producing regions where, according to the Oil and Gas
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Journal's "1999 Worldwide Gas Processing Report," we are among the three largest
midstream natural gas companies based on volumes of natural gas gathered and
processed or volumes of NGLs produced.
Raw Natural Gas Supply Arrangements. Typically, we take ownership of raw
natural gas at the wellhead. Each producer generally dedicates to us the raw
natural gas produced from designated oil and natural gas leases for a specific
term. The term will typically extend for three to seven years. We currently have
more than 15,000 active contracts with over 5,000 producers. We obtain access to
raw natural gas and provide our midstream natural gas service principally under
three types of contracts: percentage-of-proceeds contracts, fee-based contracts
and keep-whole contracts. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Overview -- Effects of Our Raw Natural
Gas Supply Arrangements" for a description of these types of contracts.
Raw Natural Gas Gathering. As of December 31, 2000, we had approximately
25 trillion cubic feet of raw natural gas supplies attached to our systems. We
receive raw natural gas from a diverse group of producers under contracts with
varying durations to provide a stable supply of raw natural gas through our
processing plants. A significant portion of the raw natural gas that is
processed by us is produced by large producers, including Phillips, Anadarko,
Enron, Exxon Mobil, and Louis Dreyfus, which together account for approximately
20% of our processed raw natural gas.
We continually seek new supplies of raw natural gas, both to offset natural
declines in production from connected wells and to increase throughput volume.
Historically, we have been successful in connecting additional supplies to more
than offset natural declines in production.
We obtain new well connections in our operating areas by contracting for
production from new wells or by obtaining raw natural gas that has been released
from other gathering systems. Producers may switch raw natural gas from one
gathering system to another to obtain better commercial terms, conditions and
service levels.
We believe our significant asset base and scope of our operations provide
us with significant opportunities to add released raw natural gas to our
systems. In addition, we have significant processing capacity in the Onshore
Gulf of Mexico, Offshore Gulf of Mexico and Rocky Mountain regions, which,
according to the EIA Report contain significant quantities of proved natural gas
reserves. We also have a presence in other potential high-growth areas such as
the Western Canadian Sedimentary Basin. As a result of new connections resulting
from both increased drilling and released raw natural gas, we connected
approximately 1,900 additional receipt points in 2000.
Gathering systems are operated at design pressures that will maximize the
total throughput from all connected wells. On gathering systems where it is
economically feasible, we operate at a relatively low pressure, which can allow
us to offer a significant benefit to raw natural gas producers. Specifically,
lower pressure gathering systems allow wells, which produce at progressively
lower field pressures as they age, to remain connected to gathering systems and
continue to produce for longer periods of time. As the pressure of a well
declines, it becomes increasingly more difficult to deliver the remaining
production in the ground against a higher pressure that exists in the connecting
gathering system. Field compression is typically used to lower the pressure of a
gathering system. If field compression is not installed, then the remaining
production in the ground will not be produced because it cannot overcome the
higher gathering system pressure. In contrast, if field compression is
installed, then a well can continue delivering production that otherwise would
not be produced. Our field compression systems provide the flexibility of
connecting a high pressure well to the downstream side of the compressor even
though the well is producing at a pressure greater than the upstream side. As
the well ages and the pressure naturally declines, the well can be reconnected
to the upstream, low pressure side of the compressor and continue to produce. By
maintaining low pressure systems with field compression units, we believe that
the wells connected to our systems are able to produce longer and at higher
volumes before disconnection is required.
Raw Natural Gas Processing. Most of our natural gas gathering systems feed
into our natural gas processing plants. Our processing plants received an
average of approximately 5.9 trillion Btus per day of raw gas and produced an
average of 360,000 barrels per day of NGLs during 2000.
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Our natural gas processing operations involve the extraction of NGLs from
raw natural gas, and, at certain facilities, the fractionation of NGLs into
their individual components (ethane, propane, butanes and natural gasoline). We
sell NGLs produced by our processing operations to a variety of customers
ranging from large, multi-national petrochemical and refining companies,
including Phillips, to small, regional retail propane distributors.
At four plants, we also extract helium from the residue gas stream. Helium
is used for medical diagnostics, in arc welding and other metallurgical and
chemical processes, in the space exploration program and other scientific
applications, for diluting oxygen for breathing (by patients with respiratory
ailments and by deep-sea divers) and for inflating lighter-than-air aircraft and
balloons. These plants are among the few helium extraction facilities in the
United States. We extracted approximately 788,000 million cubic feet of helium
during 2000, producing revenues of approximately $20.0 million.
Hydrogen sulfide also is separated in the treating and processing cycle.
During 2000, we produced and sold approximately 51,000 long tons of sulfur,
producing revenues of approximately $0.9 million.
We also remove off-quality crude oil, nitrogen, carbon dioxide and brine
from the raw natural gas stream. The nitrogen and carbon dioxide are released
into the atmosphere, and the crude oil and brine are accumulated and stored
temporarily at field compressors or the various plants. The brine is transported
to licensed disposal wells owned either by us or by third parties. The crude oil
is sold in the off-quality crude oil market.
Residue Gas Marketing. In addition to our gathering and processing
activities discussed above, we are involved in the purchase and sale of residue
gas, directly or through our wholly owned gas marketing company. Our gas
marketing efforts primarily involve supplying the residue gas demands of
end-user customers that are physically attached to our pipeline systems and
supplying the gas processing requirements associated with our keep-whole
processing agreements.
We are focused on extracting the highest possible value for the residue gas
that results from our processing and transportation operations. Of the residue
gas that we market, we currently sell approximately 25% to various on-system
users and approximately 75% to industrial end-users, national wholesale gas
marketing companies (including Duke Energy Trading and Marketing, a subsidiary
of Duke Energy and one of the largest gas marketers in the United States) and
electric utilities.
Our Spindletop storage facility plays an important role in our ability to
act as a full-service natural gas marketer. We lease approximately two-thirds of
the facility's capacity to our customers, and we use the balance to manage
relatively constant natural gas supply volumes with uneven demand levels and
provide "backup" service to our customers.
The natural gas marketing industry is a highly competitive commodity
business with a significant degree of price transparency. We provide a full
range of natural gas marketing services in conjunction with the gathering,
processing, and transportation services we offer on our facilities, which allows
us to use our asset infrastructure to enhance our revenues across each aspect of
the natural gas value chain.
Financial Services. We provide mezzanine financing to producers seeking
capital for production enhancement in our core physical and marketing asset
areas. We provide financing to operators as part of our efforts to increase
utilization of our existing assets, gain access to incremental supplies and
generate opportunities for us to expand existing infrastructure and/or construct
new gathering lines and processing facilities. The majority of the financing
plans we offer are asset-based. This program has created significant gathering
and processing opportunities for us. At December 31, 2000, we had $29.5 million
in financing outstanding under this program.
Regions of Operations
Our operations cover substantially all of the major natural gas producing
regions in the United States, as well as portions of Western Canada. Our
geographic diversity reduces the impact of regional price fluctuations and
regional changes in drilling activity.
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Our raw natural gas gathering and processing assets are managed in line
with the seven geographic regions in which we operate. The following table
provides information concerning the raw natural gas gathering systems and
processing plants owned or operated by us at December 31, 2000.
2000 OPERATING DATA(1)
GAS ------------------------
GATHERING COMPANY PLANTS NET PLANT PLANT INLET NGLS
SYSTEM OPERATED OPERATED CAPACITY VOLUME(2) PRODUCTION
REGION (MILES) PLANTS BY OTHERS (MMCF/D) (BBTU/D) (BBLS/D)
- ------ --------- -------- --------- --------- ----------- ----------
Permian Basin................... 12,774 18 2 1,406 1,393 126,265
Mid-Continent................... 30,243 19 2 2,285 1,901 124,987
East Texas-Austin Chalk-North
Louisiana..................... 5,642 9 0 1,457 1,136 67,827
Onshore Gulf of Mexico.......... 3,788 7 1 1,118 1,061 45,685
Rocky Mountains................. 3,454 9 1 590 517 28,169
Offshore Gulf of Mexico......... 452 2 5 922 226 7,978
Western Canada.................. 279 4 0 204 133 360
------ -- -- ----- ----- -------
Total........................... 56,632 68 11 7,982 6,367 401,271
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(1) Reflects 12 month average volumes except for assets acquired in connection
with the Combination, which are averaged over the 9 months following the
Combination.
(2) Excludes inlet volumes of about 500 BBtu/d net for plants operated by
others.
Our key suppliers of raw natural gas in these seven regions include major
integrated oil companies, independent oil and gas producers, intrastate pipeline
companies and natural gas marketing companies. Our principal competitors in this
segment of our business consist of major integrated oil companies, independent
oil and gas gatherers, and interstate and intrastate pipeline companies.
Regional Growth Strategies. Growth of our gas gathering and processing
operations is key to our success. Increased raw natural gas supply enables us to
increase throughput volumes and asset utilization throughout our entire
midstream natural gas value chain. As we develop our regional growth strategies,
we evaluate the nature of the opportunity that a particular region presents. The
attributes that we evaluate include the nature of the gas reserves and
production profile, existing midstream infrastructure including capacity and
capabilities, the regulatory environment, the characteristics of the
competition, and the competitive position of our assets and capabilities. In a
general sense, we employ one or more of the strategies described below:
- Growth -- in regions where production is expected to grow significantly
and/or there is a need for additional gathering and processing
infrastructure, we plan to expand our gathering and processing assets by
following a disciplined acquisition strategy, by expanding existing
infrastructure, and by constructing new gathering lines and processing
facilities.
- Consolidation -- in regions that include mature producing basins with
flat to declining production or that have excess gathering and processing
capacity, we seek opportunities to efficiently consolidate the existing
asset base in order to increase utilization and operating efficiencies
and realize economies of scale.
- Opportunistic -- in regions where production growth is not primarily
generated by new exploration drilling activity we intend to optimize our
existing assets and selectively expand certain facilities or construct
new facilities to seize opportunities to increase our throughput. These
regions are generally experiencing stable to increasing production
through the application of new drilling technologies like 3-D seismic,
horizontal drilling and improved well completion techniques. The
application of new technologies is causing the drilling of additional
wells in areas of existing production and recompletions of existing wells
which create additional opportunities to add new gas supplies.
In each region, we plan to apply both our broad overall business strategy
and the strategy uniquely suited to each region. We believe this plan will yield
balanced growth initiatives, including new construction in
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certain high growth areas, expansion of existing systems and complementary
acquisitions, combined with efficiency improvements and/or asset consolidation.
We also plan to rationalize assets and redeploy capital to higher value
opportunities.
A description of our operations, key suppliers and principal competitors in
each region is set forth below:
Permian Basin. Our facilities in this region are located in West Texas and
Southeast New Mexico. We own majority interests in and are the operator of 18
natural gas processing plants in this region. In addition, we own minority
interests in two other natural gas processing plants that are operated by
others. Our natural gas processing plants are strategically located to access
Permian Basin production. Our plants have processing capacity net to our
interest of 1.4 billion cubic feet of raw natural gas per day. Operations in
this region are primarily focused on gathering and processing, but we also are
positioned for marketing residue gas and NGLs. We offer low, intermediate, and
high pressure gathering and processing and both high and low NGLs content
treating. Three of our processing facilities provide fractionation services.
Residue gas sales are enhanced by access to the Waha Hub where multiple pipeline
interconnects source gas for virtually every market in the United States. Our
older facilities have been modernized to improve product recoveries, and some of
our plants offer sulfur removal. During 2000, these plants operated at an
overall 79% capacity utilization rate. On average, the raw natural gas from West
Texas contains approximately 6.8 gallons of NGLs per thousand cubic feet, while
raw natural gas from New Mexico contains approximately 4.6 gallons of NGLs per
thousand cubic feet.
As we generally pursue a consolidation strategy in this region, our assets
will allow us to compete for new gas supplies in most major fields and benefit
from the expected increase in drilling and production from technological
advances. In addition, our ability to redirect gas between several processing
plants allows us to maximize utilization of our processing capacity in this
region.
Our key suppliers in this region include Exxon Mobil, Occidental, Anadarko,
Phillips, Louis Dreyfus Natural Gas and Yates Petroleum. Our principal
competitors in this region include Dynegy, Sid Richardson, Conoco, Western Gas,
British Petroleum, El Paso, Marathon and Texaco.
Mid-Continent. Our facilities in this region are located in Oklahoma,
Kansas, the Texas Panhandle and the Ladder Creek area of Southeast Colorado. In
this region, we own and are the operator of 19 natural gas processing plants. We
also own minority interests in two other natural gas processing plants that are
operated by others. We gather and process raw natural gas primarily from the
Arkoma, Ardmore, and Anadarko basins, including the prolific Hugoton and
Panhandle fields. Our plants have processing capacity net to our interest of 2.3
billion cubic feet of raw natural gas per day. During 2000, our plants operated
at an overall 74% capacity utilization rate. On average, the raw natural gas
from this region contains 4.7 gallons of NGLs per thousand cubic feet.
We also produce approximately 25% of the United States domestic supply of
helium from our Mid-Continent facilities. Annual growth in demand for helium
over the past 15 years has been approximately 8.5% per year. Because of its
unique characteristics and use as an industrial gas, we expect demand for helium
to grow well into the future.
Existing production in the Mid-Continent region is typically from mature
fields with shallow decline profiles that will provide our plants with a
dependable source of raw natural gas over a long term. With the development of
improved exploration and production techniques such as 3-D seismic and
horizontal drilling over the past several years, additional reserves have become
economically producible in this region. We hold large acreage dedication
positions with various producers who have developed programs to add
substantially to their reserve base. The infrastructure of our plants and
gathering facilities is uniquely positioned to pursue our consolidation
strategy.
Our key suppliers in this region include Phillips, OXY USA and Anadarko
Petroleum. Our principal competitors in this region include El Paso Field
Services, Oneok Field Services and Enogex Inc.
East Texas-Austin Chalk-North Louisiana. Our facilities in this region are
located in East Texas, North Louisiana and the Austin Chalk formation of East
Central Texas and Central Louisiana. We own majority
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interests in and are the operator of 9 natural gas processing plants in this
region. Our plants have processing capacity net to our interest of 1.5 billion
cubic feet of raw natural gas per day. During 2000, these plants operated at an
overall 67% capacity utilization rate. In this region we also own three
gathering systems, which, in the aggregate, can gather and transport
approximately 480 million cubic feet of raw natural gas per day.
Our East Texas operations are centered around our East Texas Complex,
located near Carthage, Texas. This plant complex is the second largest raw
natural gas processing facility in the continental United States, based on
liquids recovery, and currently produces approximately 40,000 barrels per day of
NGLs. Our 165-mile gathering network aggregates production to the East Texas
Complex, which currently gathers approximately 130 million cubic feet of raw
natural gas per day. In addition, the plant is connected to and processes raw
natural gas from several other gathering systems, including those owned by Koch,
Anadarko and American Central. Most of the raw natural gas processed at the
complex is contracted under percent-of-proceeds agreements with an average
remaining term of approximately five years. This plant is adjacent to our
Carthage Hub, which delivers residue gas to interconnects with 12 interstate and
intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of
two billion cubic feet per day, acts as a key exchange point for the purchase
and sale of residue gas. In this region, we also own and operate the Fuels
Cotton Valley Gathering System, which consists of 76 miles of pipeline and
currently gathers approximately 21 million cubic feet of raw natural gas per
day.
As we pursue a combination of opportunistic and consolidation strategies in
this diverse region, we intend to leverage our modern processing capacity,
intrastate gas pipeline and NGL assets.
Our key suppliers in this region include Anadarko, Devon and Phillips. Our
principal competitors in this region include Koch, El Paso Field Services and
Southwest Pipeline Corporation.
Onshore Gulf of Mexico. Our facilities in this region are located in South
Texas and the Southeastern portions of the Texas Gulf Coast. We own a 100%
interest in and are the operator of 7 natural gas processing plants and the
Spindletop gas storage facility in this region. In addition, we own a minority
interest in one natural gas processing plant that is operated by another entity.
Our plants have processing capacity net to our interest of 1.1 billion cubic
feet of raw natural gas per day. During 2000, the plants in this region ran at
an overall 85% capacity utilization rate.
Our Spindletop natural gas storage facility is located near Beaumont, Texas
and has current working natural gas capacity of 8.5 billion cubic feet, plus
expansion potential of up to an additional 10 billion cubic feet. We currently
have approximately 5.0 billion cubic feet of the available storage capacity
under lease with expiration terms out to July 2004. This high deliverability
storage facility is positioned to meet the needs of the natural gas-fired
electric generation marketplace, currently the fastest growing demand segment of
the natural gas industry. The facility interconnects with 10 interstate and
intrastate pipelines and is designed to handle the hourly demand needs of power
generators.
To achieve growth in our Onshore Gulf of Mexico region, we intend to fully
integrate our recently acquired assets and use the diversity of our current
asset base to provide value-added services to our broad customer base. We will
also seek additional opportunities to participate in the anticipated growth in
supply from this region.
Our key suppliers in this region include Apache, United Oil and Minerals
and TransTexas. Our principal competitors in this region include El Paso Gas
Transmission, Co., Tejas Gas Corp. and Houston Pipe Line Company.
Rocky Mountains. Our facilities in this region are located in the DJ Basin
of Northern Colorado, the Greater Green River Basin and Overthrust Belt areas of
Southwest Wyoming and Northeast Utah. We own a 100% interest in and are the
operator of 9 natural gas processing plants in this region. In addition, we own
a minority interest in one natural gas processing plant that is operated by
another entity. Our plants have processing capacity net to our interest of 600
million cubic feet of raw natural gas per day. During 2000, our plants in this
region operated at an overall 74% capacity utilization rate. These assets
provide for the gathering and processing of raw natural gas and the
transportation and fractionation of NGLs.
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The Rocky Mountains region has well placed assets with strong competitive
positions in areas that are expected to benefit from increased drilling
activity, providing us with a platform for growth. In this region, we expect to
achieve growth through our existing assets, strategic acquisitions and
development of new facilities. In addition, we intend to pursue an opportunistic
strategy in areas where new technologies and recovery methods are being
employed.
Our key suppliers in the region include Patina Oil & Gas, HS Resources and
Anadarko. Our principal competitors in this region include HS Resources,
Williams Field Services and Western Gas Resources.
Offshore Gulf of Mexico. Our facilities in this region are located along
the Gulf Coast areas of Louisiana, Mississippi and Alabama. We own minority
interests in and are the operator of two natural gas processing plants in this
region. In addition, we own a 51% interest in one natural gas processing plant
and minority interests in four other natural gas processing plants, all of which
are operated by other entities. The plants have processing capacity net to our
interest of 900 million cubic feet of raw natural gas per day. During 2000, our
plants in this region operated at an overall 77% capacity utilization rate. Each
of these plants straddle offshore pipeline systems delivering a relatively lower
NGLs content gas stream than that of our onshore gathering systems, as
approximately 40% of the produced NGLs content consists of ethane. As a result,
the offshore region's revenues are concentrated in fee-based business
arrangements.
In addition, we own a 37% interest in the Dauphin Island Gathering
Partnership, an offshore gathering and transmission system. Dauphin Island has
attractive market outlets, including deliveries to Texas Eastern Transmission
Corporation, Transco, Gulf South (formerly Koch Gateway), and Florida Gas
Transmission for re-delivery to the Southeast, Mid-Atlantic, Northeast and New
England natural gas markets. Dauphin Island's leased capacity on Texas Eastern
Transmission Corporation's pipeline provides us with a means to cross the
Mississippi River to deliver or receive production from the Venice, Louisiana
natural gas hub area. Further, the Main Pass Oil Gathering Company system, in
which we own a 33% interest, also has access to a variety of markets through
existing shallow-water and deep-water interconnections and dual market outlets
into Shell's Delta terminal as well as Chevron's Cypress terminal.
We believe that the Offshore Gulf of Mexico production area will be one of
the most active regions for new drilling in the United States. Our strategic
growth plan for this region is to add new facilities to our existing base so
that we can capture new offshore development opportunities. Our existing assets
in the eastern Gulf of Mexico are positioned to access new and ongoing
production developments. Based on our broad range of assets in the region, we
intend to capture incremental margins along the natural gas value chain.
Our key suppliers in the Offshore Gulf of Mexico region include Coastal,
Exxon Mobil and CNG Producing Company. Our principal competitors in this region
include El Paso Energy, Coral Energy and Williams.
Western Canada. We own a majority interest in and are the operator of four
natural gas processing plants in Western Canada that are strategically located
in the Peace River Arch area of Northwestern Alberta. Our facilities in this
region have processing capacity net to our interest of 200 million cubic feet of
raw natural gas per day. Our 279-mile gathering system located in this region
supports these processing facilities. During 2000, our processing plants in this
area operated at an overall 59% capacity utilization rate. Our processing
facilities in this area are new, with the majority having been constructed since
1995. Our processing arrangements are primarily fee-based, providing an income
stream that is not subject to fluctuations in commodity prices. Our foreign
operations in Canada are subject to risks inherent in transactions involving
foreign currencies and political uncertainties.
The Peace River Arch area continues to be an active drilling area with land
widely held among several large and small producers. Multiple residue gas market
outlets can be accessed from our facilities through connections to TransCanada's
NOVA system, the Westcoast system into British Columbia and the Alliance
Pipeline.
According to the EIA Report, less than 20% of the gathering and processing
assets in the area are owned by midstream gathering and processing companies. As
a result, we believe that significant growth opportunities exist in this region.
We anticipate that producers in this area may follow the lead of U.S. producers
and
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divest their midstream assets over the next few years. We are positioned to
capitalize on this fundamental shift in the Canadian natural gas processing
industry and plan to expand our position in Alberta and British Columbia through
additional acquisitions and greenfield projects.
Our key suppliers in this region include Star Oil & Gas Ltd., Talisman
Energy Inc. and Anderson Exploration Ltd. Our principal competitors in the area
include TransCanada Midstream, Talisman Energy Inc. and Westcoast Energy, Inc.
NATURAL GAS LIQUIDS TRANSPORTATION, FRACTIONATION AND MARKETING
Overview
We market our NGLs and provide marketing services to third party NGL
producers and sales customers in significant NGL production and market centers
in the United States. During 2000, our NGL transportation, fractionation and
marketing activities produced $48.7 million of gross margin and $58.7 million of
EBITDA. In 2000, we marketed and traded approximately 505,000 barrels per day of
NGLs, of which approximately 79% was production for our own account, ranking us
as one of the largest NGLs marketers in the country.
Our NGL services include plant tailgate purchases, transportation,
fractionation, flexible pricing options, price risk management and
product-in-kind agreements. Our primary NGL operations are located in close
proximity to our gathering and processing assets in each of the regions in which
we operate, other than Western Canada. We own interests in two NGLs
fractionators at the Mont Belvieu, Texas market center, the Mont Belvieu I
fractionation facility and the Enterprise Products fractionation facility. In
addition, we own an interest in the Black Lake Pipeline in Louisiana and East
Texas. We also own several regional fractionation plants and NGL pipelines.
We possess a large asset base of NGL fractionators and pipelines that are
used to provide value-added services to our refining, chemical, industrial,
retail and wholesale propane-marketing customers. We intend to capture premium
value in local markets while maintaining a low cost structure by maximizing
facility utilization at our 12 regional fractionators and 10 pipeline systems.
Our current fractionation capacity is approximately 153,000 barrels per day.
Strategy
Our strategy is to exploit the size, scope and reliability of supply from
our raw natural gas processing operations and apply our knowledge of NGL market
dynamics to make additional investments in NGL infrastructure. Our
interconnected natural gas processing operations provide us with an opportunity
to capture fee-based investment opportunities in certain NGL assets, including
pipelines, fractionators and terminals. In conjunction with this investment
strategy and as an enhancement to the margin generation from our NGL assets, we
also intend to focus on the following areas: producer services, local sales and
fractionation, market hub fractionation, transportation and market center
trading and storage, each of which is discussed briefly below.
Producer Services. We plan to expand our services to producers principally
in the areas of price risk management and handling the marketing of their
products. Over the last several years, we have expanded our supply base
significantly beyond our own equity production by providing a long-term market
for third-party NGLs at competitive prices.
Local Sales and Fractionation. We will seek opportunities to maximize
value of our product by expanding local sales. We have fractionation
capabilities at 14 of our raw natural gas processing plants. Our ability to
fractionate NGLs at regional processing plants provides us with direct access to
local NGLs markets.
