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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10
GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
DUKE ENERGY FIELD SERVICES, LLC
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0632293
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
370 17TH STREET
SUITE 900
DENVER, COLORADO 80202
(Address of Principal Executive Officers) (Zip Code)
</TABLE>
(303) 595-3331
(Registrant's Telephone Number, Including Area Code)
Securities to be registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS TO BE SO REGISTERED ON WHICH EACH CLASS IS TO BE REGISTERED
<S> <C>
None Not applicable
</TABLE>
Securities to be registered pursuant to Section 12(g) of the Act:
Limited Liability Company Member Interests
(TITLE OF CLASS)
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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 businesses of Duke Energy Corporation ("Duke Energy") and
Phillips Petroleum Company ("Phillips"). The transaction in which those
businesses were combined is referred to in this registration statement 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 natural gas liquids in Mexico and the transportation, marketing
and storage of other petroleum products, unless otherwise approved by our Board
of Directors.
Unless the context otherwise requires, descriptions of assets, operations
and results in this registration statement 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 "Item 2. Financial Information -- Management's
Discussion and Analysis of Financial Condition and Results of Operations -- The
Combination." In this registration statement, the terms "we," "us" and "our"
refer to Duke Energy Field Services, LLC and our subsidiaries, giving effect to
the Combination and related transactions.
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, and 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
1999:
- we gathered and/or transported an average of approximately 7.3 billion
cubic feet per day of raw natural gas;
- we produced an average of approximately 400,000 barrels per day of NGLs;
and
- we marketed and traded an average of approximately 486,000 barrels per
day of NGLs.
During 1999, our natural gas gathering, processing, transportation,
marketing and storage segment produced $981.5 million of gross margin and $583.1
million of EBITDA, excluding general and administrative expenses, and our NGL
fractionation, transportation, marketing and trading segment produced $38.3
million of gross margin and $38.1 million of EBITDA, excluding general and
administrative expenses.
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 38,000 active connections to
producing wells.
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 70 owned and operated
plants and at 13 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 under an existing 15-year contract. We market approximately 370,000
barrels per day of NGLs processed at our owned and operated plants and 40,000
barrels per day of NGLs processed at third-party operated facilities and trade
approximately 75,000 barrels per day of NGLs at market centers.
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 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. Through our ownership of the general
partner of TEPPCO we have the right to receive from TEPPCO incentive cash
distributions in addition to a 2% share of distributions based on our general
partner interest. At TEPPCO's 1999 per unit distribution level, the general
partner:
- receives approximately 14% of the cash distributed by TEPPCO to its
partners, which consists of 12% 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.
On , 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.
INDUSTRY OVERVIEW
The midstream natural gas industry in North America is comprised of
approximately 150 companies that process approximately 45 billion cubic feet per
day of raw natural gas and produce approximately 1.9 million barrels per day of
NGLs. The industry generally is characterized by regional competition based on
the proximity of gathering systems and processing plants to natural gas
producing wells.
Demand for natural gas in North America has grown significantly in recent
years. We believe that demand will continue to increase and will be driven
primarily by the growth of natural gas-fired electric generation. According to
the Energy Information Administration's report "Annual Energy Outlook 2000" (the
"EIA Report"), U.S. demand for natural gas is expected to increase from 22
trillion cubic feet in 1999 to 32 trillion cubic feet in 2020. We believe that
oil and natural gas producers in North America will respond to increased demand
by focusing their exploration and drilling efforts on basins where pipeline and
processing capacity has been, or is being, built and where there is sufficient
capacity to meet the needs of high demand markets. We have a strong presence and
significant capacity in several of these areas (including Onshore Gulf
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of Mexico and Rocky Mountains, where, according to the Oil and Gas 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) that, according to the EIA Report, are forecasted to
have significant growth in production between now and 2020. This growth in
production, which is expected to be 2.31 trillion cubic feet in Rocky Mountain
region and 1.71 trillion cubic feet in Onshore Gulf of Mexico region by 2020,
should provide us with opportunities to increase our throughput volumes and
asset utilization.
The midstream natural gas industry has experienced significant
consolidation since the mid-1990s. We believe the following factors have
contributed to this consolidation:
- significant economies of scale resulting from improved operating
efficiencies, throughput volumes and asset utilization rates that can be
achieved by strategically growing operations;
- decisions by transmission pipelines and by exploration and production
companies to divest their gathering, processing and marketing activities
and concentrate their businesses on gas transmission and on exploration
and production; and
- technological improvements.
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 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
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.
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- 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 March 31, 2000, our raw natural gas gathering and processing operations
consisted of:
- approximately 57,000 miles of gathering pipe, with connections to
approximately 38,000 active producing wells; and
- 70 owned and operated processing plants and ownership interests in 13
additional third-party operated plants, with a combined processing
capacity of approximately 7.9 billion cubic feet per day.
In 1999, we gathered, processed and/or transported approximately 7.3
billion cubic feet per day of raw natural gas. During 1999, our natural gas
gathering, processing, transportation, marketing and storage activities produced
$981.5 million of gross margin and $583.1 million of EBITDA, excluding general
and administrative expenses.
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 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 "Item 2. Financial Information -- 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, 1999, we had approximately 17
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 ExxonMobil, Union
Pacific Resources, BP Amoco and Phillips, which together account for
approximately 20% of our processed raw natural gas.
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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 provides
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 1,300 additional wells in 1998 and 1,500 additional wells in 1999.
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 produced an
average of approximately 4.7 billion cubic feet per day of residue gas and an
average of approximately 400,000 barrels per day of NGLs during 1999.
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 three 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 1.3 billion cubic feet of helium
during 1999, producing revenues of approximately $33 million.
Hydrogen sulfide also is separated in the treating and processing cycle.
During 1999, we produced and sold approximately 93,000 long tons of sulfur,
producing revenues of approximately $1.1 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
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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, 1999, we had $21.9 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. In
addition, our geographic diversity reduces the impact of regional price
fluctuations and regional changes in drilling activity.
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 March 31, 2000.
<TABLE>
<CAPTION>
COMPANY PLANTS
GAS GATHERING OPERATED OPERATED NET PLANT
REGION SYSTEM(MILES) PLANTS BY OTHERS CAPACITY(MMcf/d)
------ ------------- -------- --------- ----------------
<S> <C> <C> <C> <C>
Permian Basin........ 12,890 19 2 1,417
Mid-Continent........ 30,820 19 2 2,273
East Texas-Austin
Chalk-North
Louisiana.......... 5,869 10 1 1,555
Onshore Gulf of
Mexico............. 3,008 7 1 1,083
Rocky Mountains...... 3,765 10 1 600
Offshore Gulf of
Mexico............. 490 2 6 909
Western Canada....... 144 3 0 109
------ -- -- -----
Total................ 56,986 70 13 7,946
====== == == =====
<CAPTION>
1999 OPERATING DATA
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PLANT INLET RESIDUE GAS NGLS
REGION VOLUME(MMcf/d) PRODUCTION(MMcf/d) PRODUCTION(Bbls/d)
------ -------------- ------------------ ------------------
<S> <C> <C> <C>
Permian Basin........ 1,123 816 124,507
Mid-Continent........ 1,459 1,223 120,551
East Texas-Austin
Chalk-North
Louisiana.......... 1,033 937 69,420
Onshore Gulf of
Mexico............. 757 675 37,944
Rocky Mountains...... 387 319 24,708
Offshore Gulf of
Mexico............. 736 691 15,148
Western Canada....... 76 72 278
----- ----- -------
Total................ 5,571 4,733 392,556(1)
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(1) Excludes approximately 7,500 barrels per day processed at third party plants
on our behalf.
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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 gathers, 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 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 19
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
production of the Permian Basin. 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 most of
our plants offer sulfur removal. During 1999, these plants operated at an
overall 79% capacity utilization rate. On average, the raw natural gas from West
Texas contains approximately 5.2 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
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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 ExxonMobil, Union Pacific
Resources and Yates Petroleum. Our principal competitors in this region include
Dynegy, Koch and Texaco.
Mid-Continent. Our facilities in this region are located in Oklahoma,
Kansas and the Texas Panhandle. In this region, we own and are the operator of
19 natural gas processing plants, 18 in which we own a 100% interest and one in
which we own a 50% interest. 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
1999, our plants operated at an overall 65% capacity utilization rate. On
average, the raw natural gas from this region contains from 3 to 5 gallons of
NGLs per thousand cubic feet.
We also produce approximately 28% 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 are 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 Coastal 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 interests in and are the
operator of 10 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 1.6
billion cubic feet of raw natural gas per day. During 1999, these plants
operated at an overall 66% capacity utilization rate. In this region we also own
three intrastate 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,
Union Pacific Resources and American Central. Substantially all of the raw
natural gas processed at the complex is contracted under percent-of-proceeds
agreements with an average remaining term of approximately six years. This plant
is adjacent to our Carthage Hub, which delivers residue gas to interconnects
with 14 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. We also operate Panola pipeline,
with throughput capacity of up to 40,000 barrels per day, which carries NGLs
from our East Texas Complex to markets in Mont Belvieu, Texas. In this region,
we also own and operate the Fuels Cotton Valley Gathering System, which consists
of 76 miles of pipeline and which gathers approximately 30 million cubic feet of
raw natural gas per day.
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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 Union Pacific Resources, 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 seven 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 1999, the plants in this region ran at
an overall 70% 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 5.6 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 12 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 Collins & Ware, United Oil and
Minerals and TransTexas. Our principal competitors in this region include PG&E
Texas Transmission, 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 Ladder Creek area of Southeast Colorado and 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 10 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 1999, our plants in this region operated at an overall 65%
capacity utilization rate. These assets provide for the gathering and processing
of raw natural gas, the transportation and fractionation of NGLs, nitrogen
rejection, and helium extraction and liquification services.
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
Union Pacific Resources. 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 50% interest in one natural gas processing plant
and minority interests in five other natural gas processing plants, all of which
are operated by other entities. The plants have processing capacity net to our
interest of 909 million cubic feet of raw natural gas per day. During 1999, our
plants in this region operated at an overall 81% 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 50% of the produced NGLs content consists of ethane. As a
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result, the offshore region's revenues are concentrated in fee-based business
arrangements and are less dependent on fluctuating commodity prices.
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, 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,
ExxonMobil 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 three
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 109 million cubic feet of
raw natural gas per day. Our 144-mile gathering system located in this region
supports these processing facilities. During 1999, our processing plants in this
area operated at an overall 70% 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.
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, scheduled to be operational in October 2000.
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 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 1999, our NGL transportation, fractionation and
marketing activities produced $38.3 million of gross margin and $38.1 million of
EBITDA, excluding general and administrative expenses. In 1999, we marketed and
traded approximately 486,000 bar-
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rels of NGLs per day, of which approximately 85% 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 interests in two major NGLs pipelines serving the Mont Belvieu
facilities, the wholly owned Panola Pipeline in East Texas and an interest in
the Black Lake Pipeline in Louisiana and East Texas. We also own several
regional fractionation plants and NGLs 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 12 pipeline systems.
Our current fractionation capacity is approximately 152,000 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 briefly is discussed 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.
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 94,500 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.
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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, Union Pacific Resources and Pacific Gas & Electric. Our largest
sales customers are Phillips, Dow Chemical and ExxonMobil, which accounted for
12%, 2% and 1%, respectively, of our total revenues in 1999. Our three principal
competitors in the marketing of NGLs are Dynegy, Koch and Enterprise. In 1999,
we marketed and traded an average of approximately 486,000 barrels per day, or
approximately 19% 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's refined products and liquefied petroleum gas pipeline system includes
approximately 4,300 miles of pipeline which extend from southeast Texas through
the central and midwestern United States to the northeastern United States.
TEPPCO's refined products and liquefied petroleum gas pipeline system has
storage capacity of 13 million barrels of refined petroleum products and 38
million barrels of liquefied petroleum gas.
Through its crude oil and NGLs transportation and marketing business,
TEPPCO gathers, stores, transports and markets crude oil, NGLs, lube oil and
specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain
region. TEPPCO's crude oil and NGLs assets include approximately 1,950 miles of
crude oil pipeline and 1.7 million barrels of crude oil storage and
approximately 425 miles of NGL pipeline with an aggregate capacity of 25,000
barrels per day.
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 appropriate assets
currently held by our company to TEPPCO.
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 or payments it makes
on behalf of TEPPCO.
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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 1999 per unit distribution level, the general partner:
- receives approximately 14% of the cash distributed by TEPPCO to its
partners, which consists of 12% 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 1999, total cash distributions to the general partner of TEPPCO were
$8.3 million.
On , 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.
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 1999. 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 "Item 2. Financial Information -- 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.
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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.
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 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 an
interest in 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.
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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 all marketers of natural gas. 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 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.
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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 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 rehearing
or 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.
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.
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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 these laws and regulations at the federal, state, and local
levels. These laws and regulations can restrict or prohibit our business
activities that affect the environment in many ways, such as:
- restricting the way we can release materials or waste products into the
air, water, or soils;
- limiting or prohibiting construction activities in sensitive areas such
as wetlands or areas of endangered species habitat, or otherwise
constraining how or when construction is conducted;
- requiring remedial action to mitigate pollution from former operations,
or requiring plans and activities to prevent pollution from ongoing
operations; and
- imposing substantial liabilities on us for pollution resulting from our
operations, including, for example, potentially enjoining the operations
of facilities if it were determined that they were not in compliance with
permit terms.
In most instances, the environmental laws and regulations affecting our
operations relate to the potential release of substances or waste products into
the air, water or soils, and include measures to control or prevent the release
of substances or waste products to the environment. Costs of planning,
designing, constructing and operating pipelines, plants, and other facilities
must incorporate compliance with environmental laws and regulation 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 and federally authorized
citizen suits. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of substances or other waste products to the environment.
The following is a discussion of certain environmental and safety concerns that
relate to the midstream natural gas and NGLs industry. It is not intended to
constitute a complete discussion of all applicable federal, state and local laws
and regulations, or specific matters, to which we may be subject.
Our operations are regulated by the Clean Air Act, as amended, and
comparable state laws and regulations. These laws and regulations govern
emissions into the air from our activities, for example in relation to our
processing plants and our compressor stations, and also impose procedural
requirements on how we conduct our operations. Due to the nature or our
business, we have numerous permits related to air emissions issued by state
governments or the United States Environmental Protection Agency ("EPA"). For
example, we have a large number of federal Operating Permits, known as Title V
permits, for our facilities that can impart specific emissions limitations as
well as specific operational practices or administrative requirements with which
we must comply. There are also other state and federal requirements that might
relate to our operations, including the federal Prevention of Significant
Deterioration permitting requirements for major sources of emissions, and
specific New Source Performance Standards or Maximum Achievable Control
Technology ("MACT") Standards issued by the EPA that apply specifically to our
industry or activities. Our failure to comply with these requirements exposes us
to civil enforcement actions from the state agencies and perhaps the EPA,
including monetary penalties, injunctions, conditions or restrictions on
operations, and, potentially, criminal enforcement actions or federally
authorized citizen suits.
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
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
18
<PAGE> 19
potential air regulations, we believe that these changes will not have a
material adverse effect on our business, financial position or results of
operations.
Our operations generate wastes, including some hazardous wastes, that are
subject to the Resource Conservation and Recovery Act ("RCRA"), as amended and
comparable state laws. However, RCRA currently exempts many natural gas
gathering and processing plant wastes from being subject to hazardous waste
requirements. Specifically, RCRA excludes from the definition of hazardous
waste, wastes associated with the exploration, development, or production of
crude oil, natural gas or geothermal energy. Unrecovered petroleum product
wastes, however, may still be regulated under RCRA as solid waste. Moreover,
ordinary industrial wastes, such as paint wastes, waste solvents, laboratory
wastes, and waste compressor oils, may be regulated. Natural gas and NGLs
transported in pipelines also have the potential to generate some hazardous
wastes. Although we believe it is unlikely that the RCRA exemption will be
repealed in the near future, repeal would increase costs for waste disposal and
environmental remediation at our facilities. Past operations are identified from
time to time as having used polychlorinated biphenyls ("PCBs"), for example, in
plant air compressor systems, and when identified we are required to address or
remediate such a system that might contain PCBs in compliance with the Toxic
Substances Control Act, including any contamination that might be associated
with a release from that system.
Our operations could incur liability under the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), also
known as "Superfund," and comparable state laws or other federal laws regardless
of our fault, in connection with the disposal or other release of hazardous
substances or wastes, including those arising out of historical operations
conducted by our predecessors. If we were to incur liability under CERCLA, we
could be subject to joint and several liability for the costs of cleaning up
hazardous substances, for damages to natural resources and for the costs of
certain health studies.
We currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the measurement, gathering,
field compression and processing of natural gas and NGLs. Although we used
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or wastes may have been disposed of or released on or under the
properties owned or leased by us or on or under other locations where such
wastes have been taken for disposal. In addition, some of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed on them may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously disposed
wastes (including waste disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination, whether from prior
owners or operators or other historic activities or spills) or to perform
remedial plugging or pit closure operations to prevent future contamination, in
some instances regardless of fault or the amount of waste we sent to the site.
EPA Region VIII issued a RCRA administrative cleanup order in 1995 with
respect to the operation of the Weld County Waste Disposal, Inc. site near Fort
Lupton Colorado, and in 1997 one of our predecessors was identified along with
other entities as a potentially responsible party for this site. We are not
aware of administrative activity at this site in the last two years. In
addition, we have various ongoing remedial matters related to historical
operations similar to others in the industry, for the reasons 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 responsibility of other entities based upon contractual obligations related
to the assets. In April 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 to 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
19
<PAGE> 20
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.
Our operations can result in discharges of pollutants to waters. The
Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), also known as
the Clean Water Act, and analogous state laws impose restrictions and strict
controls regarding the discharge of pollutants, including NGLs or unpermitted
wastes, into state waters or waters of the United States. The unpermitted
discharge of pollutants such as from spill or leak incidents are prohibited. The
FWPCA and regulations implemented thereunder also prohibit discharges of fill
material and certain other activities in wetlands unless authorized by an
appropriately issued permit. Any unexpected release of NGLs or condensates from
our systems or facilities could result in significant remedial obligations as
well as FWPCA-related fines or penalties.
We make expenditures in connection with environmental matters as part of
our normal operations and capital expenses. For each of 2000 and 2001, we
estimate that our expensed and capital-related costs will be approximately $13
million. It should be noted, however, that stricter laws and regulations, new
interpretations of existing laws and regulations, or new information or
developments could significantly increase our compliance costs and remediation
obligations.
We are subject to inherent environmental and safety risks related to our
handling of natural gas and NGL products and historical industry waste disposal
practices. We cannot assure you that we will not incur material environmental
costs and liabilities. We believe, based on our current knowledge, that we are
generally in substantial compliance with all of our necessary and material
permits, and that we are generally in substantial compliance with applicable
material environmental and safety regulations. We also use contractual measures,
such as the environmental/insurance partnership discussed above, where
appropriate to mitigate environmental claims or losses but, in the event of a
default, we could be exposed to these claims. Insurance provisions and internal
reserves are also used or applied where warranted to help mitigate the effect
from possible environmental costs and liabilities. Based on current information
and taking into account protective mechanisms mentioned here, we do not believe
that compliance with federal, state or local environmental laws and regulations
will have a material adverse effect on our business, financial position or
results of operations. In addition, we believe that the various environmental
activities in which we are presently engaged are not expected to materially
interrupt or diminish our operational ability to gather, process, and transport
natural gas and NGLs. We cannot assure you, however, that future events, such as
changes in existing laws, the promulgation of new laws, or the development or
discovery of new facts or conditions will not cause us to incur significant new
costs.
Our natural gas gathering pipelines and processing plants in Alberta,
Canada operate under permits from and are regulated by Alberta Environment. Our
West Doe natural gas gathering pipeline, which crosses the Alberta/British
Columbia border, is regulated by the National Energy Board in consultation with
the Canadian Environmental Assessment Agency.
EMPLOYEES
As of June 30, 2000, we had approximately 2,550 employees. We are a party
to two collective bargaining agreements which cover an aggregate of
approximately 180 of our employees and are bound to negotiate in good faith
toward collective bargaining agreements with two other collective bargaining
units which cover an aggregate of approximately 80 employees. We believe our
relations with our employees are good.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This registration statement contains 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-
20
<PAGE> 21
looking words, such as "may," "could," "project," "believe," "anticipate,"
"expect," "estimate," "potential," "plan," "forecast" and other similar words.
All statements other than statements of historical facts contained in this
registration statement, 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.
The forward-looking statements in this registration statement 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 our credit ratings for our debt
obligations;
- 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 and demand for our
services;
- weather and other natural phenomena;
- industry changes, including the impact of consolidations, and changes in
competition; and
- 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.
In light of these risks, uncertainties and assumptions, the events
described in the forward-looking statements in this registration statement might
not occur or might occur to a different extent or at a different time than
described in this registration statement. We undertake no obligation to update
or revise our forward-looking statements, whether as a result of new
information, future events or otherwise.
21
<PAGE> 22
ITEM 2. FINANCIAL INFORMATION
PRESENTATION OF FINANCIAL INFORMATION AND OTHER DATA
Duke Energy Field Services, LLC is a new company that holds the combined
North American midstream natural gas businesses of Duke Energy and Phillips.
Because our operations have only recently been combined and these
operations have grown significantly through acquisitions, our historical and pro
forma financial information and operating data may not provide an accurate
indication of:
- what our actual results would have been if the transactions presented on
a pro forma basis had actually been completed as of the dates presented;
or
- what our future results of operations are likely to be.
HISTORICAL FINANCIAL INFORMATION AND OTHER DATA
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 Duke Energy Field
Services, LLC immediately prior to the Combination. Duke Energy Field Services,
LLC and these former subsidiaries of Duke Energy collectively are referred to in
this registration statement as the "Predecessor Company." The historical
financial statements and related financial and other data included in this
registration statement reflect the business of the Predecessor Company. This
historical financial information and other data should be viewed in light of the
following:
- the Combination is reflected as a March 31, 2000 acquisition of the
midstream natural gas business contributed to our company by Phillips in
the Combination;
- the Predecessor Company's acquisition of Union Pacific Fuels is reflected
as a March 31, 1999 acquisition by the Predecessor Company; and
- the historical financial statements of the Predecessor Company do not
include the results of the general partner of TEPPCO.
For your additional information, we have also included the audited
financial statements of:
- the midstream natural gas business of Phillips that was transferred to us
in the Combination; and
- Union Pacific Fuels.
PRO FORMA FINANCIAL AND OTHER INFORMATION
In addition to the historical financial information and other data, this
registration statement includes:
- unaudited pro forma income statements of our company for 1999 and the
three months ended March 31, 2000, each reflecting:
- the Combination;
- the Predecessor Company's acquisition of Union Pacific Fuels;
- the transfer to us of additional midstream natural gas assets
acquired by Duke Energy or Phillips prior to consummation of the
Combination; and
- the transfer to us of the general partner of TEPPCO,
in each case as if the transactions had occurred on January 1, 1999; and
- additional financial and other data giving effect to the Union Pacific
Fuels acquisition and the Combination, as if each had occurred on January
1, 1995.
22
<PAGE> 23
SELECTED HISTORICAL AND PRO FORMA
FINANCIAL AND OTHER DATA
The following table sets forth selected historical financial and other data
for the Predecessor Company. The historical income statement data and cash flow
data for each of the three years ended December 31, 1999 and the historical
balance sheet data as of December 31 in each of those three years have been
derived from the Predecessor Company's audited historical financial statements.
The historical financial information for 1995 and 1996 and the three months
ended March 31, 1999 and 2000 is derived from unaudited financial statements.
The historical data set forth below relates only to the Predecessor Company and
does not reflect the results of operations or financial condition of the
Phillips businesses transferred to us in the Combination. In addition, the
following table sets forth selected pro forma financial and other data, which
reflect the historical results of operations of the Predecessor Company,
adjusted for:
- the acquisition of the midstream natural gas business of Phillips in the
Combination;
- the acquisition of Union Pacific Fuels;
- incurrence of indebtedness to fund the cash distributions to Duke Energy
and Phillips in connection with the Combination as described in
"Management's Discussion and Analysis of Financial Condition and Results
of Operations;"
- the transfer to our company of additional midstream natural gas assets
acquired by Duke Energy prior to consummation of the Combination; and
- the transfer to our company of the general partner of TEPPCO;
as if all had occurred as of January 1, 1999. The data should be read in
conjunction with the financial statements and related notes and other financial
information appearing elsewhere in this registration statement. The pro forma
data set forth below are not necessarily indicative of results that may occur in
the future.