Market Hub Fractionation. We will focus on optimizing our product slate
from our two Gulf Coast fractionators, the Mont Belvieu I and Enterprise
Products fractionators, where we have a combined owned capacity of 57,000
barrels per day. The control of products from these fractionators complements
our market center trading activity.
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Transportation. We will seek additional opportunities to invest in NGL
pipelines and secure favorable third party transportation arrangements. We use
company-owned NGL pipelines to transport approximately 54,500 barrels per day of
our total NGL pipeline volumes, providing transportation to market center
fractionation hubs or to end use markets. We also are a significant shipper on
third party pipelines in the Rocky Mountains, Mid-Continent and Permian Basin
producing regions and, as a result, receive the benefit of incentive rates on
many of our NGLs shipments.
Market Center Trading and Storage. We use trading and storage at the Mont
Belvieu, Texas and Conway, Kansas NGL market centers to manage our price risk
and provide additional services to our customers. We undertake these activities
through the use of fixed forward sales, basis and spread trades, storage
opportunities, put/call options, term contracts and spot market trading. We
believe there are additional opportunities to grow our price risk management
services with our industrial customer base.
Key Suppliers and Competition
The marketing of NGLs is a highly competitive business that involves
integrated oil and natural gas companies, mid-stream gathering and processing
companies, trading houses, international liquid propane gas producers and
refining and chemical companies. There is competition to source NGLs from plant
operators for movement through pipeline networks and fractionation facilities as
well as to supply large consumers such as multi-state propane, refining and
chemical companies with their NGLs needs. Our three largest suppliers are our
own plants, Anadarko and Pacific Gas & Electric. Our largest sales customers are
Phillips, Equistar Chemicals, Dow Chemical and Exxon Mobil, which accounted for
23.3%, 6.4%, 4.0% and 3.5%, respectively, of our total revenues in 2000. Our
three principal competitors in the marketing of NGLs are Dynegy, Koch and
Enterprise. In 2000, we marketed and traded an average of approximately 505,000
barrels per day, or approximately 16% of the available domestic supply, which
includes gas plant production, refinery plant production and imports.
TEPPCO
On March 31, 2000, we obtained by transfer from Duke Energy, the general
partner of TEPPCO, a publicly traded limited partnership. TEPPCO operates in two
principal areas:
- refined products and liquefied petroleum gases transportation; and
- crude oil and NGLs transportation and marketing.
TEPPCO is one of the largest pipeline common carriers of refined petroleum
products and liquefied petroleum gases in the United States. Its operations in
this line of business consist of:
- interstate transportation, storage and terminaling of petroleum products;
- short-haul shuttle transportation of liquefied petroleum gas at the Mont
Belvieu, Texas complex;
- sale of product inventory;
- fractionation of NGLs; and
- ancillary services.
TEPPCO owns and operates an approximate 4,500-mile products pipeline
system, which includes storage facilities and delivery terminals, extending from
southeast Texas through central and midwest states to the northeast United
States. TEPPCO also owns and operates approximately 2,700 miles of crude oil
gathering and trunk line pipelines and approximately 600 miles of NGL pipelines,
primarily in Texas and Oklahoma. TEPPCO also owns an interest in, and operates,
a 500-mile large diameter crude oil pipeline that is among the lowest cost and
the most direct alternative for moving imported crude oil from the Texas Gulf
Coast to the mid-continent and midwest refining sector. TEPPCO also owns
interests in two joint venture crude oil pipelines operating in New Mexico,
Oklahoma and Texas. TEPPCO's asset base includes the only pipeline system that
transports liquefied petroleum gases to the northeast United States from the
Texas Gulf Coast.
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TEPPCO recently initiated a new service to the petrochemical industry through
the construction, ownership and operation of three pipelines in Texas between
Mont Belvieu and Port Arthur.
We believe that our ownership of the general partnership interest of TEPPCO
improves our business position in the transportation sector of the midstream
natural gas industry and provides us additional flexibility in pursuing our
disciplined acquisition strategy by providing an alternative acquisition
vehicle. It also provides us with an opportunity to sell to TEPPCO appropriate
assets currently held by us.
The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO
partnership agreement and the partnership agreements of its operating
partnerships. Under the partnership agreements, the general partner of TEPPCO is
reimbursed for all direct and indirect expenses it incurs and payments it makes
on behalf of TEPPCO.
TEPPCO makes quarterly cash distributions of its available cash, which
consists generally of all cash receipts less disbursements and cash reserves
necessary for working capital, anticipated capital expenditures and
contingencies, the amounts of which are determined by the general partner of
TEPPCO.
The partnership agreements provide for incentive distributions payable to
the general partner of TEPPCO out of TEPPCO's available cash in the event
quarterly distributions to its unitholders exceed certain specified targets. In
general, subject to certain limitations, if a quarterly distribution exceeds a
target of $.275 per limited partner unit, the general partner of TEPPCO will
receive incentive distributions equal to:
- 15% of that portion of the distribution per limited partner unit which
exceeds the minimum quarterly distribution amount of $.275 but is not
more than $.325, plus
- 25% of that portion of the quarterly distribution per limited partner
unit which exceeds $.325 but is not more than $.45, plus
- 50% of that portion of the quarterly distribution per limited partner
unit which exceeds $.45.
At TEPPCO's 2000 per unit distribution level, the general partner:
- receives approximately 18% of the cash distributed by TEPPCO to its
partners, which consists of 16% from the incentive cash distribution and
2% from the general partner interest; and
- under the incentive cash distribution provisions, receives 50% of any
increase in TEPPCO's per unit cash distributions.
During 2000, total cash distributions to the general partner of TEPPCO were
$14.5 million.
In July 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield
Company's ownership interests in a 500-mile crude oil pipeline that extends from
a marine terminal at Freeport, Texas to Cushing, Oklahoma, a 416-mile crude oil
pipeline that extends from Jal, New Mexico to Cushing, a 400-mile crude oil
pipeline that extends from West Texas to Houston, crude oil terminal facilities
in Midland, Texas, Cushing and the Houston area and receipt and delivery
pipelines centered around Midland.
In August 2000, TEPPCO announced the execution of definitive agreements
with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form
Centennial Pipeline, LLC. Centennial Pipeline will own and operate an interstate
refined petroleum products pipeline extending from the upper Texas Gulf Coast to
Illinois. TEPPCO and each of the other two participants will own a one-third
interest in Centennial Pipeline.
In December 2000, TEPPCO completed an acquisition of pipeline assets from
the Company for $91 million. The purchase included two natural gas liquids
pipelines in East Texas. The Panola Pipeline, a 189-mile pipeline from Carthage,
Texas to Mont Belvieu, Texas, has a capacity of approximately 38,000 barrels per
day. The San Jacinto Pipeline, a 34-mile pipeline from Carthage to Longview,
Texas, has a capacity of approximately 11,000 barrels per day. A lease of a
34-mile condensate pipeline from Carthage to Marshall, Texas, was also assumed.
All three pipelines originate at the Company's East Texas Plant Complex in
Panola County, Texas.
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NATURAL GAS SUPPLIERS
We purchase substantially all of our raw natural gas from producers under
varying term contracts. Typically, we take ownership of raw natural gas at the
wellhead, settling payments with producers on terms set forth in the applicable
contracts. These producers range in size from small independent owners and
operators to large integrated oil companies, such as Phillips, our largest
single supplier. No single producer accounted for more than 10% of our natural
gas throughput in 2000. Each producer generally dedicates to us the raw natural
gas produced from designated oil and natural gas leases for a specific term. The
term will typically extend for three to seven years and in some cases for the
life of the lease. We currently have over 15,000 active contracts with over
5,000 producers. We consider our relations with our producers to be good. For a
description of the types of contracts we have entered into with our suppliers,
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Overview -- Effects of Our Raw Natural Gas Supply Arrangements."
COMPETITION
We face strong competition in acquiring raw natural gas supplies. Our
competitors in obtaining additional gas supplies and in gathering and processing
raw natural gas include:
- major integrated oil companies;
- major interstate and intrastate pipelines or their affiliates;
- other large raw natural gas gatherers that gather, process and market
natural gas and/or NGLs; and
- a relatively large number of smaller raw natural gas gatherers of varying
financial resources and experience.
Competition for raw natural gas supplies is concentrated in geographic
regions based upon the location of gathering systems and natural gas processing
plants. Although we are one of the largest gatherers and processors in most of
the geographic regions in which we operate, most producers in these areas have
alternate gathering and processing facilities available to them. In addition,
producers have other alternatives, such as building their own gathering
facilities or in some cases selling their raw natural gas supplies without
processing. Competition for raw natural gas supplies in these regions is
primarily based on:
- the reputation, efficiency and reliability of the gatherer/processor,
including the operating pressure of the gathering system;
- the availability of gathering and transportation;
- the pricing arrangement offered by the gatherer/processor; and
- the ability of the gatherer/processor to obtain a satisfactory price for
the producers' residue gas and extracted NGLs.
In addition to competition in raw natural gas gathering and processing,
there is vigorous competition in the marketing of residue gas. Competition for
customers is based primarily upon the price of the delivered gas, the services
offered by the seller, and the reliability of the seller in making deliveries.
Residue gas also competes on a price basis with alternative fuels such as oil
and coal, especially for customers that have the capability of using these
alternative fuels and on the basis of local environmental considerations. Also,
to foster competition in the natural gas industry, certain regulatory actions of
FERC and some states have allowed buying and selling to occur at more points
along transmission and distribution systems.
Competition in the NGLs marketing area comes from other midstream NGLs
marketing companies, international producers/traders, chemical companies and
other asset owners. Along with numerous marketing competitors, we offer price
risk management and other services. We believe it is important that we tailor
our services to the end-use customer to remain competitive.
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REGULATION
Transportation. Historically, the transportation and sale for resale of
natural gas in interstate commerce have been regulated under the Natural Gas Act
of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (FERC). In the past, the
federal government regulated the prices at which natural gas could be sold. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all
Natural Gas Act and Natural Gas Policy Act price and non-price controls
affecting wellhead sales of natural gas. Congress could, however, reenact field
natural gas price controls in the future, though we know of no current
initiative to do so.
As a gatherer, processor and marketer of raw natural gas, we depend on the
natural gas transportation and storage services offered by various interstate
and intrastate pipeline companies to enable the delivery and sale of our residue
gas supplies. In accordance with methods required by FERC for allocating the
system capacity of "open access" interstate pipelines, at times other system
users can preempt the availability of interstate natural gas transportation and
storage service necessary to enable us to make deliveries and sales of residue
gas. Moreover, shippers and pipelines may negotiate the rates charged by
pipelines for such services within certain allowed parameters. These rates will
also periodically vary depending upon individual system usage and other factors.
An inability to obtain transportation and storage services at competitive rates
can hinder our processing and marketing operations and affect our sales margins.
The intrastate pipelines that we own are subject to state regulation and,
to the extent they provide interstate services under Section 311 of the Natural
Gas Policy Act of 1978, also are subject to FERC regulation. We also own a
partnership interest in Dauphin Island Gathering Partners, which owns and
operates a natural gas gathering system and interstate transmission system
located in offshore waters south of Louisiana and Alabama. The offshore
gathering system is not a jurisdictional entity under the Natural Gas Act; the
interstate offshore transmission system is regulated by FERC.
Commencing in April 1992, FERC issued Order No. 636 and a series of related
orders that require interstate pipelines to provide open-access transportation
on a basis that is equal for users of the pipeline services. FERC has stated
that it intends for Order No. 636 to foster increased competition within all
phases of the natural gas industry. Order No. 636 applies to our activities in
Dauphin Island Gathering Partners and how we conduct gathering, processing and
marketing activities in the market place serviced by Dauphin Island Gathering
Partners. The courts have largely affirmed the significant features of Order No.
636 and the numerous related orders pertaining to individual pipelines, although
certain appeals remain pending and FERC continues to review and modify its
regulations. For example, the FERC recently issued Order No. 637 which, among
other things:
- lifts the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002 for short-term releases of
pipeline capacity of less than one year;
- permits pipelines to charge different maximum cost-based rates for peak
and off-peak periods;
- encourages, but does not mandate, auctions for pipeline capacity;
- requires pipelines to implement imbalance management services;
- restricts the ability of pipelines to impose penalties for imbalances,
overruns and non-compliance with operational flow orders; and
- implements a number of new pipeline reporting requirements.
Order No. 637 also requires the FERC to analyze whether the FERC should
implement additional fundamental policy changes, including, among other things,
whether to pursue performance-based ratemaking or other non-cost based
ratemaking techniques and whether the FERC should mandate greater
standardization in terms and conditions of service across the interstate
pipeline grid. In addition, the FERC recently implemented new regulations
governing the procedure for obtaining authorization to construct new pipeline
facilities and has issued a policy statement, which it largely affirmed in a
recent order on rehearing, establishing a presumption in favor of requiring
owners of new pipeline facilities to charge rates based solely on
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the costs associated with such new pipeline facilities. We cannot predict what
further action FERC will take on these matters. However, we do not believe that
we will be affected by any action taken previously or in the future on these
matters materially differently than other natural gas gatherers, processors and
marketers with which we compete.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, FERC and the courts. The natural gas
industry historically has been heavily regulated; therefore, there is no
assurance that the less stringent and pro-competition regulatory approach
recently pursued by FERC and Congress will continue.
Gathering. The Natural Gas Act exempts natural gas gathering facilities
from the jurisdiction of FERC. Interstate natural gas transmission facilities,
on the other hand, remain subject to FERC jurisdiction. FERC has historically
distinguished between these two types of facilities on a fact-specific basis. We
believe that our gathering facilities and operations meet the current tests that
FERC uses to grant non-jurisdictional gathering facility status. However, there
is no assurance that FERC will not modify such tests or that all of our
facilities will remain classified as natural gas gathering facilities.
Some states in which we own gathering facilities have adopted laws and
regulations that require gatherers either to purchase without undue
discrimination as to source or supplier or to take ratably without undue
discrimination natural gas production that may be tendered to the gatherer for
handling. For example, the states of Oklahoma and Kansas also have adopted
complaint-based statutes that allow the Oklahoma Corporation Commission and the
Kansas Corporation Commission, respectively, to remedy discriminatory rates for
providing gathering service where the parties are unable to agree. In a similar
way, the Railroad Commission of Texas sponsors a complaint procedure for
resolving grievances about natural gas gathering access and rate discrimination.
The FERC recently issued Order No. 639, requiring that virtually all
non-proprietary pipeline transporters of natural gas on the outer-continental
shelf report information on their affiliations, rates and conditions of service.
Among FERC's purposes in issuing these rules was the desire to provide shippers
on the outer-continental shelf with greater assurance of open-access services on
pipelines located on the outer-continental shelf and non-discriminatory rates
and conditions of service on these pipelines. The FERC exempted Natural Gas
Act-regulated pipelines, like that owned and operated by Dauphin Island
Gathering Partners, from the new reporting requirements, reasoning that the
information that these pipelines were already reporting was sufficient to
monitor conformity with existing non-discrimination mandates. However, pipelines
not regulated under the Natural Gas Act, like our gathering lines located on the
outer-continental shelf, must comply with the new rules. This could increase our
cost of regulatory compliance and place us at a disadvantage in comparison to
companies that are not required to satisfy the reporting requirements. Order No.
639 may be altered on appeal, and it is not known at this time what effect these
new rules, as they may be altered, will have on our business. We currently
believe that Order No. 639 and the related reporting requirements will not have
a material adverse effect on our existing business activities.
Processing. The primary function of our natural gas processing plants is
the extraction of NGLs and the conditioning of natural gas for marketing. FERC
has traditionally maintained that a processing plant that primarily extracts
NGLs is not a facility for transportation or sale of natural gas for resale in
interstate commerce and therefore is not subject to its jurisdiction under the
Natural Gas Act. We believe that our natural gas processing plants are primarily
involved in removing NGLs and, therefore, are exempt from the jurisdiction of
FERC.
Transportation and Sales of Natural Gas Liquids. We have non-operating
interests in two pipelines that transport NGLs in interstate commerce. The
rates, terms and conditions of service on these pipelines are subject to
regulation by the FERC under the Interstate Commerce Act. The Interstate
Commerce Act requires, among other things, that petroleum products (including
NGLs) pipeline rates be just and reasonable and non-discriminatory. The FERC
allows petroleum pipeline rates to be set on at least three bases, including
historic cost, historic cost plus an index or market factors.
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Sales of Natural Gas Liquids. Our sales of NGLs are not currently
regulated and are made at market prices. In a number of instances, however, the
ability to transport and sell such NGLs are dependent on liquids pipelines whose
rates, terms and conditions or service are subject to the Interstate Commerce
Act. Although certain regulations implemented by the FERC in recent years could
result in an increase in the cost of transporting NGLs on certain petroleum
products pipelines, we do not believe that these regulations affect us any
differently than other marketers of NGLs with whom we compete.
U.S. Department of Transportation. Some of our pipelines are subject to
regulation by the U.S. Department of Transportation with respect to their
design, installation, testing, construction, operation, replacement and
management. Comparable regulations exist in some states where we do business.
These regulations provide for safe pipeline operations and include potential
fines and penalties for violations.
Safety and Health. Certain federal statutes impose significant liability
upon the owner or operator of natural gas pipeline facilities for failure to
meet certain safety standards. The most significant of these is the Natural Gas
Pipeline Safety Act, which regulates safety requirements in the design,
construction, operation and maintenance of gas pipeline facilities. In addition,
we are subject to a number of federal and state laws and regulations, including
the federal Occupational Safety and Health Act and comparable state statutes,
whose purpose is to maintain the safety of workers, both generally and within
the pipeline industry. We have an internal program of inspection designed to
monitor and enforce compliance with pipeline and worker safety requirements. We
believe we are in substantial compliance with the requirements of these laws,
including general industry standards, recordkeeping requirements, and monitoring
of occupational exposure to hazardous substances.
Canadian Regulation. Our Canadian assets in the province of Alberta are
regulated by the Alberta Energy and Utilities Board. Our West Doe natural gas
gathering pipeline, which crosses the Alberta/British Columbia border, falls
under the jurisdiction of the National Energy Board. It is a Group 2 company
which is regulated on a complaint only basis by the National Energy Board.
ENVIRONMENTAL MATTERS
The operation of pipelines, plants and other facilities for gathering,
transporting, processing, treating, or storing natural gas, NGLs and other
products is subject to stringent and complex laws and regulations pertaining to
health, safety and the environment. As an owner or operator of these facilities,
we must comply with U.S. and Canadian laws and regulations at the federal,
state, and local levels that relate to air and water quality, hazardous and
solid waste management and disposal, and other environmental matters. Certain
environmental regulations and laws affecting us include:
- The Clean Air Act and the 1990 amendments to the Act, as well as
counterpart state laws and regulations affecting emissions to the air,
that impose responsibilities on the owners and/or operators of air
emissions sources including obtaining permits and annual compliance and
reporting obligations;
- The Federal Water Pollution Control Act and its amendments, which require
permits for facilities that discharge treated wastewater or other
materials into waters of the United States;
- The Federal Resource Conservation and Recovery Act and its amendments,
which regulate the management, treatment, and disposal of solid and
hazardous wastes, and state programs addressing parallel state issues;
- The Comprehensive Environmental Response, Compensation, and Liability Act
and its amendments, which may impose liability, regardless of fault, for
historic or future disposal or releases of hazardous substances into the
environment, including cleanup obligations associated with such releases
or discharges;
- State regulations for the reporting, assessment and remediation of
releases of material to the environment, including historic releases of
hydrocarbon liquids; and
- Canadian Environmental Laws.
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Costs of planning, designing, constructing and operating pipelines, plants,
and other facilities must incorporate compliance with environmental laws and
regulations and safety standards. Failure to comply with these laws and
regulations may trigger a variety of administrative, civil and potentially
criminal enforcement measures, which can include the assessment of monetary
penalties, the imposition of remedial requirements, the issuance of injunctions
or restrictions on operation, and potentially federally-authorized citizen
suits.
For further discussion of our environmental matters, including possible
liability and capital costs, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Environmental Considerations"
and Note 14 Commitments and Contingent Liabilities -- Environmental of the Notes
to Consolidated Financial Statements.
EMPLOYEES
As of December 31, 2000, we had approximately 3,400 employees, which
includes approximately 800 employees of our wholly-owned subsidiary Texas
Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners,
L.P. We are a party to three collective bargaining agreements which cover an
aggregate of approximately 115 of our employees. We believe our relations with
our employees are good.
ITEM 2. PROPERTIES.
For information regarding the Company's properties, see "Item 1.
Business -- Natural Gas Gathering, Processing, Transportation, Marketing and
Storage," "-- Natural Gas Liquids Transportation, Fractionation and Marketing,"
and "-- TEPPCO," each of which is incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS.
See Note 14 Commitments and Contingent Liabilities of the Notes to
Consolidated Financial Statements for discussion of the Company's legal
proceedings which is incorporated herein by reference.
Management believes that the resolution of the matters discussed will not
have a material adverse effect on the consolidated results of operations or the
financial position of the Company.
In addition to the foregoing, from time to time, we are named as parties in
legal proceedings arising in the ordinary course of our business. We believe we
have meritorious defenses to all of these lawsuits and legal proceedings and
will vigorously defend against them. Based on our evaluation of pending matters
and after consideration of reserves established, we believe that the resolution
of these proceedings will not have a material adverse effect on our business,
financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of the Company's members during the
last quarter of 2000.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Duke Energy beneficially owns 69.7% of our outstanding member interests,
and Phillips beneficially owns the remaining 30.3%. There is no market for our
member interests. Unless otherwise approved by our board of directors, we are
prohibited from making any distributions except distributions in an amount
sufficient to pay certain tax obligations of our members that arise from their
ownership of member interests.
In August 2000, we issued $300.0 million of preferred members interests to
affiliates of Duke Energy and Phillips. The proceeds from this financing were
used to repay a portion of our outstanding commercial paper. The preferred
member interests are entitled to cumulative preferential distributions of 9.5%
per annum payable, unless deferred, semi-annually. We have the right to defer
payments of preferential distributions on the preferred member interests, other
than certain tax distributions, at any time and from time to time, for up to ten
consecutive semi-annual periods. Deferred preferred distributions will accrue
additional amounts based
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on the preferential distribution rate (plus 0.5% per annum) to the date of
payment. The preferred member interests, together with all accrued and unpaid
preferential distributions, must be redeemed and paid on the earlier of the
thirtieth anniversary date of issuance or consummation of an initial public
offering of the Company's equity securities.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth selected historical financial and other data
for the Company and the Predecessor Company. The selected historical
consolidated financial data as of December 31, 2000 and for the period then
ended have been derived from the audited consolidated financial statements of
the Company included elsewhere in this Form 10-K. The selected historical
combined financial data as of December 31, 1999, 1998 and 1997 and for the
periods then ended have been derived from the Predecessor Company's audited
historical financial statements. The historical financial information for 1996
is derived from unaudited financial statements.
The data should be read in conjunction with the financial statements and
related notes and other financial information appearing elsewhere in this Form
10-K.
2000 1999(1) 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
ANNUAL INCOME STATEMENT DATA:
Operating revenues:
Sales of natural gas and
petroleum products.......... $8,893,515 $3,310,260 $1,469,133 $1,700,029 $1,321,111
Transportation, storage and
processing.................. 199,851 148,050 115,187 101,803 70,577
---------- ---------- ---------- ---------- ----------
Total operating
revenues............. 9,093,366 3,458,310 1,584,320 1,801,832 1,391,688
Costs and expenses:
Natural gas and petroleum
products.................... 7,875,418 2,965,297 1,338,129 1,468,089 1,070,805
Operating and maintenance...... 331,572 181,392 113,556 104,308 93,838
Depreciation and
amortization................ 234,862 130,788 75,573 67,701 55,500
General and administrative..... 171,154 73,685 44,946 36,023 43,871
Net (gain) loss on sale of
assets...................... (10,660) 2,377 (33,759) (236) (2,350)
---------- ---------- ---------- ---------- ----------
Total costs and
expenses............. 8,602,346 3,353,539 1,538,445 1,675,885 1,261,664
Operating income................. 491,020 104,771 45,875 125,947 130,024
Equity in earnings of
unconsolidated affiliates...... 27,424 22,502 11,845 9,784 2,997
---------- ---------- ---------- ---------- ----------
Earnings before interest and
tax............................ 518,444 127,273 57,720 135,731 133,021
Interest expense................. 149,220 52,915 52,403 51,113 12,747
---------- ---------- ---------- ---------- ----------
Earnings before income tax....... 369,224 74,358 5,317 84,618 120,274
Income tax expense (benefit)..... (310,937) 31,029 3,289 33,380 35,665
---------- ---------- ---------- ---------- ----------
Net income....................... $ 680,161 $ 43,329 $ 2,028 $ 51,238 $ 84,609
========== ========== ========== ========== ==========
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2000 1999(1) 1998 1997 1996
---------- ----------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT RATIOS AND PER UNIT DATA)
OTHER DATA:
Cash flow from operations..... $ 713,065 $ 173,136 $ 40,409 $ 173,357
Cash flow from investing
activities................. (234,733) (1,571,446) (203,625) (138,021)
Cash flow from financing
activities................. (477,571) 1,398,934 162,514 (35,061)
Acquisitions and other capital
expenditures.................. $ 370,948 $ 1,570,083 $ 185,479 $ 121,978 $ 524,730
EBITDA(2)....................... $ 753,306 $ 258,061 $ 133,293 $ 203,432 $ 188,521
Ratio of EBITDA to interest
expense(3).................... 5.05 4.88 2.54 3.98 14.79
Ratio of earnings to fixed
charges(4).................... 3.46 2.33 1.07 2.52 9.11
Gas transported and/or processed
(TBtu/d)...................... 7.6 5.1 3.6 3.4 2.9
NGLs production(MBbl/d)......... 359 192 110 108 79
MARKET DATA:
Average NGLs price per
gallon(5)..................... $ .53 $ .34 $ .26 $ .35 $ .39
Average natural gas price per
MMBtu(6)...................... $ 3.89 $ 2.27 $ 2.11 $ 2.59 $ 2.59
BALANCE SHEET DATA (END OF
PERIOD):
Total assets.................... $6,170,098 $ 3,482,296 $1,770,838 $1,649,213 $1,459,416
Long-term debt.................. $1,688,157 $ 101,600 $ 101,600 $ 101,600 $ 101,600
Preferred members' interest..... $ 300,000
- ---------------
(1) Includes the results of operations of Union Pacific Fuels for the nine
months ended December 31, 1999. Union Pacific Fuels was acquired by the
Predecessor Company on March 31, 1999.
(2) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense. EBIT
consists of income from continuing operations before interest expense and
income tax expense. Neither EBITDA nor EBIT is a measurement presented in
accordance with generally accepted accounting principles. You should not
consider either measure in isolation from or as a substitute for net income
or cash flow measures prepared in accordance with generally accepted
accounting principles or as a measure of our profitability or liquidity.
EBITDA is included as a supplemental disclosure because it may provide
useful information regarding our ability to service debt and to fund capital
expenditures. However, not all EBITDA may be available to service debt.
(3) The ratio of EBITDA to interest expense represents a ratio that provides an
investor with information as to our company's current ability to meet our
financing costs.
(4) The ratios of earnings to fixed charges are computed utilizing the
Securities and Exchange Commission ("SEC") mandated methods.
(5) Based on index prices from the Mont Belvieu and Conway market hubs that are
weighted by our component and location mix for the periods indicated.
(6) Based on the NYMEX Henry Hub prices for the periods indicated.
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ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
Duke Energy Field Services, LLC holds the combined North American midstream
natural gas gathering, processing, marketing and NGL business of Duke Energy and
Phillips Petroleum. The transaction in which those businesses were combined is
referred to as the "Combination."
On March 31, 2000, we combined the gas gathering, processing, marketing and
NGLs businesses of Duke Energy and Phillips. In connection with the Combination,
Duke Energy and Phillips transferred all of their respective interests in their
subsidiaries that conducted their midstream natural gas business to us. In
connection with the Combination, Duke Energy and Phillips also transferred to us
additional midstream natural gas assets acquired by Duke Energy or Phillips
prior to consummation of the Combination, including the Mid-Continent gathering
and processing assets of Conoco and Mitchell Energy. Concurrently with the
Combination, we obtained by transfer from Duke Energy the general partner of
TEPPCO. In exchange for the asset contribution, Phillips received 30.3% of the
member interests in our company, with Duke Energy holding the remaining 69.7% of
the outstanding member interests in our company. In connection with the closing
of the Combination, we borrowed approximately $2.8 billion in the commercial
paper market and made one-time cash distributions (including reimbursements for
acquisitions) of approximately $1.5 billion to Duke Energy and approximately
$1.2 billion to Phillips. See "-- Liquidity and Capital Resources."
The Combination was accounted for as a purchase business combination in
accordance with Accounting Principles Board Opinion (APB) No. 16, "Accounting
for Business Combinations." The Predecessor Company was the acquiror of
Phillips' midstream natural gas business in the Combination.
The following discussion details the material factors that affected our
historical financial condition and results of operations in 2000, 1999 and 1998.
This discussion should be read in conjunction with "Item 1. Business," and the
consolidated financial statements, and the related notes, included elsewhere in
this Form 10-K.
From a financial reporting perspective, we are the successor to Duke
Energy's North American midstream natural gas business. The subsidiaries of Duke
Energy that conducted this business were contributed to us immediately prior to
the Combination. For periods prior to the Combination, Duke Energy Field
Services and these subsidiaries of Duke Energy are collectively referred to
herein as the "Predecessor Company."
Unless the context otherwise requires, the discussion of our business
contained in this section for periods ending on or prior to March 31, 2000
relates solely to the Predecessor Company on an historical basis and does not
give effect to the Combination, the transfer to our company of additional
midstream natural gas assets acquired by Duke Energy or Phillips prior to
consummation of the Combination or the transfer to our company of the general
partner of TEPPCO from Duke Energy.
OVERVIEW
We operate in the two principal business segments of the midstream natural
gas industry:
- natural gas gathering, processing, transportation and storage, from which
we generate revenues primarily by providing services such as compression,
treating and gathering, processing, local fractionation, transportation
of residue gas, storage and marketing. In 2000, approximately 66% of the
Company's operating revenues prior to intersegment revenue elimination
and approximately 96% of the Company's gross margin were derived from
this segment.
- NGLs fractionation, transportation, marketing and trading, from which we
generate revenues from transportation fees, market center fractionation
and the marketing and trading of NGLs. In 2000, approximately 34% prior
to intersegment revenue elimination of the Company's operating revenues
and approximately 4% of the Company's gross margin were from this
segment.
Our limited liability company agreement limits the scope of our business to
the midstream natural gas industry in the United States and Canada, the
marketing of NGLs in Mexico and the transportation, marketing and storage of
other petroleum products, unless otherwise approved by our board of directors.
This limitation in scope is not currently expected to materially impact the
results of our operations.
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Effects of Commodity Prices
In 1999, approximately 59% of the Predecessor Company's gross margin was
generated by arrangements that are commodity price sensitive and 41% of the
Predecessor Company's gross margin was generated by fee-based arrangements.
Because the gross margin of Phillips' midstream gas business was more heavily
weighted towards arrangements that are commodity price sensitive, as a result of
the Combination the portion of our gross margin generated by fee-based
arrangements has decreased. For example, in 2000, after giving effect to the
Combination, approximately 23% of our gross margin was generated by fee-based
arrangements.
The midstream natural gas industry has been cyclical, with the operating
results of companies in the industry significantly affected by the prevailing
price of NGLs, which in turn is generally correlated to the price of crude oil.
Although the prevailing price of natural gas has less short term significance to
our operating results than the price of NGLs, in the long term the growth of our
business depends on natural gas prices being at levels sufficient to provide
incentives and capital for producers to increase natural gas exploration and
production. In the past, the prices of NGLs and natural gas have been extremely
volatile.
The gas gathering and processing price environment deteriorated between
1996 and 1997 as prices for NGLs decreased and prices for natural gas increased
from 1996 levels. Increases in worldwide crude oil supply and production in 1998
drove a steep decline in crude oil prices. NGL prices also declined sharply in
1998 as a result of the correlation between crude oil and NGL pricing. Natural
gas prices also declined during 1998 principally due to mild weather.
The lower NGL and natural gas price environment experienced in 1998
prevailed during the first quarter of 1999. However, during the last three
quarters of 1999, NGL prices increased sharply as major crude oil exporting
countries agreed to maintain crude oil production at predetermined levels and
world demand for crude oil and NGLs increased. The lower crude oil and natural
gas prices in 1998 and early 1999 caused a significant reduction in the
exploration activities of U.S. producers, which in turn had a significant
negative effect on natural gas volumes gathered and processed in 1999.
During 2000, the weighted average NGL price (based on index prices from the
Mont Belvieu and Conway market hubs that are weighted by our component and
location mix) was approximately $.53 per gallon compared to $.34 per gallon in
1999 and $.27 per gallon in 1998. In the near term, we expect NGL prices to
follow changes in crude oil prices generally, which we believe will in large
part be determined by the level of production from major crude oil exporting
countries and the demand generated by growth in the world economy. In contrast,
we believe that future natural gas prices will be influenced by supply
deliverability, the severity of winter weather and the level of U.S. economic
growth. We believe that weather will be the strongest determinant of near term
natural gas prices. The price increases in crude oil, NGLs and natural gas have
spurred increased natural gas drilling activity. For example, the average number
of active drilling rigs in North America has increased by approximately 45% from
approximately 871 in 1999 to more than 1,263 in 2000. This drilling activity
increase is expected to have a positive effect on natural gas volumes gathered
and processed in the near term.
Effects of Our Raw Natural Gas Supply Arrangements
Our results are affected by the types of arrangements we use to purchase
raw natural gas. We obtain access to raw natural gas and provide our midstream
natural gas services principally under three types of contracts:
- Percentage-of-Proceeds Contracts -- Under these contracts (which also
include percentage-of-index contracts), we receive as our fee a
negotiated percentage of the residue natural gas and NGLs value derived
from our gathering and processing activities, with the producer retaining
the remainder of the value. These type of contracts permit us and the
producers to share proportionately in price changes. Under these
contracts, we share in both the increases and decreases in natural gas
prices and NGL prices. During 2000, after giving effect to the
Combination, approximately 69% of our gross margin was generated from
percentage-of-proceeds or percentage-of-index contracts.
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- Fee-Based Contracts -- Under these contracts we receive a set fee for
gathering, processing and/or treating raw natural gas. Our revenue stream
from these contracts is correlated with our level of gathering and
processing activity and is not directly dependent on commodity prices.
During 2000, after giving effect to the Combination, approximately 23% of
our gross margin was generated from fee-based contracts.
- Keep-Whole Contracts -- Under these contracts we gather raw natural gas
from the producer for processing. After we process the raw natural gas,
we are obligated to return to the producer residue gas with a Btu content
equivalent to the Btu content of the raw natural gas gathered. As a
result of our processing, NGLs are extracted from the raw natural gas
resulting in a shrinkage in the Btu content of the natural gas. We market
the NGLs and purchase natural gas at market prices in order to return to
the producer residue gas with a Btu content equivalent to the Btu content
of the raw natural gas gathered. Accordingly, under these contracts, we
are exposed to increases in the price of natural gas and decreases in the
price of NGLs. During 2000, after giving effect to the Combination,
approximately 8% of our gross margin was generated from keep-whole
contracts.
Our current mix of percentage-of-proceeds and percentage-of-index contracts
(where we are exposed to decreases in natural gas prices) and keep-whole
contracts (where we are exposed to increases in natural gas prices)
significantly mitigates our exposure to increases in natural gas prices. Our
exposure to changes in NGL prices is partially offset by our hedging program.
Our hedging program reduces the potential negative impact that commodity price
changes could have on our earnings and improves our ability to adequately plan
for cash needed for debt service, dividends, and capital expenditures. The
primary goals of our hedging program include maintaining minimum cash flows to
fund debt service, dividends, production replacement and maintenance capital
projects; avoiding disruption of our growth capital and value creation process;
and retaining a high percentage of potential upside relating to price increases
of NGLs.
We prefer to enter into percentage-of-proceeds type supply contracts
(including percentage-of-index contracts). We believe this type of contract
provides the best alignment with our producers and represents the best
risk/reward profile for the capital we employ. Notwithstanding this preference,
we also recognize from a competitive viewpoint that we will need to offer
keep-whole contracts to attract certain supply to our systems. We also employ a
fee-type contract, particularly where there is treating and/or transportation
involved. Our contract mix and, accordingly, our exposure to natural gas and NGL
prices may change as a result of changes in producer preferences, our expansion
in regions where some types of contracts are more common and other market
factors.
Based upon the Company's portfolio of supply contracts, without giving
effect to hedging activities that would reduce the impact of commodity price
decreases, a decrease of $.01 per gallon in the price of NGLs and $.10 per
million Btus in the average price of natural gas would result in changes in
annual pre-tax net income of approximately $(26.0) million and $3.0 million,
respectively. After considering the affects of commodity hedge positions in
place at December 31, 2000, it is estimated that if NGL prices average $.01 per
gallon less in the next twelve months pre-tax net income would decrease $20.0
million.
Other Factors That Have Significantly Affected Our Results
Our results of operations also are correlated with increases and decreases
in the volume of raw natural gas that we put through our system, which we refer
to as throughput volume, and the percentage of capacity at which our processing
facilities operate, which we refer to as our asset utilization rate. Throughput
volumes and asset utilization rates generally are driven by production on a
regional basis and more broadly by demand for residue natural gas and NGLs.
Risk management, which was directed by Duke Energy's centralized program
for controlling, managing and coordinating its management of risks prior to the
Combination, also has affected our results of operations, in 1999 and 2000. Our
1999 and 2000 results of operations include hedging losses of $34.0 million and
$127.7 million, respectively. Since the Combination, we have directed our risk
management activities
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independently of Duke Energy, with goals, policies and procedures that are
different from those of Duke Energy. See "Item 7A. Quantitative and Qualitative
Disclosure about Market Risk."
In addition to market factors and production, our results have been
affected by our acquisition strategy, including the timing of acquisitions and
our ability to integrate acquired operations and achieve operating synergies.
HISTORICAL RESULTS OF OPERATIONS
The following is a discussion of our historical results of operations. The
discussion for periods ending on or prior to the Combination on March 31, 2000
relates solely to the Predecessor Company and does not give effect to the
Combination, the transfer to our company of additional midstream natural gas
assets acquired by Duke Energy or Phillips prior to consummation of the
Combination or the transfer to our company of the general partner of TEPPCO from
Duke Energy.
2000 compared with 1999
Operating Revenues. Operating revenues increased $5,635.1 million, or 163%
from $3,458.3 million in 1999 to $9,093.4 million in 2000. Operating revenues
from the sale of natural gas and petroleum products accounted for $8,893.5
million of the total and $5,583.3 million of the increase. Of this increase,
approximately $2,312.7 million was related to the addition of the Phillips'
midstream natural gas business to our operations in the Combination on March 31,
2000, and approximately $425.0 million was related to the March 31, 1999
acquisition of Union Pacific Fuels. Increased NGL trading and marketing activity
also contributed to the increase. NGL production during 2000 increased 166,100
barrels per day, or 86%, from 192,400 barrels per day to 358,500 barrels per
day, and natural gas transported and/or processed increased 2.5 trillion Btus
per day, or 49%, from 5.1 trillion Btus per day to 7.6 trillion Btus per day. Of
the 166,100 barrels per day increase in NGL production, the addition of the
Phillips' midstream natural gas business in the Combination contributed
approximately 125,800 barrels per day, and the Union Pacific Fuels acquisition
contributed approximately 25,150 barrels per day. The combination of the
acquisition of assets from Conoco/ Mitchell, our Wilcox plant expansion,
completion of our Mobile Bay Plant and the acquisition of Koch's South Texas
assets accounted for the remainder of the increase. Of the 2.5 trillion Btus per
day increase in natural gas transported and/or processed, the addition of the
Phillips' midstream natural gas business in the Combination contributed
approximately 1.6 trillion Btus per day, and the Union Pacific Fuels acquisition
contributed approximately 0.5 trillion Btus per day. The combination of other
acquisitions, plant expansions and completions accounted for the balance of the
increase.
Commodity prices significantly contributed to higher operating revenues.
Weighted average NGL prices, based on our component product mix, were
approximately $.19 per gallon higher and natural gas prices were approximately
$1.62 per million Btus higher during 2000. These price increases yielded average
prices of $.53 per gallon of NGLs and $3.89 per million Btus of natural gas,
respectively, as compared with $.34 per gallon and $2.27 per million Btus during
1999. Revenues associated with gathering, transportation, storage, processing
fees and other increased $52.0 million, or 35%, from $148.0 million to $200.0
million, mainly as a result of the Union Pacific Fuels acquisition and the
Combination. A $127.7 million hedging loss in 2000 partially offset operating
revenues increases. See "Item 7A. Quantitative and Qualitative Disclosure About
Market Risk."
Costs and Expenses. Costs of natural gas and petroleum products increased
$4,910.1 million, or 166%, from $2,965.3 million in 1999 to $7,875.4 million in
2000. This increase was due to the addition of the Phillips' midstream natural
gas business in the Combination (approximately $1,790.0 million), the Union
Pacific Fuels acquisition (approximately $340.0 million), and the interaction of
our natural gas and NGL purchase contracts with higher commodity prices and
increased trading and marketing activity.
Operating and maintenance expenses increased $150.2 million, or 83%, from
$181.4 million in 1999 to $331.6 million in 2000. Of this increase,
approximately $109.3 million is related to the addition of the Phillips'
midstream natural gas business in the Combination and approximately $13.0
million was related to the Union Pacific Fuels acquisition. General and
administrative expenses increased $97.5 million, or 132%, from
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$73.7 million in 1999 to $171.2 million in 2000. Of this increase, $12.5 million
was due to increased allocated corporate overhead from Duke Energy as a result
of our company's growth. The remainder was associated with increased activity
resulting from the addition of the Phillips' midstream natural gas business in
the Combination, the Union Pacific Fuels acquisition and increased incentive
compensation accruals for 2000.
Depreciation and amortization increased $104.1 million, or 80%, from $130.8
million in 1999 to $234.9 million in 2000. Of this increase, $72.5 million was
due to the addition of the Phillips' midstream natural gas business in the
Combination and $15.4 million was due to the Union Pacific Fuels acquisition.
The remainder was due to ongoing capital expenditures for well connections,
facility maintenance/enhancements and acquisitions.
Equity Earnings. Equity earnings of unconsolidated affiliates increased
$4.9 million, or 22%, from $22.5 million in 1999 to $27.4 million in 2000. This
increase was due primarily to interests in joint ventures and partnerships
acquired from Union Pacific Fuels and the acquisition of the general partnership
interest in TEPPCO as of March 31, 2000, offset by joint venture interest
dispositions and declining fractionation spreads associated with offshore and
South Texas processing partnerships.
Interest. Interest expense increased $96.3 million, or 182%, from $52.9
million in 1999 to $149.2 million in 2000. This increase was primarily the
result of the issuance of commercial paper and the subsequent debt offering in
the third quarter used to repay a portion of the outstanding commercial paper to
fund the distribution paid to Duke Energy and Phillips in the Combination.
Income Taxes. At March 31, 2000, the Predecessor Company converted to a
limited liability company which is a pass-through entity for income tax
purposes. As a result, substantially all of the Predecessor Company's existing
net deferred tax liability ($327.0 million) was eliminated and a corresponding
income tax benefit was recorded.
Net Income. Net income increased $636.9 million from $43.3 million in 1999
to $680.2 million in 2000. This increase was largely the result of the tax
benefit recognition discussed above, the addition of the Phillip's midstream
natural gas business in the Combination and the Union Pacific Fuels acquisition.
Higher NGL prices contributed significantly to this increase but were partially
offset by higher natural gas prices. A $127.7 million pre-tax loss from hedging
activities experienced during 2000 partially offset the increase.
EBITDA. EBITDA for the natural gas gathering, processing, transportation
and storage segment increased $567.1 million, or 190%, from $298.7 million in
1999 to $865.8 million in 2000. Of this increase, approximately $393.5 was due
to the addition of the Phillips' midstream natural gas business in the
Combination, approximately $56.0 million was due to the acquisition of Union
Pacific Fuels, and approximately $184.9 million was due to the $.19 per gallon
increase in average NGL prices. Additional increases were attributable to the
combination of our acquisition of the Conoco/Mitchell facilities, Wilcox plant
expansion, completion of our Mobile Bay plant, the acquisition of Koch's South
Texas assets, and the acquisition of the general partnership interest in TEPPCO.
These benefits were offset by a $93.8 million decrease from hedging activities
($127.7 million loss in 2000 compared to a $34.0 million loss in 1999) and by
approximately $49.8 million was due to a $1.62 per million Btu increase in
natural gas prices.
EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $25.7 million from $33.0 million in 1999 to $58.7 million in
2000 due primarily to NGL trading and marketing activity and the acquisition of
Union Pacific Fuels.
1999 compared with 1998
Operating Revenues. Operating revenues increased $1,874.0 million, or
118%, from $1,584.3 million to $3,458.3 million. Operating revenues from the
sale of natural gas and petroleum products accounted for $3,310.3 million of the
total and $1,841.2 million of the increase. Of this increase, approximately $1.0
billion was attributable to the March 31, 1999 acquisition of Union Pacific
Fuels. Increased NGL trading and marketing activity associated with the Union
Pacific Fuels acquisition also contributed to the increase. NGL production
during 1999 increased 82,000 barrels per day, or 75%, from 110,000 barrels per
day to 192,000 barrels per day. Of the 82,000 barrels per day increase, the
Union Pacific Fuels acquisition contributed 71,000
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barrels per day, with the combination of our Wilcox plant expansion, completion
of our Mobile Bay Plant and the acquisition of Koch's South Texas assets
accounting for the remainder of the increase. Raw natural gas transported and/or
processed increased 1.5 trillion Btus per day, or 42%, from 3.6 trillion Btus
per day to 5.1 trillion Btus per day. The Union Pacific Fuels acquisition
accounted for 1.4 trillion Btus per day of the natural gas increase.
Commodity prices also contributed to higher revenues. Weighted average NGL
prices, based on our component product mix, were approximately $.08 per gallon
higher and natural gas prices were approximately $.16 per million Btus higher
for 1999, yielding prices of $.34 and $2.27, respectively, as compared with $.26
and $2.11 in 1998. Revenues associated with gathering, transportation, storage,
processing fees and other increased $32.8 million, or 28%, from $115.2 million
to $148.0 million principally as a result of the Union Pacific Fuels
acquisition. Total operating revenue increases were offset by a $34.0 million
hedging loss in 1999. See "-- Quantitative and Qualitative Disclosure About
Market Risks."
Costs and Expenses. Costs of natural gas and petroleum products increased
$1,627.2 million, or 122%, from $1,338.1 million to $2,965.3 million. This
increase was due primarily to the Union Pacific Fuels acquisition ($800
million), increased NGL trading and marketing activity and the interaction of
our natural gas and NGL purchase contracts with higher commodity prices.
Operating and maintenance expenses increased $67.8 million, or 60%, from
$113.6 million to $181.4 million. Of this increase, approximately $65.0 million
was due to the Union Pacific Fuels acquisition. General and administrative
expenses increased $28.7 million, or 64%, from $45.0 million to $73.7 million.
This increase was due to a $7.0 million increase in allocated corporate overhead
from our parent, Duke Energy, and increases resulting from the Union Pacific
Fuels acquisition.
Depreciation and amortization increased $55.2 million, or 73%, from $75.6
million to $130.8 million. Of this increase, $45.2 million was due to the Union
Pacific Fuels acquisition and the remainder was due to ongoing capital
expenditures for well connections, facility maintenance/enhancements and
acquisitions.
Sale of Assets. Net (gain) loss on sales of assets decreased $36.2
million, from a $33.8 million gain to a $2.4 million loss from 1998 to 1999.
This decrease was primarily the result of a $38.0 million gain recognized in
1998 on the sale of two fractionators in Weld County, Colorado.
Equity Earnings. Equity earnings of unconsolidated affiliates increased
$10.7 million, or 91%, from $11.8 million to $22.5 million. This increase was
largely due to interests in joint ventures and partnerships acquired from Union
Pacific Fuels in 1999.
Interest. Interest expense of $52.9 million for 1999 remained almost
unchanged from 1998 and was principally related to interest on notes due to Duke
Energy.
Net Income. Net income increased $41.3 million from $2.0 million to $43.3
million. This increase was largely the result of the acquisition of Union
Pacific Fuels and higher average NGL prices experienced during 1999. The benefit
of higher NGL prices was partially offset by higher natural gas prices. The
increase in net income was largely offset by a pre-tax gain of approximately
$38.0 million recognized on the sale of our Weld County fractionators in 1998
and a $34.0 million loss on hedging activity in 1999.