<TABLE>
<CAPTION>
PREDECESSOR COMPANY HISTORICAL PRO FORMA
------------------------------------------------------------- ----------
1995 1996 1997 1998 1999(1)(2) 1999(1)
-------- ---------- ---------- ---------- ----------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C>
ANNUAL INCOME STATEMENT DATA:
Operating revenues:
Sales of natural gas and petroleum
products........................ $752,880 $1,321,111 $1,700,029 $1,469,133 $ 3,310,260 $5,268,927
Transportation, storage and
processing...................... 52,308 70,577 101,803 115,187 148,050 305,653
-------- ---------- ---------- ---------- ----------- ----------
Total operating revenues... 805,188 1,391,688 1,801,832 1,584,320 3,458,310 5,574,580
Costs and expenses:
Natural gas and petroleum
products........................ 601,533 1,070,805 1,468,089 1,338,129 2,965,297 4,554,776
Operating and maintenance......... 65,458 93,838 104,308 113,556 181,392 393,134
Depreciation and amortization..... 37,281 55,500 67,701 75,573 130,788 243,869
General and administrative........ 20,576 43,871 36,023 44,946 73,685 96,210
Net (gain) loss on sale of
assets.......................... (9,029) (2,350) (236) (33,759) 2,377 1,470
-------- ---------- ---------- ---------- ----------- ----------
Total costs and expenses... 715,819 1,261,664 1,675,885 1,538,445 3,353,539 5,289,459
Operating income.................... 89,369 130,024 125,947 45,875 104,771 285,121
Equity in earnings of unconsolidated
affiliates........................ 1,660 2,997 9,784 11,845 22,502 27,338
-------- ---------- ---------- ---------- ----------- ----------
Earnings before interest and tax.... 91,029 133,021 135,731 57,720 127,273 312,459
Interest expense.................... 20,115 12,747 51,113 52,403 52,915 219,546
-------- ---------- ---------- ---------- ----------- ----------
Earnings before income tax.......... 70,914 120,274 84,618 5,317 74,358 92,913
Income tax expense.................. 37,299 35,665 33,380 3,289 31,029 --
-------- ---------- ---------- ---------- ----------- ----------
Net income.......................... $ 33,615 $ 84,609 $ 51,238 $ 2,028 $ 43,329 $ 92,913
======== ========== ========== ========== =========== ==========
</TABLE>
23
<PAGE> 24
<TABLE>
<CAPTION>
PREDECESSOR COMPANY HISTORICAL PRO FORMA
------------------------------------------------------------- ----------
1995 1996 1997 1998 1999(1)(2) 1999(1)
-------- ---------- ---------- ---------- ----------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C>
OTHER DATA:
Cash flow data:
Cash flow from operations......... $ 173,357 $ 40,409 $ 173,136
Cash flow from investing
activities...................... (138,021) (203,625) (1,571,446)
Cash flow from financing
activities...................... (35,061) 162,514 1,398,934
Acquisitions and other capital
expenditures...................... $183,531 $ 524,730 $ 121,978 $ 185,479 $ 1,570,083 $ 429,847
EBITDA(3)........................... $128,310 $ 188,521 $ 203,432 $ 133,293 $ 258,061 $ 556,328
Gas transported and/or processed
(TBtu/d).......................... 1.9 2.9 3.4 3.6 5.1 7.3
NGLs production(MBbl/d)............. 55 79 108 110 192 400
MARKET DATA:
Average NGLs price per gallon(4).... $.29 $.39 $.35 $.26 $.34 $.33
Average natural gas price per
MMBtu(5).......................... $1.64 $2.59 $2.59 $2.11 $2.27 $2.27
BALANCE SHEET DATA (END OF PERIOD):
Total assets........................ $917,831 $1,459,416 $1,649,213 $1,770,838 $ 3,471,835
Long-term debt...................... $101,600 $ 101,600 $ 101,600 $ 101,600 $ 101,600
</TABLE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
---------------------------------------------------
PREDECESSOR COMPANY HISTORICAL PRO FORMA
------------------------------- ----------
1999(6) 2000(6) 2000(6)
----------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
QUARTERLY INCOME STATEMENT DATA:
Operating revenues:
Sales of natural gas and petroleum products....... $ 305,152 $1,415,465 $2,005,449
Transportation, storage and processing............ 29,845 35,746 45,349
----------- ---------- ----------
Total operating revenues................... 334,997 1,451,211 2,050,798
Costs and expenses:
Natural gas and petroleum products................ 272,530 1,278,511 1,703,092
Operating and maintenance......................... 29,096 49,039 99,424
Depreciation and amortization..................... 20,029 38,094 62,583
General and administrative........................ 16,112 29,701 33,952
Net (gain) loss on sale of assets................. (42) 239 151
----------- ---------- ----------
Total costs and expenses................... 337,725 1,395,584 1,899,202
----------- ---------- ----------
Operating income.................................... (2,728) 55,627 151,596
Equity in earnings of unconsolidated affiliates..... 3,286 6,759 9,968
----------- ---------- ----------
Earnings before interest and tax.................... 558 62,386 161,564
Interest expense.................................... 12,445 14,477 54,886
----------- ---------- ----------
Earnings before income tax.......................... (11,887) 47,909 106,678
Income tax expense (benefit)........................ (3,366) (313,991) --
----------- ---------- ----------
Net income (loss)................................... $ (8,521) $ 361,900 $ 106,678
=========== ========== ==========
OTHER DATA:
EBITDA(3)........................................... $ 20,587 $ 100,480 $ 224,147
Gas transported and/or processed (TBtu/d)........... 3.4 6.0 7.9
NGLs production(MBbl/d)............................. 108 231 415
MARKET DATA:
Average NGLs price per gallon(4).................... $ .23 $ .50 $ .50
Average natural gas price per MMBtu(5).............. $ 1.75 $ 2.52 $ 2.52
BALANCE SHEET DATA (END OF PERIOD):
Total assets........................................ $5,625,785
Long-term debt...................................... $ -- $ -- $ --
----------- ---------- ----------
</TABLE>
24
<PAGE> 25
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------ -----------------------
1997 1998 1999(1)(2) 1999(6) 2000(6)
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
HISTORICAL SEGMENT INFORMATION:
Operating revenues:
Natural gas.............................. $1,683,483 $1,497,901 $2,483,197 $ 308,326 $ 899,214
NGLs..................................... 423,680 309,380 1,365,577 72,582 798,816
Intersegment............................. (305,331) (222,961) (390,464) (45,911) (246,819)
---------- ---------- ---------- ---------- ----------
Total operating revenues.......... $1,801,832 $1,584,320 $3,458,310 $ 334,997 $1,451,211
========== ========== ========== ========== ==========
Margin:
Natural gas.............................. $ 334,129 $ 243,787 $ 459,843 $ 61,711 $ 147,856
NGLs..................................... (386) 2,404 33,170 756 24,844
---------- ---------- ---------- ---------- ----------
Total margin...................... $ 333,743 $ 246,191 $ 493,013 $ 62,467 $ 172,700
========== ========== ========== ========== ==========
EBITDA(3):
Natural gas.............................. $ 239,841 $ 175,835 $ 298,698 $ 35,957 $ 105,641
NGLs..................................... (386) 2,404 33,048 742 24,540
Corporate................................ (36,023) (44,946) (73,685) (16,112) (29,701)
---------- ---------- ---------- ---------- ----------
Total EBITDA...................... $ 203,432 $ 133,293 $ 258,061 $ 20,587 $ 100,480
========== ========== ========== ========== ==========
EBIT(3):
Natural gas.............................. $ 174,248 $ 102,365 $ 179,273 $ 16,501 $ 71,416
NGLs..................................... (386) 2,404 23,975 742 21,513
Corporate................................ (38,131) (47,049) (75,975) (16,685) (30,543)
---------- ---------- ---------- ---------- ----------
Total EBIT........................ $ 135,731 $ 57,720 $ 127,273 $ 558 $ 62,386
========== ========== ========== ========== ==========
Total assets:
Natural gas.............................. $1,505,111 $2,754,447 $4,726,148
NGLs..................................... 5,137 225,702 191,337
Corporate................................ 260,590 491,686 708,300
---------- ---------- ----------
Total assets...................... $1,770,838 $3,471,835 $5,625,785
========== ========== ==========
</TABLE>
---------------
(1) Includes $34.0 million of hedging losses recorded in total operating
revenues. Duke Energy commenced risk management activities associated with
its midstream natural gas business at the end of 1998. Activity for periods
prior to 1999 was not significant.
(2) 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.
(3) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense, less
interest income. EBIT consists of income from continuing operations before
interest expense and income tax expense, less interest income. 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.
(4) 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.
(5) Based on the NYMEX Henry Hub prices for the periods indicated.
(6) Includes $4.0 million of hedging gain and $46.7 million of hedging loss for
the three months ended March 31, 1999 and 2000, respectively.
25
<PAGE> 26
ADDITIONAL FINANCIAL AND OTHER DATA
The following table sets forth additional financial and other data of our
company. The additional financial and other data set forth in the table below
give effect to the Combination and the transfer to our company of additional
midstream natural gas assets acquired by Duke Energy or Phillips prior to
consummation of the Combination, which were completed on March 31, 2000 and to
the acquisition of Union Pacific Fuels, which occurred on March 31, 1999, as if
each occurred on January 1, 1995.
The additional financial and other data set forth in the table below should
not be considered to be indicative of:
- actual results that would have been realized had the Combination and the
acquisition of Union Pacific Fuels actually occurred on January 1, 1995;
or
- results of our future operations.
The data should be read in conjunction with the financial statements and related
notes and other financial information appearing elsewhere in this registration
statement.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
-------------------------------------------------------------- ---------------------
1995 1996 1997 1998 1999(1) 1999(2) 2000(2)
---------- ---------- ---------- ---------- ---------- -------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Total operating revenues... $2,413,871 $3,998,273 $4,769,072 $4,302,697 $5,574,580 $959,028 $2,050,798
Costs of natural gas and
petroleum products....... 1,729,278 2,976,059 3,798,465 3,527,533 4,554,776 761,753 1,703,092
OTHER DATA:
Gas transported and/or
processed (TBtu/d)....... 5.4 6.5 7.5 7.3 7.3 7.0 7.9
NGLs production(MBbl/d).... 277 313 358 373 400 382 415
MARKET DATA:
Average NGLs (price per
gallon)(3)............... $.28 $.38 $.34 $.25 $.33 $.22 $.50
Average natural gas (price
per MMBtu)(4)............ $1.64 $2.59 $2.59 $2.11 $2.27 $1.75 $2.52
</TABLE>
---------------
(1) Includes $34.0 million of losses from risk management activities recorded in
total operating revenues. Duke Energy commenced risk management activities
for its midstream natural gas business at the end of 1998. Activity for
periods prior to 1999 was not significant.
(2) Includes $4.0 million of hedging gain and $46.7 million of hedging loss for
the three months ended March 31, 1999 and 2000, respectively.
(3) Based on index prices from the Mont Belvieu and Conway market hubs that are
weighted by our component mix and location mix for the periods indicated.
(4) Based on the NYMEX Henry Hub prices for the periods indicated.
26
<PAGE> 27
The following table presents certain summary historical financial data of
the Predecessor Company, the midstream natural gas business of Phillips'
transferred to our company in connection with the Combination and Union Pacific
Fuels acquired by the Predecessor Company on March 31, 1999.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------------------
1995 1996 1997 1998 1999
--------- ---------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PREDECESSOR COMPANY
Gross Margin................................. $ 203,655 $ 320,883 $ 333,743 $ 246,191 $ 493,013
Operating, maintenance and general and
administrative............................. 86,034 137,709 140,331 158,502 255,077
Other income................................. 10,689 5,347 10,020 45,604 20,125
--------- ---------- --------- --------- ---------
EBITDA(1).................................... $ 128,310 $ 188,521 $ 203,432 $ 133,293 $ 258,061
========= ========== ========= ========= =========
PHILLIPS GAS COMPANY
Gross Margin................................. $ 340,751 $ 486,534 $ 444,727 $ 355,479 $ 440,547
Operating, maintenance and general and
administrative............................. 254,973 186,499 205,375 199,862 192,424
Other income................................. 1,443 4,527 2,858 10,665 1,955
--------- ---------- --------- --------- ---------
EBITDA(1).................................... $ 87,221 $ 304,562 $ 242,210 $ 166,282 $ 250,078
========= ========== ========= ========= =========
UNION PACIFIC FUELS
Gross Margin................................. $ 140,187 $ 214,797 $ 192,137 $ 173,494 $ 45,044
Operating, maintenance and general and
administrative............................. 54,655 65,538 77,621 102,626 29,443
Other income................................. 15,507 24,207 19,535 17,785 4,821
--------- ---------- --------- --------- ---------
EBITDA(1).................................... $ 101,039 $ 173,466 $ 134,051 $ 88,653 $ 20,422
========= ========== ========= ========= =========
</TABLE>
---------------
(1) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense, less
interest income. EBITDA is not a measurement presented in accordance with
generally accepted accounting principles. You should not consider it 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.
27
<PAGE> 28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion details the material factors that affected our
historical and pro forma financial condition and results of operations in 1997,
1998 and 1999 and the three months ended March 31, 1999 and 2000. This
discussion should be read in conjunction with "Selected Historical and Pro Forma
Combined Financial and Other Data," "Additional Financial and Other Data" and
the historical and pro forma financial statements, and, in each case, the notes
related thereto, included elsewhere in this registration statement.
Unless the context otherwise requires, the discussion of our business
contained in this section relates to the Predecessor Company on an historical
basis without giving 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 and 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 1999, approximately 72% of the
Predecessor Company's operating revenues and approximately 93% of the
Predecessor 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 1999, approximately 28% of the
Predecessor Company's operating revenues and approximately 7% of the
Predecessor 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.
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 is 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 January 2000, after giving effect to
the Combination, approximately 28% 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 generally is 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.
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<PAGE> 29
The following chart sets forth financial data for the Predecessor Company
and the weighted average price of NGLs for each of the five years ended December
31, 1999 and demonstrates the relationship of our EBITDA to NGL prices. The
chart below should not be viewed as indicating that the level of NGL prices is
the only factor affecting our results of operations. In addition to NGL prices,
our results of operations reflected in the chart below were primarily affected
by:
- fluctuations in raw natural gas volumes processed, including increases
resulting from our acquisitions and additions;
- the Predecessor Company's historical risk management activities; and
- gain/(loss) on the sale of assets.
[GRAPH]
Note: The weighted average NGL prices set forth in the chart above are
based on index prices from the Mont Belvieu and Conway market hubs
that are weighted by our component and location mix for the years
indicated.
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 the first quarter of 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 $.50 per gallon. 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 number of actively drilling rigs in North America has increased by
approximately 57% from approximately
29
<PAGE> 30
745 in June 1999 to more than 1,165 in June 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. In December 1999, after giving effect to the
Combination, approximately 57% of our gross margin was generated from
percentage-of-proceeds or percentage-of-index contracts.
- 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. In
December 1999, after giving effect to the Combination, approximately 25%
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. In December 1999, after giving effect to the Combination,
approximately 15% 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, while
retaining our exposure to changes in NGL prices.
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 combined company's portfolio of supply contracts in 1999,
and excluding the effect of our commodities risk management program, an increase
of $.01 per gallon in the price of NGLs and $.10 per million Btus in the average
price of natural gas throughout such period would have resulted in changes in
pre-tax net income of approximately $24 million and ($1) million, respectively.
See "-- Quantitative and Qualitative Disclosure About Market Risks."
30
<PAGE> 31
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 has been directed by Duke Energy's centralized
program for controlling, managing and coordinating its management of risks, also
has affected our results of operations, particularly in 1999 and the first
quarter of 2000. Our 1999 and first quarter 2000 results of operations include
hedging losses of $34.0 million and $46.7 million, respectively. After the
Combination, we will direct our risk management activities independently of Duke
Energy, with goals, policies and procedures that are different from those of
Duke Energy. See " -- Quantitative and Qualitative Disclosure about Market
Risks."
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.
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,
Phillips transferred all of its interest in its subsidiaries that conducted its
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 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 future integration opportunities. In addition, 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 indirectly
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 is accounted for as a purchase of the
Phillips midstream natural gas business.
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 purchase price
allocation associated with the Phillips assets is preliminary. Currently there
are no pre-acquisition contingent liabilities reflected in the purchase price
allocation. The final purchase price allocation is subject to adjustment pending
gathering of additional information regarding certain pre-acquisition contingent
liabilities and obtaining appraisals. The effect of any pre-acquisition
contingencies is not expected to have a material effect on our operating
results, liquidity or financial condition.
COMBINED RESULTS OF OPERATIONS
The following is a discussion of the combined operating revenues and cost
of sales of our company giving effect to the Combination, the transfer to our
company of the midstream natural gas businesses acquired by Duke Energy and
Phillips prior to the consummation of the Combination and the acquisition of
Union Pacific Fuels as if each transaction occurred on January 1, 1995.
This discussion should be read in conjunction with the historical and pro
forma financial statements and related notes and other financial information
appearing elsewhere in this registration statement. The data on which this
discussion is based should not be considered indicative of:
31
<PAGE> 32
- the actual results that would have been realized had the Combination and
the acquisition of Union Pacific Fuels actually occurred on January 1,
1995; or
- the results of our future operations.
THREE MONTHS ENDED MARCH 31, 2000 COMPARED WITH THREE MONTHS ENDED MARCH
31, 1999
Operating Revenues. Operating revenues increased $1,091.8 million, or 114%,
from $959.0 million to $2,050.8 million. Of this increase, approximately $1,000
million was due to increases in commodity prices, as weighted average NGL
prices, based on our component product mix, were approximately $.28 per gallon
higher and natural gas prices were approximately $.77 per million Btus higher.
Acquisitions and plant expansions contributed approximately $90 million to the
revenue increase. NGL production during the first quarter increased 33,000
barrels per day, or 9%, from 382,000 barrels per day to 415,000 barrels per day,
and natural gas transported and/or processed increased 0.9 trillion Btus per
day, or 13%, from 7.0 trillion Btus per day to 7.9 trillion Btus per day.
Included in first quarter 2000 operating revenues is a $46.7 million loss on
hedging activity compared to a $4.0 million gain in first quarter 1999.
Cost of Sales. Costs of natural gas and petroleum products increased $941.3
million, or 124%, from $761.8 million to $1,703.1 million. This increase was
primarily due to the interaction of our gas and NGL purchase contracts with
higher commodity prices. Higher natural gas and NGLs throughput associated with
our acquisitions and plant expansions also increased product purchase costs.
1999 COMPARED WITH 1998
Operating Revenues. Operating revenues increased $1,271.9 million, or 30%,
from $4,302.7 million to $5,574.6 million. Of this increase, approximately
$1,100 million was due to increases in commodity prices, as 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.
Our acquisitions and plant expansions also contributed to this increase. NGLs
production during 1999 increased 27,000 barrels per day, or 7%, from 373,000
barrels per day to 400,000 barrels per day, and natural gas transported and/or
processed remained essentially unchanged at 7.3 trillion Btus per day. The
recovery of commodity prices during the last three quarters of 1999 encouraged
exploration and production activity, which positively affected existing
throughput volumes. Included in 1999 operating revenues is approximately $34.0
million of loss on hedging activity. There were no significant hedging
activities in 1998. See "-- Quantitative and Qualitative Disclosure About Market
Risks."
Cost of Sales. Costs of natural gas and petroleum products increased
$1,027.3 million, or 29%, from $3,527.5 million to $4,554.8 million. This
increase primarily was due to the interaction of our gas and NGL purchase
contracts with higher commodity prices.
1998 COMPARED WITH 1997
Operating Revenues. Operating revenues decreased $466.4 million, or 10%,
from $4,769.1 million to $4,302.7 million. Lower commodity prices resulted in an
approximately $800 million reduction of operating revenues, as weighted average
NGL prices, based on our component product mix, were approximately $.09 per
gallon lower and natural gas prices were unchanged. Partially offsetting this
decrease was approximately $22 million additional revenues attributable to our
fourth quarter 1997 acquisition of Highlands Gas Partners and approximately $300
million additional revenues attributable to our increased NGL trading and
marketing activities. Natural gas transported and/or processed decreased .2
trillion Btus per day, or 3%, from 7.5 trillion Btus per day to 7.3 trillion
Btus per day. This decrease was primarily the result of reduced exploration and
production activity caused by depressed commodity prices. This decrease was
offset by an increase in NGLs production of 15,000 barrels per day, or 4%, from
358,000 barrels per day to 373,000 barrels per day. NGLs production growth
primarily was the result of the Highlands Gas Partners acquisition and the
restart of a processing facility in the fourth quarter of 1997.
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<PAGE> 33
Cost of Sales. Cost of natural gas and petroleum products decreased $271.0
million, or 7%, from $3,798.5 million to $3,527.5 million. This decrease
primarily was due to declining NGL prices. Increased NGL trading and marketing
activity partially offset this decrease.
QUARTERLY COMBINED RESULTS
The following table sets forth unaudited combined financial and operating
data for our company on a quarterly basis for each of 1998, 1999 and the three
months ended March 31, 2000.
<TABLE>
<CAPTION>
COMBINED
---------------------------------------------------------------------------------------
1998 1999 2000
------------------------------------- ------------------------------------- -------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total operating
revenues................. $1,113 $1,143 $1,095 $952 $959 $1,158 $1,597 $1,861 $2,051
Costs of natural gas and
petroleum products..... 902 951 900 775 762 923 1,313 1,557 1,703
Average NGL price (per
gallon)(1)............. .28 .26 .20 .22 .22 .30 .39 .41 .50
</TABLE>
---------------
(1) 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.
HISTORICAL RESULTS OF OPERATIONS
The following is a discussion of the historical results of operations of
the Predecessor Company.
THREE MONTHS ENDED MARCH 31, 2000 COMPARED WITH THREE MONTHS ENDED MARCH 31,
1999
Operating Revenues. Operating revenues increased $1,116.2 million, or 333%,
from $335.0 million to $1,451.2 million. Operating revenues from the sale of
natural gas and petroleum products accounted for $1,415.5 million of the total
and $1,110.3 million of the increase. Of this increase, approximately $425
million is 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 the first quarter increased 123,600 barrels per day, or
115%, from 107,600 barrels per day to 231,200 barrels per day, and natural gas
transported and/or processed increased 2.6 trillion Btus per day, or 76%, from
3.4 trillion Btus per day to 6.0 trillion Btus per day. Of the 123,600 barrels
per day increase, the Union Pacific Fuels acquisition contributed 100,600
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. Of the 2.6 trillion Btus per day
increase, the Union Pacific Fuels acquisition contributed 2.0 trillion Btus per
day, with the combination of other acquisitions, plant expansions and
completions accounting for the balance of the increase.
Commodity prices also contributed to higher revenues. Weighted average NGL
prices, based on our component product mix, were approximately $.27 per gallon
higher and natural gas prices were approximately $.77 per million Btus higher
for the first quarter. These price increases yielded average prices of $.50 per
gallon and $2.52 per million Btus, respectively, as compared with $.23 per
gallon and $1.75 per million Btus for the first quarter of 1999. Revenues
associated with gathering, transportation, storage, processing fees and other
increased $5.9 million, or 20%, from $29.8 million to $35.7 million, mainly as a
result of the Union Pacific Fuels acquisition. A $46.7 million hedging loss in
the first quarter of 2000 offset total operating revenue increases. See
"-- Quantitative and Qualitative Disclosure About Market Risks."
Costs and Expenses. Costs of natural gas and petroleum products increased
$1,006 million, or 369%, from $272.5 million to $1,278.5 million. This increase
was due to the Union Pacific Fuels acquisition (approximately $340 million), the
interaction of our natural gas and NGL purchase contracts with higher commodity
prices and increased trading and marketing activity.
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<PAGE> 34
Operating and maintenance expenses increased $19.9 million, or 68%, from
$29.1 million to $49.0 million. Of this increase, approximately $13 million was
due to the Union Pacific Fuels acquisition. General and administrative expenses
increased $13.6 million, or 84%, from $16.1 million to $29.7 million. Of this
increase, $5.1 million was due to increased allocated corporate overhead from
our parent, Duke Energy. The remainder was associated with increased activity
resulting from the Union Pacific Fuels acquisition and increased fiscal year
2000 incentive compensation accruals.
Depreciation and amortization increased $18.1 million, or 91%, from $20
million to $38.1 million. Of this increase, $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
$3.5 million, or 106%, from $3.3 million to $6.8 million. This increase was
largely due to interests in joint ventures and partnerships acquired from Union
Pacific Fuels.
Interest. Interest expense increased $2.1 million, or 17%, from $12.4
million to $14.5 million. This increase is primarily related to interest on
notes due to Duke Energy.
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, the Predecessor Company's existing net deferred tax
liability ($333 million) was eliminated with a corresponding income tax benefit
recorded.
Net Income. Net income increased $370.4 million from a loss of $8.5 million
to $361.9 million. This increase was largely the result of tax benefit
recognition discussed above and the acquisition of Union Pacific Fuels and
higher average NGL prices. The benefit of higher NGL prices was partially offset
by higher natural gas prices. A $46.7 million pre-tax loss from hedging
activities experienced during the first quarter of 2000 partially offset the
increase.
EBITDA. In addition to the GAAP measures described above, we also use the
non-GAAP measure of EBITDA. EBITDA is a measure used to provide information
regarding our ability to cover fixed charges such as interest, taxes, dividends
and capital expenditures. In addition, EBITDA provides a comparable measure to
evaluate our performance relative to that of our competitors by eliminating the
capitalization structure and depreciation charges, which may vary significantly
within our industry. Although the GAAP financial statement measure of net income
or loss, in total and by segment, is indicative of our profitability, net income
does not necessarily reflect our ability to fund our fixed charges on a periodic
basis. We therefore use GAAP and non-GAAP measures in evaluating our overall
performance as well as that of our related segments. In addition, we use both
types of measures to evaluate our performance relative to other companies within
our industry.
EBITDA for the natural gas gathering, processing, transportation and
storage segment increased $69.6 million from $36.0 million to $105.6 million. Of
this increase, approximately $56 million was due to the acquisition of Union
Pacific Fuels and approximately $60 million was due to a $.27 per gallon
increase in average NGL prices. Additional increases were attributable to the
combination of our Wilcox plant expansion, completion of our Mobile Bay plant
and the acquisition of Koch's South Texas assets. These benefits were offset by
a $50.7 million decrease from hedging activities ($46.7 million loss in 2000
compared to a $4.0 million gain in 1999) and approximately $6 million due to a
$.77 per million Btu increase in natural gas prices.
EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $23.8 million from $.7 million to $24.5 million 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
34
<PAGE> 35
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 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
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<PAGE> 36
$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.
1998 COMPARED WITH 1997
Operating Revenues. Operating revenues decreased $217.5 million, or 12%,
from $1,801.8 million to $1,584.3 million. Operating revenues from the sale of
natural gas and petroleum products decreased $230.9 million, or 14%, from
$1,700.0 million to $1,469.1 million. This decrease was largely due to commodity
prices, as weighted average NGLs prices, based on our component product mix,
were approximately $.09 per gallon lower and natural gas prices were
approximately $.48 per MMBtu lower for 1998, yielding prices of $.26 and $2.11,
respectively, as compared with $.35 and $2.59 in 1997. This NGL price decline
was partially offset by an increase in NGL production during 1998 of 2,000
barrels per day, or 2%, from 108,000 barrels per day to 110,000 barrels per day,
and by an increase in natural gas gathered, transported and/or processed of .2
trillion Btus per day, or 6%, from 3.4 trillion Btus per day to 3.6 trillion
Btus per day, due to increased production on existing facilities. Revenues
associated with gathering, transportation, storage, processing fees and other
increased $13.4 million, or 13%, from $101.8 million to $115.2 million. This
increase was principally the result of increased volumes.
Costs and Expenses. Costs of natural gas and petroleum products decreased
$130.0 million, or 9%, from $1,468.1 million to $1,338.1 million. This decrease
was primarily due to declining NGL prices. The NGL price decline was partially
offset by increases in system throughput volumes.
Operating and maintenance expenses increased $9.3 million, or 9%, from
$104.3 million to $113.6 million. This increase was primarily due to higher
property tax accruals associated with property additions and other inflationary
factors. General and administrative expenses increased $8.9 million, or 25%,
from $36.0 million to $44.9 million. This increase was due primarily to an
increase in the incentive bonus accrual and internal growth.
Depreciation and amortization increased $7.9 million, or 12%, from $67.7
million to $75.6 million. This increase was primarily due to ongoing capital
expenditures for well connections, facility maintenance/enhancements and
acquisitions.
Sales of Assets. Net (gain) loss on sales of assets increased $33.6
million, from a $.2 million gain to a $33.8 million gain from 1997 to 1998. This
increase was primarily due to a $38.0 million gain recognized in March 1998 on
the sale of the Weld County fractionators.