EBITDA. EBITDA for the natural gas gathering, processing, transportation
and storage segment increased $122.9 million from $175.8 million to $298.7
million. Of the increase, approximately $110 million was due to the acquisition
of Union Pacific Fuels and $80.0 million was due to $.08 per gallon higher NGL
prices. Additional increases were recognized with the combination of our Wilcox
plant expansion, completion of our Mobile Bay Plant and the acquisition of
Koch's South Texas assets. These increases were offset by a $38.0 million gain
recognized in 1998 on the sale of the Weld County fractionators, hedging losses
in 1999 of $34.0 million, an approximately $5 million decrease due to $.16 per
million BTU increase in gas prices and a $7.0 million increase in allocated
corporate overhead from our parent, Duke Energy.
EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $30.6 million from $2.4 million to $33.0 million due primarily
to the acquisition of Union Pacific Fuels.
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ENVIRONMENTAL CONSIDERATIONS
On June 17, 1999, the Environmental Protection Agency (the "EPA") published
in the Federal Register a final Maximum Available Control Technology ("MACT")
standard under Section 112 of the Clean Air Act to limit emissions of Hazardous
Air Pollutants ("HAPs") from oil and natural gas production as well as from
natural gas transmission and storage facilities. The MACT standard requires that
affected facilities reduce their emissions of HAPs by 95%, and this will affect
our various large dehydration units and potentially some of our storage vessels.
This new standard will require that we achieve this reduction by either process
modifications or installing new emissions control technology. The MACT standard
will affect us and our competitors in varying degrees. The rule allows most
affected sources until at least June 2002 to comply with the requirements. While
additional capital costs are likely to result from this rule or other potential
air regulations, we believe that these changes will not have a material adverse
effect on our business, financial position or results of operations.
We have various ongoing remedial matters related to historical operations
similar to others in the industry, based primarily on state authorities
generally described under Item 1. Business -- Environmental Matters. These are
typically managed in conjunction with the relevant state or federal agencies to
address specific conditions, and in some cases are the responsibility of other
entities based upon contractual obligations related to the assets. In March
1999, we acquired the midstream natural gas gathering and processing assets of
Union Pacific Resources located in several states, which include 18 natural gas
plants and 365 gathering facility sites. We have entered into an agreement for
pre-April 1999 soil and ground water conditions identified as part of this
transaction with a third party environmental/insurance partnership for a
one-time premium payment subject to certain deductibles. With respect to these
identified environmental conditions, the environmental partner has assumed
liability and management responsibility for environmental remediation, and the
insurance partner is providing financial management, program oversight,
remediation cost cap insurance coverage for a 30 year term, and pollution legal
liability coverage for a 20 year term. While we could face liability in the
event of default, we believe this innovative approach can promote pro-active
site cleanup and closure, reduce internal resource needs for managing
remediation, and may improve the marketability of assets based on
transferability of this insurance coverage. Also, in August 1996, we acquired
certain gas gathering and processing assets in three states from Mobil
Corporation. Under the terms of the asset purchase agreement, Mobil has retained
the liabilities and costs related to various pre-August 1996 environmental
conditions that were identified with respect to those assets. Mobil has
formulated or is in the process of developing plans to address certain of these
conditions, which we will review and monitor as clean-up activities proceed.
We are presently resolving non-compliance issues with the Texas Natural
Resources Conservation Commission associated with the timing of air permit
annual compliance certifications submitted to the agency in 1998 and 1999. This
matter, a large portion of which was voluntarily self-disclosed to the agency,
involves approximately 115 of our facilities that did not meet specific
administrative filing deadlines for required air permit paperwork. In addition,
at this time we are actively resolving with the New Mexico Environment
Department alleged non-compliance with various air permit requirements at four
of our New Mexico facilities. These matters, the majority of which were also
voluntarily self-disclosed to the agency, generally involve document preparation
and submittal as required by permits, compliance testing requirements at two
facilities, and compliance with permit emissions limits at one facility. We
believe that these apparent non-compliance issues being addressed with the Texas
and New Mexico agencies under relevant air programs will result in total penalty
assessments of less than $500,000.
We have been in discussions with the Colorado Air Pollution Control
Division regarding various asserted non-compliance issues arising from agency
inspections of our Colorado facilities in 1999 and 2000, and arising from
compliance issues disclosed to the agency pursuant to permit requirements or
voluntarily disclosed to the agency in 2000. These items relate to various
specific and detailed terms of the Title V Operating Permits at seven gas plants
and two compressor stations in Colorado, including, for example, record keeping
requirements, parametric monitoring requirements, delayed filings, and
operations inconsistent with throughput limits on particular pieces of
equipment. As a result of these discussions, we received from the agency in
March 2001 a comprehensive proposed settlement agreement to resolve all of these
various items related to air permit
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compliance at the nine facilities. Although we are still discussing the
appropriate resolution of these apparent instances of non-compliance with the
Colorado agency, we believe that the comprehensive resolution for all nine
facilities will result in a total penalty assessment of less than $575,000.
We make expenditures in connection with environmental matters as part of
our normal operations and as capital expenses. For each of 2001 and 2002, we
estimate that our expensed and capital-related environmental costs will be
approximately $16 million.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Prior to the Combination
The Predecessor Company's capital investments and acquisitions were
financed by cash flow from operations and non-interest bearing advances from
Duke Energy or its subsidiaries under various arrangements. Under Duke Energy's
centralized cash management system, Duke Energy deposited sufficient funds in
our bank accounts for us to meet our daily obligations and withdrew excess funds
from those accounts. Advances were offset by cash provided by operations to
yield net advances from Duke Energy which were included in the historical
consolidated balance sheets and statements of cash flows of the Predecessor
Company. The Predecessor Company had notes to and advances from subsidiaries of
Duke Energy which were terminated in connection with the Combination. In
connection with the Combination, notes and advances payable to Duke Energy of
$2,319.0 million were capitalized to equity.
Bank Financing and Commercial Paper
On March 31, 2000, we entered into a $2,800.0 million credit facility with
several financial institutions. The credit facility is used as the liquidity
backstop to support a commercial paper program. On April 3, 2000 we borrowed
$2,790.9 million in the commercial paper market to fund the one-time cash
distributions (including reimbursements for acquisitions) of $1,524.5 million to
Duke Energy and $1,219.8 million to Phillips in connection with the Combination
and to cover working capital requirements. The credit facility matures on March
30, 2001 and borrowings bear interest at a rate equal to, at our option, either
(1) LIBOR plus .625% per year or (2) the higher of (a) the Bank of America prime
rate and (b) the Federal Funds rate plus .50% per year. The Company reduced the
size of the facility to $2,500.0 million effective August 10, 2000, to $1,000.0
million effective August 17, 2000, and to $700.0 million effective February 6,
2001, due to the issuance of preferred members' interest and debt securities
referred to below. At December 31, 2000, there were no borrowings against the
credit facility.
At December 31, 2000 we had $346.4 million in outstanding commercial paper,
with maturities ranging from 2 days to 19 days and annual interest rates ranging
from 7.05% to 7.6%. At no time did the amount of our outstanding commercial
paper exceed the available amount under the credit facility. In the future, our
debt levels will vary depending on our liquidity needs, capital expenditures and
cash flow.
The Company closed its new credit facility (the "New Facility") on March
30, 2001. The New Facility replaces the credit facility that matured on March
30, 2001. The New Facility will be used to support the Company's commercial
paper program and for working capital and other general corporate purposes. The
New Facility matures on March 29, 2002, however any outstanding loans under the
New Facility at maturity, may, at the Company's option, be converted at maturity
to a one-year term loan. The New Facility is a $675 million revolving credit
facility, of which $150 million can be used for letters of credit. The New
Facility requires the Company to maintain at all times a debt to total
capitalization ratio of less than or equal to 53%. If the Company converts from
a limited liability company to a "C" Corporation, the Company is required to
maintain at all times a debt to total capitalization ratio of less than or equal
to 57%. The New Facility bears interest at a rate equal to, at the Company's
option and based on the Company's current debt rating, either (1) LIBOR plus
0.75% per year or (2) the higher of (a) the Bank of America prime rate and (b)
the Federal Funds rate plus 0.50% per year.
Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program and the New
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Facility, will be sufficient to enable us to meet our current and anticipated
cash operating requirements and working capital needs for the next year. Actual
capital requirements, however, may change, particularly as a result of any
acquisitions that we may make. Our ability to meet current and anticipated
operating requirements will depend on our future performance.
Preferred Financing
In August 2000, we issued $300.0 million of preferred member interests to
affiliates of Duke Energy and Phillips. The proceeds from this financing were
used to repay a portion of our outstanding commercial paper. The preferred
member interests are entitled to cumulative preferential distributions of 9.5%
per annum payable, unless deferred, semi-annually. We have the right to defer
payments of preferential distributions on the preferred member interests, other
than certain tax distributions, at any time and from time to time, for up to ten
consecutive semi-annual periods. Deferred preferred distributions will accrue
additional amounts based on the preferential distribution rate (plus 0.5% per
annum) to the date of payment. The preferred member interests, together with all
accrued and unpaid preferential distributions, must be redeemed and paid on the
earlier of the thirtieth anniversary date of issuance or consummation of an
initial public offering of equity securities. As of December 31, 2000, we have
paid preferential distributions of $11.7 million.
Debt Securities
During 2000 and 2001, we registered and issued the following series of
unsecured senior debt securities:
ISSUE PRINCIPAL INTEREST
DATE ($000S) RATE DUE DATE
- ----- --------- -------- --------
August 16, 2000................................. $600,000 7 1/2% August 16, 2005
August 16, 2000................................. $800,000 7 7/8% August 16, 2010
August 16, 2000................................. $300,000 8 1/8% August 16, 2030
February 2, 2001................................ $250,000 6 7/8% February 1, 2011
The notes mature and become due and payable on the respective due dates,
and are not subject to any sinking fund provisions. Interest is payable
semiannually. Each series of notes is redeemable, in whole or in part, at our
option. The proceeds from the issuance of debt securities were used to repay a
portion of our outstanding commercial paper.
Distributions
In connection with the Combination, we are required to make quarterly
distributions to Duke Energy and Phillips based on allocated taxable income. Our
Limited Liability Company Agreement provides for taxable income to be allocated
in accordance with the Internal Revenue Code Section 704(c). This Code section
takes into account the variation between the adjusted tax basis and the book
value of assets contributed to the joint venture. The distribution is based on
the highest taxable income allocated to either member, with the other member
receiving a proportionate amount to maintain the ownership capital accounts at
69.7% for Duke Energy and 30.3% for Phillips. As of December 31, 2000, the
distributions based on allocated taxable income payable to the members were
$127.6 million and were paid in January 2001.
Capital Expenditures
Our capital expenditures consist of expenditures for acquisitions and
construction of additional gathering systems, processing plants, fractionators
and other facilities and infrastructure in addition to well connections and
upgrades to our existing facilities. For the year ended December 31, 2000, we
spent approximately $370.9 million on capital expenditures.
On March 31, 2000, we acquired gathering and processing assets located in
central Oklahoma from Conoco and Mitchell Energy. We paid cash of $99.8 million
and exchanged our interest in certain gathering and marketing joint ventures
located in southeast Texas having a total fair value of approximately $42.0
million as consideration for these assets.
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In 2000, the Company acquired various gathering and processing entities and
assets including a 50% interest in El Paso Field Services' 265 mile San Jacinto
natural gas pipeline, that brought our ownership to 100 percent, Gas
Transmission Teco, Inc. and the Gordondale gas processing plant.
The remaining capital expenditures were primarily for well connections and
plant upgrades.
Our level of capital expenditures for acquisitions and construction depends
on many factors, including industry conditions, the availability of attractive
acquisition candidates and construction projects, the level of commodity prices
and competition. We expect to finance our capital expenditures with our cash on
hand, cash flow from operations and borrowings available under our commercial
paper program, our credit facilities or other available sources of financing.
Our capital expenditure budget for well connections and plant upgrades of our
existing facilities in 2001 is approximately $210 million.
Cash Flows
Net cash provided by operating activities for 2000 improved to $713.1
million, from net cash provided by operating activities of $173.1 million for
1999, primarily due to higher commodity prices and acquisitions. Net cash used
in investing activities was $234.7 million for 2000 compared to $1,571.4 million
for 1999. Acquisitions of the Conoco and Mitchell Energy assets in 2000 and the
Union Pacific Fuels assets in 1999 were the primary uses of the invested cash.
The net cash used in investing activities was financed through operating
activities, advances from Duke Energy and proceeds from the issuance of short
term debt.
ACCOUNTING PRONOUNCEMENTS
In June 1998, Statement of Financial Accounting Standard ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," was issued. We
were required to adopt this standard by January 1, 2001. SFAS No. 133 requires
that all derivatives be recognized as either assets or liabilities and measured
at fair value, and changes in the fair value of derivatives are reported in
current earnings, unless the derivative is designated and effective as a hedge.
If the intended use of the derivative is to hedge the exposure to changes in the
fair value of an asset, a liability or a firm commitment, then changes in the
fair value of the derivative instrument will generally be offset in the income
statement by changes in the hedged item's fair value. However, if the intended
use of the derivative is to hedge the exposure to variability in expected future
cash flows, then changes in the fair value of the derivative instrument will
generally be reported in Other Comprehensive Income (OCI). The gains and losses
on the derivative instrument that are reported in OCI will be reclassified to
earnings in the periods in which earnings are impacted by the hedged item.
We have determined the effect of implementing SFAS 133 and recorded a
cumulative-effect adjustment of $0.4 million as a reduction in earnings and a
cumulative-effect adjustment increasing OCI and Equity by $6.6 million on
January 1, 2001.
Currently, there are on-going discussions surrounding the implementation
and interpretation of SFAS No. 133 by the Financial Accounting Standards Board's
Derivatives Implementation Group. We implemented SFAS No. 133 based on current
rules and guidance in place as of January 1, 2001. However, if the definition of
derivative instruments is altered, this may impact our transition adjustment
amounts and subsequent reported operating results.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
COMMODITY PRICE RISK
We are subject to significant risks due to fluctuations in commodity
prices, primarily with respect to the prices of NGLs that we own as a result of
our processing activities. Based upon the Company's portfolio of supply
contracts, without giving effect to hedging activities that would reduce the
impact of commodity price decreases, a decrease of $.01 per gallon in the price
of NGLs and $.10 per million Btus in the average price of natural gas would
result in changes in annual pre-tax net income of approximately $(26.0) million
and $3.0 million, respectively. After considering the affects of commodity hedge
positions in place at Decem-
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ber 31, 2000, it is estimated that if NGL prices average $.01 per gallon less in
the next twelve months pre-tax net income would decrease approximately $20.0
million
Commodity derivatives such as futures, swaps and options are available to
reduce such exposure to fluctuations in commodity prices. Gains and losses
related to commodity derivatives are recognized in income when the underlying
hedged physical transaction closes, and such gains and losses are included in
sales of natural gas and petroleum products in our statement of income. See Note
12 of the Notes to Consolidated Financial Statements for additional information.
The Company's Risk Management Committee ("RMC") oversees risk exposure to
fluctuations in commodity prices. The RMC ensures that proper policies and
procedures are in place to adequately manage our commodity price risks. The risk
in the commodity trading portfolio is measured and monitored on a daily basis
utilizing a Value-at-Risk model to determine the maximum potential one-day
favorable or unfavorable Daily Earnings at Risk ("DER"). The DER is monitored
daily in comparison to established thresholds. Other measures are also utilized
to limit and monitor the risk in the commodity trading portfolio on daily and
monthly bases.
The DER computations are based on a historical simulation, which utilizes
price movements over a specified period to simulate forward price curves in the
energy markets to estimate the favorable or unfavorable impact of one day's
price movement on the existing portfolio. The historical simulation emphasizes
the most recent market activity, which is considered the most relevant predictor
of immediate future market movements for crude, natural gas liquids, gas and
other energy-related products. The DER computations utilize several key
assumptions, including 95% confidence level for the resultant price movement and
the holding period specified for the calculation. The Company's DER calculation
includes commodity derivatives instruments held for trading purposes. The DER at
December 31, 2000 was $2.3 million and the 2000 average was $1.2 million.
The Company sells natural gas liquids to a variety of customers ranging
from large, multi-national petrochemical and refining companies to small
regional retail propane distributors. Substantially all of the company's NGL
sales are made at market-based prices, including approximately 40 percent of the
Company's NGL production that is committed to Phillips and Chevron Phillips
Chemical LLC, under an existing 15-year contract, of which 14 years remain. This
concentration of credit risk may affect the Company's overall credit risk in
that these customers may be similarly affected by changes in economic,
regulatory or other factors. On all transactions where the Company is exposed to
credit risk, the Company analyses the counterparties' financial condition prior
to entering into an agreement, establishes credit limits and monitors the
appropriateness of these limits on an ongoing basis.
Natural gas and crude oil futures, which are used to hedge NGL prices,
involve the buying and selling of natural gas and crude oil for future delivery
at a fixed price. Over-the-counter swap agreements require us to receive or make
payments on the difference between a specified price and the actual price of
natural gas or crude oil.
Crude oil options are also used to hedge NGL prices utilizing collars.
Collars contain a fixed floor price (Company purchases a put) and ceiling price
(Company sells a call). If the market price of crude oil exceeds the call strike
price or falls below the put strike price, the Company receives the fixed price
and pays the market price. If the market price of crude oil is between the call
and put strike price, no payments are due to or from the counterparty.
An active forward market for hedging of NGL products is not normally
available for hedging a significant amount of our NGL production beyond a one to
three month time horizon. With an anticipated hedging horizon of up to 12
months, crude oil derivatives, which historically have had a high correlation
with NGL prices, will typically be the mechanism used for longer-term price risk
management.
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INTEREST RATE RISK
Prior to the Combination, we had no material interest rate risk associated
with debt used to finance our operations due to limited third party borrowings.
As of December 31, 2000, we had approximately $346.4 million outstanding under a
commercial paper program. As a result, we are exposed to market risks related to
changes in interest rates. In the future, we intend to manage our interest rate
exposure using a mix of fixed and floating interest rate debt. An increase of
.5% in interest rates would result in an increase in annual interest expense of
approximately $1.7 million. See Note 12 of the Notes to Consolidated Financial
Statements.
FOREIGN CURRENCY RISK
Our primary foreign currency exchange rate exposure at December 31, 2000
was the Canadian dollar. Foreign currency risk associated with this exposure was
not material.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS)
2000 1999 1998
---------- ---------- ----------
OPERATING REVENUES:
Sales of natural gas and petroleum products............ $6,787,599 $2,613,560 $ 932,833
Sales of natural gas and petroleum
products -- affiliates.............................. 2,105,916 696,700 536,300
Transportation, storage and processing................. 188,501 138,151 108,787
Transportation, storage and processing -- affiliates... 11,350 9,899 6,400
---------- ---------- ----------
Total operating revenues....................... 9,093,366 3,458,310 1,584,320
---------- ---------- ----------
COSTS AND EXPENSES:
Natural gas and petroleum products..................... 7,114,070 2,836,697 1,258,529
Natural gas and petroleum products -- affiliates....... 761,348 128,600 79,600
Operating and maintenance.............................. 331,572 181,392 113,556
Depreciation and amortization.......................... 234,862 130,788 75,573
General and administrative............................. 140,557 54,585 32,846
General and administrative -- affiliates............... 30,597 19,100 12,100
Net (gain) loss on sale of assets...................... (10,660) 2,377 (33,759)
---------- ---------- ----------
Total costs and expenses....................... 8,602,346 3,353,539 1,538,445
---------- ---------- ----------
OPERATING INCOME......................................... 491,020 104,771 45,875
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES.......... 27,424 22,502 11,845
---------- ---------- ----------
EARNINGS BEFORE INTEREST AND TAXES....................... 518,444 127,273 57,720
INTEREST EXPENSE:
Interest expense (income).............................. 134,016 (985) (7,697)
Interest expense (income) -- affiliates................ 15,204 53,900 60,100
---------- ---------- ----------
Total interest expense......................... 149,220 52,915 52,403
---------- ---------- ----------
INCOME BEFORE INCOME TAXES............................... 369,224 74,358 5,317
INCOME TAX EXPENSE (BENEFIT)............................. (310,937) 31,029 3,289
---------- ---------- ----------
NET INCOME............................................... 680,161 43,329 2,028
DIVIDENDS ON PREFERRED MEMBERS' INTEREST................. 11,717 -- --
---------- ---------- ----------
EARNINGS AVAILABLE FOR MEMBERS' INTEREST................. 668,444 43,329 2,028
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Foreign currency translation adjustment................ (2,717) 288 --
---------- ---------- ----------
TOTAL COMPREHENSIVE INCOME............................... $ 665,727 $ 43,617 $ 2,028
========== ========== ==========
See Notes to Consolidated Financial Statements.
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DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS)
2000 1999 1998
----------- ----------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 680,161 $ 43,329 $ 2,028
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 234,862 130,788 75,573
Deferred income taxes................................... (308,001) 86,301 45,315
Equity in earnings of unconsolidated affiliates......... (27,424) (22,502) (11,845)
Loss (gain) on sale of assets........................... (10,660) 2,377 (33,759)
Change in operating assets and liabilities (net of effects
of acquisitions) which provided (used) cash:
Accounts receivable..................................... (137,771) (168,806) 130,086
Accounts receivable -- affiliates....................... (189,300) (6,202) 3,375
Inventories............................................. (70,153) (5,303) 1,762
Unrealized gains on mark-to-market transactions......... (35,724) (10,461) --
Other current assets.................................... 41,324 20,356 10,149
Other noncurrent assets................................. (9,414) -- --
Accounts payable........................................ 451,081 101,309 (169,880)
Accounts payable -- affiliates.......................... (906) 51,608 (7,538)
Accrued interest payable................................ 49,641 -- --
Unrealized losses on mark-to-market transactions........ 41,100 10,079 --
Other current liabilities............................... 51,036 (4,390) (4,857)
Other long term liabilities............................. (46,787) (55,347) --
----------- ----------- ---------
Net cash from operating activities................. 713,065 173,136 40,409
----------- ----------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions and other capital expenditures............... (370,948) (1,570,083) (185,479)
Investment expenditures................................... (5,323) (62,752) (84,884)
Investment distributions.................................. 43,557 31,999 15,051
Proceeds from sales of assets............................. 97,981 29,390 51,687
----------- ----------- ---------
Net cash from investing activities................. (234,733) (1,571,446) (203,625)
----------- ----------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in advances -- parents............ (55,509) 1,350,054 162,514
Distributions to parents.................................. (2,744,319) -- --
Proceeds from issuing preferred members' interest......... 300,000 -- --
Short term debt -- net.................................... 346,410
Proceeds from issuing debt................................ 1,687,564 48,880 --
Payment of dividends...................................... (11,717) -- --
----------- ----------- ---------
Net cash from financing activities................. (477,571) 1,398,934 162,514
----------- ----------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS................... 761 624 702
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR................ 792 168 870
----------- ----------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR...................... $ 1,553 $ 792 $ 168
=========== =========== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION -- Cash
paid for interest (net of amounts capitalized)............ $ 95,805 $ 52,915 $ 52,948
See Notes to Consolidated Financial Statements.
33
37
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2000 AND 1999
(IN THOUSANDS)
2000 1999
---------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 1,553 $ 792
Accounts receivable:
Customers, net.......................................... 725,379 370,139
Affiliates.............................................. 253,277 63,927
Other................................................... 67,316 30,067
Inventories............................................... 83,325 38,701
Unrealized gains on mark-to-market transactions........... 46,185 10,461
Notes receivable.......................................... 7,833 13,050
Other..................................................... 6,442 1,580
---------- ----------
Total current assets............................... 1,191,310 528,717
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 4,152,480 2,409,385
INVESTMENT IN AFFILIATES.................................... 261,551 343,835
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net.................. 97,956 102,382
Goodwill, net............................................. 376,195 85,846
---------- ----------
Total intangible assets............................ 474,151 188,228
---------- ----------
OTHER NONCURRENT ASSETS..................................... 90,606 12,131
---------- ----------
TOTAL ASSETS....................................... $6,170,098 $3,482,296
========== ==========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade................................................... $ 915,130 $ 354,359
Affiliates.............................................. 61,464 62,370
Other................................................... 41,322 33,858
Short term debt........................................... 346,410 --
Accrued taxes other than income........................... 21,717 15,653
Advances, net............................................. -- 1,579,475
Notes payable -- affiliates............................... -- 588,880
Distributions payable to members.......................... 127,561 --
Accrued interest payable.................................. 49,641 --
Unrealized losses on mark to market transactions.......... 51,179 10,079
Other..................................................... 114,408 6,372
---------- ----------
Total current liabilities.......................... 1,728,832 2,651,046
---------- ----------
DEFERRED INCOME TAXES....................................... -- 308,308
NOTE PAYABLE TO PARENT...................................... -- 101,600
LONG TERM DEBT.............................................. 1,688,157 --
OTHER LONG TERM LIABILITIES................................. 32,274 34,871
PREFERRED MEMBERS' INTEREST................................. 300,000 --
COMMITMENTS AND CONTINGENT LIABILITIES
EQUITY:
Common stock.............................................. -- 1
Additional paid-in capital................................ -- 213,091
Members' interest......................................... 1,709,290 --
Retained earnings......................................... 713,974 173,091
Accumulated other comprehensive income (loss)............. (2,429) 288
---------- ----------
Total equity....................................... 2,420,835 386,471
---------- ----------
TOTAL LIABILITIES AND EQUITY................................ $6,170,098 $3,482,296
========== ==========
See Notes to Consolidated Financial Statements.
34
38
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF EQUITY
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS)
ACCUMULATED
OTHER
ADDITIONAL COMPREHENSIVE
COMMON PAID-IN MEMBERS' RETAINED INCOME
STOCK CAPITAL INTEREST EARNINGS (LOSS) TOTAL
------ ---------- ----------- --------- ------------- -----------
BALANCE, JANUARY 1, 1998... $ 3 $ 200,326 $ -- $ 128,268 $ -- $ 328,597
Contributions.............. -- 2,197 -- -- -- 2,197
Net Income................. -- -- -- 2,028 -- 2,028
--- --------- ----------- --------- ------- -----------
BALANCE, DECEMBER 31,
1998..................... 3 202,523 -- 130,296 -- 332,822
Contributions.............. -- 10,568 -- -- -- 10,568
Net Income................. -- -- -- 43,329 -- 43,329
Other...................... (2) -- -- (534) 288 (248)
--- --------- ----------- --------- ------- -----------
BALANCE, DECEMBER 31,
1999..................... 1 213,091 173,091 288 386,471
Combination at March 31,
2000 -- see Note 2:
Contribution of TEPPCO
general partnership
interest.............. -- 2,148 -- -- -- 2,148
Contribution of DEFS Inc.
and DEFSCL to DEFS,
LLC................... (1) (215,239) 215,240 -- -- --
Contribution of notes and
advances payable...... -- -- 2,318,569 -- -- 2,318,569
Contribution of GPM
assets and
liabilities........... -- -- 1,919,800 -- -- 1,919,800
Distributions............ -- -- (2,744,319) (127,561) -- (2,871,880)
Dividends on preferred
members' interest........ -- -- -- (11,717) -- (11,717)
Net Income................. -- -- -- 680,161 -- 680,161
Other...................... -- -- -- -- (2,717) (2,717)
--- --------- ----------- --------- ------- -----------
BALANCE, DECEMBER 31,
2000..................... $-- $ -- $ 1,709,290 $ 713,974 $(2,429) $ 2,420,835
=== ========= =========== ========= ======= ===========
See Notes to Consolidated Financial Statements.
35
39
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
1. ACCOUNTING POLICIES SUMMARY
Basis of Presentation -- Duke Energy Field Services, LLC (with its
consolidated subsidiaries, "the Company" or "Field Services LLC") operates in
the midstream natural gas gathering, marketing and natural gas liquids
industries. The Company operates in the two principal segments of the midstream
natural gas industry of (1) natural gas gathering, processing, transportation,
marketing and storage; and (2) natural gas liquids (NGLs) fractionation,
transportation, marketing and trading. Field Services LLC's limited liability
company agreement limits the scope of the Company's business to the midstream
natural gas industry in the United States and Canada, the marketing of natural
gas liquids in Mexico and the transportation, marketing and storage of other
petroleum products.
Effective March 31, 2000, and in connection with the Combination (see Note
2), Duke Energy Field Services, Inc. was converted to a limited liability
company and contributed to the Company as a wholly-owned subsidiary by Duke
Energy Corporation (Duke Energy). Also on March 31, 2000, Duke Energy
contributed Duke Energy Field Services Canada, Ltd. to the Company. As a result
of these contributions to the Company, the financial statements are reflected as
consolidated.
The Company is the successor to Duke Energy's North American midstream
natural gas business. The subsidiaries of Duke Energy that conducted this
business were contributed to the Company immediately prior to the Combination.
For periods prior to the Combination, Duke Energy Field Services and these
subsidiaries of Duke Energy are collectively referred to herein as the
"Predecessor Company."
Principles of Consolidation -- The consolidated financial statements
include the accounts of the Company and its majority owned subsidiaries. All
significant intercompany transactions have been eliminated. Investments in 20%
to 50% owned affiliates are accounted for using the equity method. Investments
greater than 50% are consolidated unless the Company does not operate these
investments and as a result does not have the ability to exercise control or
control is considered to be temporary (See Note 8).
Use of Estimates -- The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
Cash and Cash Equivalents -- All liquid investments with maturities at date
of purchase of three months or less are considered cash equivalents.
Inventories -- Inventories are recorded at the lower of cost or market
using the average cost method.
Property, Plant and Equipment -- Property, plant and equipment are stated
at cost. Depreciation is computed using the straight-line method over the
estimated useful lines of the individual assets (see Note 7). Interest totaling
$0.3 million, $0.9 million and $1.6 million has been capitalized on construction
projects for 2000, 1999 and 1998, respectively.
Impairment of Long-Lived Assets -- The recoverability of long-lived assets
and intangible assets are reviewed whenever events or changes in circumstances
indicate that the carrying amount of the asset may not be recoverable. Such
evaluation is based on various analyses, including undiscounted cash flow
projections. For the years presented, there has been no impairment.
Revenue Recognition -- The Company recognizes revenues on sales of natural
gas and petroleum products in the period of delivery and transportation revenues
in the period service is provided. An allowance for doubtful accounts is
established based on agings of accounts receivable and the credit worthiness of
our customers. Bad debt expense and writeoffs for each year presented are not
significant. During 2000, the
36
40
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company adopted the provisions of Staff Accounting Bulletin (SAB) 101 issued by
the Securities and Exchange Commission. The impact of adopting SAB 101 was not
material to the Company.
Accounting for Risk Management and Commodity Trading
Activities -- Commodity derivatives utilized for trading purposes are accounted
for using the mark-to-market method. Under this methodology, these instruments
are adjusted to market value, and the unrealized gains and losses are recognized
in current period income and are included in the Consolidated Statements of
Income and Comprehensive Income as Sales of natural gas and petroleum products,
and in the Consolidated Balance Sheets as Unrealized gains on mark-to-market
transactions and Unrealized losses on mark-to-market transactions.
Commodity derivatives such as futures, forwards, over-the-counter swap
agreements and options are also utilized for non-trading purposes to hedge the
impact of market fluctuations in the price of natural gas and other
energy-related products. To qualify as a hedge, the price movements in the
commodity derivatives must be highly correlated with the underlying hedged
commodity. Under the deferral method of accounting, gains and losses related to
commodity derivatives which qualify as gas hedges are recognized in income when
the underlying hedged physical transaction closes and are included in the
Consolidated Statements of Income and Comprehensive Income as cost of Natural
gas and petroleum products. Gains and losses related to commodity derivatives
which qualify as hedges of exposure to natural gas liquids pricing fluctuations
are recognized in income when the underlying hedged physical transaction closes
and are included in the Consolidated Statements of Income and Comprehensive
Income as Sales of natural gas and petroleum products. If the commodity
derivative is no longer sufficiently correlated to the underlying commodity, or
if the underlying commodity transaction closes earlier than anticipated, the
deferred gains or losses are recognized in income.
The Company periodically utilizes interest rate lock agreements or interest
rate swaps to hedge interest rate risk associated with new debt issuances. Under
the deferral method of accounting, gains or losses on such agreements, when
settled, are deferred in the Consolidated Balance Sheets as Other Long-Term
Liabilities and are amortized in the Consolidated Statements of Income and
Comprehensive Income as an adjustment to interest expense.
Significant Customers -- Duke Energy Trading and Marketing, L.L.C. (DETM),
an affiliated company, is a significant customer. Sales to DETM totaled $1,444.0
million, $684.0 million and $522.0 million during 2000, 1999 and 1998,
respectively.
Unamortized Debt Premium, Discount and Expense -- Premiums, discounts and
expenses incurred in connection with the issuance of presently outstanding long
term debt are amortized over the terms of the respective issues.
Intangibles Amortization -- Goodwill is amortized over the period of
expected benefit. Goodwill is being amortized on a straight-line basis over 15
years related to the 1991 acquisition of MEGA Natural Gas Company and 20 years
related to the UP Fuels acquisition (see Note 3) and the GPM combination (see
Note 2). Natural gas liquids sales contracts are amortized on a straight-line
basis over the contract lives, which average 15 years.
Environmental Costs -- Environmental expenditures are expensed or
capitalized as appropriate, depending upon the future economic benefit.
Expenditures that relate to an existing condition caused by past operations, and
that do not have future benefit, are expensed. Liabilities for these
expenditures are recorded on an undiscounted basis when environmental
assessments or clean-ups are probable and the costs can be reasonably estimated.
Recorded environmental liabilities at the end of 2000 were $38.7 million.
Recorded environmental liabilities at the end of 1999 and 1998 were
insignificant (see Note 14).
Gas Imbalance Accounting -- Quantities of natural gas over-delivered or
under-delivered related to imbalance agreements are recorded monthly as
receivables or payables using index prices or the weighted
37
41
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
average prices of natural gas at the plant or system. Generally, these balances
are settled with deliveries of natural gas.
Foreign Currency Translation -- Assets and liabilities of the Company's
Canadian operations, where the Canadian dollar is the functional currency, have
been translated at a year-end exchange rate, and revenues and expenses have been
translated using average exchange rates prevailing during the year. Adjustments
resulting from translation are included in the Consolidated Statements of Income
and Comprehensive Income.
Income Taxes -- At March 31, 2000, the Company converted to a limited
liability company which is a pass-through entity for income tax purposes. As a
result, substantially all of the existing net deferred tax liability of $327.0
million was eliminated with a corresponding income tax benefit recorded. Income
taxes on a go forward basis will consist primarily of miscellaneous state, local
and foreign taxes (see Note 10).
In connection with the Combination (see Note 2), the Company is required to
make quarterly distributions to Duke Energy and Phillips Petroleum Company
(Phillips) based on allocated taxable income. The limited liability company
agreement, as amended, provides for taxable income to be allocated in accordance
with the Internal Revenue Code section 704(c). This Code Section takes into
account the variation between the adjusted tax basis and the book value of
assets contributed to the joint venture. The distribution is based on the
highest taxable income allocated to either member, with the other member
receiving a proportionate amount to maintain the ownership capital accounts at
69.7% for Duke Energy and 30.3% for Phillips. As of December 31, 2000, the total
estimated distributions due to the members are approximately $127.6 million,
which were accrued, and were paid in January 2001.
Stock Based Compensation -- Under Duke Energy's 1998 Long-term Incentive
Plan, stock options of Duke Energy's common stock may be granted to key
employees of the Company. The Company accounts for stock-based compensation
using the intrinsic method of accounting. Under this method, compensation cost,
if any, is measured as the excess of the quoted market price of stock at the
date of the grant over the amount an employee must pay to acquire stock.
Restricted stock grants and Company performance awards are recorded as
compensation cost over the requisite vesting period based on the market value on
the date of the grant. Pro forma disclosures utilizing the fair value accounting
method are included in Note 15 to the Consolidated Financial Statements. All
outstanding common stock amounts and compensation awards have been adjusted to
reflect Duke Energy's two-for-one stock split effected January 26, 2001. See
Note 15 to the Consolidated Financial Statements for additional information on
the stock split.
New Accounting Standards -- In June 1998, Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities," was issued. The Company was required to adopt this standard by
January 1, 2001. SFAS No. 133 requires that all derivatives be recognized as
either assets or liabilities and measured at fair value, and changes in the fair
value of derivatives are reported in current earnings, unless the derivative is
designated and effective as a hedge. If the intended use of the derivative is to
hedge the exposure to changes in the fair value of an asset, a liability or a
firm commitment, then changes in the fair value of the derivative instrument
will generally be offset in the income statement by changes in the hedged item's
fair value. However, if the intended use of the derivative is to hedge the
exposure to variability in expected future cash flows, then changes in the fair
value of the derivative instrument will generally be reported in Other
Comprehensive Income (OCI). The gains and losses on the derivative instrument
that are reported in OCI will be reclassified to earnings in the periods in
which earnings are impacted by the hedged item.
The Company has determined the effect of implementing SFAS No. 133 and
recorded a cumulative-effect adjustment of $0.4 million as a reduction in
earnings and a cumulative-effect adjustment increasing OCI and Equity by $6.6
million on January 1, 2001.
Reclassifications -- Certain prior period amounts have been reclassified in
the Consolidated Financial Statements to conform to the current presentation.
38
42
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. COMBINATION
On March 31, 2000, the natural gas gathering, processing and NGL assets,
operations, and subsidiaries of Duke Energy were contributed to Field Services
LLC. In connection with the contribution of assets and subsidiaries at March 31,
2000, notes and advances payable to subsidiaries of Duke Energy were eliminated
and contributed to equity. Also on March 31, 2000, Phillips contributed its
midstream natural gas gathering, processing and NGL operations to Field Services
LLC. This contribution and Duke Energy's contribution to Field Services LLC are
referred to as the "Combination." In connection with the Combination, the
Company made one-time distributions to Phillips of $1,219.8 million and to Duke
Energy of $1,524.5 million. In exchange for the contributions, and after the
one-time distributions, Duke Energy received a 69.7% member interest in Field
Services LLC, with Phillips holding the remaining 30.3% member interest.
The Combination with Phillips has been accounted for as a purchase business
combination in accordance with Accounting Principles Board Opinion No. 16
"Accounting for Business Combinations." The Phillips assets, net of liabilities,
have been valued at $1,919.8 million excluding $20.1 million of acquisition
costs. Following is a summary of the allocated purchase price (in millions):
Property, plant and equipment............................. $1,619.8
Goodwill.................................................. 306.0
Current assets............................................ 228.3
Other noncurrent assets................................... 57.7
Current liabilities....................................... (228.3)
Other noncurrent liabilities.............................. (43.6)
--------
Total purchase price............................ $1,939.9
========
Working Capital Adjustments -- In connection with the Combination, Duke
Energy and Phillips each were to make contributions to Field Services LLC, or
receive distributions from Field Services LLC so that each of Duke Energy and
Phillips would have contributed to Field Services LLC net working capital
positions equal to zero as of March 31, 2000. As of December 31, 2000, the net
working capital positions were settled.
Unaudited Pro Forma Disclosures -- Revenues for the years ended December
31, 2000 and 1999, on a pro forma basis would have increased $542.4 million and
$1,095.7 million, respectively, and net income for the years ended December 31,
2000 and 1999, on a pro forma basis would have increased by $65.7 million and
$21.2 million, respectively, if the acquisition of the Phillips midstream
business had occurred at the beginning of 1999.
TEPPCO General Partner -- On March 31, 2000, and in connection with the
Combination, Duke Energy contributed the general partner of TEPPCO Partners,
L.P. (TEPPCO) to Field Services LLC. In connection with the contribution of the
general partner of TEPPCO, the Company recorded an investment in TEPPCO of $2.1
million and increased equity by $2.1 million.
TEPPCO is a publicly traded limited partnership that owns and operates a
network of pipelines for refined products and crude oil. The general partner is
responsible for the management and operations of TEPPCO. Through the ownership
of the general partner of TEPPCO, Field Services LLC has the right to receive
from TEPPCO incentive cash distributions in addition to a 2% share of
distributions based on the general partner interest. At TEPPCO's 2000 per unit
distribution level, the general partner received approximately 18% of the cash
distributed by TEPPCO to its partners. Due to the general partner's share of
unit distributions and degree of control exercised through its management of the
partnership, the Company's investment in TEPPCO is accounted for under the
equity method.
39
43
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. ACQUISITIONS AND DISPOSITIONS
Disposition of NGL Pipeline Assets -- On December 31, 2000, the Company
sold pipeline assets to TEPPCO for $91.0 million. The NGL pipeline assets sold
included the Panola Pipeline and the San Jacinto Pipeline. TEPPCO also assumed
the lease of a 34 mile condensate pipeline. A $12.0 million gain and a $3.2
million deferred gain was recorded in connection with the sale.
Conoco and Mitchell Assets -- On March 31, 2000, Field Services LLC
acquired gathering and processing facilities located in central Oklahoma from
Conoco, Inc. and Mitchell Energy & Development Corp. Field Services LLC paid
cash of $99.8 million, and exchanged its interests in certain gathering and
marketing joint ventures located in southeast Texas having a total fair value of
$42.0 million as consideration for these facilities. A $3.9 million gain was
recorded in connection with the exchange. Following is a summary of the
allocated purchase price (in millions):
Property, plant and equipment.............................. $136.9
Current assets............................................. 3.8
Current liabilities........................................ (0.2)
Other noncurrent liabilities............................... (40.7)
------
Total purchase price............................. $ 99.8
======
Union Pacific Fuels, Inc. -- On March 31, 1999, the Company acquired the
assets and assumed certain liabilities of Union Pacific Fuels, Inc. (UP Fuels),
a wholly-owned subsidiary of Union Pacific Resources Company (UPR), for a total
purchase price of $1,359.0 million. The acquisition was accounted for under the
purchase method of accounting, and the assets and liabilities and results of
operations of UP Fuels have been consolidated in the Company's financial
statements since the date of purchase. Revenues and net income for the year
ended December 31, 1999 on a pro forma basis would have increased $298.0 million
and $3.4 million respectively, if the acquisition of UP Fuels had occurred on
January 1, 1999. In connection with the acquisition $77.6 million of goodwill
was recorded and is being amortized over twenty years, its estimated useful
life.
4. AGREEMENTS AND TRANSACTIONS WITH DUKE ENERGY
Services Agreement with Duke Energy -- In connection with the Combination,
the Company entered into a services agreement with Duke Energy and some of its
subsidiaries, dated as of March 14, 2000, as amended on December 15, 2000. Under
this agreement, Duke Energy and those subsidiaries will provide the Company with
various staff and support services, including information technology products
and services, payroll, employee benefits, insurance, cash management, ad valorem
taxes, treasury, media relations, printing, records management, legal functions
and investor services. These services are priced on the basis of a monthly
charge which management believes approximates market prices. Additionally, the
Company may use other Duke Energy services subject to hourly rates, including
legal, insurance, internal audit, tax planning, human resources and security
departments. This agreement, as amended, expires on December 31, 2001.
License Agreement -- In connection with the Combination, Duke Energy has
licensed to the Company a non-exclusive right to use the phrase "Duke Energy"
and its logo and certain other trademarks in identifying the Company's
businesses. This right may be terminated by Duke Energy at its sole option any
time after Duke Energy's direct or indirect ownership interest in the Company is
less than or equal to 35%; or Duke Energy no longer controls, directly or
indirectly, the management and policies of the Company.
Transactions between Duke Energy and the Company -- The Company sells a
portion of its residue gas and NGLs to, purchases raw natural gas and other
petroleum products from, and provides gathering and transportation services to
Duke Energy and its subsidiaries at contractual prices that have approximated
40
44
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
market prices in the ordinary course of the Company's business. The Company
anticipates continuing to purchase and sell these commodities and provide these
services to Duke Energy in the ordinary course of business.
5. AGREEMENTS AND TRANSACTIONS WITH PHILLIPS
Services Agreement with Phillips -- Effective with the Combination, the
Company entered into a services agreement with Phillips (the "Phillips Services
Agreement"). Under the Phillips Services Agreement, Phillips will provide the
Company with various staff and support services, including information
technology products and services, cash management, real estate and property tax
services. These services will be priced on a basis of a monthly charge equal to
Phillips' fully-burdened cost of providing the services. The original term of
this agreement expired on December 31, 2000; however, the Company is in
negotiations with Phillips to extend the term for some of these services. Both
companies continue to perform under the original agreement.
Long-Term NGLs Purchases Contract with Phillips -- In connection with the
Combination, the Company has agreed to maintain the NGL Output Purchase and Sale
Agreement (the "Phillips NGL Agreement") between Phillips and the midstream
natural gas assets that were contributed by Phillips to the Company in the
Combination. Under the Phillips NGL Agreement, Phillips 66 Company, a
wholly-owned subsidiary of Phillips, has the right to purchase at index-based
prices substantially all NGLs produced by the processing plants which were
acquired by Field Services LLC from Phillips in the Combination. The Phillips
NGL Agreement also grants Phillips 66 Company the right to purchase at
index-based prices certain quantities of NGLs produced at processing plants that
are acquired and/or constructed by the Company in the future in various counties
in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The
primary term of the agreement is effective until December 31, 2014.
Transactions between Phillips and the Midstream Business Acquired from
Phillips -- Through March 31, 2000, the Phillips' businesses (the "Phillips
Combined Subsidiaries") that owned the midstream natural gas assets that were
contributed to the Company in the Combination had conducted a series of
transactions with Phillips in which the Phillips Combined Subsidiaries sold a
portion of their residue gas and other by-products to Phillips at contractual
prices that approximated market prices. In addition, the Phillips Combined
Subsidiaries purchased raw natural gas from Phillips at contractual prices that
have approximated market prices. The Company is continuing these transactions in
the ordinary course of business.
6. INVENTORIES
A summary of inventories by category follows:
DECEMBER 31,
-----------------
2000 1999
------- -------
(IN THOUSANDS)
Gas held for resale......................................... $11,512 $18,114
NGLs........................................................ 64,454 18,211
Materials and supplies...................................... 7,359 2,376
------- -------
Total inventories................................. $83,325 $38,701
======= =======
41
45
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. PROPERTY, PLANT AND EQUIPMENT
A summary of property, plant and equipment by classification follows:
DECEMBER 31,
DEPRECIATION -----------------------
RATES 2000 1999
------------ ---------- ----------
(IN THOUSANDS)
Gathering........................................ 4% - 6% $2,409,136 $1,231,050
Processing....................................... 4% 1,802,824 1,197,993
Transmission..................................... 4% 424,120 413,633
Underground storage.............................. 2% - 5% 77,174 73,958
General plant.................................... 20% - 33% 83,175 37,614
Construction work in progress.................... 154,330 51,262
---------- ----------
4,950,759 3,005,510
Accumulated depreciation....................... (798,279) (596,125)
---------- ----------
Property, plant and equipment, net............. $4,152,480 $2,409,385
========== ==========
8. INVESTMENTS IN AFFILIATES
The Company has investments in the following businesses accounted for using
the equity method:
DECEMBER 31,
-------------------
OWNERSHIP 2000 1999
--------- -------- --------
(IN THOUSANDS)
Dauphin Island Gathering Partners.................... 37.28% $102,440 $ 99,878
Mont Belvieu I....................................... 20.00% 38,936 40,440
Mobile Bay Processing Partners....................... 28.81% 34,571 35,906
Sycamore Gas System General Partnership.............. 48.45% 22,172 21,985
Main Pass Oil Gathering.............................. 33.33% 17,131 16,967
Black Lake Pipeline.................................. 50.00% 8,751 35,641
Ferguson-Burleson.................................... 55.00% -- 23,631
Westana Gathering Company............................ 50.00% -- 15,246
TEPPCO Partners, L.P................................. 2.00% 3,323 --
Other affiliates..................................... Various 34,227 54,141
-------- --------
Total investments in affiliates............ $261,551 $343,835
======== ========
Dauphin Island Gathering Partners -- Dauphin Island Gathering Partners is a
partnership which owns the Dauphin Island Gathering system and the Main Pass Gas
Gathering system, which are natural gas gathering systems in the Gulf of Mexico.
Mont Belvieu I -- Mont Belvieu I operates a 200 MBbl/d fractionation
facility in the Mont Belvieu, Texas Market Center.