Equity Earnings. Equity earnings of unconsolidated affiliates increased
$2.0 million, or 20%, from $9.8 million to $11.8 million. This increase was
largely due to increased earnings from Dauphin Island Gathering and Main Pass
Oil in the offshore region.
Interest. Interest expense increased $1.3 million, or 3%, from $51.1
million to $52.4 million. Interest expense reflects interest on notes due to
affiliated companies.
Net Income. Net income decreased $49.2 million, or 96%, from $51.2 million
to $2.0 million. This decrease was largely the result of substantially lower
commodity prices. A pre-tax gain of approximately $38.0 million recognized on
the sale of our Weld County fractionators in March 1998 partially offset the
impact of the sharp NGL price decline.
EBITDA. EBITDA for the natural gas gathering, processing, transportation
and storage segment decreased $64.0 million from $239.8 million to $175.8
million. Of the decrease, approximately $80 million was due to $.09 per gallon
lower NGL prices and approximately $18 million was due to increased operating
and general and administrative expenses resulting from higher property tax
accruals associated with property additions, an increase in the incentive bonus
accrual and internal growth. These decreases were partially offset by a $38.0
million gain recognized in March 1998 on the sale of the Weld County
fractionators.
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<PAGE> 37
EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $2.8 million from $(.4) million to $2.4 million due to
increased trading and marketing activity.
ENVIRONMENTAL CONSIDERATIONS
Environmental expenditures are expensed or capitalized as appropriate,
depending upon the future economic benefit. Historically these expenditures have
been between $5 million and $15 million annually except for those environmental
liabilities identified with the acquisition of Union Pacific Fuels of
approximately $63 million. The Union Pacific Fuels environmental liabilities
associated with soil and groundwater contamination were transferred to a third
party at a cost of approximately $48 million.
The outlook for environmental spending, both capitalized and expensed, is
not expected to change materially from historical levels of $5 to $15 million
annually.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY PRIOR TO THE COMBINATION
The Predecessor Company's capital investments and acquisitions have been
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. In 1999, the Predecessor Company had notes to and advances from Duke
Energy which were terminated in connection with the Combination.
FINANCING TRANSACTIONS IN CONNECTION WITH THE COMBINATION
In connection with the Combination, all advances from Duke Energy were
capitalized to equity and all advances from Phillips were capitalized.
On March 31, 2000, we entered into a $2.8 billion credit facility with
several financial institutions. The credit facility will be used as the
liquidity backstop to support a commercial paper program. On April 3, 2000 we
borrowed approximately $2.8 billion in the commercial paper market to fund the
one-time cash distributions (including reimbursements for acquisitions) of
approximately $1.5 billion to Duke Energy and approximately $1.2 billion to
Phillips and to cover working capital requirements. At June 30, 2000 we had $2.6
billion in outstanding commercial paper, with maturities ranging from one day to
60 days and annual interest rates ranging from 6.71% and 7.20%. At no time will
the amount of our outstanding commercial paper exceed the available amount under
the credit facility. The credit facility matures on March 30, 2001 and
borrowings bear interest at a rate equal to, at our option, either (1) LIBOR
plus .50% per year for the first 90 days following the closing of the credit
facility and LIBOR plus .625% per year thereafter or (2) the higher of (a) the
Bank of America prime rate and (b) the Federal Funds rate plus .50% per year.
The amount available under the bank credit facility and corresponding
commercial paper program will be reduced by the amount, if any, of long-term
debt we may issue, but in no event will the credit facility be reduced to below
$1.0 billion. In the future, our debt levels will vary depending on our
liquidity needs, capital expenditures and cash flow.
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 credit facilities, 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.
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<PAGE> 38
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
repairs and maintenance of our existing facilities. Our capital expenditure
budget for well connections and repair and maintenance of our existing
facilities in 2000 is approximately $175 million, of which approximately $25
million was spent in the three months ended March 31, 2000.
On March 31, 2000, we acquired gathering and processing assets located in
central Oklahoma from Conoco and Mitchell Energy. We paid cash of $99.5 million
and exchanged its interest in certain gathering and marketing joint ventures
located in southeast Texas having a total fair value of approximately $42
million as consideration for these assets.
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.
CASH FLOWS
Net cash provided by operating activities for the Predecessor Company for
the three months ended March 31, 2000 improved to $184.8 million from $24.4
million for the same period in 1999, primarily due to higher commodity prices
and acquisitions. Net cash used in investing activities by the Predecessor
Company was $111.4 million for the three months ended March 31, 2000 compared to
$1,458.2 million for the same period in 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.
Net cash provided by operating activities for the Predecessor Company in
1999 improved to $173.1 million from $40.4 million in 1998, primarily due to
higher commodity prices and acquisitions. Net cash used in investing activities
by the Predecessor Company was $1,571.4 million for 1999 compared to $203.6
million for 1998, of which $1,456.5 million was used for acquisitions and the
remainder was used principally for capital expenditures. 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.
Net cash provided by operating activities for the Predecessor Company was
$40.4 million for 1998 compared to $173.4 million for 1997. This decrease was
primarily due to the reduction of trade accounts payable to producers for the
purchase of raw natural gas at purchase prices lower than those in 1997. Net
cash used in investing activities by the Predecessor Company in 1998 increased
to $203.6 million from $138.0 million in 1997. In 1998, $185.5 million was used
for capital expenditures and $84.9 million was used for investments in
affiliates. The net cash used in investing activities was provided by operating
activities and advances from Duke Energy.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
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 Predecessor Company's portfolio of
supply contracts in 1999, 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
throughout 1999 would have resulted in changes in pre-tax net income of
approximately $(15) million and $5 million, respectively. Based upon the
combined company's portfolio of supply contracts in 1999, and excluding the
effects of our commodities risk management program, similar
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<PAGE> 39
commodities price changes in 1999 would have resulted in changes in pre-tax net
income of approximately $(24) million and $1 million, respectively.
Commodity derivatives such as futures and swaps 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.
Natural gas and crude oil futures, which are used to hedge NGLs 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.
Historically, the Predecessor Company's commodity price risk was managed by
Duke Energy's centralized program for controlling, managing and coordinating its
risk management activities. Under this program, the Predecessor Company used
futures and swaps to manage margins on offsetting fixed-price purchase or sale
commitments for physical quantities of natural gas and NGLs. Historically,
futures and swaps conducted through Duke Energy were handled through Duke Energy
Trading and Marketing, LLC, a partnership in which Duke Energy owns a 60%
interest. Under this arrangement, the Predecessor Company did not experience
margin requirements.
At December 31, 1998 and 1999 the Predecessor Company (through Duke Energy)
had outstanding futures and swaps for an absolute notional contract quantity of
10.92 and 7.8 Bcf of natural gas and an absolute notional contract quantity of
59,000 and 32,764,000 barrels of crude oil, respectively, both of which were
intended to offset the risk of price fluctuations under fixed-price commitments
for delivering and purchasing natural gas and NGLs, respectively. The gains,
losses and costs related to those financial instruments that qualify as a hedge
are not recognized until the underlying physical transaction occurs. At December
31, 1998 and 1999, the Predecessor Company had current unrecognized net gains
(losses) of $1.8 million and $(63.5) million, respectively, related to commodity
instruments. All unrecognized gains and losses at March 31, 2000, the date of
the Combination, remain with Duke Energy and will not have an impact on our
company's future earnings.
Losses relating to hedging with commodity derivatives included in the
Predecessor Company's statement of income equaled $34.0 million for 1999. There
were no corresponding losses in 1997 or 1998. For the three months ended March
31, 1999 and 2000, the Predecessor Company recorded a hedging gain of $4.0
million and a hedging loss of $46.7 million, respectively.
After the Combination, we began directing our risk management activities
independently of Duke Energy.
We use commodity-based derivative contracts to reduce the risk in our
overall earnings and cash flow with the primary goals of:
- maintaining minimum cash flow to fund debt service, dividends, and
maintenance type capital projects;
- avoiding disruption of our growth capital and value creation process; and
- retaining a high percentage of the potential upside relating to commodity
price increases.
We implemented a risk management policy that provides guidelines for
entering into contractual arrangements to manage our commodity price exposure.
Our risk management committee has ongoing responsibility for the content of this
policy and has principal oversight responsibility for compliance with the policy
framework by ensuring proper procedures and controls are in place.
In general, we seek to provide downside protection to our business
activities while retaining most of the upside potential by using floors and
other similar hedging structures. These structures will typically require the
payment of a premium to protect the downside while retaining exposure to the
upside. Historically, NGLs and related commodity products have shown a mean
reverting tendency to long term average prices, which implies
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<PAGE> 40
that supply and demand for products balance over cycles. Therefore, we may
choose to forego price upside in favor of a known, hedged cash flow position as
prices rise significantly above historical levels and depending upon existing
market drivers.
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.
As of March 31, 2000, the existing commodity positions under the Duke
Energy centralized program were transferred to Duke Energy. In establishing its
initial independent commodity risk management position on April 1, 2000, the
Company acquired a portion of Duke Energy's existing commodity derivatives held
for non-trading purposes. The absolute notional contract quantity of the
positions acquired was 4,607,000 barrels of crude oil. Such positions were
acquired at market value.
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 June 30, 2000, we had approximately $2.6 billion 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. Assuming none of
our outstanding commercial paper is refinanced with long-term fixed rate debt,
an increase of .5% in interest rates would result in an increase in annual
interest expense of approximately $13.0 million.
FOREIGN CURRENCY RISK
Currently we have no material foreign currency exposure.
ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). SFAS 133 establishes standards for
derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If certain conditions are met, a derivative may be
specifically designated as:
- a hedge of the exposure to changes in the fair value of a recognized
asset or liability or an unrecognized firm commitment;
- a hedge of the exposure to variable cash flows of a forecasted
transaction; or
- a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale
security, or a foreign-currency-denominated forecasted transaction.
The accounting for changes in the fair value of a derivative (gains and
losses) depends on the intended use of the derivative and the resulting
designation. We are required to adopt SFAS 133 on January 1, 2001. We have not
completed the process of evaluating the impact that will result from adopting
SFAS 133.
ITEM 3. PROPERTIES
For information regarding our raw natural gas gathering and processing
properties, see "Item 1. Business -- Natural Gas Gathering, Processing,
Transportation, Marketing and Storage -- Regions of Operations," which is
incorporated into this Item 3 by reference.
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<PAGE> 41
For information regarding our NGL operations properties, see "Item 1.
Business -- Natural Gas Liquids Transportation, Fractionation and
Marketing -- Overview," which is incorporated into this Item 3 by reference.
For information regarding the properties owned by TEPPCO, see "Item 1.
Business -- TEPPCO," which is incorporated into this Item 3 by reference.
ITEM 4. 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;
- our Chief Executive Officer and each of our next five most highly
compensated executive officers;
- each director; and
- all directors and executive officers as a group.
<TABLE>
<CAPTION>
NAME OF BENEFICIAL OWNERS BENEFICIAL OWNERSHIP
------------------------- --------------------
<S> <C>
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.......................................... --
David D. Frederick.......................................... --
Robert F. Martinovich....................................... --
William W. Slaughter........................................ --
Martha B. Wyrsch............................................ --
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 (12
persons)(1)(2)............................................ 100.0%
</TABLE>
---------------
(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.
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<PAGE> 42
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS
The following table provides information regarding our directors and
executive officers:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Jim W. Mogg........................... 51 Director and Chairman of the Board,
President and Chief Executive
Officer
Michael J. Panatier................... 51 Vice Chairman of the Board
Mark A. Borer......................... 45 Senior Vice President, Southern Region
Michael J. Bradley.................... 45 Senior Vice President, Northern Region
David D. Frederick.................... 40 Senior Vice President and Chief
Financial Officer
Robert F. Martinovich................. 42 Senior Vice President, Western Region
William W. Slaughter.................. 52 Executive Vice President
Martha B. Wyrsch...................... 42 Senior Vice President, General Counsel
and Secretary
Fred J. Fowler........................ 54 Director
John E. Lowe.......................... 41 Director
J. J. Mulva........................... 53 Director
Richard B. Priory..................... 53 Director
</TABLE>
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 a director
of the general partner of TEPPCO. Mr. Mogg has 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 Region 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 Region 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.
David D. Frederick is Senior Vice President and Chief Financial Officer of
our company. Mr. Frederick held the same position with the Predecessor Company
from 1998 until the Combination. From 1996 until 1998, Mr. Frederick served as
Vice President and Controller of Panhandle Eastern Pipe Line Company and
Trunkline Gas Company. From 1993 until 1996, Mr. Frederick served as Controller
of Panhandle Eastern Pipe Line Company. Mr. Frederick has been in the energy
industry since 1988.
Robert F. Martinovich is Senior Vice President, Western Region 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 for the Oklahoma Region for GPM Gas
Corporation, and from 1994 until 1996, he was Business Development Manager for
GPM Gas Services Company. 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
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<PAGE> 43
for Duke Energy. From 1994 until 1997, Mr. Slaughter served as Vice President of
Corporate Strategic Planning for Pan Energy and President of Pan Energy
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 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 served K N Energy,
Inc. in a variety of positions from 1991 to 1996, including Assistant General
Counsel, Senior Counsel and Assistant Secretary. 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
Planning and Strategic Transactions of Phillips Petroleum Company, and has held
that position since 2000. 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 and Chief
Executive Officer of Phillips Petroleum Company and has held these positions
since 1999. 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.
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<PAGE> 44
ITEM 6. EXECUTIVE COMPENSATION
The following table sets forth compensation information for the year ended
December 31, 1999 for the Chief Executive Officer and each of our next five most
highly compensated executive officers. These six individuals are referred to in
this registration statement as the "Named Executive Officers."
<TABLE>
<CAPTION>
ANNUAL COMPENSATION LONG-TERM COMPENSATION
-------------------------------- ------------------------------------
OTHER RESTRICTED SECURITIES
ANNUAL STOCK UNDERLYING LTIP ALL OTHER
SALARY BONUS COMPENSATION AWARDS STOCK OPTIONS PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION ($) ($) ($)(4) ($) (#) ($) ($)(12)
--------------------------- ------- ------- ------------ ---------- ------------- ------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Jim W. Mogg(1)............ 256,883 104,019 19,426 947,250(5) 41,300(10) 51,964 87,335
Chairman of the Board,
President and Chief
Executive Officer
Michael J. Panatier(2).... 333,000 351,445 -- 82,971(6) 24,200(11) -- 15,266
Vice Chairman of the
Board
David D. Frederick(1)..... 163,542 56,683 43 257,025(7) 15,100(10) 19,262 [173,954]
Senior Vice President and
Chief Financial Officer
Mark A. Borer(1)(3)....... 139,604 49,187 -- 167,063(8) 16,800(10) -- 241,959
Senior Vice President,
Southern Region
Michael J. Bradley(1)..... 192,317 68,200 3,613 296,138(9) 17,200(10) 19,503 253,687
Senior Vice President,
Northern Region
Robert F. Martinovich(2)... 169,740 107,749 -- -- 8,400(11) -- 12,305
Senior Vice President,
Western Region
</TABLE>
---------------
(1) Prior to the Combination all compensation paid to Messrs. Mogg, Frederick,
Borer and Bradley was paid by Duke Energy and was attributable to services
provided to the Predecessor Company.
(2) Prior to the Combination all compensation paid to Messrs. Panatier and
Martinovich was paid by Phillips.
(3) Mr. Borer joined the Predecessor Company in April 1999. Amounts shown
relate to the period from April 1999 to December 31, 1999.
(4) Represents payment of taxes owed by Mr. Mogg, Mr. Frederick and Mr.
Bradley. 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.
(5) At December 31, 1999, Mr. Mogg held an aggregate of 18,000 restricted
shares of Duke Energy common stock having a value of $902,250. Dividends
are paid on such shares. The vesting of these shares is determined by,
among other things, the performance of Duke Energy.
(6) At December 31, 1999, Mr. Panatier held an aggregate of 14,564 restricted
shares of Phillips common stock having a value of $684,508. On April 1,
2000, Mr. Panatier surrendered these shares to Phillips in return for the
contribution of approximately $757,473 to a key employee deferred
compensation plan established by Phillips for his benefit.
(7) At December 31, 1999, Mr. Frederick held an aggregate of 4,600 restricted
shares of Duke Energy common stock having a value of $230,575. Dividends
are paid on such shares. The vesting of these shares is determined by,
among other things, our performance.
(8) At December 31, 1999, Mr. Borer held an aggregate of 3,000 restricted
shares of Duke Energy common stock having a value of $150,375. Dividends
are paid on such shares. One third of the restricted stock award will vest
each year on April 1, beginning on April 1, 2000.
(9) At December 31, 1999, Mr. Bradley held an aggregate of 5,300 restricted
shares of Duke Energy common stock having a value of $265,663. Dividends
are paid on such shares. The vesting of these shares is determined by,
among other things, our performance.
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<PAGE> 45
(10) Represents options granted by Duke Energy to purchase shares of Duke Energy
common stock.
(11) Represents options granted by Phillips to purchase shares of Phillips
common stock.
(12) Represents the following:
- Matching contributions under the Duke Energy Retirement Savings Plan as
follows: J. Mogg, $9,600; D. Frederick, $9,434; M. Borer, $5,550; M.
Bradley, $9,600.
- Make-whole matching contribution credits under the Duke Energy Executive
Savings Plan as follows: J. Mogg, $10,111; D. Frederick, $2,220; M.
Borer, $2,775; M. Bradley, $3,977.
- Matching contributions under the Phillips Thrift Plan as follows: M.
Panatier, $2,000; R. Martinovich, $2,000.
- Matching contributions under the Phillips Long-Term Stock Savings Plan as
follows: M. Panatier, $12,580; R. Martinovich, $10,143.
- Early payment of banked vacation time benefit earned under Duke Energy
benefits program as follows: J. Mogg, $67,624; M. Bradley, $28,757.
- Supplemental relocation payments made under Duke Energy's relocation
policy as follows: M. Borer, $33,634.
- Retention bonuses paid by Duke Energy as follows: D. Frederick, $162,500;
M. Borer, $200,000; M. Bradley, $209,000.
- Mortgage rate differential payments paid by Duke Energy to account for
increased mortgage payments due to employee relocation as follows: M.
Bradley, $2,353.
- Life insurance premiums paid by Phillips as follows: M. Panatier, $686;
R. Martinovich, $162.
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 two years from April 1, 2000. During the term of this
employment agreement, Mr. Panatier will receive a 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 our benefit plans on
the same basis as other similarly-situated executives of our company.
Under the terms of the employment agreement, as amended, Mr. Panatier will
also receive a long-term incentive award on each of May 26, 2000 and May 26,
2001, with a value equal to 220% of his annual base salary on those dates. These
awards, which earn interest at a rate of 6% per annum, are payable in cash on
the second anniversary of his employment agreement. In the event we complete an
initial public offering of equity securities prior to the payment of these
awards they will be converted, along with unpaid interest, into stock options
and restricted stock of the public company. In addition, the employment
agreement, as amended, grants Mr. Panatier a cash retention award valued at 250%
of his annual base salary. This award, which earns interest at a rate of 6% per
annum, will vest 50% on each of the first and second anniversary of his
employment agreement provided that Mr. Panatier is employed by us on the
scheduled payment dates. In the event we complete an initial public offering of
equity securities prior to the payment of this retention award, the unpaid
portion, along with unpaid interest, will be converted into a restricted stock
award of the public company.
If we terminate Mr. Panatier's employment for any reason other than death,
disability or cause or if Mr. Panatier terminates his employment for cause, all
long-term incentive awards and his retention award will immediately vest. In
addition, if a change of control of our company occurs during the term of the
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<PAGE> 46
employment agreement and Mr. Panatier is terminated without cause or Mr.
Panatier terminates his employment with cause, Mr. Panatier will also be
entitled to a lump sum severance payment equal to 200% of his annual salary in
effect at the time, plus his target bonus and to participate in our group
medical plan (unless Mr. Panatier is eligible for coverage by a subsequent
employer) for a period of two years following such termination.
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, as amended, 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 vest 50%
on each of the first and second anniversary of grant, and will automatically be
converted into stock options and restricted stock in the event of an initial
public offering of equity securities.
OPTION GRANTS IN LAST FISCAL YEAR
In the fiscal year ended December 31, 1999, none of the Named Executive
Officers received options to purchase member interests in our company. None of
the Named Executive Officers held options to purchase member interests in our
company at December 31, 1999.
ITEM 7. 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, Phillips transferred
all of its interest in its subsidiaries that conducted its midstream natural gas
business to us. In connection with the Combination, Duke Energy and Phillips
also transferred to us the midstream natural gas assets acquired by Duke Energy
or Phillips prior to consummation of the Combination, including 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 future integration
opportunities. In addition, 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 indirectly 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 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 enter into, or 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. 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, corporate insurance, cash management, ad valorem taxes and shareholder
services. The above services are priced on the basis of a monthly charge.
Additionally, we may use other Duke Energy services subject to hourly rates,
including legal, internal audit, tax planning, human resources and security
departments. This
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<PAGE> 47
agreement expires on December 31, 2000. We believe that 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."
TRANSACTIONS PRIOR TO THE COMBINATION
Transactions between Duke Energy and Phillips' midstream natural gas
business. Prior to the Combination, Duke Energy and its subsidiaries engaged in
a number of transactions with the subsidiaries of Phillips that were transferred
to us in the Combination, including GPM Gas Corporation (the "Phillips Combined
Subsidiaries"). These transactions were entered into in the ordinary course of
Duke Energy's and the Phillips Combined Subsidiaries' business and were related
to the purchase and sale of raw natural gas, residue gas and NGLs at market
prices.
Transactions between Duke Energy and the Predecessor Company. Prior to the
Combination, Duke Energy and its subsidiaries engaged in a number of
transactions with the Predecessor Company. The following is a description of
those transactions.
The Predecessor Company historically sold a portion of its residue gas and
NGLs to Duke Energy and its subsidiaries, including Duke Energy Trading and
Marketing, at contractual prices that approximated market prices. The
Predecessor Company's revenues from such sales were approximately $567.8 million
in 1997, $536.3 million in 1998 and $696.7 million in 1999. We anticipate that
we will continue to sell residue gas and NGLs to Duke Energy and its
subsidiaries (including Duke Energy Trading and Marketing) at market prices in
the ordinary course of our business.
The Predecessor Company historically purchased raw natural gas and other
petroleum products from Duke Energy and its subsidiaries at contractual prices
that approximated market prices. The Predecessor Company's purchases of raw
natural gas and other petroleum products from Duke Energy and its subsidiaries
totaled $48.9 million in 1997, $79.6 million in 1998 and $128.6 million in 1999.
We anticipate that we will continue to purchase residue gas and other petroleum
products at market prices from Duke Energy and its subsidiaries in the ordinary
course of our business.
The Predecessor Company historically provided gathering and transportation
services over its gathering systems and pipelines to Duke Energy and its
subsidiaries at market prices. The Predecessor Company generated no revenues in
1997, $6.4 million in 1998 and $2.7 million in 1999 from the provision of such
services. We anticipate that we will continue to provide gathering and
transportation to Duke Energy and its subsidiaries at market prices in the
ordinary course of our business.
Duke Energy historically provided the Predecessor Company with various
support services, including information technology services, accounting, legal,
insurance, payroll, cash management, risk management and welfare benefits
services. Duke Energy historically billed the Predecessor Company for such
services at prices that approximate their cost to provide such services. The
Predecessor Company was charged $11.7 million in 1997, $12.1 million in 1998 and
$19.1 million in 1999 for such services. Duke will continue to provide some of
these services under the terms of the Services Agreement described above.
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On June 30, 1995, the Predecessor Company issued a $101.6 million note to
Duke Energy. The note was scheduled to mature in 2004 and bore interest at 8.5%.
In addition, on December 31, 1996, the Predecessor Company issued a $540 million
note to Duke Energy. The note matured at the end of each year and was extended
for subsequent one year periods at each year end. The note bore interest at
prime rate, adjusted quarterly. Upon consummation of the Combination, these
notes were capitalized to equity.
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. This agreement expires
on December 31, 2000.
TRANSACTIONS PRIOR TO THE COMBINATION
Transactions between Phillips and Duke Energy's midstream natural gas
business. Prior to the Combination, Phillips engaged in a number of transactions
with the Predecessor Company. These transactions were entered into in the
ordinary course of Phillips' and the Predecessor Company's business and were
related to the purchase and sale of raw natural gas, residue gas and NGLs at
market prices.
Transactions between Phillips and its midstream natural gas business. Prior
to the Combination, Phillips engaged in a number of transactions with GPM Gas
Corporation. The following is a description of those transactions.
GPM Gas Corporation, the subsidiary of Phillips that owned its midstream
natural gas assets that were contributed to us in the Combination, and Phillips
66 Company, a division of Phillips, entered into an NGL Output Purchase and Sale
Agreement effective as of January 1, 2000. The agreement allows Phillips 66
Company to purchase at index-based prices approximately all of the NGLs produced
by the processing plants owned by GPM Gas Corporation prior to the Combination.
The 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 us in the future in various counties in the
Mid-Continent and Permian Basin regions and the Austin Chalk area. The agreement
has a 15-year primary term and a four-year phase-down period. The agreement
prohibits us from modifying our normal business practices to divert or reduce
NGLs available for purchase by Phillips 66 Company from current delivery levels.
GPM Gas Corporation historically sold a portion of its residue gas and
other by-products to Phillips at contractual prices that approximated market
prices. In addition, GPM Gas Corporation sold NGLs to Phillips at prices based
upon quoted market prices for fractionated NGLs, less transportation,
fractionation and quality-adjustment fees. GPM Gas Corporation's operating
revenues from the sale of residue gas, other by-products and NGLs to Phillips
were approximately $758.7 million in 1997, $537.5 million in 1998 and $725.5
million in 1999. We anticipate that we will continue to sell residue gas and
NGLs to Phillips and its subsidiaries or co-venturers at market prices in the
ordinary course of our business, including in connection with our long term
contract with Phillips described above.
The Phillips Combined Subsidiaries historically purchased raw natural gas
from Phillips at contractual prices that approximated market prices. The
Phillips Combined Subsidiaries' purchases of raw natural gas from Phillips
totaled $118.8 million in 1997, $76.6 million in 1998 and $100.3 million in
1999. We anticipate that we will continue to purchase raw natural gas from
Phillips at market prices in the ordinary course of our business.
Phillips historically provided the Phillips Combined Subsidiaries with
various field services and other general administrative services including
insurance, personnel administration, employee benefits, office space,
communications, data processing, engineering, automotive and other field
equipment, and other miscellaneous services, including legal, treasury,
planning, tax, auditing and other corporate services. These services were
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priced to reimburse Phillips for its actual costs to provide the services.
Charges for these services and benefits were $12.1 million in 1997, $12.1
million in 1998 and $11.4 million in 1999. These services were terminated upon
consummation of the Combination other than as provided in the Transition
Services Agreement.
Phillips 66 Company, has historically purchased sulfur from GPM Gas
Corporation under an agreement for sulfur sales that is renewed annually.
Phillips 66 Company's purchases of sulfur from GPM Gas Corporation totaled
$446,000 in 1997, $412,000 in 1998 and $1.1 million in 1999. Phillips 66 Company
will continue to purchase sulfur from GPM Gas Corporation under the terms of the
agreement currently in effect.
Prior to the Combination, all operational and personnel requirements of the
Phillips Combined Subsidiaries were met by Phillips' employees. All services
provided by Phillips were priced to cover the actual costs of these services,
which equaled $76.6 million in 1997, $74.8 million in 1998 and $74.9 million in
1999. These services were terminated when we hired most of the employees of the
Phillip Combined Subsidiaries in connection with the Combination.
The Phillips Combined Subsidiaries earned interest of $2.7 million in 1997,
$2.4 million in 1998 and $2.5 million in 1999 from participation in Phillips'
centralized cash management system. Participation in the system was terminated
upon the completion of the Combination.
Phillips Gas Company had long-term borrowings from Phillips and other
liabilities outstanding to Phillips of $655.0 million at the end of 1997, $560.0
million at the end of 1998 and $1,350.0 million at the end of 1999. Phillips Gas
Company incurred interest expense of $20.3 million in 1997, $35.9 million in
1998 and $35.6 million in 1999 on these borrowings. Included in the $1,350.0
million of borrowings outstanding at the end of 1999 is a $780.0 million
dividend from Phillips Gas Company to Phillips in the form of a note payable.
These borrowings from Phillips were paid at the closing of the Combination.
The Phillips Combined Subsidiaries historically provided Phillips with
other minor administrative services. Costs allocated to Phillips for these
services were $120,000 in 1997, $79,000 in 1998 and $72,000 in 1999. These
services were terminated upon the consummation of the Combination other than as
provided in the Transition Services Agreement.
The Phillips Combined Subsidiaries periodically bought from, or sold to,
Phillips various assets in the operation of its business. These net acquisitions
totaled $22,000 in 1997, $60,000 in 1998 and $239,000 in 1999.
ITEM 8. LEGAL PROCEEDINGS
In November 1997, Chevron U.S.A. sued GPM Gas Corporation, one of our
subsidiaries, in the United States District Court for the Western District of
Texas, Midland Division, for alleged breach by GPM Gas Corporation of favored
nations clauses in several 1961 gas supply contracts. The case was tried in
October 1998, and in September 1999, the trial court issued an opinion and final
judgment against GPM for $13.8 million through July 1998, plus attorneys' fees
and interest for the period after July 1998. GPM Gas Corporation has appealed
the judgment to the U.S. Court of Appeals for the Fifth Circuit.
In recent years, the midstream natural gas industry has seen an increase in
the number of class actions in suits involving royalty disputes, mismeasurement
and mispayment. Although the industry has seen these types of cases before, they
were previously typically brought by a single plaintiff or small group of
plaintiffs. Many of these cases are now being brought as class actions or under
the Civil False Claims Act. We are currently named defendants in a number of
these types of cases. Although we believe we have meritorious defenses to these
cases and will continue to vigorously defend against them, these class actions
are expected to be costly and time consuming to defend.
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.
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ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE 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.
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES
We have not sold any securities, registered or otherwise, within the past
three years, except as set forth below.
On December 15, 1999, Duke Energy formed our company as a single member
limited liability company. On March 31, 2000, in connection with the
Combination, Duke Energy and Phillips Gas Company each contributed certain gas
gathering, processing and marketing and NGLs assets to us, in exchange for which
Phillips Gas Company received 30.3% of the member interests in our company. Duke
Energy received no additional consideration or securities in our company. In
each case, we relied on the provisions of Section 4(2) of the Securities Act of
1933, as amended (the "Securities Act"), in claiming exemption for the offering,
sale and delivery of such securities from registration under the Securities Act.
ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED
This registration statement relates to the limited liability company member
interests in our company, which represent the only ownership interests in our
company. For a detailed description of the characteristics of our limited
liability company member interests, see our limited liability company agreement
which is included as Exhibit 3.1 hereto and which is incorporated by reference
herein.
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 18-108 of the Delaware Limited Liability Company Act provides:
Subject to such standards and restrictions, if any, as are set forth in its
limited liability company agreement, a limited liability company may, and shall
have the power to, indemnify and hold harmless any member or manager or any
other person from and against any and all claims and demands whatsoever. Our
limited liability company agreement permits us to indemnify any of our directors
or officers against liabilities to the fullest extent permitted by law.
Additionally, we carry insurance policies covering our directors and officers.
Some of our directors and officers may also be indemnified by Duke Energy or
Phillips for liabilities incurred as a result of serving as a director or
officer of our company.
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ITEM 13. FINANCIAL STATEMENTS
UNAUDITED PRO FORMA INCOME STATEMENTS
The following unaudited pro forma income statements (the "Unaudited Pro
Forma Income Statements") of Duke Energy Field Services, LLC were derived by the
application of pro forma adjustments to historical combined and consolidated
financial statements included elsewhere in this registration statement. In
December 1999, Duke Energy Field Services, LLC (the "Company") was formed to
facilitate the combination of the midstream natural gas businesses of Duke
Energy and Phillips Petroleum Company (the "Combination").
The Combination occurred on March 31, 2000. As part of the Combination,
distributions of $1,524,519 and $1,219,800 payable to Duke Energy and Phillips,
respectively, have been recorded. In addition to contributing its midstream
natural gas business, Duke Energy contributed to the Company the General Partner
of TEPPCO Partners, L.P., a publicly traded limited partnership ("TEPPCO General
Partner"), and the mid-continent midstream natural gas assets of Conoco, Inc.
and Mitchell Energy & Development Corp. acquired immediately prior to the
Combination. Subsequent to March 31, 2000 the Company borrowed $2,790,900 in
commercial paper (the "Indebtedness") and made the distributions discussed
above.
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 ("GPM") in the Combination.
The contributions have been reflected in the March 31, 2000 balance sheet
of the Predecessor Company. All of the events described above are referred to
collectively as the "Transactions."
The Unaudited Pro Forma Income Statements give effect to i) the
Transactions and ii) acquisition of the gas gathering business of Union Pacific
Resources (the "UP Fuels Acquisition"), which occurred on March 31, 1999 as if
such transactions were consummated as of January 1, 1999.
The adjustments are described in the accompanying Notes to the Unaudited
Pro Forma Income Statements. The Unaudited Pro Forma Income Statements should
not be considered indicative of the actual results that would have been achieved
had the Transactions or the UP Fuels Acquisition been consummated on the dates
or for the period indicated and do not purport to indicate results of operations
as of any future date or for any future period. The Unaudited Pro Forma Income
Statements should be read in conjunction with the historical combined and
consolidated financial statements of the Predecessor Company, UP Fuels, GPM and
the notes thereto included elsewhere in this registration statement.
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DUKE ENERGY FIELD SERVICES, LLC
UNAUDITED PRO FORMA INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREDECESSOR CONOCO/
COMPANY UP FUELS GPM MITCHELL TEPPCO GP
HISTORICAL ACQUISITION(1) HISTORICAL ACQUISITION(2) CONTRIBUTION(3)
----------- -------------- ---------- -------------- ---------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum products........ $3,310,260 $228,600 $1,501,178 $228,889 $
Transportation, storage and processing............. 148,050 69,324 88,279 -- --
---------- -------- ---------- -------- ------
Total operating revenues..................... 3,458,310 297,924 1,589,457 228,889 --
COSTS AND EXPENSES
Natural gas and petroleum products................. 2,965,297 252,880 1,148,910 187,689 --
Operating and maintenance.......................... 181,392 22,478 176,864 12,400 --
Depreciation and amortization...................... 130,788 15,125 80,458 6,200 --
General and administrative......................... 73,685 6,965 15,560 -- --
Net (gain) loss on sale of assets.................. 2,377 (907) -- --
---------- -------- ---------- -------- ------
Total costs and expenses..................... 3,353,539 297,448 1,420,885 206,289 --
---------- -------- ---------- -------- ------
OPERATING INCOME.................................... 104,771 476 168,572 22,600 --
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES..... 22,502 4,821 1,048 (8,994) 9,300
---------- -------- ---------- -------- ------
EARNINGS BEFORE INTEREST AND
TAXES.............................................. 127,273 5,297 169,620 13,606 9,300
INTEREST EXPENSE.................................... 52,915 35,643 -- --
---------- -------- ---------- -------- ------
EARNINGS BEFORE INCOME TAXES........................ 74,358 5,297 133,977 13,606 9,300
INCOME TAX EXPENSE.................................. 31,029 1,900 52,244 5,170 3,534
---------- -------- ---------- -------- ------
INCOME FROM CONTINUING OPERATIONS................... $ 43,329 $ 3,397 $ 81,733 $ 8,436 $5,766
========== ======== ========== ======== ======
<CAPTION>
ADJUSTMENTS(4) PRO FORMA
-------------- ----------
<S> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum products........ $ $5,268,927
Transportation, storage and processing............. -- 305,653
--------- ----------
Total operating revenues..................... -- 5,574,580
COSTS AND EXPENSES
Natural gas and petroleum products................. -- 4,554,776
Operating and maintenance.......................... -- 393,134
Depreciation and amortization...................... 11,298(5) 243,869
General and administrative......................... -- 96,210
Net (gain) loss on sale of assets.................. -- 1,470
--------- ----------
Total costs and expenses..................... 11,298 5,289,459
--------- ----------
OPERATING INCOME.................................... (11,298) 285,121
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES..... (1,339)(6) 27,338
--------- ----------
EARNINGS BEFORE INTEREST AND
TAXES.............................................. (12,637) 312,459
INTEREST EXPENSE.................................... (130,988)(7) 219,546
--------- ----------
EARNINGS BEFORE INCOME TAXES........................ (143,625) 92,913
INCOME TAX EXPENSE.................................. (93,877)(8) --
--------- ----------
INCOME FROM CONTINUING OPERATIONS................... $ (49,748) $ 92,913
========= ==========
</TABLE>
See Notes to the Unaudited Pro Forma Income Statements.
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DUKE ENERGY FIELD SERVICES, LLC
UNAUDITED PRO FORMA INCOME STATEMENT
FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2000
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREDECESSOR GPM CONOCO/MITCHELL TEPPCO GP
COMPANY HISTORICAL ACQUISITION(2) CONTRIBUTION(3) ADJUSTMENTS(4) PRO FORMA
----------- ---------- --------------- --------------- -------------- ----------
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum
products......................... $1,415,465 $532,762 $57,222 $ -- $ -- $2,005,449
Transportation, storage and
processing....................... 35,746 9,603 -- -- -- 45,349
---------- -------- ------- ------ --------- ----------
Total operating revenues..... 1,451,211 542,365 57,222 -- -- 2,050,798
COSTS AND EXPENSES
Natural gas and petroleum
products......................... 1,278,511 377,659 46,922 -- -- 1,703,092
Operating and maintenance.......... 49,039 47,285 3,100 -- -- 99,424
Depreciation and amortization...... 38,094 20,700 1,550 -- 2,239(5) 62,583
General and administrative......... 29,701 4,251 -- -- -- 33,952
Net (gain) loss on sale of
assets........................... 239 (88) -- -- -- 151
---------- -------- ------- ------ --------- ----------
Total costs and expenses..... 1,395,584 449,807 51,572 -- 2,239 1,899,202
---------- -------- ------- ------ --------- ----------
OPERATING INCOME.................... 55,627 92,558 5,650 -- (2,239) 151,596
EQUITY EARNINGS (LOSS) OF
UNCONSOLIDATED AFFILIATES.......... 6,759 (250) (895) 4,700 (346)(6) 9,968
---------- -------- ------- ------ --------- ----------
EARNINGS BEFORE INTEREST AND
TAXES.............................. 62,386 92,308 4,755 4,700 (2,585) 161,564
INTEREST EXPENSE.................... 14,477 17,865 -- -- (22,544)(7) 54,886
---------- -------- ------- ------ --------- ----------
EARNINGS BEFORE INCOME TAXES........ 47,909 74,443 4,755 4,700 (25,129) 106,678
INCOME TAX EXPENSE (BENEFIT)........ (313,991) 29,110 1,807 1,786 281,288(8) --
---------- -------- ------- ------ --------- ----------
NET INCOME FROM CONTINUING
OPERATIONS......................... $ 361,900 $ 45,333 $ 2,948 $2,914 $(306,417) $ 106,678
========== ======== ======= ====== ========= ==========
</TABLE>
See Notes to the Unaudited Pro Forma Income Statements.
53
<PAGE> 54
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO THE UNAUDITED PRO FORMA INCOME STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 1999 AND THE THREE MONTH PERIOD ENDED MARCH 31,
2000
(IN THOUSANDS)
1. Reflects the historical operating results of UP Fuels for the three month
period ended March 31, 1999, the date the UP Fuels Acquisition was
consummated by the Predecessor Company.
2. Reflects the results of operations associated with the acquisition of the
Conoco and Mitchell businesses, net of the earnings from the
Ferguson/Burleson Joint Venture interest exchanged as part of the
consideration for the businesses.
3. Reflects equity earnings of the TEPPCO general partnership interest
contributed by Duke Energy.
4. The pro forma adjustments exclude non-recurring expenses directly related to
the Transactions which the Company anticipates will be reflected in the
income statement for the period including the Transactions.
5. The excess purchase cost over the book value of net GPM assets acquired in
the Combination has not yet been fully allocated to individual assets and
liabilities acquired. However, the Company believes a portion will be
allocated to property, plant and equipment and identifiable intangibles and
will be amortized over 20 years. Given its preliminary estimate of the
allocation of the purchase cost to net assets acquired, management has
estimated a composite life of 20 years.
The adjustment to depreciation and amortization was calculated as follows:
<TABLE>
<CAPTION>
PERIOD ENDED
-------------------------
DECEMBER 31, MARCH 31,
1999 2000
------------ ----------
<S> <C> <C>
Net book value of GPM property at January 1, 1999......... $ 943,302 $ 943,302
Excess purchase price over net assets acquired in
Combination Allocated to property and equipment......... 891,808 891,808
---------- ----------
Subtotal................................................ 1,835,110 1,835,110
Composite life -- 20 years................................ 20 20
Depreciation and amortization calculated.................. 91,756 22,939
Less: GPM historical depreciation and amortization........ (80,458) (20,700)
---------- ----------
Net adjustment............................................ $ 11,298 $ 2,239
========== ==========
</TABLE>
6. Reflects elimination of the equity earnings associated with the Predecessor
Company's investment in Westana, which was sold in February 2000 in
connection with the Combination.
7. The pro forma adjustment to interest expense, net is as follows:
<TABLE>
<CAPTION>
PERIOD ENDED
--------------------------
DECEMBER 31, MARCH 31,
1999 2000
------------ -----------
<S> <C> <C>
Estimated interest at 8% including deferred cost
amortization............................................. $ 219,546 $ 54,886
Less: historical interest expense.......................... (88,558) (32,342)
--------- -----------
Incremental interest expense............................... $ 130,988 $ 22,544
========= ===========
</TABLE>
A .125% increase or decrease in the assumed weighted average interest rate
would change pro forma interest expense and net income by $3,430 on an annual
basis.
8. The pro forma adjustment reflects the elimination of income taxes as a result
of the conversion of the predecessor company to a limited liability company
which is a pass-through entity for income tax purposes.
54
<PAGE> 55
INDEPENDENT AUDITORS' REPORT
Duke Energy Field Services, LLC and Affiliates
We have audited the accompanying combined balance sheets of Duke Energy
Field Services, LLC and Affiliates ("the Predecessor Companies") as of December
31, 1998 and 1999, and the related combined statements of income and equity and
cash flows for each of the three years in the period ended December 31, 1999.
The Predecessor Companies are under common ownership and common management.
These financial statements are the responsibility of the Predecessor Companies'
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 financial statements present fairly, in all material
respects, the combined financial position of the Predecessor Companies as of
December 31, 1998 and 1999, and the combined results of their operations and
their combined cash flows for each of the three years in the period ended
December 31, 1999 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
February 18, 2000
Denver, Colorado
55
<PAGE> 56
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
COMBINED BALANCE SHEETS
DECEMBER 31, 1998 AND 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1999
---------- ----------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 168 $ 792
Accounts receivable:
Customers (net of allowance for doubtful accounts,
1998, $749 and 1999, $6,743).......................... 155,143 370,139
Affiliates............................................. 57,725 63,927
Other.................................................. 27,246 30,067
Inventories............................................... 23,713 38,701
Notes receivable.......................................... 5,266 13,050
Other..................................................... 531 1,580
---------- ----------
Total current assets.............................. 269,792 518,256
PROPERTY, PLANT AND EQUIPMENT:
Cost...................................................... 1,763,594 3,005,510
Accumulated depreciation and amortization................. (480,296) (596,125)
---------- ----------
Net property, plant, and equipment................ 1,283,298 2,409,385
INVESTMENTS IN AFFILIATES................................... 187,938 343,835
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net.................. 102,382
Goodwill, net............................................. 15,299 85,846
OTHER NONCURRENT ASSETS..................................... 14,511 12,131
---------- ----------
TOTAL ASSETS................................................ $1,770,838 $3,471,835
========== ==========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade.................................................. $ 200,864 $ 353,977
Affiliates............................................. 10,762 62,370
Other.................................................. 5,556 33,858
Accrued taxes other than income........................... 14,194 15,653
Advances, net -- parents.................................. 334,057 1,579,475
Notes payable -- affiliates............................... 540,000 588,880
Other..................................................... 8,976 6,372
---------- ----------
Total current liabilities......................... 1,114,409 2,640,585
DEFERRED INCOME TAXES....................................... 222,007 308,308
NOTE PAYABLE TO PARENT...................................... 101,600 101,600
OTHER LONG TERM LIABILITIES................................. 34,871
COMMITMENTS AND CONTINGENT LIABILITIES
EQUITY:
Common stock.............................................. 3 1
Paid-in capital........................................... 202,523 213,091
Retained earnings......................................... 130,296 173,091
Other comprehensive income................................ 288
---------- ----------
Total equity...................................... 332,822 386,471
---------- ----------
TOTAL LIABILITIES AND EQUITY................................ $1,770,838 $3,471,835
========== ==========
</TABLE>
See Notes to the Combined Financial Statements.
56
<PAGE> 57
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
COMBINED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
OPERATING REVENUES:
Sales of natural gas and petroleum products............ $1,700,029 $1,469,133 $3,310,260
Transportation and storage of natural gas.............. 41,896 50,097 76,604
Other.................................................. 59,907 65,090 71,446
---------- ---------- ----------
Total operating revenues....................... 1,801,832 1,584,320 3,458,310
---------- ---------- ----------
COSTS AND EXPENSES:
Natural gas and petroleum products..................... 1,468,089 1,338,129 2,965,297
Operating and maintenance.............................. 104,308 113,556 181,392
Depreciation and amortization.......................... 67,701 75,573 130,788
General and administrative............................. 36,023 44,946 73,685
Net (gain) loss on sale of assets...................... (236) (33,759) 2,377
---------- ---------- ----------
Total costs and expenses....................... 1,675,885 1,538,445 3,353,539
---------- ---------- ----------
OPERATING INCOME......................................... 125,947 45,875 104,771
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES.......... 9,784 11,845 22,502
---------- ---------- ----------
EARNINGS BEFORE INTEREST AND TAXES....................... 135,731 57,720 127,273
INTEREST EXPENSE......................................... 51,113 52,403 52,915
---------- ---------- ----------
INCOME BEFORE INCOME TAXES............................... 84,618 5,317 74,358
INCOME TAXES............................................. 33,380 3,289 31,029
---------- ---------- ----------
NET INCOME............................................... $ 51,238 $ 2,028 $ 43,329
========== ========== ==========
</TABLE>
See Notes to the Combined Financial Statements.
57
<PAGE> 58
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
COMBINED STATEMENTS OF EQUITY
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL OTHER
COMMON PAID-IN RETAINED COMPREHENSIVE
STOCK CAPITAL EARNINGS INCOME TOTAL
------ ---------- -------- ------------- --------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1996....... $ 3 $200,326 $77,030 $277,359
Contributions....................
Net income....................... 51,238 51,238
--- -------- -------- ---- --------
BALANCE, DECEMBER 31, 1997....... 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
=== ======== ======== ==== ========
</TABLE>
See Notes to the Combined Financial Statements.
58
<PAGE> 59
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
COMBINED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1998 1999
----------- --------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................... $ 51,238 $ 2,028 $ 43,329
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization..................... 67,701 75,573 130,788
Deferred income tax expense....................... 35,823 45,315 86,301
Equity in undistributed earnings.................. (9,784) (11,846) (22,502)
Loss (gain) on sale of assets..................... (236) (33,759) 2,377
Net change in operating assets and liabilities:
Accounts receivable............................... (76,679) 133,461 (175,008)
Inventories....................................... 5,572 1,762 (5,303)
Other current assets.............................. 11,320 10,150 20,356
Accounts payable.................................. 101,763 (177,418) 152,535
Other current liabilities......................... (13,361) (4,857) (4,390)
Other long term liabilities....................... (55,347)
----------- --------- -----------
Net cash provided by operating activities.... 173,357 40,409 173,136
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions and other capital expenditures.......... (121,978) (185,479) (1,570,083)
Investment in affiliates............................. (29,600) (84,884) (62,752)
Affiliate distributions.............................. 10,742 15,051 31,999
Proceeds from sales of assets........................ 2,815 51,687 29,390
----------- --------- -----------
Net cash used in investing activities........ (138,021) (203,625) (1,571,446)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in advances -- parents....... (35,061) 162,514 1,350,054
Notes payable borrowings............................. 48,880
----------- --------- -----------
Net cash flows provided by (used in)
financing activities....................... (35,061) 162,514 1,398,934
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS... 275 (702) 624
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR........... 595 870 168
----------- --------- -----------
CASH AND CASH EQUIVALENTS, END OF YEAR................. $ 870 $ 168 $ 792
=========== ========= ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION --Cash
paid for interest (net of amounts capitalized)....... $ 51,765 $ 52,948 $ 52,915
</TABLE>
See Notes to the Combined Financial Statements.
59
<PAGE> 60
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
1. ACCOUNTING POLICIES SUMMARY
Principles of Combining -- The accounting policies are presented to assist
the reader in evaluating the combined financial statements of Duke Energy Field
Services, LLC, Duke Energy Field Services, Inc. (DEFSI), Panhandle Field
Services Company (PFSC), Panhandle Gathering Company (PGC), and Duke Energy
Services Canada, Ltd. (DESCL) (together, "Duke Energy Field Services, LLC and
Affiliates" or the Predecessor Companies). The Predecessor Companies are
indirect subsidiaries of Duke Energy Corporation (Duke Energy). During 1999,
PFSC and PGC were contributed to and became wholly-owned subsidiaries of DEFSI.
The resulting December 31, 1999 stockholders' equity (1,000 shares authorized
and issued, $1.00 par value) reflects that of DEFSI and DESCL. 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 natural
gas liquids in Mexico and the transportation, marketing and storage of other
petroleum products.
The Combination -- On December 16, 1999, Duke Energy and Phillips Petroleum
Company
(Phillips) entered into an agreement to combine their United States and Canadian
midstream natural gas gathering, processing and natural gas liquid operations
(the Combination). In connection with the Combination, Duke Energy's midstream
natural gas gathering and processing business was transferred to Duke Energy
Field Services, LLC and the Combination will be accounted for as an acquisition
by the Predecessor Companies of Phillips' midstream business.
Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles 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, which does not purport to represent replacement or realizable value.
Assets, including goodwill and other intangibles, are evaluated for potential
impairment based on undiscounted cash flows and any impairment recorded is
derived based on discounted cash flows. There was no impairment during 1997,
1998 or 1999. Depreciation of property, plant and equipment is computed using
the straight-line method (see Note 4).
Interest totaling $2.3 million, $1.6 million and $.9 million has been
capitalized on construction projects for 1997, 1998 and 1999, respectively.
Revenue Recognition -- The Predecessor Companies recognize 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.
Equity in Unconsolidated Affiliates -- Investments in 20% to 50% owned
affiliates are accounted for using the equity method. Investments greater than
50% are consolidated unless the Predecessor Companies do not operate these
investments and as a result do not have the ability to exercise control or
control is considered to be temporary (See Note 5).
Derivative Contracts -- The Predecessor Companies use commodity swaps,
futures and option contracts in the conduct of their business. Unrealized gains
and losses associated with activity other than trading are
60
<PAGE> 61
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
recognized when the underlying physical transaction is recorded. Trading
activity is marked-to-market and reflected in the statements of income as sales
of natural gas and petroleum products or costs of such.
Significant Customers -- Duke Energy Trading and Marketing, L.L.C. (DETM),
an affiliated company, is a significant customer. Sales to DETM totaled $567
million, $522 million and $684 million during 1997, 1998 and 1999, respectively.
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 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.
Environmental liabilities at the end of 1998 and 1999 were insignificant.
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 average prices of
natural gas at the plant or system. Generally, these balances are settled with
deliveries of natural gas.
Deferred Income Tax -- The Predecessor Companies follow the asset and
liability method of accounting for income tax. Deferred taxes are provided for
temporary differences in the tax and financial reporting basis of assets and
liabilities. The effect of a change in tax rates on deferred tax assets and
liabilities is recognized in income in the period the rate change is enacted.
Stock Based Compensation -- The Predecessor Companies account 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 is recorded as compensation cost over the
requisite vesting period based on the market value on the date of the grant.
Earnings Per Share -- The historical capital structure of the Predecessor
Companies is not representative of the future capital structure of DEFSI (see
Note 2), as all companies were wholly-owned subsidiaries. Accordingly, the
historical net income per share and weighted average number of common shares
outstanding are not shown for any of the periods presented.
Comprehensive Income -- The Predecessor Companies' only item of other
comprehensive income is foreign currency translation.