Mobile Bay Processing Partners -- Mobile Bay Processing Partners is a
partnership formed to engage in the financing, ownership, construction and
operation of one or more natural gas processing facilities onshore in Mobile
County, Alabama.
Sycamore Gas System General Partnership -- Sycamore Gas System General
Partnership is a partnership formed for the purpose of constructing, owning and
operating a gas gathering and compression system in Carter County, Oklahoma.
42
46
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Main Pass Oil Gathering -- Main Pass Oil Gathering is a joint venture whose
primary operation is a crude oil gathering pipeline system of 81 miles in the
Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico.
Black Lake Pipeline -- Black Lake Pipeline owns a 317 mile long NGL
pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline
receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are
transported to Mont Belvieu fractionators.
Equity in earnings amounted to the following for the years ended December
31:
2000 1999 1998
------- ------- -------
(IN THOUSANDS)
Dauphin Island Gathering Partners....................... $ 3,835 $ 5,974 $ 7,234
Mont Belvieu I.......................................... (501) 440 --
Mobile Bay Processing Partners.......................... 2,413 2,307 65
Sycamore Gas System General Partnership................. 44 142 261
Main Pass Oil Gathering................................. 2,973 3,638 2,598
Black Lake Pipeline..................................... 1,833 1,141 --
Ferguson-Burleson....................................... 651 5,600 --
Westana Gathering Company............................... 346 1,339 409
TEPPCO Partners, L.P.................................... 10,589 -- --
Other affiliates........................................ 5,241 1,921 1,278
------- ------- -------
Total equity earnings......................... $27,424 $22,502 $11,845
======= ======= =======
Distributions in excess of earnings were $4.2 million, $9.5 million and
$3.2 million in 2000, 1999 and 1998, respectively.
In connection with the Combination, the Predecessor Company's interest in
Westana Gathering Company was sold in February 2000. Proceeds and loss on the
sale approximated $12 million and $4 million, respectively.
On March 31, 2000, Ferguson-Burleson was exchanged in connection with the
acquisition of the Conoco and Mitchell assets (see Note 3).
The following summarizes combined financial information of unconsolidated
affiliates for the years ended December 31:
2000 1999 1998
--------- --------- -------
(IN THOUSANDS)
Income statement:
Operating revenues................................ $ 242,900 $ 452,118 $61,618
Operating expenses................................ 216,334 374,079 36,173
Net income........................................ 27,278 55,606 27,878
Balance sheet:
Current assets.................................... $ 97,478 $ 119,506
Noncurrent assets................................. 749,772 761,270
Current liabilities............................... (79,567) (113,121)
Noncurrent liabilities............................ (133,058) (14,853)
--------- ---------
Net assets................................ $ 634,625 $ 752,802
========= =========
43
47
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. TRANSACTIONS WITH AFFILIATES
As of December 31, 1999, the Predecessor Company had a $101.6 million note
payable to Duke Energy, scheduled to mature in 2004 bearing interest at 8.5%.
Additionally, as of December 31, 1999, the Predecessor Company had a $540.0
million note payable to Duke Energy, scheduled to mature December 31, 2000
bearing interest at prime (8.5% at December 31, 1999), adjusted quarterly, and
notes payable of $44.3 million and $4.6 million to Duke Energy, payable on
demand and bearing interest at the Canadian Prime Rate (6.5% at December 31,
1999), plus fifty basis points, adjusted quarterly. These notes were terminated
in connection with the Combination.
Intercompany advances do not bear interest. Advances are carried as open
accounts and are not segregated between current and non-current amounts.
Increases and decreases in advances result from the movement of funds to provide
for operations, capital expenditures, and debt payments of Duke Energy and its
subsidiaries. In addition, current income tax balances are recorded in these
accounts. Average intercompany advances payable approximated $1,410.0 million
and $203.8 million for 1999 and 1998, respectively. These advances from Duke
Energy were terminated in connection with the Combination.
See Notes 4 and 5 for discussion of other specific transactions with
affiliates.
10. INCOME TAXES
At March 31, 2000, the Company converted to a limited liability company
which is a pass-through entity for income tax purposes. As a result,
substantially all of the existing net deferred tax liability of $327.0 million
was eliminated and a corresponding income tax benefit was recorded.
The Predecessor Companies' taxable income is included in a consolidated
federal income tax return with Duke Energy. Therefore, income tax has been
provided in accordance with Duke Energy's tax allocation policy, which requires
subsidiaries to calculate federal income tax as if separate taxable income, as
defined, was reported. Foreign income taxes are not material and therefore are
not shown separately.
Income tax as presented in the Statements of Income and Comprehensive
Income is summarized as follows:
YEARS ENDED DECEMBER 31,
-------------------------------
2000 1999 1998
--------- -------- --------
(IN THOUSANDS)
Current:
Federal........................................... $ (5,066) $(46,429) $(36,142)
State............................................. 2,130 (8,843) (5,884)
--------- -------- --------
Total current............................. (2,936) (55,272) (42,026)
--------- -------- --------
Deferred:
Federal........................................... (268,911) 73,201 38,961
State............................................. (39,090) 13,100 6,354
--------- -------- --------
Total deferred............................ (308,001) 86,301 45,315
--------- -------- --------
Total income tax expense............................ $(310,937) $ 31,029 $ 3,289
========= ======== ========
44
48
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Total income tax expense in 1999 and 1998 differed from the amount computed
by applying the federal income tax rate to earnings before income tax. The
reasons for this difference are as follows:
YEARS ENDED
DECEMBER 31,
----------------
1999 1998
------- ------
(IN THOUSANDS)
Federal income tax rate..................................... 35.0% 35.0%
======= ======
Income tax, computed at the statutory rate.................. $26,025 $1,861
Adjustments resulting from:
State income tax, net of federal income tax effect........ 2,863 186
Non-deductible amortization and other..................... 2,141 1,242
------- ------
Total income tax.................................. $31,029 $3,289
======= ======
The tax effects of temporary differences that resulted in deferred income
tax assets and liabilities, and a description of the significant items that
created these differences at December 31, 1999 were as follows (in thousands):
Deferred income tax assets.............................. $ 7,600
---------
Property, plant, and equipment.......................... (275,008)
Deferred charges........................................ (15,300)
State deferred income tax, net of federal tax effect.... (25,600)
---------
Total deferred income tax liabilities......... (315,908)
---------
Net deferred income tax liability....................... $(308,308)
=========
11. FINANCING
Credit Facility with Financial Institutions -- In March 2000, Field
Services LLC entered into a $2,800 million credit facility with several
financial institutions. The credit facility is used to support a commercial
paper program for short term financing requirements. On April 3, 2000, Field
Services LLC borrowed $2,790.9 million in the commercial paper market to fund
one-time cash distributions of $1,524.5 million to Duke Energy and $1,219.8
million to Phillips, and to meet working capital requirements. The credit
facility matures on March 30, 2001, and bears interest at a rate equal to, at
the Company's option, either (1) LIBOR plus 0.625% per year or (2) the higher of
(a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per
year. The Company reduced the size of the facility to $2,500 million effective
August 10, 2000, to $1,000 million effective August 17, 2000, and to $700
million effective February 6, 2001, due to the issuance of preferred members'
interest and debt securities described below. At December 31, 2000, there were
no borrowings against the credit facility. At December 31, 2000 we had $346.4
million in outstanding commercial paper, with maturities ranging from 2 days to
19 days and annual interest rates ranging from 7.05% to 7.6%. At no time did the
amount of our outstanding commercial paper exceed the available amount under the
credit facility.
Preferred Financing -- In August 2000, the Company issued $300.0 million of
preferred member interests to affiliates of Duke Energy and Phillips. The
proceeds from this financing were used to repay a portion of the Company's
outstanding commercial paper. The preferred member interests are entitled to
cumulative preferential distributions of 9.5% per annum payable, unless
deferred, semi-annually. The Company has the right to defer payments of
preferential distributions on the preferred member interests, other than certain
tax distributions, at any time and from time to time, for up to ten consecutive
semi-annual periods. Deferred preferred distributions will accrue additional
amounts based on the preferential distribution
45
49
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
rate (plus 0.5% per annum) to the date of payment. The preferred member
interests, together with all accrued and unpaid preferential distributions, must
be redeemed and paid on the earlier of the thirtieth anniversary date of
issuance or consummation of an initial public offering of equity securities. As
of December 31, 2000, the Company has paid preferential distributions of $11.7
million.
Debt Securities -- Long-term debt at December 31, 2000 was as follows:
PRINCIPAL/
DISCOUNT INTEREST
($000S) ISSUE DATE RATE DUE DATE
---------- ---------- -------- --------
Debt Securities................ $ 600,000 August 16, 2000 7 1/2% August 16, 2005
800,000 August 16, 2000 7 7/8% August 16, 2010
300,000 August 16, 2000 8 1/8% August 16, 2030
Unamortized discount........... (11,843)
----------
Net long-term debt............. $1,688,157
==========
In 2005, only the $600 million notes become due. The notes mature and
become due and payable on the respective due dates, and are not subject to any
sinking fund provisions. Interest is payable semiannually. The notes are
redeemable at the option of the Company. The Company used the proceeds from the
issuance of the debt securities to repay short term debt.
In addition, the Company issued $250 million of senior unsecured 10-year
notes in February 2001.
12. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Commodity Derivatives -- Trading -- The Company engages in the trading of
commodity derivatives, and therefore experiences net open positions. The Company
manages its open positions with strict policies which limit its exposure to
market risk and require daily reporting to management of potential financial
exposure. These policies include statistical risk tolerance limits using
historical price movements to calculate a daily earnings at risk measurement.
The weighted-average life of the Company's commodity trading portfolio was
approximately three months at December 31, 2000. The Company did not trade
commodity derivatives prior to 1999.
GAIN (LOSSES) RECOGNIZED FROM TRADING COMMODITY DERIVATIVES:
YEARS ENDED
DECEMBER 31,
-----------------
2000 1999
------- -------
(IN THOUSANDS)
NGLs........................................................ $12,525 $20,254
Crude oil................................................... (2,825) (3,354)
ABSOLUTE NOTIONAL CONTRACT QUANTITY OF COMMODITY DERIVATIVES HELD FOR
TRADING PURPOSES:
DECEMBER 31,
--------------
2000 1999
------ -----
NGLs, in thousands of barrels............................... 15,209 5,826
Crude oil, in thousands of barrels.......................... 4,995 6,487
46
50
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FAIR VALUES OF COMMODITY DERIVATIVES -- TRADING (In thousands):
2000 1999
--------------------- ---------------------
ASSETS LIABILITIES ASSETS LIABILITIES
------- ----------- ------- -----------
Fair value at December 31..................... $46,185 $51,179 $10,461 $10,079
Average fair value for the year............... 52,726 47,581 8,588 8,359
Commodity Derivatives -- Non-Trading -- Historically, the Company's
commodity price risk management program had been directed by Duke Energy under
its centralized program for controlling, managing and coordinating its
management of risks. During the three months ended March 31, 2000 and the year
ended December 31, 1999, the Company recorded hedging losses of $46.7 million
and $34.0 million, respectively, under Duke Energy's centralized program. As of
March 31, 2000, the commodity positions then held by the Company under the
centralized program were transferred to Duke Energy.
Effective April 1, 2000, the Company began directing its risk management
activities, including commodity price risk for market fluctuations in the price
of NGLs, independently of Duke Energy. The Company uses commodity-based
derivative contracts to reduce the risk in the Company's overall earnings and
cash flow with the primary goals of: (1) maintaining minimum cash flow to fund
debt service, dividends and maintenance type capital projects; and (2) avoiding
disruption of the Company's growth capital and value creation process. The
Company has implemented a risk management policy that provides guidelines for
entering into contractual arrangements to manage commodity price exposure. Swaps
and options are used to manage and hedge prices related to these market
exposures. During the nine months ended December 31, 2000, the Company recorded
a hedging loss of $81.0 million under the Company's self-directed risk
management program.
The Company manages its exposure to risk from existing assets, liabilities
and commitments by hedging the impact of market fluctuations. At December 31,
2000 and 1999, the Company held or issued several commodity derivatives that
reduce exposure to market fluctuations in the price and transportation costs of
natural gas and NGLs. The Company's market exposure arises from inventory
balances and fixed-price purchase and sale commitments that extend for periods
of up to 10 years. Futures and swaps are used to manage and hedge prices and
location risk related to these market exposures. Futures and swaps are also used
to manage margins on offsetting fixed-price purchase or sale commitments for
physical quantities of natural gas and NGLs.
The gains, losses and costs related to non-trading commodity derivatives
are not recognized until the underlying physical transaction closes. At December
31, 2000 and 1999, the Company had unrealized net losses related to commodity
derivative hedges of $15.3 million and $63.5 million, respectively.
ABSOLUTE NOTIONAL CONTRACT QUANTITY OF COMMODITY DERIVATIVES HELD FOR
NON-TRADING PURPOSES:
DECEMBER 31,
---------------
2000 1999
------ ------
Natural gas, in billion cubic feet.......................... 25.57 7.8
Crude oil, in thousands of barrels.......................... 19,079 32,764
Propane, in thousands of barrels............................ 1,000 --
Hedging losses in 2000 and 1999 totaled approximately $127.7 and $34.0
million, respectively.
Market and Credit Risk -- The Company sells natural gas liquids to a
variety of customers ranging from large, multi-national petrochemical and
refining companies to small regional retail propane distributors. Substantially
all of the Company's NGL sales are made at market-based prices, including
approximately 40 percent of the Company's NGL production that is committed to
Phillips and Chevron Phillips
47
51
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Chemical LLC, under an existing 15-year contract, of which 14 years remain. This
concentration of credit risk may affect the Company's overall credit risk in
that these customers may be similarly affected by changes in economic,
regulatory or other factors. On all transactions where the Company is exposed to
credit risk, the Company analyzes the counterparties' financial condition prior
to entering into an agreement, establishes credit limits and monitors the
appropriateness of these limits on an ongoing basis.
Natural gas and crude oil futures, which are used to hedge commodity price
risk for market fluctuations in the price of NGLs for the Company's NGL
production, involve the buying and selling of natural gas and crude oil for
future delivery at a fixed price. Over-the-counter swap agreements require us to
receive or make payments on the difference between a specified price and the
actual price of natural gas or crude oil.
Crude oil options are also used to hedge market price fluctuations for the
Company's NGL production utilizing collars. Collars contain a fixed floor price
(the Company purchases a put) and ceiling price (the Company sells a call). If
the market price of crude oil exceeds the call strike price or falls below the
put strike price, the Company receives the fixed price and pays the market
price. If the market price of crude oil is between the call and put strike
price, no payments are due to or from the counterparty.
An active forward market for hedging NGL products is not normally available
for hedging a significant amount of our NGL production beyond a one to three
month time horizon. With an anticipated hedging horizon of up to 12 months,
crude oil derivatives, which historically have had a high correlation with NGL
prices, will typically be the mechanism used for longer-term price risk
management.
Interest Rate Derivatives -- In the second and third quarter of 2000, the
Company entered into treasury rate locks and interest rate swaps to reduce the
Company's exposure to market fluctuations in the interest rates related to the
debt securities that were issued in August 2000. The Company's interest rate
exposure resulted from changes in interest rates between the date that the
Company decided to sell debt securities and the date the debt securities were
actually sold. The net settlement loss of $13.4 million related to these
interest rate derivatives is being recognized over the estimated life of the
debt securities.
13. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following fair value amounts have been determined by the Company, using
available market information and appropriate valuation methodologies. However,
considerable judgment is necessarily required in interpreting market data to
develop the estimates of fair value. Accordingly, the estimates presented herein
are not necessarily indicative of the amounts that the Company could realize in
a current market exchange. The use of different market assumptions and/or
estimation methodologies may have a material effect on the estimated fair value
amounts.
DECEMBER 31, 2000 DECEMBER 31, 1999
---------------------------- ----------------------------
CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR
AMOUNT VALUE AMOUNT VALUE
----------- -------------- ----------- --------------
(IN THOUSANDS)
Accounts receivable............. $ 1,047,972 $ 1,047,972 $ 464,133 $ 464,133
Notes receivable................ 29,465 29,465 21,866 22,582
Accounts payable................ (1,035,910) (1,035,910) (450,205) (450,205)
Advances, net -- parents........ -- -- (1,579,475) (1,579,475)
Notes payable................... -- -- (690,480) (655,843)
Natural gas, NGL and oil hedge
contracts..................... -- (15,298) (63,500) --
Short term debt................. (346,410) (346,410) -- --
Long term debt.................. (1,688,157) (1,795,371) -- --
48
52
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The fair value of cash and cash equivalents, accounts receivable, accounts
payable, and short term debt are not materially different from their carrying
amounts because of the short term nature of these instruments or the stated
rates approximating market rates.
Notes receivable is carried in the accompanying balance sheet at cost. The
Company anticipates selling the majority of notes receivable at face value to
Duke Capital Partners, an affiliated company, during 2001. Therefore, the fair
value has been determined using the face value.
Related party advances and notes payable are carried at cost. Fair value
has been estimated using discounted cash flows of maturities of five years and
interest rates of 8.0%.
The estimated fair value of the natural gas, NGL and oil hedge contracts is
determined by multiplying the difference between the quoted termination prices
for natural gas, NGL and oil and the hedge contract prices by the quantities
under contract. The estimated fair value of options is determined by the
Black-Scholes options valuation model.
The estimated fair value of long term debt is determined by prices obtained
from market quotes.
14. COMMITMENTS AND CONTINGENT LIABILITIES
Litigation -- The midstream natural gas industry has seen an increase in
the number of class action lawsuits involving royalty disputes, mismeasurement
and mispayment allegations. Although the industry has seen these types of cases
before, they were typically brought by a single plaintiff or small group of
plaintiffs. Many of these cases are now being brought as class actions. The
Company and its subsidiaries are currently named as defendants in certain of
these cases. Management believes the Company and its subsidiaries have
meritorious defenses to these cases, and therefore will continue to defend them
vigorously. However, these class actions can be costly and time consuming to
defend.
A judgement has been entered in the case of Chevron U.S.A., Inc. versus GPM
Gas Corporation (GPM), a wholly owned subsidiary of Field Services LLC,
upholding and construing most favored nations clauses in three 1961 West Texas
gas purchase contracts. Although a U.S. District Court for the Western District
of Texas, Midland Division decided in September 1999 that GPM owes Chevron
damages in the amount of $13.8 million through July 31, 1998, plus 6% interest
from that date and attorneys' fees in the amount of $0.3 million, GPM has
appealed the judgement to the U.S. Court of Appeals for the Fifth Circuit on
October 14, 1999.
Management believes that the final deposition of these proceedings will not
have a material adverse effect on the consolidated results of operations or
financial position of the Company.
Environmental -- On June 17, 1999, the EPA published in the Federal
Register a final MACT standard under Section 112 of the Clean Air Act to limit
emissions of Hazardous Air Pollutants ("HAPs") from oil and natural gas
production as well as from natural gas transmission and storage facilities. The
MACT standard requires that affected facilities reduce their emissions of HAPs
by 95%, and this will affect the Company's various large dehydration units and
potentially some of the Company's storage vessels. This new standard will
require that the Company achieve this reduction by either process modifications
or installing new emissions control technology. The MACT standard will affect
the Company and its competitors in varying degrees. The rule allows most
affected sources until at least June 2002 to comply with the requirements. While
additional capital costs are likely to result from this rule or other potential
air regulations, Management believes that these changes will not have a material
adverse effect on the Company's business, financial position or results of
operations.
The Company has various ongoing remedial matters related to historical
operations similar to others in the industry, based primarily on state
authorities generally described above. These are typically managed in
conjunction with the relevant state or federal agencies to address specific
conditions, and in some cases are the
49
53
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
responsibility of other entities based upon contractual obligations related to
the assets. On March 31, 1999, the Company acquired the midstream natural gas
gathering and processing assets of Union Pacific Resources located in several
states, which include 18 natural gas plants and 365 gathering facility sites. In
connection with pre-April 1999 soil and ground water conditions identified as
part of this transaction, the Company has entered into an agreement with a third
party environmental/insurance partnership for a one-time premium payment subject
to certain deductibles. With respect to these identified environmental
conditions, the environmental partner has assumed liability and management
responsibility for environmental remediation, and the insurance partner is
providing financial management, program oversight, remediation cost cap
insurance coverage for a 30 year term, and pollution legal liability coverage
for a 20 year term. While the Company could face liability in the event of
default, management believes this innovative approach can promote pro-active
site cleanup and closure, reduce internal resource needs for managing
remediation, and may improve the marketability of assets based on
transferability of this insurance coverage. Also, in August 1996, the Company
acquired certain gas gathering and processing assets in three states from Mobil
Corporation. Under the terms of the asset purchase agreement, Mobil has retained
the liabilities and costs related to various pre-August 1996 environmental
conditions that were identified with respect to those assets. Mobil has
formulated or is in the process of developing plans to address certain of these
conditions which the Company will review and monitor as clean-up activities
proceed.
The Company is presently resolving non-compliance issues with the Texas
Natural Resources Conservation Commission associated with the timing of air
permit annual compliance certifications submitted to the agency in 1999 and
1998. This matter, a large portion of which was voluntarily self-disclosed to
the agency, involves approximately 115 of the Company's facilities that did not
meet specific administrative filing deadlines for required air permit paperwork.
In addition, at this time the Company is actively resolving with the New Mexico
Environment Department alleged non-compliance with various air permit
requirements at four of our New Mexico facilities. These matters, the majority
of which were also voluntarily self-disclosed to the agency, generally involve
document preparation and submittal as required by permits, compliance testing
requirements at two facilities, and compliance with permit emissions limits at
one facility. Management believes that these apparent non-compliance issues
being addressed with the Texas and New Mexico agencies under relevant air
programs will result in total penalty assessments of less than $500,000.
We have been in discussions with the Colorado Air Pollution Control
Division regarding various asserted non-compliance issues arising from agency
inspections of our Colorado facilities in 2000 and 1999, and arising from
compliance issues disclosed to the agency pursuant to permit requirements or
voluntarily disclosed to the agency in 2000. These items relate to various
specific and detailed terms of the Title V Operating Permits at seven gas plants
and two compressor stations in Colorado, including, for example, record keeping
requirements, parametric monitoring requirements, delayed filings, and
operations inconsistent with throughput limits on particular pieces of
equipment. As a result of these discussions, we received from the agency in
March 2001 a comprehensive proposed settlement agreement to resolve all of these
various items related to air permit compliance at the nine facilities. Although
we are still discussing the appropriate resolution of these apparent instances
of non-compliance with the Division, we believe that the comprehensive
resolution for all nine facilities will result in a total penalty assessment of
less than $575,000.
Other Commitments and Contingencies -- The Company utilizes assets under
operating leases in several areas of operation. Combined rental expense amounted
to $20.2 million, $11.8 million and $8.2 million in 2000, 1999 and 1998,
respectively. Minimum rental payments under the Company's various operating
leases for the years 2001 through 2005 are $8.2, $7.1, $6.4, $5.5 and $5.4
million, respectively. Thereafter, payments aggregate $13.0 million through
2008.
50
54
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. STOCK-BASED COMPENSATION
Under Duke Energy's 1998 Long-term Incentive Plan, stock options for Duke
Energy's common stock may be granted to key employees of the Company. Under the
plan, the exercise price of each option granted is no less than the market price
of Duke Energy's common stock on the date of grant. Vesting periods range from
one to five years with a maximum term of ten years.
On December 20, 2000, Duke Energy announced a two-for-one common stock
split effective January 26, 2001, to shareholders of record on January 3, 2001.
The option information which follows has been restated to reflect the stock
split, and appropriate adjustments have been made in the exercise price and
number of shares subject to stock options.
The following tables set forth information regarding options to purchase
Duke Energy's common stock granted to employees of the Company.