Recently Issued Accounting Pronouncements -- In June 1998, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133). SFAS 133 establishes standards for derivative instruments, including
certain derivative instruments embedded in other contracts (collectively
referred to as derivatives) and for hedging activities. SFAS 133 requires that
an entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. If
certain conditions are met, a derivative may be specifically designated as (a) a
hedge of the exposure to changes in the fair value of a recognized asset or
liability or an unrecognized firm commitment, (b) a hedge of the exposure to
variable cash flows of a forecasted transaction, or (c) a hedge of the foreign
currency exposure of a net investment in a foreign operation, an unrecognized
firm commitment, an available-for-sale security, or a foreign-currency-
denominated forecasted transaction. The accounting for changes in the fair value
of a derivative (gains and
61
<PAGE> 62
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
losses) depends on the intended use of the derivative and the resulting
designation. The Predecessor Companies are required to adopt SFAS 133 on January
1, 2001. The Predecessor Companies have not completed the process of evaluating
the impact that will result from adopting SFAS 133.
2. BUSINESS COMBINATIONS/DISPOSITIONS
In March 1998, the Predecessor Companies sold a fractionator to TEPPCO
Colorado, L.L.C., an indirect, wholly-owned subsidiary of TEPPCO Partners, L.P.
(TEPPCO), of which Duke Energy, through an indirect, wholly-owned subsidiary,
has an equity interest of approximately 18%. The fractionator was sold for $40
million and the Predecessor Companies realized a gain of approximately $38
million.
On March 31, 1999, the Predecessor Companies 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 billion. 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 Predecessor Companies'
financial statements since the date of purchase. The purchase price has been
allocated to the assets acquired and liabilities assumed based on estimated fair
value, as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
Property, plant and equipment...................... $1,046,316
Partnerships and other joint venture investments... 116,644
Natural gas liquids sales contracts................ 107,771
Goodwill........................................... 75,548
Gas marketing...................................... 104,843
Deferred tax asset................................. 10,200
Net working capital................................ (8,207)
Environmental and other liabilities................ (94,018)
----------
Net.............................................. $1,359,097
==========
</TABLE>
The gas marketing component of UP Fuels was immediately transferred to an
affiliate of Duke Energy after the acquisition at the above fair value. Revenues
and net income for 1998 on a pro forma basis would have increased $1.4 billion
and $54.9 million, respectively, if the acquisition had occurred on January 1,
1998. Revenues and net income for 1999 on a pro forma basis would have increased
$298 million and $2.8 million, respectively, if the acquisition had occurred on
January 1, 1999.
3. INVENTORIES
A summary of inventories by category follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1999
------- -------
(IN THOUSANDS)
<S> <C> <C>
Gas held for resale......................................... $13,202 $18,114
NGLs........................................................ 5,962 18,211
Materials and supplies...................................... 4,549 2,376
------- -------
Total inventories................................. $23,713 $38,701
======= =======
</TABLE>
62
<PAGE> 63
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
4. PROPERTY, PLANT AND EQUIPMENT
A summary of property, plant and equipment by classification follows:
<TABLE>
<CAPTION>
DECEMBER 31,
DEPRECIATION -----------------------
RATES 1998 1999
------------ ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Gathering...................................... 4% - 6% $ 923,350 $1,231,050
Processing..................................... 4% 416,572 1,197,993
Transmission................................... 4% 251,079 413,633
Underground storage............................ 2% - 5% 79,875 73,958
General plant.................................. 20% - 33% 36,214 37,614
Construction work in progress.................. 56,504 51,262
---------- ----------
Total property, plant and
equipment.......................... $1,763,594 $3,005,510
========== ==========
</TABLE>
5. INVESTMENTS IN AFFILIATES
The Predecessor Companies have investments in the following businesses
accounted for using the equity method:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
OWNERSHIP 1998 1999
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Dauphin Island Gathering Partners................... 37.28% $ 96,869 $ 99,878
Mont Belvieu I...................................... 20.00% 40,440
Mobile Bay Processing Partners...................... 28.81% 30,166 35,906
Black Lake Pipeline................................. 50.00% 35,641
Sycamore Gas System General Partnership............. 48.45% 19,344 21,985
Main Pass Oil Gathering............................. 33.33% 15,762 16,967
Ferguson-Burleson................................... 55.00% 23,631
Other affiliates.................................... Various 12,406 54,141
-------- --------
174,547 328,589
Westana Gathering Company........................... 50.00% 13,391 15,246
-------- --------
Total investments in affiliates........... $187,938 $343,835
======== ========
</TABLE>
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.
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.
63
<PAGE> 64
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
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.
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.
Ferguson-Burleson -- Ferguson-Burleson operates two independent gas
gathering systems, rich and lean, that are interconnected. The rich gas system
is comprised of over 1,450 miles of gathering lines serving six counties in
South Central Texas. The lean gas system consists of approximately 100 miles of
pipelines in two counties in South Central Texas. We own 55% of the economic
interest in Ferguson-Burleson but have only a 50% voting interest. The operator
of the assets controls the other 50% voting interest and manages the operations
on a daily basis. The Predecessor Companies do not have the ability to control
Ferguson-Burleson and therefore do not consolidate its results.
Equity in earnings amounted to the following for the years ended December
31:
<TABLE>
<CAPTION>
1997 1998 1999
------ ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Dauphin Island Gathering Partners........................ $4,250 $ 7,234 $ 5,974
Mont Belvieu I........................................... 440
Mobile Bay Processing Partners........................... 65 2,307
Black Lake Pipeline...................................... 1,141
Sycamore Gas System General Partnership.................. 261 142
Main Pass Oil Gathering.................................. 1,665 2,598 3,638
Ferguson-Burleson........................................ 5,600
Other affiliates......................................... 3,062 1,279 1,921
------ ------- -------
8,977 11,437 21,163
Westana Gathering Company................................ 807 409 1,339
------ ------- -------
Total equity earnings.......................... $9,784 $11,846 $22,502
====== ======= =======
</TABLE>
Distributions in excess of earnings were $1.0 million, $3.2 million and
$9.5 million in 1997, 1998 and 1999, respectively.
In connection with the Combination, the Predecessor Companies' interest in
Westana Gathering Company was sold in February 2000. Proceeds and loss on sale
approximated $12 million and $4 million, respectively.
64
<PAGE> 65
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
The following summarizes combined financial information of unconsolidated
affiliates excluding Westana for the years ended December 31:
<TABLE>
<CAPTION>
1997 1998 1999
------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Income statement:
Operating revenues................................. $54,898 $ 61,618 $ 452,118
Operating expenses................................. 34,281 36,173 374,079
Net income......................................... 21,318 27,878 55,606
Balance sheet:
Current assets..................................... $ 57,926 $ 119,506
Noncurrent assets.................................. 388,562 761,270
Current liabilities................................ (25,671) (113,121)
Noncurrent liabilities............................. (8,094) (14,853)
-------- ---------
Net assets................................. $412,723 $ 752,802
======== =========
</TABLE>
6. TRANSACTIONS WITH AFFILIATES
A summary of transactions with affiliates included in the combined
statements of income follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1997 1998 1999
-------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Sales of natural gas and petroleum products......... $567,800 $536,300 $ 696,700
Natural gas and petroleum products purchased........ 48,900 79,600 128,600
Transportation revenue.............................. 6,400 2,700
Operating expenses -- Billed to affiliates(1)....... 4,200 7,200
General and administrative expenses(1):
Billed to affiliates.............................. 1,200 502
Billed from affiliates............................ 11,700 12,100 19,100
Interest expense.................................... 60,100 60,100 53,900
</TABLE>
--------------------
(1) Operating, general and administrative expenses are allocated to
affiliates based on cost.
As of December 31, 1998 and 1999, the Predecessor Companies 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
Companies had a $540 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 a $44.3 million and $4.6 million note payable 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.
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 $117.3 million,
$203.8 million and $1,410 million for 1997, 1998 and 1999, respectively.
Duke Energy supplies the Predecessor Companies with various staff and
support services, including information technology products and services,
payroll, employee benefits, corporate insurance, cash manage-
65
<PAGE> 66
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
ment, ad valorem taxes, treasury and legal functions. These expenditures are
allocated to the Predecessor Companies using a cost based method of allocation.
Management believes the allocation is reasonable and estimates that such costs
approximate the costs for such services that would have been incurred on a stand
alone basis.
See Notes 5 and 12 for discussion of other specific transactions with
affiliates.
7. INCOME TAXES
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 combined statements of income is summarized
as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------
1997 1998 1999
------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current:
Federal........................................... $(1,012) $(36,142) $(46,429)
State............................................. (1,431) (5,884) (8,843)
------- -------- --------
Total current............................. (2,443) (42,026) (55,272)
------- -------- --------
Deferred:
Federal........................................... 30,800 38,961 73,201
State............................................. 5,023 6,354 13,100
------- -------- --------
Total deferred............................ 35,823 45,315 86,301
------- -------- --------
Total income tax expense............................ $33,380 $ 3,289 $ 31,029
======= ======== ========
</TABLE>
Total income tax expense differs from the amount computed by applying the
federal income tax rate to earnings before income tax. The reasons for this
difference are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1997 1998 1999
------- ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal income tax rate................................ 35.0% 35.0% 35.0%
======= ====== =======
Income tax, computed at the statutory rate............. $29,616 $1,861 $26,025
Adjustments resulting from:
State income tax, net of federal income tax effect... 2,962 186 2,863
Non-deductible amortization and other................ 802 1,242 2,141
------- ------ -------
Total income tax............................. $33,380 $3,289 $31,029
======= ====== =======
</TABLE>
66
<PAGE> 67
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
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 are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Alternative minimum tax credit carryforward....... $ 20,400 $ 20,400 $ --
Other............................................. 2,300 500 7,600
--------- --------- ---------
Total deferred income tax assets........ 22,700 20,900 7,600
--------- --------- ---------
Property, plant, and equipment.................... (160,200) (209,507) (275,008)
Deferred charges.................................. (900) (15,000) (15,300)
State deferred income tax, net of federal tax
effect.......................................... (14,300) (18,400) (25,600)
--------- --------- ---------
Total deferred income tax liabilities... (175,400) (242,907) (315,908)
--------- --------- ---------
Net deferred income tax liability................. $(152,700) $(222,007) $(308,308)
========= ========= =========
</TABLE>
8. BUSINESS SEGMENTS AND RELATED INFORMATION
The Predecessor Companies operate in two principal business segments as
follows: (1) natural gas gathering, processing, transportation, marketing and
storage, and (2) natural gas liquids fractionation, transportation, marketing
and trading. These segments are separately monitored by management for
performance against its internal forecast and are consistent with the
Predecessor Companies internal financial reporting package. These segments have
been identified based upon 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.
The following table sets forth the Predecessor Companies' segment
information as of and for the years ended December 31, 1997, 1998 and 1999.
<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues:
Natural gas............................................ $1,683,483 $1,497,901 $2,483,197
NGLs................................................... 423,680 309,380 1,365,577
Intersegment(a)........................................ (305,331) (222,961) (390,464)
---------- ---------- ----------
Total operating revenues....................... 1,801,832 1,584,320 3,458,310
---------- ---------- ----------
Margin:
Natural gas............................................ 334,129 243,787 459,843
NGLs................................................... (386) 2,404 33,170
---------- ---------- ----------
Total margin................................... 333,743 246,191 493,013
---------- ---------- ----------
Other operating costs:
Natural gas............................................ 104,072 79,797 182,062
NGLS................................................... -- -- 1,707
Corporate.............................................. 36,023 44,946 73,685
---------- ---------- ----------
Total other operating costs.................... 140,095 124,743 257,454
---------- ---------- ----------
</TABLE>
67
<PAGE> 68
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Equity in earnings of unconsolidated affiliates:
Natural gas............................................ 9,784 11,845 20,917
NGLs................................................... 1,585
---------- ---------- ----------
Total equity in earnings of unconsolidated
affiliates................................... 9,784 11,845 22,502
---------- ---------- ----------
EBITDA(b):
Natural gas............................................ 239,841 175,835 298,698
NGLs................................................... (386) 2,404 33,048
Corporate.............................................. (36,023) (44,946) (73,685)
---------- ---------- ----------
Total EBITDA................................... 203,432 133,293 258,061
---------- ---------- ----------
Depreciation and amortization:
Natural gas............................................ 65,593 73,470 119,425
NGLs................................................... 9,073
Corporate.............................................. 2,108 2,103 2,290
---------- ---------- ----------
Total depreciation and amortization............ 67,701 75,573 130,788
---------- ---------- ----------
EBIT:
Natural gas............................................ 174,248 102,365 179,273
NGLs................................................... (386) 2,404 23,975
Corporate.............................................. (38,131) (47,049) (75,975)
---------- ---------- ----------
Total EBIT..................................... 135,731 57,720 127,273
---------- ---------- ----------
Corporate interest expense............................... 51,113 52,403 52,915
---------- ---------- ----------
Income before income taxes:
Natural gas............................................ 174,248 102,365 179,273
NGLs................................................... (386) 2,404 23,975
Corporate.............................................. (89,244) (99,452) (128,890)
---------- ---------- ----------
Total income before income taxes............... $ 84,618 $ 5,317 $ 74,358
---------- ---------- ----------
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------
1998 1999
---------- ----------
<S> <C> <C>
Total assets:
Natural gas............................................... $1,505,111 $2,754,447
NGLs...................................................... 5,137 225,702
Corporate(c).............................................. 260,590 491,686
---------- ----------
Total assets...................................... $1,770,838 $3,471,835
========== ==========
</TABLE>
---------------
(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, less
interest income. EBITDA is not a measurement presented in accordance with
generally accepted accounting principles. You should not consider it 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
68
<PAGE> 69
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
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.
(c) Includes items such as unallocated working capital, intercompany accounts
and intangible and other assets.
9. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The Predecessor Companies' operations are subject to the volatility of
commodity prices, particularly that of NGL prices. The Predecessor Companies
manage exposure to risk from existing contractual commitments through forward
contracts, futures and over-the-counter swap agreements (collectively,
"commodity instruments"). Energy commodity forward contracts involve physical
delivery of an energy commodity. Energy commodity futures involve the buying or
selling of natural gas, crude oil (used to hedge NGLs prices) and NGLs at a
fixed price. Over-the-counter swap agreements require the Predecessor Companies
to receive or make payments based on the difference between a specified price
and the actual price of the underlying commodity.
Commodity Instruments -- Trading -- The Predecessor Companies, through a
wholly-owned subsidiary, engage in the trading of NGLs and crude oil commodity
instruments, and therefore experience net open positions. The Predecessor
Companies manage open positions with policies which limit its exposure to market
risk and require daily reporting to management of potential financial exposure.
The weighted-average life of the Predecessor Companies commodity risk portfolio
was approximately 2 months at December 31, 1999. During 1999 net gains of $9.7
million were recognized from trading NGLs and crude oil derivatives. The
Predecessor Companies were not trading NGLs nor crude oil commodity instruments
prior to 1999. As of December 31, 1999, the absolute notional contract quantity
of NGLs and crude oil commodity derivatives held for trading purposes was
5,826,000 and 6,486,500 barrels, respectively.
<TABLE>
<CAPTION>
1999
---------------------
ASSETS LIABILITIES
------- -----------
(IN THOUSANDS)
<S> <C> <C>
Fair value at December 31................................... $10,461 $10,079
Average fair value for the year............................. 8,588 8,359
</TABLE>
Commodity Derivatives -- Non-Trading -- At December 31, 1998 and 1999, the
Predecessor Companies held or issued derivatives that reduce the Predecessor
Companies' exposure to market fluctuations in the price and transportation costs
of natural gas and NGLs. The Predecessor Companies' 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 those commodity derivatives that
qualify as a hedge are not recognized until the underlying physical transaction
occurs. At December 31, 1998 and 1999, the Predecessor Companies unrealized net
gains (losses) related to commodity derivative hedges was $1.8 million and
$(63.5) million, respectively. As of December 31, 1998 and 1999, the absolute
notional contract quantity of commodity derivatives held for non-trading
purposes was 10.92 and 7.8 billion cubic feet (Bcf) of natural gas and 59,000
and 32,764,000 barrels of crude oil, respectively. Hedging losses in 1999
totaled approximately $34 million.
69
<PAGE> 70
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
Market and Credit Risk -- Most futures and swaps are conducted through
either DETM or Duke Energy Merchants (DEM). Under these arrangements the
Predecessor Companies do not have margin requirements.
New York Mercantile Exchange (Exchange) traded futures contracts are
guaranteed by the Exchange and have nominal credit risk. On all other
transactions previously described, the Predecessor Companies are exposed to
credit risk in the event of nonperformance by the counterparties. For each
counterparty, the Predecessor Companies analyze the financial condition prior to
entering into an agreement. The change in market value of exchange-traded
futures contracts other than those conducted through either DETM or DEM require
daily cash settlement in margin accounts with brokers. Swap contracts are
generally settled at the expiration of the contract term and may be subject to
margin requirements with the counterparty.
Gathering, processing, and transportation services are provided to
producers, refiners, and a variety of wholesale and retail customers located in
the Mid-Continent, Gulf Coast and Rocky Mountain areas as well as in Canada. The
principal markets for natural gas marketing services are industrial end-users
and utilities located throughout the United States. The Predecessor Companies
have a concentration of receivables due from gas and electric utilities and
their affiliates, as well as industrial customers throughout the United States.
These concentrations of customers may affect the Predecessor Companies' overall
credit risk in that certain customers may be similarly affected by changes in
economic, regulatory or other factors. Trade receivables are generally not
collateralized; however, the Predecessor Companies analyze customers' financial
condition prior to extending credit, establish credit limits and monitor the
appropriateness of these limits on an ongoing basis.
10. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of SFAS No. 107,
"Disclosures about Fair Value of Financial Instruments." The estimated fair
value amounts have been determined by the Predecessor Companies, 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 Predecessor Companies
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.
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
--------------------------- -------------------------
CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR
AMOUNT VALUE AMOUNT VALUE
---------- -------------- -------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents.............. $ 168 $ 168 $ 792 $ 792
Accounts receivable.................... 240,114 240,114 464,133 464,133
Notes receivable....................... 15,096 15,294 21,866 22,582
Accounts payable....................... 217,182 217,182 450,205 450,205
Advances, net -- parents............... 334,057 334,057 1,579,475 1,579,475
Notes payable.......................... 641,600 601,606 690,480 655,843
Natural gas, NGL and oil hedge
contracts............................ -- 1,800 -- (63,500)
</TABLE>
The fair value of cash and cash equivalents, accounts receivable, and
accounts payable are not materially different from their carrying amounts
because of the short-term nature of these instruments or the stated rates
approximating market rates.
70
<PAGE> 71
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
Notes receivable is carried in the accompanying balance sheet at cost. Fair
value has been estimated using discounted cash flows assuming current interest
rates, similar credit risk and maturities.
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.
11. COMMITMENTS AND CONTINGENT LIABILITIES
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 Predecessor Companies
are currently named as defendants in certain of these cases. Management believes
the Predecessor Companies 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.
The Predecessor Companies are subject to federal, state and local
regulations regarding air and water quality, hazardous and solid waste disposal
as well as other environmental matters. The Predecessor Companies are not aware
of any material violations and have accrued for the known remediation that is in
process. In connection with the UP Fuels acquisition, the Predecessor Companies
analyzed water and soil samples surrounding UP Fuels facilities and identified
necessary remedial actions. The Predecessor Companies transferred this
obligation to a third party for a payment of approximately $48 million.
Generally, environmental liabilities are not expected to be recoverable from
insurance or other third parties.
The Predecessor Companies utilize assets under operating leases in several
areas of operation. Combined rental expense amounted to $8.1 million, $8.2
million and $11.8 million in 1997, 1998 and 1999, respectively. Minimum rental
payments under the Predecessor Companies' various operating leases for the years
2000 through 2004 are $6.1, $6.0, $5.0, $5.0 and $4.3 million, respectively.
Thereafter, payments aggregate $15.4 million through 2011.
71
<PAGE> 72
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
12. STOCK-BASED COMPENSATION, PENSION AND OTHER BENEFITS
Under Duke Energy's 1999 Stock Incentive Plan, stock options of Duke
Energy's common stock may be granted to key employees of the Predecessor
Companies. Under the plan, the exercise price of each option granted equals 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 exercise term of ten years. The
following tables set forth information regarding options to purchase Duke
Energy's common stock granted to employees of the Predecessor Companies.
Stock Option Activity
<TABLE>
<CAPTION>
WEIGHTED
OPTIONS AVERAGE
(IN THOUSANDS) EXERCISE PRICE
-------------- --------------
<S> <C> <C>
Outstanding at December 31, 1996............................ 254 $20
Granted................................................... 25 44
Exercised................................................. (54) 18
Forfeited................................................. -- --
----- ---
Outstanding at December 31, 1997............................ 225 23
Granted................................................... 279 55
Exercised................................................. (70) 21
Forfeited................................................. -- --
----- ---
Outstanding at December 31, 1998............................ 434 44
Granted................................................... 878 53
Exercised................................................. (33) 25
Forfeited................................................. (18) 55
----- ---
Outstanding at December 31, 1999............................ 1,261 51
</TABLE>
Stock Options at December 31, 1999
<TABLE>
<CAPTION>
OUTSTANDING EXERCISABLE
---------------------------------------- -------------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF AVERAGE AVERAGE AVERAGE
EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE
PRICES (IN THOUSANDS) LIFE (YEARS) PRICE (IN THOUSANDS) PRICE
-------- -------------- ------------ -------- -------------- --------
<S> <C> <C> <C> <C> <C>
$10 to $14 16 1.5 $11 16 $ 11
$15 to $20 52 3.9 18 52 18
$21 to $25 25 5.1 23 25 23
$26 to $31 10 6.1 27 10 27
$42 to $50 474 9.8 49 22 44
$55 to $60 684 8.8 56 66 55
----- ---
Total 1,261 191 34
</TABLE>
There were 29,646 and 82,050 options exercisable at December 31, 1997 and
1998 with a weighted average exercise price of $21 and $22 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, $9.00 and $10.00 per option during 1997,
1998 and 1999, respectively. The fair value of each option granted was estimated
on the date of grant using the Black-Scholes option-pricing model. The
weighted-average assumptions for option-pricing in 1997, 1998 and
72
<PAGE> 73
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
1999 were: stock dividend yield of 3.5%, 4.2% and 4.1%, expected stock price
volatility of 20.7%, 15.1% and 18.8% and risk-free interest rates of 6.5%, 5.6%
and 5.9%, respectively. The expected option life for 1997, 1998 and 1999 was
seven years. Stock-based compensation expense calculated using the Black-Scholes
option-pricing model for 1997, 1998 and 1999 would have been $0.1 million, $0.8
million and $2.5 million, respectively and net income would have been $51.1
million, $1.5 million and $41.8 million, respectively.
In addition, Duke Energy granted restricted shares of Duke Energy common
stock to key employees of the Predecessor Companies under Duke Energy stock
incentive plans. Grants under the plans vest over periods ranging from one to
seven years. In 1997 and 1999 Duke Energy awarded 2,817 shares (fair value at
grant dates of approximately $168,000) and 36,300 shares (fair value at grant
dates of approximately $2 million) to key employees of the Predecessor
Companies. No restricted shares were awarded in 1998. Compensation expense for
the stock grants is charged to the earnings of the Predecessor Companies over
the vesting period, and amounted to approximately $168,000, $0 and $488,000 in
1997, 1998 and 1999, respectively.
Duke Energy has, and the Predecessor Companies' participate in, a
non-contributory trustee pension plan which covers eligible employees with a
minimum of one year vesting service. The plan provides pension benefits for
eligible employees of the Predecessor Companies 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 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 Companies is as follows:
COMPONENTS OF NET PERIODIC PENSION COSTS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1997 1998 1999
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost................................................ $ 950 $ 911 $ 1,280
Interest cost............................................... 681 794 1,375
Expected return on plan assets.............................. (1,227) (1,391) (2,307)
Amortization of transition (asset)/liability................ (86) (86) (85)
Amortization of prior service cost.......................... 29 43 34
Amortization of (gains)/losses.............................. 6
Settlement gain............................................. (40)
------- ------- -------
Net periodic pension cost................................... $ 347 $ 231 $ 303
======= ======= =======
</TABLE>
73
<PAGE> 74
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED
RECONCILIATION OF FUNDED STATUS TO PRE-FUNDED PENSION COSTS
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1999
------- -------
(IN THOUSANDS)
<S> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year..................... $ 9,219 $14,651
Service cost................................................ 911 1,280
Interest cost............................................... 794 1,375
Intercompany transfers...................................... 802 8,519
Benefits paid............................................... (250) (190)
Actuarial (gains)/losses.................................... 3,261 (3,789)
Plan amendments............................................. (86)
------- -------
Benefit obligation at end of year........................... $14,651 $21,846
======= =======
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1999
------- -------
(IN THOUSANDS)
<S> <C> <C>
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year.............. $16,868 $20,211
Intercompany transfers...................................... 743 8,519
Actual return on plan assets................................ 2,580 4,985
Employer contributions...................................... 270 302
Benefits paid............................................... (250) (190)
------- -------
Fair value of plan assets at end of year.................... $20,211 $33,827
======= =======
Funded status............................................... $ 5,563 $11,982
Unrecognized net transition asset........................... (510) (425)
Unrecognized prior service cost............................. 302 268
Unrecognized gains.......................................... (794) (7,267)
------- -------
Pre-funded pension costs.................................... $ 4,561 $ 4,558
======= =======
</TABLE>
Intercompany transfers relate to benefit obligations and plan assets
associated with employees transferring between the Predecessor Companies and
other Duke Energy affiliates.
ASSUMPTIONS USED FOR PENSION BENEFIT ACCOUNTING
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
--------------------
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
Discount rate............................................... 7.25% 6.75% 7.50%
Rate of increase in compensation levels..................... 4.75% 4.67% 4.50%
Expected long-term rate of return on plan assets............ 9.25% 9.25% 9.25%
</TABLE>
The Predecessor Companies also sponsor an employee savings plan which
covers substantially all employees. During 1997, 1998 and 1999, the Predecessor
Companies expensed plan contributions of $1.6 million, $1.8 million and $3.6
million, respectively.
The Predecessor Companies' 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
1997, 1998 and 1999.
74
<PAGE> 75
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1999 2000
------------ -----------
(UNAUDITED)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 792 $ 172
Accounts receivable:
Customers, net......................................... 370,139 496,102
Affiliates............................................. 63,927 79,824
Other.................................................. 30,067 29,031
Receivable from parents -- working capital adjustments.... -- 12,616
Inventories............................................... 38,701 26,877
Notes receivable.......................................... 13,050 8,309
Other..................................................... 1,580 2,710
---------- ----------
Total current assets.............................. 518,256 655,641
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 2,409,385 4,424,525
INVESTMENT IN AFFILIATES.................................... 343,835 275,280
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net.................. 102,382 103,977
Goodwill, net............................................. 85,846 86,407
OTHER NONCURRENT ASSETS..................................... 12,131 79,955
---------- ----------
TOTAL ASSETS...................................... $3,471,835 $5,625,785
========== ==========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade.................................................. $ 353,977 $ 478,671
Affiliates............................................. 62,370 75,252
Other.................................................. 33,858 30,765
Accrued taxes other than income........................... 15,653 19,617
Advances, net............................................. 1,579,475 --
Distributions payable -- Parents.......................... -- 2,744,319
Notes payable -- affiliates............................... 588,880 --
Other..................................................... 6,372 30,927
---------- ----------
Total current liabilities......................... 2,640,585 3,379,551
DEFERRED INCOME TAXES....................................... 308,308 --
NOTE PAYABLE TO PARENT...................................... 101,600 --
OTHER LONG TERM LIABILITIES................................. 34,871 33,703
COMMITMENTS AND CONTINGENT LIABILITIES
EQUITY:
Common Stock.............................................. 1 --
Paid-in capital........................................... 213,091 --
Members' Interest......................................... -- 1,677,536
Retained earnings......................................... 173,091 534,991
Other comprehensive income................................ 288 4
---------- ----------
Total equity...................................... 386,471 2,212,531
---------- ----------
TOTAL LIABILITIES AND EQUITY................................ $3,471,835 $5,625,785
========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
75
<PAGE> 76
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF INCOME
MARCH 31, 1999 AND 2000
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
---------------------------------
MARCH 31, MARCH 31,
1999 2000
--------------- ---------------
<S> <C> <C>
OPERATING REVENUES:
Sales of natural gas and petroleum products............... $305,152 $1,415,465
Transportation, storage and processing.................... 29,845 35,746
-------- ----------
Total operating revenues.......................... 334,997 1,451,211
-------- ----------
COSTS AND EXPENSES:
Natural gas and petroleum products........................ 272,530 1,278,511
Operating and maintenance................................. 29,096 49,039
Depreciation and amortization............................. 20,029 38,094
General and administrative................................ 16,112 29,701
Net (gain) loss on sale of assets......................... (42) 239
-------- ----------
Total costs and expenses.......................... 337,725 1,395,584
-------- ----------
OPERATING INCOME (LOSS)..................................... (2,728) 55,627
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES............. 3,286 6,759
-------- ----------
EARNINGS BEFORE INTEREST AND TAXES.......................... 558 62,386
INTEREST EXPENSE............................................ 12,445 14,477
-------- ----------
INCOME (LOSS) BEFORE INCOME TAXES........................... (11,887) 47,909
INCOME TAX EXPENSE (BENEFIT)................................ (3,366) (313,991)
-------- ----------
NET INCOME (LOSS)........................................... $ (8,521) $ 361,900
======== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
76
<PAGE> 77
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF EQUITY
THREE MONTH PERIOD ENDED MARCH 31, 2000
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL OTHER
COMMON PAID-IN MEMBERS' RETAINED COMPREHENSIVE
STOCK CAPITAL INTEREST EARNINGS INCOME TOTAL
------ ---------- ----------- -------- ------------- -----------
<S> <C> <C> <C> <C> <C> <C>
Balance, January 1, 2000............. $ 1 $ 213,091 $ -- $173,091 $ 288 $ 386,471
Combination at March 31,
2000 -- see Note 2
Contribution of TEPPCO general
partnership interest........... 2,265 2,265
Contribution of DEFS Inc. and
DEFSCL to DEFS, LLC............ (1) (215,356) 215,357 --
Contribution of notes and
advances payable............... 2,286,698 2,286,698
Contributions of GPM assets and
liabilities.................... 1,919,800 1,919,800
Distributions.................... (2,744,319) (2,744,319)
Net income......................... 361,900 361,900
Other.............................. (284) (284)
--- --------- ----------- -------- ----- -----------
Balance, March 31, 2000.............. $-- $ -- $ 1,677,536 $534,991 $ 4 $ 2,212,531
=== ========= =========== ======== ===== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
77
<PAGE> 78
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
MARCH 31, 1999 AND 2000
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
------------------------
MARCH 31, MARCH 31,
1999 2000
----------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ (8,521) $ 361,900
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization.......................... 20,029 38,094
Deferred income tax expense (benefit).................. 6,780 (308,230)
Equity in earnings of unconsolidated affiliates........ (3,286) (6,759)
Loss (gain) on sale of assets.......................... (42) 239
Net change in operating assets and liabilities:
Accounts receivable.................................... (66,206) 80,530
Inventories............................................ 1,757 (13,843)
Other current assets................................... 18,625 114,328
Other non-current assets............................... 16,610 3,016
Accounts payable....................................... 51,536 (54,910)
Other current liabilities.............................. (12,914) (10,132)
Other long term liabilities............................ -- (19,436)
----------- ---------
Net cash provided by operating activities......... 24,368 184,797
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions and other capital expenditures............... (1,443,961) (129,591)
Investment expenditures................................... (21,606) (521)
Investment distributions.................................. 7,379 5,662
Proceeds from sales of assets............................. -- 13,031
----------- ---------
Net cash used in investment activities............ (1,458,188) (111,419)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in advances -- parents............ 1,391,328 (73,998)
Proceeds from issuing debt................................ 42,368 --
----------- ---------
Net cash flows provided by (used in) financing
activities...................................... 1,433,696 (73,998)
NET DECREASE IN CASH AND CASH EQUIVALENTS:.................. (124) (620)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.............. 168 792
----------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................... $ 44 $ 172
----------- ---------
</TABLE>
See Notes to Consolidated Financial Statements.
78
<PAGE> 79
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
(UNAUDITED)
1. GENERAL
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.
Effective March 31, 2000, and in connection with the Combination (see Note
2), Duke Energy Field Services, Inc. (DEFS Inc.) was converted to a limited
liability company, and was contributed by Duke Energy Corporation (Duke Energy)
to the Company as a wholly-owned subsidiary. Also on March 31, 2000, Duke Energy
contributed Duke Energy Field Services Canada, Ltd. (DEFSCL) to Field Services
LLC. As a result of these contributions to the Company, the March 31, 2000
financial statements are reflected as consolidated.
The interim consolidated financial statements presented herein should be
read in conjunction with the combined financial statements and notes thereto of
Duke Energy Field Services, LLC and Affiliates. In the opinion of management,
all adjustments necessary for a fair presentation of the results for the
unaudited interim periods have been made. Except as explicitly noted, these
adjustments consist solely of normal recurring accruals.
2. COMBINATION
On March 31, 2000, the natural gas gathering, processing and natural gas
liquid 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 Duke Energy were
eliminated and contributed to equity. Also on March 31, 2000, Phillips Petroleum
Company (Phillips) contributed its midstream natural gas gathering, processing
and natural gas liquid operations to Field Services LLC. This contribution and
Duke Energy's contribution to Field Services LLC are referred to as the
"Combination." In exchange for the contributions, Duke Energy received 69.7% of
the member interests in Field Services LLC, with Phillips holding the remaining
30.3% of the outstanding member interests.
The Combination has been accounted for as a purchase business combination
in accordance with Accounting Principles Board Opinion (APB) No. 16 "Accounting
for Business Combinations". The Phillips assets, net of liabilities, have been
valued at $1,919.8 million. Following is a summary of the preliminary allocation
of purchase price (in millions):
<TABLE>
<S> <C>
Property, plant and equipment............................... $1,878.4
Other assets, net........................................... 41.4
--------
Total purchase price.............................. $1,919.8
========
</TABLE>
The purchase price has not yet been fully allocated to the individual
assets and liabilities acquired. The final allocation will be determined based
on independent appraisals.
In connection with the Combination, the Company has recorded a non-interest
bearing distribution payable to Phillips of $1,219.8 million and a non-interest
bearing distribution payable to Duke Energy of $1,524.5 million.
Working Capital Adjustments -- In connection with the Combination, Duke
Energy and Phillips each will either make contributions to Field Services LLC,
or receive distributions from Field Services LLC so that
79
<PAGE> 80
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
each of Duke Energy and Phillips will have contributed to Field Services LLC net
working capital positions equal to zero as of March 31, 2000.
Pro Forma Disclosures -- Revenues for the three months ended March 31, 1999
and 2000, on a pro forma basis would have increased $264.9 million and $542.4
million, respectively, and net income for the three months ended March 31, 1999
and 2000, on a pro forma basis would have decreased $18.7 million and increased
$65.7, respectively, if the acquisition of the Phillips midstream business had
occurred at the beginning of the period presented.
TEPPCO General Partner Interest -- On March 31, 2000, and in connection
with the Combination, Duke Energy contributed the general partner interest of
TEPPCO Partners L.P. to Field Services LLC. In connection with the contribution
of the general partner interest in TEPPCO, the Company recorded an investment in
TEPPCO of $2.3 million and increased stockholders' equity by $2.3 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 1999 per unit
distribution level, the general partner received approximately 14% of the cash
distributed by TEPPCO to its partners. Due to the general partner's share of
unit distributions and control exercised through its management of the
partnership, the Company's investment in TEPPCO is accounted for under the
equity method.
3. INCOME TAXES
At March 31, 2000 the Company converted to the limited liability company
which is a pass-through entity for income tax purposes. As a result, the
existing net deferred tax liability ($333 million) was eliminated with a
corresponding income tax benefit recorded.
4. ACQUISITIONS
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 Corporation, for a total
purchase price of $1,359 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 three
months ended March 31, 1999 on a pro forma basis would have increased $298
million and $3.4 million respectively, if the acquisition of UP Fuels had
occurred on January 1, 1999.
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 $99.5 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
reported in connection with the exchange.
5. AGREEMENTS AND TRANSACTIONS WITH DUKE ENERGY
Services Agreement with Duke Energy -- Effective with the Combination, the
Company entered into a services agreement with Duke Energy ("the Duke Energy
Services Agreement"). Under the Duke Energy Services Agreement, Duke Energy will
provide the Company with various staff and support services, including
information technology products and services, payroll, employee benefits,
corporate insurance, cash management, ad valorem taxes, treasury and legal
functions and shareholder services. These services will be priced on
80
<PAGE> 81
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
the basis of a monthly charge approximating market prices. The Duke Energy
Services Agreement expires on December 31, 2000.
Transactions between Duke Energy and the Company -- Through March 31, 2000,
the Company has conducted a series of transactions with Duke Energy in which the
Company has sold a portion of its residue gas and NGLs to, purchased raw natural
gas and other petroleum products from, and provided gathering and transportation
services over its gathering systems and pipelines to, Duke Energy and its
subsidiaries at contractual prices that have approximated market prices in the
ordinary course of the Company's business. The Company anticipates continuing
these transactions in the ordinary course of business.
6. 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 Phillips Services
Agreement expires on December 31, 2000.
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 ("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 approximately 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 Basis 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, Phillips Combined
Subsidiaries purchased raw natural gas from Phillips at contractual prices that
have approximated market prices. The Company anticipates continuing these
transactions in the ordinary course of business.
7. 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 will be 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 on such date, and to meet working capital requirements. The
credit facility matures on March 30, 2001, and bears interest at a rate equal
to, at Field Services LLC's option, either (1) the London Interbank Offered Rate
(LIBOR) plus .50% per year for the first 90 days following March 31, 2000 and
LIBOR plus .625% per year thereafter, or (2) the higher of (a) the Bank of
America prime rate and (b) the Federal Funds rate plus .50% per year.
81
<PAGE> 82
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
8. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
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, 1999 and 2000, the Company recorded a hedging gain of $4.0 million and
a hedging loss of $46.7 million, respectively, under Duke Energy's centralized
program. As of March 31, 2000, the existing commodity positions held under the
Duke Energy 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 plans to use 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; (2) avoiding
disruption of the Company's growth capital and value creation process; and (3)
retaining a high percentage of the potential upside relation to commodity price
increases. The Company has implemented a risk management policy that provides
guidelines for entering into contractual arrangements to manage commodity price
exposure. Futures and swaps will be used to manage and hedge prices related to
these market exposures.
In establishing its initial independent commodity risk management position,
on April 1, 2000 the Company acquired a portion of Duke Energy's existing
commodity derivatives held for non trading purposes. The absolute notional
contract quantity of the positions acquired was 4,607,000 barrels of crude oil.
Such positions were acquired at market value.
9. COMMITMENTS AND CONTINGENT LIABILITIES
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.
10. PENSION AND OTHER BENEFITS
Effective March 31, 2000, participation by the Company's employees in Duke
Energy's non-contributory trustee pension 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.
11. BUSINESS SEGMENTS
The Company operates in two principal business segments as follows: (1)
natural gas gathering, processing, transportation, marketing and storage, and
(2) natural gas liquids 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
82
<PAGE> 83
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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.
The following table sets forth the Company's segment information for the
three months ended March 31, 1999 and 2000 and as of December 31, 1999 and March
31, 2000.
<TABLE>
<CAPTION>
FOR THE THREE MONTH PERIODS
ENDED
-------------------------------
MARCH 31, MARCH 31,
1999 2000
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Operating revenues:
Natural Gas............................................... $ 308,326 $ 899,214
NGLs...................................................... 72,582 798,816
Intersegment(a)........................................... (45,911) (246,819)
---------- ----------
Total operating revenues.......................... 334,997 1,451,211
---------- ----------
Margin:
Natural Gas............................................... 61,711 147,856
NGLs...................................................... 756 24,844
---------- ----------
Total margin...................................... 62,467 172,700
---------- ----------
Other operating costs:
Natural Gas............................................... 29,040 48,729
NGLs...................................................... 14 549
Corporate................................................. 16,112 29,701
---------- ----------
Total other operating costs....................... 45,166 78,979
---------- ----------
Equity in earnings of unconsolidated affiliates:
Natural Gas............................................... 3,286 6,514
NGLs...................................................... 245
---------- ----------
Total equity in earnings of unconsolidated
affiliates...................................... 3,286 6,759
---------- ----------
EBITDA(b):
Natural Gas............................................... 35,957 105,641
NGLs...................................................... 742 24,540
Corporate................................................. (16,112) (29,701)
---------- ----------
Total EBITDA...................................... 20,587 100,480
---------- ----------
Depreciation and amortization:
Natural Gas............................................... 19,456 34,225
NGLs...................................................... -- 3,027
Corporate................................................. 573 842
---------- ----------
Total depreciation and amortization............... 20,029 38,094
---------- ----------
EBIT:
Natural Gas............................................... 16,501 71,416
NGLs...................................................... 742 21,513
Corporate................................................. (16,685) (30,543)
---------- ----------
Total EBIT........................................ 558 62,386
---------- ----------
</TABLE>
83
<PAGE> 84
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
<TABLE>
<CAPTION>
FOR THE THREE MONTH PERIODS
ENDED
-------------------------------
MARCH 31, MARCH 31,
1999 2000
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Corporate interest expense.................................. 12,445 (353,102)
---------- ----------
Income before income taxes:
Natural gas............................................... 16,501 71,416
NGLs...................................................... 742 21,513
Corporate................................................. (29,130) (45,020)
---------- ----------
Total income (loss) before income taxes........... $ (11,887) $ 47,909
========== ==========
</TABLE>
<TABLE>
<CAPTION>
AS OF
----------------------------------
DECEMBER 31, MARCH 31,
1999 2000
-------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Total assets:
Natural Gas............................................... $2,754,447 $4,726,148
NGLs...................................................... 225,702 191,337
Corporate(c).............................................. 491,686 708,300
---------- ----------
Total assets...................................... $3,471,835 $5,625,785
========== ==========
</TABLE>
---------------
(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, less
interest income. EBITDA is not a measurement presented in accordance with
generally accepted accounting principles. You should not consider it 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.
(c) Includes items such as unallocated working capital, intercompany accounts
and intangible and other assets.
84
<PAGE> 85
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholder
Phillips Gas Company
We have audited the accompanying consolidated balance sheets of Phillips
Gas Company as of December 31, 1998 and 1999, and the related consolidated
statements of income, changes in stockholders' equity (deficit) and cash flows
for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Phillips Gas
Company at December 31, 1998 and 1999, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 6, 2000
85
<PAGE> 86
PHILLIPS GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
AT DECEMBER 31,
-----------------------
1998 1999
---------- ----------
<S> <C> <C>
ASSETS
Cash and cash equivalents................................... $ 27,045 $ 164,078
Accounts receivable
Affiliate................................................. 51,415 104,159
Trade (less allowances: 1998 -- $648; 1999 -- $329)....... 93,764 104,555
Inventories................................................. 4,957 3,066
Deferred income taxes....................................... 2,160 30,293
Prepaid expenses and other current assets................... 2,916 3,407
---------- ----------
Total Current Assets.............................. 182,257 409,558
Investments and long-term receivables....................... 13,013 9,585
Properties, plants and equipment (net)...................... 943,302 995,406
Deferred gathering fees..................................... 43,531 50,662
---------- ----------
Total............................................. $1,182,103 $1,465,211
========== ==========
LIABILITIES
Accounts payable
Affiliate................................................. $ 23,946 $ 106,410
Trade..................................................... 139,729 178,891
Deferred purchase obligation due within one year............ -- 8,300
Accrued income and other taxes.............................. 8,363 12,140
Other accruals.............................................. 212 63
---------- ----------
Total Current Liabilities......................... 172,250 305,804
Long-term debt due to affiliate............................. 560,000 1,350,000
Other liabilities and deferred credits...................... 4,908 3,065
Deferred income taxes....................................... 68,160 128,907
Deferred gain on sale of assets............................. 16,237 15,154
---------- ----------
Total Liabilities................................. 821,555 1,802,930
---------- ----------
STOCKHOLDER'S EQUITY/(DEFICIT)
Common stock -- 1,000 shares authorized at $.01 par value;
issued and outstanding -- 1,000 shares
Par value................................................. -- --
Capital in excess of par.................................. 142,917 --
Retained earnings/(accumulated deficit)..................... 217,631 (337,719)
---------- ----------
Total Stockholder's Equity/(Deficit).............. 360,548 (337,719)
---------- ----------
Total............................................. $1,182,103 $1,465,211
========== ==========
</TABLE>
See Notes to Financial Statements.
86
<PAGE> 87
PHILLIPS GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
REVENUES
Natural gas liquids...................................... $ 711,785 $ 514,758 $ 714,439
Residue gas.............................................. 923,376 722,931 786,739
Other.................................................... 80,994 68,919 90,234
---------- ---------- ----------
Total Revenues................................. 1,716,155 1,306,608 1,591,412
---------- ---------- ----------
COSTS AND EXPENSES
Gas purchases............................................ 1,268,570 940,464 1,148,910
Operating expenses....................................... 190,385 186,572 176,864
Selling, general and administrative expenses............. 14,990 13,290 15,560
Depreciation............................................. 76,737 77,240 80,458
Interest expense......................................... 20,468 36,194 35,643
---------- ---------- ----------
Total Costs and Expenses....................... 1,571,150 1,253,760 1,457,435
---------- ---------- ----------
Income before income taxes............................... 145,005 52,848 133,977
Provision for income taxes............................... 54,998 21,535 52,244
---------- ---------- ----------
NET INCOME............................................... 90,007 31,313 81,733
Preferred stock dividend requirements.................... 30,813 -- --
---------- ---------- ----------
NET INCOME APPLICABLE TO COMMON STOCK.................... $ 59,194 $ 31,313 $ 81,733
========== ========== ==========
</TABLE>
See Notes to Financial Statements.
87
<PAGE> 88
PHILLIPS GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................ $ 90,007 $ 31,313 $ 81,733
Adjustments to reconcile net income to net cash provided
by operating activities
Non-working capital adjustments
Depreciation......................................... 76,737 77,240 80,458
Deferred taxes....................................... 38,700 41,550 60,747
Deferred gathering fees.............................. (7,803) (7,231) (7,131)
Gain on sale of assets............................... (1,965) (9,848) (907)
Other................................................ (2,119) (6,795) 644
Working capital adjustments
Decrease (increase) in accounts receivable........... 70,180 27,847 (63,465)
Decrease (increase) in inventories................... (798) 2,259 1,891
Decrease (increase) in prepaid expenses and other
current assets, including deferred taxes........... (1,654) 3,084 (28,624)
Increase (decrease) in accounts payable.............. (30,027) (98,776) 121,626
Increase (decrease) in taxes and other accruals...... (12,712) (6,191) 3,628
--------- --------- ---------
Net Cash Provided by Operating Activities................. 218,546 54,452 250,600
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and investments...................... (116,520) (83,152) (124,009)
Proceeds from asset dispositions.......................... 5,499 17,611 442
--------- --------- ---------
Net Cash Used for Investing Activities.................... (111,021) (65,541) (123,567)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred stock dividends................................. (34,922) -- --
Redemption of preferred stock............................. (345,000) -- --
Issuance of debt.......................................... 345,000 -- 10,000
Repayment of debt......................................... -- (95,000) --
Payment of note payable................................... (18,500) -- --
--------- --------- ---------
Net Cash Provided by (Used for) Financing Activities...... (53,422) (95,000) 10,000
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...... 54,103 (106,089) 137,033
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR.............. 79,031 133,134 27,045
--------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR.................... $ 133,134 $ 27,045 $ 164,078
========= ========= =========
</TABLE>
See Notes to Financial Statements.
88
<PAGE> 89
PHILLIPS GAS COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY/(DEFICIT)
(IN THOUSANDS)
<TABLE>
<CAPTION>
SHARES COMMON STOCK RETAINED
-------------------- --------------------- EARNINGS/
PREFERRED COMMON PREFERRED PAR CAPITAL IN (ACCUMULATED
STOCK STOCK STOCK VALUE EXCESS OF PAR DEFICIT)
----------- ------ --------- ----- ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
December 31, 1996............ 13,800,000 1,000 $ 345,000 -- $ 142,917 $ 131,233
Net income................... 90,007
Cash dividends paid on
preferred stock............ (34,922)
Redemption of preferred
stock...................... (13,800,000) (345,000)
----------- ----- --------- -- --------- ---------
December 31, 1997............ -- 1,000 -- -- 142,917 186,318
Net income................... 31,313
----------- ----- --------- -- --------- ---------
December 31, 1998............ -- 1,000 -- -- 142,917 217,631
Net income................... 81,733
Dividend declared............ (142,917) (637,083)
----------- ----- --------- -- --------- ---------
December 31, 1999............ -- 1,000 $ -- -- $ -- $(337,719)
=========== ===== ========= == ========= =========
</TABLE>
See Notes to Financial Statements.
89
<PAGE> 90
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Consolidation Principles and Basis of Presentation -- Phillips Gas Company
(PGC or the company) is a subsidiary of Phillips Petroleum Company (Phillips).
Phillips owns 100 percent of the company's outstanding common stock.
Majority-owned, controlled subsidiaries are consolidated. Investments in
affiliates in which the company owns 20 percent to 50 percent of voting control
are accounted for using the equity method.
Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires Management to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and the disclosures of contingent assets and
liabilities. Actual results could differ from the estimates and assumptions
used.
Cash and Cash Equivalents -- Cash and cash equivalents are held by Phillips
as part of its centralized cash management system. Interest is paid monthly
based on the average daily balance of funds invested at a rate equal to the
weighted-average rate earned by Phillips or at the applicable federal funds
rate.
Cash equivalents are highly liquid short-term investments that are readily
convertible to known amounts of cash and have original maturities within three
months from their date of purchase.
Inventories -- Helium inventory is valued at cost, which is lower than
market, mainly on the last-in, first-out (LIFO) basis. Materials and supplies
are valued at, or below, average cost.
Derivative Contracts -- The company uses commodity swap and option
contracts. Commodity option contracts are recorded at market value through
monthly adjustments for unrealized gains and losses; however, swaps are not
marked to market. Gains and losses are recognized during the same period in
which the gains and losses from the underlying exposures being hedged are
recognized. In 1998 and 1999, the net realized and unrealized gains and losses
from derivative contracts were not material to the company's financial
statements.
Revenue Recognition -- Revenues associated with sales of natural gas,
natural gas liquids, and all other items are recorded when title passes to the
customer upon delivery.
Gas Exchanges and Imbalances -- Quantities of gas over-delivered or
under-delivered related to exchange or imbalance agreements are recorded monthly
as receivables or payables using the index price or the average price of gas at
the plant or system. Generally, these balances are settled with deliveries of
gas.
Depreciation -- Depreciation of plants and systems is determined using the
group composite straight-line method over an estimated life of 20 years for most
of the assets. Plants and systems are grouped for this purpose based on their
relative similarity and the degree of physical and economic interdependence
between individual pieces of equipment. Other relatively insignificant
properties and equipment are depreciated using the straight-line method over the
estimated useful lives of the individual assets.
Impairment of Assets -- Long-lived assets used in operations are assessed
for impairment whenever changes in facts and circumstances indicate a possible
significant deterioration in the future cash flows expected to be generated by
an asset group. If, upon review, the sum of the undiscounted pretax cash flows
are less than the carrying value of the asset group, the carrying value is
written down to estimated fair value.
The expected future cash flows used for impairment reviews and related fair
value calculations are based on the production volumes, prices and costs
considering all available evidence at the date of the review.
Property Dispositions -- When complete units of depreciable property are
retired or sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in income. When less than complete
units of depreciable property are disposed of or retired, the difference between
asset cost and salvage value is charged or credited to accumulated depreciation
with no recognition of gain or loss. Retirements or sales of equipment, whether
complete units of depreciable property or less than complete units of
depreciable property, have been infrequent and not significant to the financial
statements.
90
<PAGE> 91
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
Environmental Costs -- Environmental expenditures are expensed or
capitalized as appropriate, depending upon their future economic benefit.
Expenditures that relate to an existing condition caused by past operations, and
that do not have future economic 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.
Income Taxes -- Deferred taxes are computed using the liability method and
provided on all temporary differences between the financial reporting basis and
the tax basis of the assets and liabilities. Allowable tax credits are applied
currently as reductions of the provision for income taxes. The company's results
of operations for 1998 and 1999 were included in the consolidated federal income
tax return of Phillips, with any resulting tax liability or refund settled with
Phillips on a current basis. Income tax expense represents amounts due Phillips
for federal income taxes as if the company were filing a separate return, except
that the same principles and elections used in the consolidated return were
applied. Results of operations for 1997 were included in the separate federal
income tax return of Phillips Gas Company.
Income Per Share of Common Stock -- Income per share of common stock has
been omitted from the consolidated statement of income because all common stock
is owned by Phillips.
Comprehensive Income -- The company does not have any items of other
comprehensive income, as defined in Financial Accounting Standards Board (FASB)
Statement No. 130, "Reporting Comprehensive Income."
2. THE COMPANY'S BUSINESS
The company owns and operates natural gas gathering systems and processing
facilities concentrated in four major gas-producing areas in the Southwest. The
company's core gathering and processing regions are concentrated in the Permian
Basin area of West Texas and southeastern New Mexico, the Panhandle areas of
Texas and Oklahoma, and central and western Oklahoma. Under FASB Statement No.