Stock Option Activity
WEIGHTED
AVERAGE
OPTIONS EXERCISE
(IN THOUSANDS) PRICE
-------------- --------
Outstanding at December 31, 1997............................ 450 $ 12
Granted................................................... 558 28
Exercised................................................. (140) 11
Forfeited................................................. -- --
----- ----
Outstanding at December 31, 1998............................ 868 22
Granted................................................... 1,756 27
Exercised................................................. (66) 13
Forfeited................................................. (36) 28
----- ----
Outstanding at December 31, 1999............................ 2,522 26
Granted................................................... 837 41
Exercised................................................. (568) 22
Forfeited................................................. (223) 27
----- ----
Outstanding at December 31, 2000............................ 2,568 $ 31
===== ====
Stock Options at December 31, 2000
OUTSTANDING
----------------------------------------
WEIGHTED WEIGHTED EXERCISABLE WEIGHTED
AVERAGE AVERAGE -------------- AVERAGE
RANGE OF NUMBER REMAINING EXERCISE NUMBER EXERCISE
EXERCISE PRICES (IN THOUSANDS) LIFE (YEARS) PRICE (IN THOUSANDS) PRICE
- --------------- -------------- ------------ -------- -------------- --------
$8 to $10.......................... 16 4.1 $10 16 $10
$11 to $12......................... 25 4.2 12 25 12
$13 to $16......................... 3 5.1 13 3 13
$21 to $25......................... 765 8.9 25 192 25
$26 to $30......................... 1,025 8.0 28 167 28
G $34............................ 734 10.0 43 -- --
----- ---
Total.................... 2,568 8.8 31 403 25
===== ===
51
55
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
There were 382,000 and 164,100 options exercisable at December 31, 1999 and
1998 with a weighted average exercise price of $17 and $11 per option.
No compensation cost related to the stock options has been recorded as the
intrinsic method of accounting is used and the exercise price of each option
granted equaled the market price on the date of grant. The weighted average fair
value of options granted was $10.00, $5.00 and $4.00 per option during 2000,
1999 and 1998, respectively. The fair value of each option granted was estimated
on the date of grant using the Black-Scholes option-pricing model.
Weighted-Average Assumptions for Option-Pricing
2000 1999 1998
------- ------- -------
Stock dividend yield...................................... 3.7% 4.1% 4.2%
Expected stock price volatility........................... 25.1% 18.8% 15.1%
Risk-free interest rates.................................. 5.3% 5.9% 5.6%
Expected option lives..................................... 7 years 7 years 7 years
Stock-based compensation expense calculated using the Black-Scholes
option-pricing model for 2000, 1999 and 1998 would have been $2.9 million, $2.5
million and $0.8 million, respectively and net income would have been $678.2
million, $41.8 million and $1.5 million, respectively.
Duke Energy granted restricted shares of Duke Energy common stock to key
employees of the Predecessor Company under the 1996 Stock Incentive Plan.
Restricted stock grants under the 1996 plan vest over periods ranging from one
to five years. Duke Energy awarded 28,526 restricted shares in 2000 (fair value
at date of grants of approximately $822,000) and 11,100 shares in 1999 (fair
value at grant dates of approximately $618,000). No restricted shares were
awarded in 1998. Compensation expense for the stock grants is charged to the
earnings of the Predecessor Company over the vesting period, and amounted to
approximately $402,000, $275,000, and $0 in 2000, 1999, and 1998, respectively.
In addition, Duke Energy granted performance awards of Duke Energy common
stock to key employees of the Predecessor Company under the 1998 Long-Term
Incentive Plan. Performance awards under the 1998 plan vest over periods ranging
from one to seven years. Duke Energy did not award any performance awards in
2000 or 1998. Duke Energy awarded 86,400 shares in 1999 (fair value at grant
dates of approximately $2.3 million). Compensation expense for the performance
grants is charged to the earnings of the Predecessor Company over the vesting
period, and amounted to approximately $1.2 million, $305,000, and $0 in 2000,
1999, and 1998, respectively.
16. PENSION AND OTHER BENEFITS
Effective March 31, 2000, participation by the Company's employees in Duke
Energy's non-contributory defined benefit retirement plan and employee savings
plan were terminated. Effective April 1, 2000, the Company's employees began
participation in the Company's employee savings plan, in which the Company
contributes 4% of each eligible employee's qualified wages. Additionally, the
Company matches employees' contributions to the plan up to 6% of qualified
wages. During 2000, the Company expensed plan contributions of $8.9 million.
Duke Energy has, and the Predecessor Company participated in, a
non-contributory trustee pension plan which covered eligible employees with a
minimum service requirements using a cash balance formula. The plan provides
pension benefits for eligible employees of the Predecessor Company that are
generally based on the employee's actual eligible earnings and accrued interest.
Through December 31, 1998, for certain eligible employees, a portion of their
benefit may also be based on the employee's years of benefit accrual service and
highest average eligible earnings. Effective January 1, 1999, the benefit
formula under the plan for all eligible
52
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DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
employees was changed to a cash balance formula. Duke Energy's policy is to fund
amounts, as necessary, on an actuarial basis to provide assets sufficient to
meet benefits to be paid to plan members. Aspects of the plan specific to the
Predecessor Company are as follows:
COMPONENTS OF NET PERIODIC PENSION COSTS
YEARS ENDED DECEMBER 31,
-------------------------
2000 1999 1998
----- ------- -------
(IN THOUSANDS)
Service cost benefit earned during year................... $ 480 $ 1,280 $ 911
Interest cost on projected benefit obligation............. 460 1,375 794
Expected return on plan assets............................ (674) (2,307) (1,391)
Amortization of net transition asset...................... (21) (85) (86)
Amortization of prior service cost........................ 8 34 43
Recognized actuarial loss................................. -- 6 --
Settlement gain........................................... -- -- (40)
----- ------- -------
Net periodic pension cost................................. 253 303 231
Impact of terminating plan participation.................. 483 -- --
----- ------- -------
Total pension cost for fiscal 2000........................ $ 736 $ 303 $ 231
===== ======= =======
RECONCILIATION OF FUNDED STATUS TO PRE-FUNDED PENSION COSTS
DECEMBER 31,
------------------
2000 1999
-------- -------
(IN THOUSANDS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year..................... $ 21,846 $14,651
Service cost................................................ 480 1,280
Interest cost............................................... 460 1,375
Intercompany transfers(a)................................... 128 8,519
Benefits paid............................................... (180) (190)
Actuarial (gains)/losses.................................... -- (3,789)
Impact of terminating plan participation.................... (22,734) --
-------- -------
Benefit obligation at end of year........................... $ -- $21,846
======== =======
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DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31,
------------------
2000 1999
-------- -------
(IN THOUSANDS)
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year.............. $ 33,827 $20,211
Intercompany transfers(a)................................... 128 8,519
Actual return on plan assets................................ 37 4,985
Employer contributions...................................... 736 302
Benefits paid............................................... (180) (190)
Impact of terminating plan participants..................... (34,548) --
-------- -------
Fair value of plan assets at end of year.................... $ -- $33,827
======== =======
Funded status............................................... $ -- $11,982
Unrecognized net transition asset........................... -- (425)
Unrecognized prior service cost............................. -- 268
Unrecognized experience gain................................ -- (7,267)
-------- -------
Pre-funded pension costs.................................... $ -- $ 4,558
======== =======
- ---------------
(a) Intercompany transfers relate to benefit obligations and plan assets
associated with employees transferring between the Predecessor Company and
other Duke Energy affiliates.
ASSUMPTIONS USED FOR PENSION BENEFIT ACCOUNTING
YEARS ENDED
DECEMBER 31,
--------------------
2000 1999 1998
---- ---- ----
Discount rate............................................... 7.50% 7.50% 6.75%
Rate of increase in compensation levels..................... 4.53% 4.50% 4.67%
Expected long-term rate of return on plan assets............ 9.25% 9.25% 9.25%
The Predecessor Company also sponsors an employee savings plan which covers
substantially all employees. During 1999 and 1998, the Company expensed plan
contributions of $3.6 million and $1.8 million, respectively.
The Predecessor Company's postretirement benefits, in conjunction with Duke
Energy, consist of certain health care and life insurance benefits for certain
retired employees. Postretirement benefits costs were not material in 2000, 1999
and 1998. The Company does not have any continuing obligations with respect to
post-requirement benefits that are significant.
17. BUSINESS SEGMENTS
The Company operates in two principal business segments as follows: (1)
natural gas gathering, processing, transportation, marketing and storage, and
(2) NGL fractionation, transportation, marketing and trading. These segments are
monitored separately by management for performance against its internal forecast
and are consistent with the Company's internal financial reporting. These
segments have been identified based on the differing products and services,
regulatory environment and the expertise required for these operations. Margin,
earnings before interest, taxes, depreciation and amortization (EBITDA) and
earnings before interest and taxes (EBIT) are the performance measures utilized
by management to monitor the business of each segment. The accounting policies
for the segments are the same as those described in Note 1. Foreign operations
are not material and are therefore not separately identified.
54
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DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the Company's segment information.
YEARS ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
----------- ---------- ----------
(IN THOUSANDS)
Operating revenues:
Natural gas................................ $ 7,036,003 $2,483,197 $1,497,901
NGLs....................................... 3,652,120 1,365,577 309,380
Intersegment(a)............................ (1,594,757) (390,464) (222,961)
----------- ---------- ----------
Total operating revenues........... $ 9,093,366 $3,458,310 $1,584,320
=========== ========== ==========
Margin:
Natural gas................................ $ 1,169,286 $ 459,843 $ 243,787
NGLs....................................... 48,662 33,170 2,404
----------- ---------- ----------
Total margin....................... $ 1,217,948 $ 493,013 $ 246,191
=========== ========== ==========
Other operating costs:
Natural gas................................ $ 329,054 $ 182,062 $ 79,797
NGLs....................................... (8,142)(c) 1,707 --
Corporate.................................. 171,154 73,685 44,946
----------- ---------- ----------
Total other operating costs........ $ 492,066 $ 257,454 $ 124,743
=========== ========== ==========
Equity in earnings of unconsolidated
affiliates:
Natural gas................................ $ 25,554 $ 20,917 $ 11,845
NGLs....................................... 1,870 1,585 --
----------- ---------- ----------
Total equity in earnings of
unconsolidated affiliates........ $ 27,424 $ 22,502 $ 11,845
=========== ========== ==========
EBITDA(b):
Natural gas................................ $ 865,786 $ 298,698 $ 175,835
NGLs....................................... 58,674 33,048 2,404
Corporate.................................. (171,154) (73,685) (44,946)
----------- ---------- ----------
Total EBITDA....................... $ 753,306 $ 258,061 $ 133,293
=========== ========== ==========
Depreciation and amortization:
Natural gas................................ $ 218,593 $ 119,425 $ 73,470
NGLs....................................... 12,636 9,073 --
Corporate.................................. 3,633 2,290 2,103
----------- ---------- ----------
Total depreciation and
amortization..................... $ 234,862 $ 130,788 $ 75,573
=========== ========== ==========
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DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEARS ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
----------- ---------- ----------
(IN THOUSANDS)
EBIT(b):
Natural gas................................ $ 647,193 $ 179,273 $ 102,365
NGLs....................................... 46,038 23,975 2,404
Corporate.................................. (174,787) (75,975) (47,049)
----------- ---------- ----------
Total EBIT......................... $ 518,444 $ 127,273 $ 57,720
=========== ========== ==========
Corporate interest expense................... $ 149,220 $ 52,915 $ 52,403
=========== ========== ==========
Income before income taxes:
Natural gas................................ $ 647,193 $ 179,273 $ 102,365
NGLs....................................... 46,038 23,975 2,404
Corporate.................................. (324,007) (128,890) (99,452)
----------- ---------- ----------
Total income before income taxes... $ 369,224 $ 74,358 $ 5,317
=========== ========== ==========
Capital Expenditures:
Natural gas................................ $ 356,542 $1,387,805 $ 183,750
NGLs....................................... 1,284 177,070 146
Corporate.................................. 13,122 5,208 1,583
----------- ---------- ----------
Total Capital Expenditures......... $ 370,948 $1,570,083 $ 185,479
=========== ========== ==========
AS OF DECEMBER 31,
-----------------------
2000 1999
---------- ----------
(IN THOUSANDS)
Total assets:
Natural gas............................................... $4,896,542 $2,754,447
NGLs...................................................... 219,282 236,163
Corporate(d).............................................. 1,054,274 491,686
---------- ----------
Total assets...................................... $6,170,098 $3,482,296
========== ==========
- ---------------
(a) Intersegment sales represent sales of NGLs from the natural gas segment to
the NGLs segment at either index prices or weighted average prices of NGLs.
Both measures of intersegment sales are effectively based on current
economic market conditions.
(b) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense.
EBIT is EBITDA less depreciation and amortization. These measures are not a
measurement presented in accordance with generally accepted accounting
principles and should not be considered in isolation from or as a
substitute for net income or cash flow measures prepared in accordance with
generally accepted accounting principles or as a measure of the Company's
profitability or liquidity. The measures are included as a supplemental
disclosure because it may provide useful information regarding the
Company's ability to service debt and to fund capital expenditures.
However, not all EBITDA or EBIT may be available to service debt.
(c) Other operating cost for NGLs in 2000 include a gain on sale of NGL
Pipeline Assets of $12 million.
(d) Includes items such as unallocated working capital, intercompany accounts
and intangible and other assets.
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DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
18. QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
2000
Operating revenue.............. $1,451,211 $2,172,360 $2,551,995 $2,917,800 $9,093,366
Operating income............... 55,627 136,881 152,501 146,011 491,020
EBIT........................... 62,386 144,829 156,809 154,420 518,444
Net income..................... 361,900 92,229 114,304 111,728 680,161
1999
Operating revenue.............. $ 334,997 $ 773,847 $1,040,653 $1,308,813 $3,458,310
Operating income............... (2,728) 29,761 38,119 39,619 104,771
EBIT........................... 558 36,750 48,870 41,095 127,273
Net income..................... (8,521) 14,676 20,770 16,404 43,329
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DUKE ENERGY FIELD SERVICES, LLC
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
ADDITIONS
------------------------
BALANCE AT CHARGED TO BALANCE AT
BEGINNING CHARGED TO OTHER END OF
OF PERIOD EXPENSES ACCOUNTS(B) DEDUCTIONS PERIOD
---------- ---------- ----------- ---------- ----------
DECEMBER 31, 2000:
Allowance for doubtful accounts...... $ 6.7 $1.2 $ -- $ (4.3) $ 3.6
Environmental........................ 15.7 .7 26.5 (4.2) 38.7
Litigation........................... 10.9 -- 20.0 (2.2) 28.7
Other(a)............................. 19.5 -- 2.6 (3.5) 18.6
----- ---- ----- ------ -----
$52.8 $1.9 $49.1 $(14.2) $89.6
DECEMBER 31, 1999:
Allowance for doubtful accounts...... $ 1.1 -- $ 5.6 $ -- $ 6.7
Environmental........................ 5.8 -- 63.0 (53.1) 15.7
Litigation........................... -- -- 11.0 (.1) 10.9
Other(a)............................. 11.3 -- 17.0 (8.8) 19.5
----- ---- ----- ------ -----
$18.2 -- $96.6 $(62.0) $52.8
DECEMBER 31, 1998:
$18.2
- ---------------
(a) Principally consists of other contingency reserves which are included in
the "Other Current Liabilities" or "Other Long Term Liabilities".
(b) Principally consists of environmental, litigation and other contingency
reserves assumed in business acquisitions and combinations.
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INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Members of
Duke Energy Field Services, LLC
We have audited the accompanying consolidated balance sheets of Duke Energy
Field Services, LLC and subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of income and comprehensive income, equity, and
cash flows for each of the three years in the period ended December 31, 2000.
Our audits also included the financial statement schedule listed in the Index at
Item 14. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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, such consolidated financial statements present fairly, in
all material respects, the financial position of the companies at December 31,
2000 and 1999, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2000 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Denver, Colorado
March 2, 2001
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The following table provides information regarding our directors and
executive officers:
NAME AGE POSITION
- ---- --- --------
Jim W. Mogg.......................... 52 Director and Chairman of the Board, President and Chief
Executive Officer
Michael J. Panatier.................. 52 Vice Chairman of the Board
Mark A. Borer........................ 46 Senior Vice President, Southern Division
Michael J. Bradley................... 46 Senior Vice President, Northern Division
John E. Jackson...................... 42 Vice President and Chief Financial Officer
Robert F. Martinovich................ 43 Senior Vice President, Western Division
William W. Slaughter................. 53 Executive Vice President
Martha B. Wyrsch..................... 43 Senior Vice President, General Counsel and Secretary
Fred J. Fowler....................... 55 Director
John E. Lowe......................... 42 Director
J. J. Mulva.......................... 54 Director
Richard B. Priory.................... 54 Director
Jim W. Mogg is Chairman of the Board, President and Chief Executive Officer
of our company. Mr. Mogg also serves as Senior Vice President -- Field Services
for Duke Energy. Mr. Mogg was President and Chief Executive Officer of the
Predecessor Company from 1994 until the Combination. Mr. Mogg is also Vice
Chairman and a director of the general partner of TEPPCO. Mr. Mogg as been in
the energy industry since 1973.
Michael J. Panatier, an executive officer of our company, serves our board
of directors in an advisory capacity as Vice Chairman. Mr. Panatier served as
Senior Vice President of Gas Processing and Marketing for Phillips from 1998
until the Combination. From 1994 until the Combination, he also served as
President and Chief Executive Officer of GPM Gas Corporation, a subsidiary of
Phillips. Mr. Panatier has been in the energy industry since 1975.
Mark A. Borer is Senior Vice President, Southern Division of our company.
Mr. Borer held the same position with the Predecessor Company from 1999 until
the Combination. From 1992 until 1999, Mr. Borer served as Vice President of
Natural Gas Marketing for Union Pacific Fuels, Inc. Mr. Borer is also a director
of the general partner of TEPPCO. Mr. Borer has been in the energy industry
since 1978.
Michael J. Bradley is Senior Vice President, Northern Division of our
company. Mr. Bradley held the same position with the Predecessor Company from
1994 until the Combination. Mr. Bradley has been in the energy industry since
1979.
John E. Jackson was named Vice President and Chief Financial Officer of our
Company effective February 21, 2001. Mr. Jackson joined the Company on April 1,
1999 as Vice President and Controller. He was previously the Chief Financial
Officer of Union Pacific Fuels from 1997 to 1999. From 1996 to 1997, Mr. Jackson
served as Controller of Union Pacific Resources. From 1995 to 1996, Mr. Jackson
served as Treasurer of Union Pacific Resources. Mr. Jackson has been in the
energy industry since 1981.
Robert F. Martinovich is Senior Vice President, Western Division of our
company. Mr. Martinovich was Senior Vice President of GPM Gas Corporation, a
subsidiary of Phillips, from 1999 until the Combination. From 1996 until 1999,
Mr. Martinovich was Vice President, Oklahoma Region for GPM Gas Corporation,
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64
and from 1994 until 1996, he was Business Development Manager for GPM Gas
Corporation. Mr. Martinovich has been in the energy industry since 1980.
William W. Slaughter is Executive Vice President of our company. Mr.
Slaughter held the position of Advisor to the Chief Executive Officer of the
Predecessor Company from 1998 until his appointment as Executive Vice President
in 2000. From 1997 until 1998, Mr. Slaughter was Vice President of Energy
Services for Duke Energy. From 1994 until 1997, Mr. Slaughter served as Vice
President of Corporate Strategic Planning for PanEnergy and President of
PanEnergy International Development Corporation. Mr. Slaughter is also a
director of the general partner of TEPPCO. Mr. Slaughter has been in the energy
industry since 1970.
Martha B. Wyrsch is Senior Vice President, General Counsel and Secretary of
our company. Ms. Wyrsch held the same position with the Predecessor Company from
1999 until the Combination. Ms. Wyrsch also currently serves as Senior Vice
President and General Counsel -- Energy Transmission for Duke Energy. From 1997
until 1999, Ms. Wyrsch served as Vice President, General Counsel and Secretary
of K N Energy, Inc. From 1996 until 1997, Ms. Wyrsch served as Vice President,
Deputy General Counsel and Secretary of K N Energy, Inc. Ms. Wyrsch has been in
the energy industry since 1991.
Fred J. Fowler, a Director of our company, is Group President -- Energy
Transmission of Duke Energy and has held that position since 1997. Mr. Fowler
served as Group Vice President of Pan Energy from 1996 until 1997. From 1994
until 1996, Mr. Fowler served as President of Texas Eastern Transmission
Corporation. Mr. Fowler is also a director of the general partner of TEPPCO. Mr.
Fowler has been in the energy industry since 1968.
John E. Lowe, a Director of our company, is the Senior Vice President of
Corporate Strategy and Development and Interim Head of Refining, Marketing and
Transportation for Phillips since February 2001. Mr. Lowe served as Senior Vice
President of Planning and Strategic Transactions of Phillips from 2000 to 2001.
Mr. Lowe served as Vice President of Planning and Strategic Transactions of
Phillips from 1999 to 2000. From 1997 to 1999, Mr. Lowe served as Supply Chain
Manager for Refining, Marketing and Transportation of Phillips. From 1993 to
1997 he served as Manager of Finance for Phillips. Mr. Lowe has been in the
energy industry since 1981.
J.J. Mulva, a Director of our company, is Chairman of the Board of
Directors and Chief Executive Officer of Phillips and has held these positions
since 1999. From June 1999 to October 1999, Mr. Mulva served as Vice Chairman,
President and Chief Executive Officer of Phillips. From 1994 to 1999, Mr. Mulva
served as President and Chief Operating Officer of Phillips. Mr. Mulva has been
in the energy industry since 1973.
Richard B. Priory, a Director of our company, is the Chairman, President
and Chief Executive Officer of Duke Energy and has held that position since
1998. Mr. Priory served as Chairman and CEO of Duke Energy from 1997 to 1998.
From 1994 until 1997, Mr. Priory served as President and Chief Operating Officer
of Duke Energy. Mr. Priory is also a director of Dana Corporation and US Airways
Group, Inc. Mr. Priory has been in the energy industry since 1976.
Pursuant to our limited liability company agreement, we have five directors
two of which are appointed by Phillips and three of which are appointed by Duke
Energy.
There are no family relationships between any of the executive officers nor
any arrangement or understanding between any executive officer and any other
person pursuant to which the officer was selected.
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ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth compensation information for the year ended
December 31, 2000 for the Chief Executive Officer and each of our next four most
highly compensated executive officers. These five individuals are referred to as
the "Named Executive Officers."
LONG-TERM COMPENSATION}
ANNUAL COMPENSATION ------------------------------------
-------------------------------- RESTRICTED SECURITIES
OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER
SALARY BONUS COMPENSATION AWARDS STOCK OPTIONS PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION ($) ($) ($)(3) ($)(4) (#) ($) ($)(10)
- --------------------------- ------- ------- ------------ ---------- ------------- ------- ------------
Jim W. Mogg(1).............. 376,474 475,219 -- 193,513(5) 133,000(9) 76,102 37,399
Chairman of the Board,
President and Chief
Executive Officer
Michael J. Panatier(2)...... 366,865 473,800 -- -- -- -- 30,909
Vice Chairman of the Board
Mark A. Borer(1)............ 196,154 166,300 -- 145,730(6) 33,600(9) -- 24,497
Senior Vice President,
Southern Division
Michael J. Bradley(1)....... 196,154 169,400 -- 145,730(7) 34,400(9) 52,553 19,277
Senior Vice President,
Northern Division
Robert F. Martinovich(2).... 190,797 160,400 -- 145,730(8) 36,600(9) -- 54,507
Senior Vice President,
Western Division
- ---------------
(1) Prior to the Combination on March 31, 2000 all compensation paid to Messrs.
Mogg, Borer and Bradley was paid by Duke Energy and was attributable to
services provided to the Predecessor Company.
(2) Prior to the Combination on March 31, 2000 all compensation paid to Messrs.
Panatier and Martinovich was paid by Phillips.
(3) Perquisites and other personal benefits received by each Named Executive
Officer did not exceed the lesser of $50,000 or 10% of any such officer's
salary and bonus disclosed in the table.
(4) Messrs. Mogg, Borer, Bradley and Martinovich elected to receive a portion
of the value of their long-term incentive component of their 2001
compensation in the form of phantom stock. The awards were granted under
the Duke Energy 1998 Long-Term Incentive Plan on December 20, 2000. Phantom
stock is represented by units denominated in shares of Duke Energy common
stock. Each phantom stock unit represents the right to receive, upon
vesting, one share of Duke Energy common stock. One quarter of each award
vests on each of the first four anniversaries of the grant date provided
the recipient continues to be employed by the Company or his or her
employment terminates on account of retirement. The awards fully vest in
the event of the recipient's death or disability or a change in control as
specified in the Plan. If the recipient's employment terminates other than
on account of retirement, death or disability, any unvested shares
remaining on the termination date are forfeited. The phantom stock awards
also grant an equal number of dividend equivalents, which represent the
right to receive cash payments equivalent to the cash dividends paid on the
number of shares of Duke Energy common stock represented by the phantom
stock units awarded, until the related phantom stock units vest or are
forfeited.