131, "Disclosures about Segments of an Enterprise and Related Information," the
four regions have been aggregated into a single segment for financial reporting
purposes. At December 31, 1999, the company wholly owned 15 natural gas liquids
extraction plants, and had an interest in another. The plants are located in
Texas (9), Oklahoma (3), and New Mexico (4). During 1999, the company purchased
a co-venturer's interest in the Artesia plant and gathering system in New Mexico
that the company had operated under a construction and operating agreement since
1959.
The company sells substantially all of its natural gas liquids to Phillips.
The company is able to interconnect to major gas transmission pipelines in each
of its regions in order to sell residue gas to local distribution companies,
electric utilities, various other business and industrial users and marketers.
The company's major residue gas markets are located primarily in Texas, Oklahoma
and the midwestern United States.
3. INVENTORIES
Inventories at December 31 consisted of the following:
<TABLE>
<CAPTION>
1998 1999
------ ------
(IN THOUSANDS)
<S> <C> <C>
Helium...................................................... $1,027 $ --
Materials, supplies and other............................... 3,930 3,066
------ ------
$4,957 $3,066
====== ======
</TABLE>
91
<PAGE> 92
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
The company's helium inventory was sold in March 1999 for $4,989,000,
resulting in after-tax income of $2,575,000.
4. INVESTMENTS AND LONG-TERM RECEIVABLES
Components of investments and long-term receivables at December 31 were as
follows:
<TABLE>
<CAPTION>
1998 1999
------- ------
(IN THOUSANDS)
<S> <C> <C>
Investment in affiliated company............................ $ 3,328 $3,421
Long-term receivables....................................... 9,685 6,164
------- ------
$13,013 $9,585
======= ======
</TABLE>
In 1993 the company formed GPM Gas Gathering L.L.C. (GGG), a limited
liability company in which PGC invested approximately $4 million in exchange for
a 50 percent equity interest. In December 1993, the company sold a portion of
its gas gathering assets in the West Texas region of the Permian Basin to GGG
for $138 million. GGG is providing gas gathering services to the company under a
twenty-year contract. This contract does not represent a take-or-pay or
unconditional purchase obligation. Because of the company's continuing
involvement in GGG, a $22 million gain from the sale of the assets was deferred
and is being recognized over the economic life of the gathering assets. The
deferred gain recognized during 1998 and 1999 was $1,082,000 and $1,083,000,
respectively. Distributions received from GGG during 1998 and 1999 were
$1,153,000 and $955,000 respectively. See Note 10 for the gathering fees paid by
the company to GGG under this contract.
5. PROPERTIES, PLANTS AND EQUIPMENT
Properties, plants and equipment (net) at December 31 included the
following:
<TABLE>
<CAPTION>
USEFUL LIFE 1998 1999
----------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Gathering.................................... 15-20 Years $1,529,026 $1,657,605
Processing................................... 15-20 Years 561,170 591,127
Work in progress............................. 42,694 6,484
Other........................................ 3-5 Years 10,670 11,788
---------- ----------
Total property, plant & equipment (at
cost)...................................... 2,143,560 2,267,004
Less accumulated depreciation and
amortization............................... 1,200,258 1,271,598
---------- ----------
$ 943,302 $ 995,406
========== ==========
</TABLE>
6. DEBT
Long-term debt due to affiliate at December 31 was:
<TABLE>
<CAPTION>
1998 1999
-------- ----------
(IN THOUSANDS)
<S> <C> <C>
Note due 2001............................................... $215,000 $ 225,000
Note due 2002............................................... -- 780,000
Note due 2005............................................... 345,000 345,000
-------- ----------
$560,000 $1,350,000
======== ==========
</TABLE>
92
<PAGE> 93
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
On December 9, 1999, Phillips Gas Company declared and distributed a
dividend to Phillips in the form of a note payable in the amount of $780
million. The note payable is due in full at maturity on December 9, 2002, bears
interest at a rate of 5.74 percent per annum, and may be paid prior to maturity
at any time without penalty or premium. The amount of the dividend exceeded the
company's historical-cost-based net assets, resulting in a negative balance in
stockholder's equity.
The declaration and payment of dividends is at the discretion of the
company's Board of Directors. In connection with each dividend declaration, the
Board of Directors makes a determination that, based upon its familiarity with
the company's business, prospects and financial condition, the company's recent
earnings history and forecast, an appraisal of the company's assets and
discussions with the company's executive officers, attorneys and accountants,
the dividend is a permitted dividend under Delaware law. This determination was
made prior to the declaration of the $780 million dividend made on December 9,
1999.
The note due 2001 bears interest at LIBOR plus 1/2 percent per annum (6.33
percent at December 31, 1999). Any amount repaid may be reborrowed as long as
the agreement is in effect. The note due 2005 bears interest at the applicable
federal mid-term rate (6.03 percent monthly rate for December 1999). The
carrying amount of the floating-rate debt approximates fair value.
7. FINANCIAL INSTRUMENTS
Concentrations of Credit Risk
The company's financial instruments that are exposed to concentrations of
credit risk consist primarily of cash equivalents, accounts receivable and
over-the-counter derivative contracts. Derivative contracts are immaterial to
the financial statements of the company.
The company's cash and cash equivalents are held by Phillips as part of its
centralized cash management system. Cash equivalents are in high-quality
securities placed with major international banks and financial institutions.
Phillips' investment policy limits the company's exposure to concentrations of
credit risk with respect to its cash equivalent investments.
The company's affiliate receivables result primarily from its sales of
natural gas liquids and residue gas to Phillips. The company's trade receivables
result primarily from domestic sales of residue gas to local distribution
companies, electric utilities, various other business and industrial end-users,
and marketers. The company routinely assesses the financial strength of its
unaffiliated residue-gas customers. The company considers its concentrations of
credit risk, other than those with Phillips, to be limited.
Fair Values of Financial Instruments
The following methods and assumptions were used by the company in
estimating the fair value of its financial instruments:
Cash and cash equivalents: The carrying amount reported in the balance
sheet approximates fair value because of the short-term nature of these
investments.
Deferred purchase obligation due within one year: The carrying amount
reported in the balance sheet approximates fair value because of the
short-term nature of the obligation.
Long-term debt: The carrying amount of the company's floating- and
fixed-rate debt approximates fair value based on current market rates.
93
<PAGE> 94
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
8. PREFERRED STOCK
On December 15, 1997, the company redeemed its 13,800,000 shares of Series
A 9.32% Cumulative Preferred Stock at par. The liquidation value for each Series
A preferred share was $25, plus $.2006 for unpaid dividends.
9. CONTINGENT LIABILITIES
The company is a party to a number of legal proceedings pending in various
courts or agencies for which no provision has been made. Costs related to
contingencies are provided when a loss is probable and the amount can be
reasonably estimated. These accruals are not discounted for delays in future
payment and are not reduced for potential insurance recoveries. If applicable,
undiscounted receivables are accrued for probable insurance recoveries.
A judgment has been entered in the case of Chevron U.S.A., Inc. versus GPM
Gas Corporation (GPM), a wholly owned subsidiary of the company, upholding and
construing most favored nations clauses in three 1961 West Texas gas purchase
contracts. Although a federal district court decided that GPM owes Chevron
damages in the amount of $13,828,030 through July 31, 1998, plus 6 percent
interest from that date and attorneys' fees in the amount of $329,994, GPM has
appealed the judgment to the U.S. Court of Appeals for the Fifth Circuit.
Based on currently available information, after taking into consideration
amounts already accrued and the pending appeal in the Chevron litigation, PGC
believes that any liability resulting from any of the above matters will not
have a material adverse effect on its financial statements. However, such
matters could have a material effect on results of operations in a particular
quarter or fiscal year as they develop or as new issues are identified.
10. RELATED PARTY TRANSACTIONS
Significant transactions with affiliated parties were:
<TABLE>
<CAPTION>
1997 1998 1999
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues(a)................................ $758,700 $537,528 $725,478
Gas purchases(b)..................................... 118,827 76,617 100,253
Operating expenses(c)(e)(h).......................... 115,698 113,475 110,897
Selling, general and administrative
expenses(c)(d)(e).................................. 12,828 10,059 13,306
Interest income(f)................................... 2,701 2,430 2,487
Interest expense(g).................................. 20,340 35,880 35,610
</TABLE>
------------
(a) The company sells a portion of its residue gas and other by-products to
Phillips at contractual prices that approximate market prices. The company
sells substantially all of its natural gas liquids to Phillips at prices
based upon quoted market prices for fractionated natural gas liquids, less
charges for transportation, fractionation and quality-adjustment fees.
Effective January 1, 2000, the pricing formula contained in the natural gas
liquids supply arrangement with Phillips was renegotiated, as allowed under
the contract, to reflect current market conditions. The new arrangement
will be maintained for an initial term of 15 years. PGC believes that the
loss of Phillips as a natural gas liquids customer would have a material,
adverse effect on its revenues and operating results.
(b) The company purchases raw gas from Phillips at contractual prices that
approximate market prices. During 1999, Phillips provided the company with
approximately 8 percent of its raw gas throughput, under long-term supply
contracts, making Phillips its largest single supplier. PGC believes that
the loss of
94
<PAGE> 95
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
Phillips as a raw gas supplier would have a material adverse effect on its
dedicated raw gas supplies and its operating results.
(c) Phillips provides the company with various field services (costs included
in operating expenses) and other general administrative services (costs
included in selling, general and administrative expenses) including
insurance, personnel administration, office space, communications, data
processing, engineering, automotive and other field equipment, and other
miscellaneous services. Charges for these services and benefits are based
on usage and actual costs or other allocation methods the company considers
reasonable.
(d) Phillips charges the company a portion of its corporate indirect overhead
costs including executive, legal, treasury, planning, tax, auditing and
other corporate services, under an administrative services agreement.
Charges for these services and benefits are based on usage and actual costs
or other allocation methods the company considers reasonable.
(e) All operational and staff personnel requirements are met by Phillips'
employees, most of whom are associated with the GPM Gas Services Company
division of Phillips. All services provided by Phillips, including (c) and
(d) above, are priced to reimburse Phillips for its actual costs. Charges
for these services and benefits are based on usage and actual costs or
other allocation methods the company considers reasonable. Selling, general
and administrative expenses included a severance charge reversal of $2
million in 1998, and a $2 million severance charge in 1999.
(f) The company earns interest from participation in Phillips' centralized cash
management system.
(g) The company incurs interest expense on borrowings from and debt to
Phillips.
(h) Beginning January 1, 1994, the company began paying GGG a fee for gas
gathering services under a long-term contract. The gas gathering fee
structure in the long-term contract contains a component that is paid to
GGG in an accelerated manner. Because GGG is providing the same gas
gathering services to the company over the contract period, recognition of
expenses related to this component of the gathering fee is deferred and
recognized on a straight-line basis through the remaining period of the
long-term contract. In 1997, 1998 and 1999, the total gathering fees were
$42,755,000, $42,951,000 and $41,447,000, respectively, of which
$34,952,000, $35,720,000 and $34,316,000, respectively, were expensed.
The company provides Phillips with other minor administrative services.
Costs allocated to Phillips for these services have been netted against the
above direct charges from Phillips and were $120,000, $79,000 and $72,000 in
1997, 1998 and 1999, respectively.
The company periodically buys from, or sells to, Phillips various assets
used in the operations of the business. These net acquisitions were recorded at
the assets' historical net book values, which generally approximated fair market
value, and totaled $22,000, $60,000 and $239,000 in 1997, 1998 and 1999,
respectively. Prior to such acquisition or sale, the company paid or received a
fee based on usage of such assets (included in operating expenses above). In
addition, the company purchases plastic pipe from Phillips, which is used in the
construction of gathering systems. Purchases in 1997, 1998 and 1999 were
$3,942,000, $2,276,000 and $2,175,000, respectively.
11. EMPLOYEE BENEFIT PLANS
Substantially all employees of Phillips' GPM Gas Services Company division
participate in Phillips' benefit plans, including pension plans, defined
contribution plans, stock option plans and health and life insurance plans.
Costs are allocated to the company based principally on base payroll costs of
participating employees. Total benefit plan costs charged to the company were
$22,095,000, $22,522,000 and $21,005,000 for the years ended 1997, 1998 and
1999, respectively.
95
<PAGE> 96
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
12. INCOME TAXES
Taxes charged to income were:
<TABLE>
<CAPTION>
1997 1998 1999
------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal
Current.............................................. $17,117 $(23,339) $19,072
Deferred............................................. 31,114 40,747 25,646
State
Current.............................................. 443 215 558
Deferred............................................. 6,324 3,912 6,968
------- -------- -------
$54,998 $ 21,535 $52,244
======= ======== =======
</TABLE>
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Major components of the
company's deferred taxes at December 31 were:
<TABLE>
<CAPTION>
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Deferred Tax Liabilities
Depreciation................................................ $164,065 $188,829
Prepaid gas gathering fees.................................. 17,612 20,374
-------- --------
Total deferred tax liabilities.............................. 181,677 209,203
-------- --------
Deferred Tax Assets
Alternative minimum tax credit carryforward................. 55,385 55,385
Net operating loss carryforwards............................ 45,104 36,312
Deferred gain on sale of assets............................. 6,495 6,062
Investment in partnerships.................................. 3,553 4,549
Contingency accruals........................................ 2,973 4,924
Benefit plan accruals....................................... 1,715 2,030
Other (net)................................................. 452 1,327
-------- --------
Total deferred tax assets................................... 115,677 110,589
-------- --------
Net deferred tax liabilities................................ $ 66,000 $ 98,614
======== ========
</TABLE>
The tax bases in the company's assets were increased as a result of the
1992 transfer of substantially all of its assets to GPM Gas Corporation and the
subsequent issuance and sale of preferred stock. The net operating loss
carryforwards and the alternative minimum tax credit carryforwards resulted
primarily from tax depreciation on the increased bases in the company's assets.
The company believes it is more likely than not that it will fully realize
its deferred tax assets, and, accordingly, a valuation allowance has not been
provided. Management expects that the deferred tax assets will be realized as
reductions in future taxable operating income or by utilizing available tax
planning strategies. Uncertainties that may affect the realization of these
assets include tax law changes, change in control as discussed in Note 16, and
the future level of product costs. Therefore, the company periodically reviews
its ability to realize these assets and will establish a valuation allowance if
needed.
At December 31, 1999, the company had net operating loss carryforwards of
$71 million for U.S. income tax purposes, and $221 million for state income tax
purposes. The U.S. income tax carryforwards begin
96
<PAGE> 97
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
expiring in 2009, and the state income tax carryforwards begin expiring in 2000.
The alternative minimum tax credit can be carried forward indefinitely to reduce
the company's regular tax liability.
The reconciliation of income tax at the federal statutory rate with the
provision for income taxes follows:
<TABLE>
<CAPTION>
PERCENT OF
PRETAX INCOME
------------------
1997 1998 1999 1997 1998 1999
------- ------- ------- ---- ---- ----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Federal statutory income tax....... $50,752 $18,497 $46,892 35.0% 35.0% 35.0%
State income tax................... 4,399 2,683 4,893 3.0 5.1 3.7
Other.............................. (153) 355 459 (0.1) 0.6 0.3
------- ------- ------- ---- ---- ----
$54,998 $21,535 $52,244 37.9% 40.7% 39.0%
======= ======= ======= ==== ==== ====
</TABLE>
13. KEEP WELL REPLACEMENT AGREEMENT
The redemption of the company's outstanding shares of Series A 9.32%
Cumulative Preferred Stock on December 15, 1997, cancelled the previous Keep
Well Agreement and triggered the need for a Keep Well Replacement Agreement
between Phillips and PGC. The Keep Well Replacement Agreement provides for
Phillips to maintain PGC's consolidated tangible net worth in an amount not less
than $50 million, or to irrecoverably and unconditionally guaranty the full and
timely performance, payment and discharge by PGC of all its obligations and
liabilities. Effective February 1, 2000, Phillips furnished a guaranty to GGG
assuring payment by PGC of all its existing or future obligations and
liabilities to GGG.
14. CASH FLOW INFORMATION
<TABLE>
<CAPTION>
1997 1998 1999
------- ------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Non-Cash Investing and Financing Activities
Liquidating dividend to parent company in the form of a
promissory note...................................... $ -- $ -- $780,000
Deferred payment obligation to purchase property, plant
and equipment........................................ -- -- 8,300
Cash Payments
Interest............................................... 20,452 36,108 32,789
Income taxes, including payments to Phillips........... 25,432 123 20,773
</TABLE>
The deferred purchase obligation resulted from the company's July 1, 1999,
purchase of American Liberty Oil Company's interest in the Artesia plant and
gathering system in New Mexico. At the time of closing, a partial cash payment
was made. A second and final payment was made on January 3, 2000.
15. OTHER FINANCIAL INFORMATION
<TABLE>
<CAPTION>
1997 1998 1999
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Taxes other than income and payroll taxes............... $10,765 $10,772 $12,626
</TABLE>
16. PROPOSED BUSINESS COMBINATION
On December 16, 1999, Phillips and Duke Energy Corporation (Duke Energy)
announced that they had signed definitive agreements to combine the two
companies' gas gathering, processing and marketing
97
<PAGE> 98
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--CONTINUED
businesses to form a new midstream company to be called Duke Energy Field
Services, LLC (Field Services LLC). The definitive agreements have been
unanimously approved by both companies' Boards of Directors. Subject to
regulatory approval, the transaction is expected to close by the end of the
first quarter of 2000.
If the transaction closes as expected, the subsidiaries of PGC will be
contributed to Field Services LLC in a partially tax-free exchange, and those
subsidiaries will cease to be wholly owned subsidiaries of Phillips. As part of
the transaction, the existing natural gas liquids purchase contract between
Phillips and the company will be maintained by the new company for an initial
term of 15 years. At closing, Duke Energy will own about 70 percent of Field
Services LLC, and Phillips will own about 30 percent.
17. IMPACT OF TRANSITION TO YEAR 2000 (UNAUDITED)
PGC relies on Phillips for computer systems, hardware and software for
operation of its facilities and business support systems. PGC's operations and
facilities were included as part of Phillips' companywide Year 2000 Project that
addressed the issue of computer programs and embedded computer chips being
unable to distinguish between the year 1900 and the year 2000. That project is
now complete. With the rollover into 2000, neither PGC nor Phillips experienced
any significant Year 2000 failures. Some minor Year 2000 issues occurred and
were resolved, but none have had a material impact on PGC's results of
operations, liquidity, financial condition or safety record. The total costs
associated with Year 2000 issues were not material to PGC's or Phillips'
financial position. Phillips continues to monitor its mission-critical computer
applications and those of its suppliers and vendors throughout the year 2000 to
ensure that any latent Year 2000 matters that may arise are addressed promptly.
98
<PAGE> 99
PHILLIPS GAS COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1999 2000
-------- --------
(UNAUDITED)
<S> <C> <C>
REVENUES
Natural gas liquids......................................... $104,035 $286,961
Residue gas................................................. 141,706 224,524
Other....................................................... 19,910 33,345
-------- --------
Total Revenues......................................... 265,651 544,830
-------- --------
COSTS AND EXPENSES
Gas purchases............................................... 189,421 377,659
Operating expenses.......................................... 42,741 47,285
Selling, general and administrative expenses................ 4,880 4,251
Depreciation................................................ 19,262 20,700
Interest expense............................................ 7,255 20,492
-------- --------
Total Costs and Expenses............................... 263,559 470,387
-------- --------
Income before income taxes.................................. 2,092 74,443
Provision for income taxes.................................. 851 29,110
-------- --------
NET INCOME.................................................. $ 1,241 $ 45,333
======== ========
</TABLE>
See Notes to Financial Statements.
99
<PAGE> 100
PHILLIPS GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1999 2000
-------- --------
(UNAUDITED)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income.................................................. $ 1,241 $ 45,333
Adjustments to reconcile net income to net cash provided by
operating activities
Non-working capital adjustments
Depreciation......................................... 19,262 20,700
Deferred taxes....................................... 5,783 13,891
Deferred gathering fees.............................. (1,679) (1,651)
Gain on sale of assets............................... (212) (88)
Other................................................ 337 1,896
Working capital adjustments
Decrease (increase) in accounts receivable........... 4,028 (13,646)
Decrease (increase) in inventories................... 1,000 (298)
Decrease in prepaid expenses and other current
assets, including deferred taxes.................. 555 14,338
Decrease in accounts payable......................... (17,224) (64,535)
Decrease in taxes and other accruals................. (1,875) (753)
-------- --------
Net Cash Provided by Operating Activities................... 11,216 15,187
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and investments........................ (13,532) (11,985)
Proceeds from asset dispositions............................ 55 673
-------- --------
Net Cash Used for Investing Activities...................... (13,477) (11,312)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of note payable..................................... -- (8,300)
-------- --------
Net Cash Used for Financing Activities...................... -- (8,300)
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS..................... (2,261) (4,425)
Cash and cash equivalents at beginning of period............ 27,045 164,078
-------- --------
Cash and Cash Equivalents at End of Period.................. $ 24,784 $159,653
======== ========
</TABLE>
See Notes to Financial Statements.
100
<PAGE> 101
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
1. INTERIM FINANCIAL INFORMATION
The financial information for the interim periods presented in the
financial statements included in this report is unaudited and includes all known
accruals and adjustments that Phillips Gas Company (PGC or the company)
considers necessary for a fair statement of the results for such periods. All
such adjustments are of a normal and recurring nature.
2. BUSINESS COMBINATION
On March 31, 2000, Phillips Petroleum Company (Phillips) combined its gas
gathering, processing and marketing business with Duke Energy Corporation's
(Duke Energy) gas gathering, processing and marketing business to form a new
midstream company called Duke Energy Field Services LLC (DEFS).
PGC contributed its holdings in its limited-liability-company subsidiaries
to DEFS in a tax-free exchange. The operations of these subsidiaries comprise
substantially all of the operations of PGC. Effective March 31, 2000, the
company is accounting for its investment in DEFS using the equity method.
In connection with the combination DEFS borrowed approximately $2.75
billion of short-term debt. In April 2000, the proceeds of the debt were used to
make one-time cash distributions of approximately $1,525 million to Duke Energy
and $1,220 million to Phillips. Duke Energy owns about 70 percent of DEFS, and
Phillips, through PGC, owns about 30 percent.
3. INCOME TAXES
The company's effective tax rate for the first three months of 1999 was 41
percent, compared with 39 percent for the same period of 2000.
Deferred income taxes are computed using the liability method and provided
on all temporary differences between the financial reporting basis and the tax
basis of the assets and liabilities. Allowable tax credits are applied currently
as reductions of the provision for income taxes. The results of operations for
1999 and 2000 are included in the consolidated federal income tax return of
Phillips, with any resulting tax liability or refund settled with Phillips on a
current basis. Income tax expense represents PGC on a separate return basis,
except that the same principles and elections used in the consolidated return
were applied.
4. RELATED PARTY TRANSACTIONS
Significant transactions with affiliated parties were:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1999 2000
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Operating revenues.......................................... $110,613 $287,294
Gas purchases............................................... 17,970 35,499
Operating expenses.......................................... 27,363 29,509
Selling, general and administrative expenses................ 4,361 3,750
Interest income............................................. 452 2,618
Interest expense............................................ 7,224 20,474
</TABLE>
Prior to the contribution of its subsidiaries to DEFS on March 31, 2000,
the company purchased raw gas from, and sold a portion of its residue gas and
substantially all of its natural gas liquids to, Phillips. Phillips also
provided the company with various field and general administrative services. In
addition, the company purchased Phillips' plastic pipe, which is used in the
construction of gathering systems.
101
<PAGE> 102
PHILLIPS GAS COMPANY
NOTES TO FINANCIAL STATEMENTS -- CONTINUED
The company earns interest from participation in Phillips' centralized cash
management system and incurs interest expense on its borrowings from Phillips.
The company paid gathering fees to GPM Gas Gathering L.L.C. (GGG) until it
contributed its equity interest in GGG into DEFS on March 31, 2000. In the first
three months of 1999 and 2000, net fees paid to GGG for gas gathering services
were $10,334,831 and $10,101,951, respectively; $8,655,478 and $8,450,827 were
expensed.
Selling, general and administrative expenses included a $2 million
severance charge during the first three months of 1999.
5. CASH FLOW INFORMATION
NON-CASH INVESTING ACTIVITIES
On March 31, 2000, the company contributed its holdings in its
limited-liability-company subsidiaries to DEFS. The contribution included
property, plant and other assets and liabilities held by these companies, except
for cash invested with Phillips, deferred taxes and current taxes payable.
Other non-cash investing activities and cash payments for the three-month
periods ended March 31 were as follows:
<TABLE>
<CAPTION>
1999 2000
------ -------
(IN THOUSANDS)
<S> <C> <C>
CASH PAYMENTS
Interest.................................................... $7,296 $20,477
Income taxes, including payments to Phillips................ 1,432 21
</TABLE>
102
<PAGE> 103
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Management of
Duke Energy Field Services
Denver, Colorado
We have audited the accompanying combined statements of income and cash
flows of the UPFuels Division of Union Pacific Resources Group Inc. (a Utah
Corporation) for the year ended December 31, 1998 and the three-month period
ended March 31, 1999. These financial statements are the responsibility of the
UPFuels Division's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the combined results of operations and cash
flows of the UPFuels Division for the year ended December 31, 1998, and the
three-month period ended March 31, 1999, in conformity with accounting
principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 10, 2000
103
<PAGE> 104
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas
We have audited the accompanying combined statements of income and cash
flows for the year ended December 31, 1997 of the UPFuels Division of Union
Pacific Resources Group Inc. (as restated). These financial statements are the
responsibility of the UPFuels Division's management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. 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 audit provides a reasonable basis for our opinion.