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66
The aggregate number of phantom stock units held by Messrs. Mogg, Borer,
Bradley and Martinovich at December 31, 2000 and their values on that date
are as follows:
NUMBER OF VALUE AT
PHANTOM STOCK UNITS DECEMBER 31, 2000
------------------- -----------------
J. Mogg..................................... 4,520 $192,665
M. Borer.................................... 1,120 47,740
M. Bradley.................................. 1,120 47,740
R. Martinovich.............................. 1,120 47,740
(5) In addition to the 4,520 phantom stock units in note 4, at December 31,
2000, Mr. Mogg held an aggregate of 36,000 restricted shares of Duke Energy
common stock having a value of $1,534,500. Dividends are paid on such
shares. The vesting of these shares is determined by, among other things,
the performance of Duke Energy.
(6) In addition to the 1,120 phantom stock units in note 4, at December 31,
2000, Mr. Borer held an aggregate of 7,390 restricted shares of Duke Energy
common stock having a value of $314,999. Dividends are paid on such shares.
Of these restricted shares, 2,000 shares will vest on each of April 1, 2001
and April 1, 2002. The remaining 3,390 shares will vest on May 26, 2003.
(7) In addition to the 1,120 phantom stock units in note 4, at December 31,
2000, Mr. Bradley held an aggregate of 3,390 restricted shares of Duke
Energy common stock having a value of $144,499. Dividends are paid on such
shares. These shares will vest on May 26, 2003.
(8) In addition to the 1,120 phantom stock units in note 4, at December 31,
2000, Mr. Martinovich held an aggregate of 3,390 restricted shares of Duke
Energy common stock having a value of $144,499. Dividends are paid on such
shares. One half of these shares will vest on each of May 26, 2001 and May
26, 2002.
(9) Represents options granted by Duke Energy to purchase shares of Duke Energy
common stock.
(10) Represents the following:
- Matching contributions under the Company's 401(k) and Retirement Plan as
follows: J. Mogg, $6,275; M. Panatier, $15,000; M. Borer, $11,140; M.
Bradley, $10,833; R. Martinovich, $14,616.
- Make-whole matching contribution credits under the Duke Energy Executive
Cash Balance Plan as follows: J. Mogg, $4,328; M. Borer, $370; M.
Bradley, $698.
- Make-whole contributions under the Company's Executive Deferred
Compensation Plan as follows: J. Mogg, $22,955; M. Panatier, $13,062; M.
Borer, $3,476; M. Bradley, $3,782.
- Mortgage rate differential payments paid by the Company to account for
increased mortgage payments due to employee relocation as follows: M.
Bradley, $2,353.
- Supplemental relocation payments made under the Company's relocation
policy as follows: M. Borer, $7,900; R. Martinovich, $38,845.
- Life Insurance premiums paid by the Company as follows: J. Mogg, $3,841;
M. Panatier, $2,847; M. Borer, $1,611; M. Bradley, $1,611; R.
Martinovich, $1,046.
BOARD COMPENSATION
Our Directors do not receive a retainer or fees for service on our Board of
Directors or any committees. All of our directors are reimbursed for reasonable
out-of-pocket expenses incurred in attending meetings of our Board of Directors
or committees and for other reasonable expenses related to the performance of
their duties as directors.
EMPLOYMENT AND CONSULTING AGREEMENTS
We have entered into an employment agreement with Mr. Panatier which
provides for a term of one year and expires March 31, 2001. During the term of
this employment agreement, Mr. Panatier will receive a
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67
monthly salary of $32,000, which may be increased upon the recommendation of our
Compensation Committee. The agreement also provides for a target bonus of 60% of
Mr. Panatier's annual base salary. Mr. Panatier is entitled to participate in
all of our benefit plans on the same basis as other similarly-situated
executives of our company.
Under the terms of the employment agreement, Mr. Panatier will also receive
a long-term cash incentive award of $844,000 on April 1, 2001, plus accrued but
unpaid interest on such amount of $43,188, based on an interest rate of 6% per
annum from May 26, 2000 to April 1, 2001. In addition, the employment agreement
grants Mr. Panatier a cash retention award of $960,000 on April 1, 2001, plus
interest on such amount of $49,078, based on an interest rate of 6% per annum
from May 26, 2000 to April 1, 2001. Mr. Panatier intends to leave the employment
of the Company effective March 31, 2001.
We have entered into a contract for consulting services with Mr. Slaughter
that terminates in June 2002. During the term of this contract, Mr. Slaughter
will receive a quarterly retainer of $46,860, in exchange for which Mr.
Slaughter has agreed to perform services for us for up to 30 days per quarter.
If Mr. Slaughter works more than 30 days per quarter, he is entitled to
additional compensation at the rate of $1,562 for each additional day. In
addition, under the terms of the contract, Mr. Slaughter will receive a
long-term incentive award that tracks the performance of Duke Energy common
stock. The award, valued at $360,000 at the time of grant, will be paid in cash,
50% on each of the first and second anniversary of grant. Any unpaid portion of
such award will automatically be converted into stock options and restricted
stock in the event of an initial public offering of equity securities occurring
before the payment date.
OPTION GRANTS IN LAST FISCAL YEAR
None of the Named Executive Officers has received options to purchase
members interests in our company. None of the Named Executive Officers held
options to purchase member interests in our company at December 31, 2000.
This table shows options granted of Duke Energy common stock to the Named
Executive Officers during 2000, along with the present value of the options on
the date they were granted, calculated as described in footnote 2 to the table.
Grants shown in the table with an expiration date of December 20, 2010, were
awarded on December 20, 2000, and relate to compensation for 2001.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
--------------------------------------------------------------------
NUMBER OF SHARES % OF TOTAL
UNDERLYING OPTIONS/SARS
OPTIONS/SARS GRANTED TO EXERCISE OR BASE GRANT DATE PRESENT
NAME GRANTED(1)(#) EMPLOYEES(2) PRICE ($/SH) EXPIRATION DATE VALUE(3)($)
- ---- ---------------- ------------ ---------------- --------------- ------------------
J. W. Mogg.............. 58,400 --(4) 29.50 6/29/2010 606,309
74,600 1.2%(4) 42.8125 12/20/2010 774,497
M. J. Panatier.......... 0 --(4) -- -- 0
M. A. Borer............. 33,600 --(4) 42.8125 12/20/2010 348,835
M. J. Bradley........... 34,400 -- (4) 42.8125 12/20/2010 357,141
R. F. Martinovich....... 18,000 --(4) 29.50 6/29/2010 186,876
18,600 --(4) 42.8125 12/20/2010 193,105
- ---------------
(1) Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons.
(2) Reflects percentage that the grant represents of the total options granted
to employees of Duke Energy and its subsidiaries during 2000.
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(3) Based on the Black-Scholes option valuation model. The following table lists
key input variables used in valuing the options:
INPUT VARIABLE:
- ---------------
Risk-free Interest Rate................................... 5.45%
Dividend Yield............................................ 3.70%
Stock Price Volatility.................................... 25.88%
Option Term............................................... 10 years
With respect to all option grants listed in the table, the volatility
variable reflected historical monthly stock price trading date from November 30,
1997 through November 30, 2000. An adjustment was made with respect to each
valuation for a risk of forfeiture during the vesting period. The actual value,
if any, that a grantee may realized will depend on the excess of the stock price
over the exercise price on the date the option is exercised, so that there is no
assurance the value realized will be at or near the value estimated based upon
the Black-Scholes model.
(4) less than one percent.
OPTION EXERCISES AND YEAR-END VALUES
This tables shows aggregate exercises of options for Duke Energy common
stock during 2000 by the Named Executive Officers, and the aggregate year-end
value of the unexercised options held by them. The value assigned to each
unexercised "in-the-money" stock option is based on the positive spread between
the exercise price of the stock option and the split-adjusted fair market value
of Duke Energy common stock on December 31, 2000, which was $42.86. The fair
market value is the average of the high and low prices of a share of Duke Energy
common stock on that date as reported on the New York Stock Exchange Composite
Transactions Tape. The ultimate value of a stock option will depend on the
market value of the underlying shares on a future date.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUES
NUMBER OF
SECURITIES
UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS/SARS AT OPTIONS/SARS AT
FY-END*(#) FY-END($)
--------------- --------------------
SHARES ACQUIRED EXERCISABLE/ EXERCISABLE/
NAME ON EXERCISE(#) VALUE REALIZED($) UNEXERCISABLE UNEXERCISABLE
---- --------------- ----------------- --------------- --------------------
J. W. Mogg.................. 11,184 218,185 48,618/210,250 839,554/2,000,547
M. J. Panatier.............. -- -- -- --
M. A. Borer................. -- -- 8,400/ 43,800 139,050/ 417,151
M. J. Bradley............... 16,314 215,107 9,530/ 50,600 243,537/ 497,508
R. F. Martinovich........... -- -- 0/ 36,600 0/ 240,480
- ---------------
* Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following table sets forth information regarding the beneficial
ownership of the member interests in our company by:
- each holder of more than 5% of our member interests;
- the Named Executive Officers;
- each director; and
- all directors and executive officers as a group.
NAME OF BENEFICIAL OWNERS BENEFICIAL OWNERSHIP
- ------------------------- --------------------
Duke Energy Corporation........................... 69.7%
526 South Church Street
Charlotte, North Carolina 28201-1006
Phillips Petroleum Company........................ 30.3
Phillips Building
Bartlesville, Oklahoma 74004
Jim W. Mogg....................................... --
Michael J. Panatier............................... --
Mark A. Borer..................................... --
Michael J. Bradley................................ --
Robert F. Martinovich............................. --
Fred J. Fowler.................................... --
John E. Lowe...................................... --
J.J. Mulva(1)..................................... 30.3
Richard B. Priory(2).............................. 69.7
All directors and executive officers as a group
(13 persons)(1)(2).............................. 100.0%
- ---------------
(1) Mr. Mulva serves as Chairman and Chief Executive Officer of Phillips. As
such, Mr. Mulva may be deemed to have voting and dispositive power over our
member interests beneficially owned by Phillips. Mr. Mulva disclaims
beneficial ownership of the securities owned by Phillips.
(2) Mr. Priory serves as Chairman, President and Chief Executive Officer of Duke
Energy. As such, Mr. Priory may be deemed to have voting and dispositive
power over our member interests beneficially owned by Duke Energy. Mr.
Priory disclaims beneficial ownership of the securities owned by Duke
Energy.
In August 2000, we issued $300.0 million of preferred member interests to
affiliates of Duke Energy and Phillips. Duke Energy Field Services Investment
Corp. was issued a preferred member interest representing 69.7% of the
outstanding preferred member interests in our company and Phillips Gas
Investment Company was issued a preferred member interest representing a 30.3%
of the outstanding preferred member interests in our company. See Note 11 to the
Notes to Consolidated Financial Statements. The preferred member interests have
no voting rights in the election of our directors. Duke Energy and Mr. Priory
may be deemed to have dispositive power over the preferred member interest held
by Duke Energy Field Services Investment Corp., and Phillips and Mr. Mulva may
be deemed to have dispositive power over the preferred member interest held by
Phillips Gas Investment Company. Mr. Priory disclaims beneficial ownership of
the preferred member interests held by Duke Energy Field Services Investment
Corp. and Mr. Mulva disclaims beneficial ownership of the preferred member
interests held by Phillips Gas Investment Company.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
On March 31, 2000, we combined the midstream natural gas businesses of Duke
Energy and Phillips. In connection with the Combination, Duke Energy and
Phillips transferred all of their respective interests in their
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subsidiaries that conducted their midstream natural gas business to us. In
connection with the Combination, Duke Energy and Phillips also transferred to us
additional midstream natural gas assets acquired by Duke Energy or Phillips
prior to consummation of the Combination, including the Mid-Continent gathering
and processing assets of Conoco and Mitchell Energy. In addition, concurrently
with the Combination, we obtained by transfer from Duke Energy the general
partner of TEPPCO. In exchange for the asset contributions, Phillips received
30.3% of the outstanding non-preferred member interests in our company, with
Duke Energy holding the remaining 69.7% of the outstanding non-preferred member
interests in our company. In connection with the closing of the Combination, we
borrowed approximately $2.8 billion in the commercial paper market and made
one-time cash distributions (including reimbursements for acquisitions) of
approximately $1.5 billion to Duke Energy and approximately $1.2 billion to
Phillips.
There are significant transactions and relationships between us, Duke
Energy and Phillips. For purposes of governing these ongoing relationships and
transactions, we will continue in effect the agreements described below. We
intend that the terms of any future transactions and agreements between us and
Duke Energy or Phillips will be at least as favorable to us as could be obtained
from third parties. Depending on the nature and size of the particular
transaction, in any such reviews, our Board of Directors may rely on our
management's knowledge, use outside experts or consultants, secure appropriate
appraisals, refer to industry statistics or prices, or take other actions as are
appropriate under the circumstances.
TRANSACTIONS WITH DUKE ENERGY
Services Agreement
We have entered into a services agreement with Duke Energy and some of its
subsidiaries, dated as of March 14, 2000, as amended on December 15, 2000. Under
this agreement, Duke Energy and those subsidiaries will provide us with various
staff and support services, including information technology products and
services, payroll, employee benefits, insurance, cash management, ad valorem
taxes, treasury, media relations, printing, records management, legal functions
and shareholder services. These services are priced on the basis of a monthly
charge approximating market prices. Additionally, we may use other Duke Energy
services subject to hourly rates, including legal, insurance, internal audit,
tax planning, human resources and security departments. This agreement, as
amended, expires on December 31, 2001. We believe that the overall charges under
this agreement will not exceed charges we would have incurred had we obtained
similar services from outside sources.
License Agreement
In connection with the Combination, Duke Energy has licensed to us a
non-exclusive right to use the phrase "Duke Energy" and its logo and certain
other trademarks in identifying our businesses. This right may be terminated by
Duke Energy at its sole option any time after:
- Duke Energy's direct or indirect ownership interest in our company is
less than or equal to 35%; or
- Duke Energy no longer controls, directly or indirectly, the management
and policies of our company.
Following the receipt of Duke Energy's notice of termination, we have
agreed to amend our organizational documents and those of our subsidiaries to
remove the "Duke" name and to phase out within 180 days of the date of the
notice the use of existing signage, printed literature, sales and other
materials bearing a name, phrase or logo incorporating "Duke."
Other Transactions
Prior to the Combination, Duke Energy and its subsidiaries engaged in a
number of transactions with the Predecessor Company. This included sales of
residue gas and NGLs, the purchase of raw natural gas and other petroleum
products and providing natural gas gathering and transportation services to Duke
Energy and its subsidiaries. We anticipate that we will continue to engage is
such activities with Duke Energy and its
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subsidiaries in the ordinary course of business. In 2000, our total revenues
from such activities with Duke Energy and its subsidiaries were approximately
$1,459.2 million.
TRANSACTIONS WITH PHILLIPS
Transition Services Agreement
We have entered into a Transition Services Agreement with Phillips, dated
as of March 17, 2000. Under this agreement, Phillips will provide us with
various staff and support services, including information technology products
and services, cash management, real estate, claims and property tax services.
The above services are priced on the basis of a monthly charge equal to
Phillips' fully-burdened cost of providing the services. The original term of
this agreement expired on December 31, 2000; however, we are in negotiations
with Phillips to extend the term for some of these services. Both companies
continue to perform under the original agreement.
Other Transactions
Prior to the Combination, Phillips engaged in a number of transactions with
GPM Gas Corporation, the subsidiary of Phillips that owned its midstream natural
gas assets that were transferred to us as part of the Combination. This included
the sale of residue gas, NGLs and sulfur, and the purchase of raw natural gas.
In addition, it included a long-term agreement with Phillips and Chevron
Phillips Chemical Company LLC ("CPC") for the sale of NGLs at index-based
prices. We anticipate that we will continue to engage in such activities with
Phillips and its subsidiaries and CPC in the ordinary course of business. From
the date of the combination through December 31, 2000, our total revenues from
such activities with Phillips and its subsidiaries, and CPC were approximately
$942.3 million.
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Consolidated Financial Statements, Supplemental Financial Data and
Supplemental Schedule included in Part II of this annual report are as follows:
Consolidated Financial Statements
Consolidated Statements of Income and Comprehensive Income for the Years
Ended December 31, 2000, 1999 and 1998
Consolidated Statements of Cash Flows for the Years Ended December 31,
2000, 1999 and 1998
Consolidated Balance Sheets as of December 31, 2000 and 1999
Consolidated Statements of Equity for the Years Ended December 31, 2000,
1999 and 1998
Notes to Consolidated Financial Statements
Quarterly Financial Data (unaudited) (included in Note 18 of the Notes to
Consolidated Financial Statements)
Consolidated Financial Statement Schedule II -- Valuation and Qualifying
Accounts and Reserves for the Years Ended December 31, 2000, 1999 and 1998
All other schedules are omitted because of the absence of the conditions
under which they are required or because the required information is included in
the financial statements or notes thereto.
(b) Reports on Form 8-K
None.
(c) Exhibits -- See Exhibit Index immediately following the signature page.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
DUKE ENERGY FIELD SERVICES, LLC
By: /s/ JIM W. MOGG
----------------------------------
Jim W. Mogg
Chairman of the Board, President
and
Chief Executive Officer
March 30, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
SIGNATURE TITLE
--------- -----
/s/ JIM W. MOGG Chairman of the Board, President and Chief
- ----------------------------------------------------- Executive Officer (Principal Executive
Jim W. Mogg Officer)
/s/ JOHN E. JACKSON Chief Financial Officer (Principal Financial
- ----------------------------------------------------- and Accounting Officer)
John E. Jackson
/s/ FRED J. FOWLER Director
- -----------------------------------------------------
Fred J. Fowler
/s/ JOHN E. LOWE Director
- -----------------------------------------------------
John E. Lowe
/s/ J.J. MULVA Director
- -----------------------------------------------------
J.J. Mulva
/s/ RICHARD B. PRIORY Director
- -----------------------------------------------------
Richard B. Priory
Date: March 30, 2001
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EXHIBIT INDEX
Exhibits filed herewith are designated by an asterisk(*). All exhibits not
so designated are incorporated by reference to a prior filing, as indicated.
Items constituting management contracts or compensatory plans or arrangements
are designated by a double asterisk (**).
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
3.1 -- Amended and Restated Limited Liability Company Agreement
of Duke Energy Field Services, LLC by and between
Phillips Gas Company and Duke Energy Field Services
Corporation, dated as of March 31, 2000 (incorporated by
reference to Exhibit 3.1 to Form 10 (Registration No.
000-31095) of registrant filed on July 20, 2000).
3.2 -- First Amendment to Amended and Restated Limited Liability
Company Agreement of Duke Energy Field Services, LLC
dated as of August 4, 2000 (incorporated by reference to
Exhibit 3.1 to Current Report on Form 8-K of registrant
filed on August 16, 2000).
4.1 -- Form of Indenture (incorporated by reference to Exhibit
4.1 to Registration Statement on Form S-3/A (Registration
No. 333-41854) of registrant filed on August 2, 2000).
4.2 -- First Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of August 16, 2000 (incorporated by reference to
Exhibit 4.1 to Current Report on Form 8-K of registrant
filed on August 16, 2000).
4.3 -- Second Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of February 2, 2001 (incorporated by reference
to Exhibit 4.1 to Current Report on Form 8-K of
registrant filed on February 1, 2001).
10.1 -- Second Amendment to Parent Company Agreement among
Phillips Petroleum Company, Duke Energy Corporation, Duke
Energy Field Services, LLC and Duke Energy Field Services
Corporation dated as of August 4, 2000 (incorporated by
reference to Exhibit 10.1 to Current Report on Form 8-K
of registrant filed on August 16, 2000).
10.2** -- Employment Agreement dated as of April 1, 2000 between
Duke Energy Field Services Assets, LLC and Michael J.
Panatier (incorporated by reference to Exhibit 10.1 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on May 4, 2000).
10.3** -- First Amendment to Employment Agreement dated as of June
28, 2000 between Duke Energy Field Services Assets, LLC
and Michael J. Panatier (incorporated by reference to
Exhibit 10.1(b) to Form 10/A (Registration No. 000-31095)
of registrant filed on August 2, 2000).
10.4 -- Services Agreement dated as of March 14, 2000 by and
between Duke Energy Corporation, Duke Energy Business
Services, LLC, Pan Service Company, Duke Energy Gas
Transmission Corporation and Duke Energy Field Services,
LLC (incorporated by reference to Exhibit 10.3 to
Registration Statement on Form S-1/ A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on March 27, 2000).
*10.5 -- First Amendment to Services Agreement dated as of
December 15, 2000 between Duke Energy Corporation, Duke
Energy Business Services, LLC, Pan Service Company, Duke
Energy Gas Transmission Corporation and Duke Energy Field
Services, LLC.
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EXHIBIT NUMBER DESCRIPTION
-------------- -----------
10.6 -- Transition Services Agreement dated as of March 17, 2000
among Phillips Petroleum Company and Duke Energy Field
Services, LLC (incorporated by reference to Exhibit 10.4
to Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on March 27, 2000).
10.7 -- Trademark License Agreement dated as of March 31, 2000
among Duke Energy Corporation and Duke Energy Field
Services, LLC (incorporated by reference to Exhibit 10.5
to Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on May 4, 2000).
10.8 -- Contribution Agreement dated as of December 16, 1999
among Duke Energy Corporation, Phillips Petroleum Company
and Duke Energy Field Services, LLC (incorporated by
reference to Exhibit 2.1 to Duke Energy Corporation's
Form 8-K filed on December 30, 1999).
10.9 -- First Amendment to Contribution and Governance Agreement
dated as of March 23, 2000 among Phillips Petroleum
Company, Duke Energy Corporation and Duke Energy Field
Services, LLC (incorporated by reference to Exhibit
10.7(b) to Registration Statement on Form S-1/A
(Registration No. 333-32502) of Duke Energy Field
Services Corporation, filed on March 27, 2000).
10.10 -- NGL Output Purchase and Sale Agreement effective as of
January 1, 2000 between GPM Gas Corporation and Phillips
66 Company, a division of Phillips Petroleum Company, as
amended by Amendment No. 1 dated December 16, 1999
(incorporated by reference to Exhibit 10.8 to
Registration Statement on Form S-1/ A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on March 15, 2000).
10.11 -- Sulfur Sales Agreement effective as of January 1, 1999
between Phillips 66 Company, a division of Phillips
Petroleum Company, and GPM Gas Corporation (incorporated
by reference to Exhibit 10.9 to Registration Statement on
Form S-1/ A (Registration No. 333-32502) of Duke Energy
Field Services Corporation, filed on March 27, 2000).
10.12 -- Parent Company Agreement dated as of March 31, 2000 among
Phillips Petroleum Company, Duke Energy Corporation, Duke
Energy Field Services, LLC and Duke Energy Field Services
Corporation (incorporated by reference to Exhibit 10.10
to Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on May 4, 2000).
10.13 -- First Amendment to the Parent Company Agreement dated as
of May 25, 2000 among Phillips Petroleum Company, Duke
Energy Corporation, Duke Energy Field Services, LLC and
Duke Energy Field Services Corporation (incorporated by
reference to Exhibit 10.8(b) to Form 10 (Registration No.
333-41854) of registrant filed on July 20, 2000).
10.14** -- Contract for Services dated as of April 1, 2000 between
Duke Energy Field Services Assets, LLC and William W.
Slaughter (incorporated by reference to Exhibit 10.11 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on May 4, 2000).
10.15** -- First Amendment to Contract for Services dated as of June
29, 2000 between Duke Energy Field Services Assets, LLC
and William W. Slaughter (incorporated by reference to
Exhibit 10.9(b) to Form 10/A (Registration No. 333-
41854) of registrant filed on August 2, 2000).
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EXHIBIT NUMBER DESCRIPTION
-------------- -----------
10.16 -- 364-Day Credit Facility among Duke Energy Field Services,
LLC,Duke Energy Field Services Corporation, Bank of
America, N.A., Morgan Stanley Senior Funding, Inc.,
Merrill Lynch Capital Corporation, and Morgan Guaranty
Trust Company of New York dated March 31, 2000
(incorporated by reference to Exhibit 10.12 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation,
filed on May 23, 2000).
*12.1 -- Calculation of Ratio of Earnings to Fixed Charges.
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of Deloitte & Touche LLP.
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