In our opinion, such combined financial statements present fairly, in all
material respects, the combined results of operations and cash flows of the
UPFuels Division for the year ended December 31, 1997, in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas
June 12, 1998
104
<PAGE> 105
UPFUELS DIVISION
COMBINED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998 AND FOR THE QUARTER ENDED MARCH
31, 1999
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1997 1998 1999
------ -------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues:
Gathering and processing.................................. $321.7 $ 227.2 $ 54.5
Pipelines................................................. 401.2 305.0 75.8
Marketing................................................. 2,761.6 3,062.8 784.0
Intersegment.............................................. (269.3) (188.6) (45.2)
------ -------- --------
Total operating revenues............................ 3,215.2 3,406.4 869.1
------ -------- --------
Product purchases:
Gathering and processing.................................. 157.1 119.6 30.9
Pipelines................................................. 312.4 198.4 44.9
Marketing................................................. 2,728.5 2,986.3 757.9
Intersegment.............................................. (269.3) (188.6) (45.2)
------ -------- --------
Total product purchases............................. 2,928.7 3,115.7 788.5
------ -------- --------
Gross margin:
Gathering and processing.................................. 164.6 107.6 23.6
Pipelines................................................. 88.8 106.6 30.9
Marketing................................................. 33.1 76.5 26.1
------ -------- --------
Total gross margin.................................. 286.5 290.7 80.6
------ -------- --------
Operating expenses:
Gathering and processing.................................. 57.9 66.4 17.7
Pipelines................................................. 27.3 37.3 7.8
Marketing................................................. -- -- --
------ -------- --------
Total operating expenses............................ 85.2 103.7 25.5
------ -------- --------
General & administrative expenses:
Gathering and processing.................................. 6.0 8.0 1.9
Pipelines................................................. 1.3 2.9 0.7
Marketing................................................. 13.0 13.0 3.0
Corporate................................................. 7.0 7.2 2.0
------ -------- --------
Total general & administrative expenses............. 27.3 31.1 7.6
------ -------- --------
Depreciation and amortization expense
Gathering and processing.................................. 44.0 41.6 11.8
Pipelines................................................. 29.4 32.7 8.0
Marketing................................................. 1.1 6.2 4.1
------ -------- --------
Total depreciation and amortization expense......... 74.5 80.5 23.9
------ -------- --------
Operating income (loss):
Gathering and processing.................................. 56.7 (8.4) (7.8)
Pipelines................................................. 30.8 33.7 14.4
Marketing................................................. 19.0 57.3 19.0
Corporate................................................. (7.0) (7.2) (2.0)
------ -------- --------
Total operating income.............................. 99.5 75.4 23.6
------ -------- --------
Other income................................................ -- 0.6 --
Minority interest........................................... (9.8) (7.6) (2.1)
------ -------- --------
Income before income taxes.................................. 89.7 68.4 21.5
Income taxes................................................ 33.2 25.3 8.0
------ -------- --------
Net income.................................................. $ 56.5 $ 43.1 $ 13.5
====== ======== ========
</TABLE>
The accompanying accounting policies and notes to the combined
financial statements are an integral part of these statements.
105
<PAGE> 106
UPFUELS DIVISION
COMBINED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998 AND FOR THE QUARTER ENDED MARCH
31, 1999
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1997 1998 1999
------- ------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Cash provided by operations:
Net income................................................ $ 56.5 $ 43.1 $ 13.5
Depreciation and amortization.......................... 74.5 80.5 23.9
Deferred income taxes.................................. 15.1 (24.0) 10.8
Minority interest earnings............................. 9.8 7.6 2.1
Other non-cash charges (credits) -- net................ 8.1 (1.0) (0.4)
Changes in current assets and liabilities................. 14.6 (35.8) 18.0
------- ------- ------
Cash provided by operations....................... 178.6 70.4 67.9
------- ------- ------
Investing activities:
Capital expenditures...................................... (168.5) (143.8) (32.0)
Acquisition of Highlands Gas Corporation.................. (179.4) -- --
Acquisition of certain assets of Norcen................... -- (83.2) --
------- ------- ------
Cash used by investing activities................. (347.9) (227.0) (32.0)
------- ------- ------
Financing activities:
Capital contributions by/(distributions to) Union Pacific
Resources Group Inc. .................................. 187.4 170.0 (39.9)
Distributions to minority interest owners................. (20.2) (11.3) (1.5)
------- ------- ------
Cash provided by (used in) financing activities... 167.2 158.7 (41.4)
------- ------- ------
Net change in cash and temporary investments................ (2.1) 2.1 (5.5)
Balance at beginning of period.............................. 9.5 7.4 9.5
------- ------- ------
Balance at end of period.................................... $ 7.4 $ 9.5 $ 4.0
======= ======= ======
Changes in current assets and liabilities:
Accounts receivable....................................... 1.4 13.1 35.7
Inventories............................................... (15.2) (10.4) 12.7
Other current assets...................................... (5.2) 11.3 0.7
Accounts payable.......................................... 30.5 (45.9) (29.4)
Other current liabilities................................. 3.1 (3.9) (1.7)
------- ------- ------
Total............................................. $ 14.6 $ (35.8) $ 18.0
======= ======= ======
</TABLE>
The accompanying accounting policies and notes to the combined
financial statements are an integral part of these statements.
106
<PAGE> 107
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING POLICIES
Principles of Combination. The combined financial statements include the
accounts of certain gathering, processing, transporting and marketing operations
of companies which are wholly-owned subsidiaries of Union Pacific Resources
Group Inc. ("UPR"), a Utah Corporation. In addition, the combined financial
statements include the operations of certain gathering and processing assets
owned by wholly-owned subsidiaries of UPR that are not included in their
entirety herein. Collectively, these wholly-owned subsidiaries and assets are
considered and referred to herein as the "UPFuels Division" of UPR. All material
intra-divisional transactions have been eliminated.
The UPFuels Division accounts for its investments in pipeline partnerships
and joint ventures under the equity method of accounting for entities owned
20%-50% by the UPFuels Division and fully consolidates entities owned greater
than 50% by the UPFuels Division. The minority interest recorded by the UPFuels
Division represents the ownership of other parties in entities in which the
UPFuels Division owns greater than 50% but less than 100%.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions. These estimates and assumptions affect the reported
amounts of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities. Management believes its estimates and
assumptions are reasonable; however, there are a number of risks and
uncertainties which may cause actual results to differ materially from the
estimates.
Depreciation and amortization. Provisions for depreciation of property,
plant and equipment are computed on the straight-line method based on estimated
service lives which range from three to 30 years. The cost of acquired gas
purchase and marketing contracts are amortized using the straight-line method
over the applicable period. Goodwill is being amortized using the straight-line
method over 20 years. Amortization of goodwill was $2.0 million, $4.5 million
and $1.1 million for the years ended December 31, 1997 and 1998 and for the
quarter ended March 31, 1999, respectively. The value of goodwill is
periodically evaluated based on the expected future undiscounted operating cash
flows to determine whether any potential impairment exists.
Revenue Recognition. The UPFuels Division recognizes revenues as gas and
natural gas liquids are delivered and services are rendered. Revenues are
recorded on an accrual basis, including an estimate for gas and natural gas
liquids delivered but unbilled at the end of each accounting period.
Derivative Financial Instruments. Unrealized gains/losses on derivative
financial instruments used for hedging purposes are not recorded. Recognition of
realized gains/losses and option premium payments/receipts are deferred and
recorded in the combined statement of income when the underlying physical
product is purchased or sold. The cash flow impact of derivative and other
financial instruments is reflected in cash provided by operations in the
combined statements of cash flows.
Income Taxes. The UPFuels Division is included in the consolidated Federal
income tax return of UPR. The consolidated Federal income tax liability of UPR
is allocated among all corporate entities on the basis of the entity's
contributions to the consolidated Federal income tax liability. Full benefit of
tax losses and credits made available and utilized in UPR's consolidated Federal
income tax returns are being allocated to the individual companies generating
such items. Income tax expense represents federal income taxes as if the company
were filing a separate return.
Environmental Expenditures. Environmental expenditures related to treatment
or cleanup are expensed when incurred, while environmental expenditures which
extend the life of the property or prevent future contamination are capitalized
in accordance with generally accepted accounting principles. Liabilities for
these expenditures are recorded when it is probable that obligations have been
incurred and the amounts can
107
<PAGE> 108
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
be reasonably estimated, based on current law and existing technologies.
Environmental accruals are recorded at undiscounted amounts and exclude claims
for recoveries from insurance or other third parties.
Earnings Per Share. Earnings per share have been omitted from the combined
statements of income as the UPFuels Division was wholly owned by UPR for all
periods presented.
1. NATURE OF OPERATIONS
The UPFuels Division owns and operates natural gas and natural gas liquids
gathering and pipeline systems and gas processing plants and is engaged in the
business of purchasing, gathering, processing, transporting, storing and
marketing natural gas and natural gas liquids. Through a related party
transaction, the UPFuels Division markets a substantial portion of UPR's natural
gas and natural gas liquid production together with significant volumes of
natural gas and natural gas liquids produced by others. The UPFuels Division has
a diverse customer base for its hydrocarbon products.
The UPFuels Division's results of operations are largely dependent on the
difference between the prices received for its hydrocarbon products and the cost
to acquire and market such resources. Hydrocarbon prices are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the control of the UPFuels Division. These factors include
worldwide political instability, the foreign supply of oil and natural gas, the
price of foreign imports, the level of consumer demand and the price and
availability of alternative fuels. Historically, the UPFuels Division has been
able to manage a portion of the operating risk relating to hydrocarbon price
volatility through hedging activities.
2. ACQUISITION OF THE UPFUELS DIVISION BY DUKE ENERGY FIELD SERVICES INC.
In November 1998, UPR reached an agreement with Duke Energy Field Services,
Inc. whereby Duke Energy Field Services would acquire certain gathering,
processing, pipeline and marketing assets of UPR. The sale transaction closed
effective March 31, 1999, with the purchase price being $1.35 billion. Certain
liabilities primarily income tax and retiree benefits obligations, were not
assumed by Duke Energy Field Services in connection with the sale transaction.
3. RELATED PARTY TRANSACTIONS
The UPFuels Division enters into certain natural gas and crude hedging
transactions on behalf of UPR. Services performed by UPR on behalf of the
UPFuels Division include cash management, internal audit and tax and employee
benefits administration. In the UPFuels Division originally issued financial
statements, there was no cost allocated for these services. The UPFuels Division
management subsequently determined that $2.0 million, $2.0 million and $0.5
million for 1997, 1998 and the three months ended March 31, 1999, respectively,
should have been allocated. As a result, the accompanying financial statements
have been revised from their original presentation. Other general and
administrative expenses have been allocated to the UPFuels Division, including
office rent expense. Since treasury is considered to be a UPR corporate
function, no interest expense has been allocated to the UPFuels Division in the
accompanying combined statements of income.
The UPFuels Division has a buy/sell agreement with UPR. Under this
agreement, the UPFuels Division gathers, transports, processes and sells natural
gas and natural gas liquids for UPR and purchases natural gas and natural gas
liquids from UPR.
The charges for allocated services are based on estimated full time
equivalent headcount at fully burdened rates. The buy/sell arrangements are
based on prevailing market conditions in each regional area. Accordingly, these
transactions reflect UP Fuels results as if they were on a stand alone basis.
108
<PAGE> 109
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
The following table reflects the intercompany balance outstanding at each
period end as well as the high and low balance for each period.
<TABLE>
<CAPTION>
AVERAGE
BALANCE HIGH LOW
OUTSTANDING BALANCE BALANCE
----------- ------- -------
($ IN MILLIONS)
<S> <C> <C> <C>
1997...................................................... $ 93.7 $187.4 $ 0
1998...................................................... $272.4 $357.4 $187.5
First Quarter 1999........................................ $337.5 $357.4 $317.5
</TABLE>
The following table summarizes product purchases, in volumes and dollars,
made by the UPFuels Division from UPR during each of the years ended December
31, 1997 and 1998 and the quarter ended March 31, 1999:
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1997 1998 1999
------ ------ ---------
(VOLUMES)
<S> <C> <C> <C>
Gas (MMcf/day).............................................. 860.8 923.1 846.2
Natural gas liquids (Mbbls/day)............................. 68.8 68.5 63.1
(MILLIONS OF DOLLARS)
Gas......................................................... $628.4 $630.1 $140.1
Natural gas liquids......................................... $281.3 $203.5 $ 43.3
</TABLE>
4. SIGNIFICANT ACQUISITION
Highlands Gas Corporation. In August 1997, the UPFuels Division acquired
100% of the outstanding stock of Highlands Gas Corporation ("Highlands") for an
adjusted purchase price of approximately $179.4 million. Highlands is in the
business of gathering, purchasing, processing and transporting natural gas and
natural gas liquids. The acquisition included three natural gas processing
plants, five gathering systems with over 700 miles of gas and natural gas
liquids gathering pipeline and 400 miles of transportation pipeline located in
Western Texas and Eastern New Mexico. Results of operations for Highlands
subsequent to the acquisition date are included in the consolidated statements
of income.
The following unaudited pro forma combined results of operations for the
year ended December 31, 1997 are presented as if the Highlands acquisition had
been made at the beginning of the year. The unaudited pro forma information is
not necessarily indicative of either the results of operations that would have
occurred had the purchase been made during the periods presented or the future
results of the combined operations.
PRO FORMA RESULTS
<TABLE>
<CAPTION>
1997
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Revenues........................................ $3,376.8
Operating income................................ 96.3
Net income...................................... $ 54.5
</TABLE>
5. FINANCIAL INSTRUMENTS
Hedging. The UPFuels Division has established policies and procedures for
managing risk within its organization. It is balanced by internal controls and
governed by a risk management committee. The level of risk assumed by the
UPFuels Division is based on its objectives and earnings, and its capacity to
manage risk.
109
<PAGE> 110
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
Limits are established for each major category of risk, with exposures monitored
and managed by UPFuels Division management, and reviewed semi-annually by the
risk management committee. Major categories of the UPFuels Division's risk are
defined as follows:
Commodity Price Risk -- Non-Trading Activities. The UPFuels Division uses
derivative financial instruments for non-trading purposes in the normal course
of business to manage and reduce risks associated with contractual commitments,
price volatility, and other market variables in conjunction with transportation,
storage, and customer service programs. These instruments are generally put in
place to limit risk of adverse price movements, however, when this is done,
these same instruments usually limit future gains from favorable price
movements. Such risk management activities are generally accomplished pursuant
to exchange-traded contracts or over-the-counter options.
Recognition of realized gains/losses and option premium payments/receipts
are also deferred in the combined statements of income until the underlying
physical product is sold. Unrealized gains/losses on derivative financial
instruments are not recorded. The cash flow impact of derivative and other
financial instruments is reflected as cash flows provided from operations in the
combined statements of cash flows.
Commodity Price Risk -- Trading Activities. Periodically, the UPFuels
Division may enter into transactions involving a wide range of energy related
derivative financial transactions that are not the result of hedging activities.
These instruments are generally put into place based on the UPFuels Division's
analysis and expectations with respect to price movement or changes in other
market variables. As of March 31, 1999, there were no transactions in place
which would materially affect the results of operations or financial condition
of the UPFuels Division.
Credit Risk. Credit risk is the risk of loss as a result of nonperformance
by counterparties pursuant to the terms of their contractual obligations.
Because the loss can occur at some point in the future, a potential exposure is
added to the current replacement value to arrive at a total expected credit
exposure. The UPFuels Division has established methodologies to establish
limits, monitor and report creditworthiness and concentrations of credit to
reduce such credit risk. At March 31, 1999, the UPFuels Division's largest
credit risk associated with any single counterparty, represented by the net fair
value of open contracts with such counterparty was $2.2 million.
Performance Risk. Performance risk results when a counterparty fails to
fulfill its contractual obligations such as commodity pricing or volume
commitments. Typically, such risk obligations are defined within the trading
agreements. The UPFuels Division utilizes its credit risk methodology to manage
performance risk.
Concentrations of Credit Risk. Financial instruments which subject the
UPFuels Division to concentrations of credit risk consist principally of trade
receivables and short-term cash investments. A significant portion of the
UPFuels Division's trade receivables relate to customers in the energy industry,
and, as such, the UPFuels Division is directly affected by the economy of that
industry. However, excluding the relationship with UPR, the credit risk
associated with trade receivables is minimized by the UPFuels Division's diverse
customer base which includes local gas distribution companies, power generation
facilities, pipelines, industrial plants and other wholesale marketing
companies. Ongoing procedures are in place to monitor the creditworthiness of
customers. The UPFuels Division generally requires no collateral from its
customers and historically has not experienced significant losses on trade
receivables.
6. INCOME TAXES
The UPFuels Division is included in the consolidated Federal income tax
return of UPR. The consolidated Federal income tax liability of UPR is allocated
among all corporate entities on the basis of the entity's contributions to the
consolidated Federal income tax liability. Full benefit of tax losses and
credits made available and utilized in UPR's consolidated Federal income tax
returns are being allocated to the individual companies generating such items.
110
<PAGE> 111
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
Components of income tax expense for the years ended December 31, 1997 and
1998 and for the quarter ended March 31, 1999.
<TABLE>
<CAPTION>
1997 1998 1999
----- ------ -----
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current:
Federal.................................................. $17.2 $ 46.7 $(2.7)
State.................................................... .9 2.6 (0.1)
----- ------ -----
Total current.................................... 18.1 49.3 (2.8)
Deferred:
Federal.................................................. 14.2 (22.7) 10.2
State.................................................... 0.9 (1.3) 0.6
----- ------ -----
Total deferred...................................... 15.1 (24.0) 10.8
----- ------ -----
Total............................................ $33.2 $ 25.3 $ 8.0
===== ====== =====
</TABLE>
A reconciliation between statutory and effective tax rates for the years
ended December 31, 1997 and 1998 and for the quarter ended March 31, 1999 is as
follows:
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
Statutory tax rate.......................................... 35.0% 35.0% 35.0%
State taxes -- net.......................................... 2.0% 2.0% 2.0%
---- ---- ----
Effective tax rate........................................ 37.0% 37.0% 37.0%
==== ==== ====
</TABLE>
All tax years prior to 1986 have been closed with the Internal Revenue
Service ("IRS"). On behalf of the UPFuels Division, UPR, through Union Pacific
Corporation ("UPC"), is negotiating with the Appeals Office concerning 1986
through 1989. The IRS is examining UPR's returns for 1990 through 1994 in
connection with the IRS' examination of UPC's returns. The UPFuels Division
believes it has adequately provided for Federal and state income taxes.
7. LEASES
The UPFuels Division leases certain compressors and other property. Future
minimum lease payments for operating leases with initial non-cancelable lease
terms in excess of one year as of March 31, 1999, are as follows:
<TABLE>
<CAPTION>
(MILLIONS OF DOLLARS)
<S> <C>
1999............................................ $ 1.9
2000............................................ 2.5
2001............................................ 2.4
2002............................................ 1.5
2003............................................ 1.2
Later years..................................... 5.4
-----
Total minimum payments................ $14.9
=====
</TABLE>
Rent expense for operating leases with terms exceeding one year was $1.1
million and $1.3 million for the years ended December 31, 1997 and 1998,
respectively, and $0.5 million for the quarter ended March 31, 1999. Currently
there is no sublease income for the next five years or thereafter.
111
<PAGE> 112
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
8. EMPLOYEE STOCK OPTION PLANS
Stock Option and Retention Stock Plans. Pursuant to the UPR's stock option
and retention stock plans, UPR stock options under the plans are granted at 100%
of fair market value at the date of grant, become exercisable no earlier than
one year after grant and are exercisable for a period of up to eleven years from
grant date. Option grants have been made to directors, officers and employees
and vest over a period up to ten years from the grant date.
Retention shares of UPR common stock are awarded under the plans to
eligible employees, subject to forfeiture if employment terminates during the
prescribed retention period, generally one to five years from grant. Multi-year
retention stock awards also have been made, with vesting two to five years from
grant.
Expense related to these stock option and retention stock programs of UPR,
which pertain to UPFuels Division employees, amounted to $1.2 million, $1.3
million and $.7 million for the years ended 1997 and 1998 and the quarter ended
March 31, 1999, respectively.
Since UPR applies the intrinsic value method in accounting for its stock
option and retention stock plans, it generally records no compensation cost for
its stock option plans. Had compensation cost for UPR's stock option plan been
determined based on the fair value at the grant dates for awards to UPFuels
Division employees under the plan and for options that were converted at the
times of the initial public offering and spin-off of UPR from UPC, the UPFuels
Division's net income would have been reduced by $.6 million, $1.9 million and
$0.1 million for the years ended December 31, 1997 and 1998 and the quarter
ended March 31, 1999, respectively.
Employee Stock Ownership Plan. Effective January 2, 1997, UPR instituted an
employee stock ownership plan ("ESOP"). The ESOP purchased 3.7 million shares or
$107.3 million of newly issued common stock (the "ESOP Shares") from UPRG, which
will be used to fund UPR's matching obligation under its 401(k) Thrift Plan. All
regular employees of the UPFuels Division are eligible to participate in the
ESOP.
During the years ended December 31, 1997 and 1998, and the quarter ended
March 31, 1999, compensation cost related to the allocation of ESOP shares to
participants' accounts was $1.4 million, $1.6 million and $0.4 million,
respectively, for the UPFuels Division.
9. ENVIRONMENTAL EXPOSURE
The UPFuels Division generates and disposes of hazardous and nonhazardous
waste in its current and former operations and is subject to increasingly
stringent Federal, state and local environmental regulations. Certain Federal
legislation imposes joint and several liability for the remediation of various
sites; consequently, the UPFuels Division's ultimate environmental liability may
include costs relating to other parties in addition to costs relating to its own
activities at each site. In addition, the UPFuels Division is or may be liable
for certain environmental remediation matters involving existing or former
facilities.
The UPFuels Division has recorded environmental reserves related to future
costs of all sites where the UPFuels Division's obligation is probable and where
such costs reasonably can be estimated. This accrual includes future costs for
remediation and restoration of sites, as well as for ongoing monitoring costs,
but excludes any anticipated recoveries from third parties.
The UPFuels Division also is involved in reducing emissions, spills and
migration of hazardous materials. Remediation of identified sites and control of
environmental exposures required $1.2 million in 1998 and no spending for the
quarter ended March 31, 1999.
112
<PAGE> 113
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
10. COMMITMENTS AND CONTINGENCIES
The UPFuels Division is party to several long-term firm gas transportation
agreements, the largest of which are with Kern River Gas Transportation Company
("Kern River"), Texas Gas Transmission Corporation ("Texas Gas"), and Pacific
Gas Transmission ("PGT"). At December 31, 1997, the UPFuels Division had a keep
whole agreement with UPR which expired at the end of 2003 whereby UPR reimbursed
the UPFuels Division for the excess of the contractual fixed price over the
prevailing market price for the transportation. Conversely, the UPFuels
Division, under the keep whole agreement, was to pay UPR when the prevailing
market price exceeded the contractual fixed price. Accordingly, at December 31,
1997, the UPFuels Division recorded a reserve for the fair value of the
difference between the fixed rate under the firm transportation agreements and
the estimated market rates for the period from 2004 to the end of the respective
contract periods. At December 31, 1997, the reserves, which were included in
other long-term liabilities, were $13.0 million, $5.5 million, and $7.6 million
for the Kern River, Texas Gas, and PGT agreements, respectively.
In conjunction with the sale of the UPFuels Division to Duke Energy Field
Services, Inc. during 1998 the UPFuels Division extended the keep whole
agreement with UPR to cover a 10 year period commencing March 1, 1999 or through
the expiration of the contract, whichever is earlier. In addition, UPR retained
the transportation contract with Kern River. Accordingly, no reserves for the
Kern River and Texas Gas Agreements were recorded at December 31, 1998 or March
31, 1999 and $17.6 million was recorded at December 31, 1998 and March 31, 1999
for the PGT agreement, reflecting additional liabilities for volumes acquired in
1998, partially offset by the extension of the keep whole agreement. During
1998, $8.5 million was recorded as a change in divisional equity for the change
in the keep whole agreement. A detailed explanation of the three major long-term
firm transportation agreements are as follows:
Under the Kern River transportation agreement which expires in 2007, the
UPFuels Division has the right to transport 75 MMcfd of gas on the Kern River
Pipeline system which extends from Opal, Wyoming, to an interconnection with the
Southern California Gas Company pipeline system in southern California. Nine
years remain on the primary term of the agreement, and the current
transportation rate is $0.69 per Mcf. Thereafter, this rate can change based on
Kern River's cost of service and upon rate regulation policies of the Federal
Energy Regulatory Commission ("FERC"). Under a 1993 ruling of the FERC, the
UPFuels Division is obligated to pay all of the fixed costs included in the
transportation rate, whether or not the UPFuels Division actually uses Kern
River's pipeline to transport gas. Those fixed costs presently amount to $0.61
per Mcf. The undiscounted amount of the nine year fixed cost commitment,
assuming no future changes in the rate, is $136 million. The 1993 FERC ruling
was issued notwithstanding a provision in the transportation agreement between
Kern River and the UPFuels Division in which the parties agreed that a portion
of the fixed costs would be paid by the UPFuels Division only if and to the
extent that the UPFuels Division uses the pipeline. In light of recent changes
in the regulatory policies of FERC, the UPFuels Division is seeking
reinstatement of the contractually agreed rate structure, but there is no
assurance that such efforts will be successful.
The UPFuels Division is a party to an additional agreement under which it
may acquire, in 2001, at its option, an additional 25 MMcfd of transportation
rights on the Kern River system beginning in 2002.
Under the Texas Gas transportation agreement, which expires in 2008, the
UPFuels Division has the rights to transport 90 MMcfd of gas from the UPFuels
Division's East Texas plant. The UPFuels Division is obligated to pay a fixed
transportation rate of $0.33 per Mmbtu regardless of the volumes transported
under the agreement. The undiscounted amount of this commitment is $104 million.
Under the PGT transportation agreement, which expires in 2023, the UPFuels
Division has the rights to transport 25 MMcfd of gas from Kingsgate, British
Columbia to the California/Oregon border. The UPFuels Division is obligated to
pay a fixed transportation rate of $0.33 per Mmbtu regardless of the volumes
113
<PAGE> 114
UPFUELS DIVISION
NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED
transported under the agreement. However, the UPFuels Division has third party
agreements that reimburse the UPFuels Division for 90 percent of the firm
transportation cost until October 2002. As part of the third party agreements,
the UPFuels Division assigned 50 percent of the firm transportation capacity.
The term for the keep whole agreement for this contract commences on November 1,
2002 and terminates on February 28, 2009. The undiscounted amount of this
commitment, net of the third party reimbursements, is $64 million.
During 1998, the UPFuels Division assumed responsibility for additional
long-term firm transportation agreements with PGT to transport gas from
Kingsgate, British Columbia to the California/Oregon border. Under the
transportation agreements, the UPFuels Division has the rights to transport 106
Mmbtu per day of which 47 Mmbtu per day will expire in October 2007 and the
balance of the contract commitment will expire in October 2023. The UPFuels
Division does have a third party agreement that recovers all the transportation
cost for 20 Mmbtu per day through June 2011.
The UPFuels Division is a defendant in a number of lawsuits and is involved
in governmental proceedings arising in the ordinary course of business,
including contract claims, personal injury claims and environmental claims.
While management of the UPFuels Division cannot predict the outcome of such
litigation and other proceedings, management does not expect those matters to
have a materially adverse effect on the consolidated financial condition or
results of operations of the UPFuels Division.
114
<PAGE> 115
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS
(a) Financial Statements
The following financial statements are filed herewith as part of Item
13, Financial Statements.
<TABLE>
<CAPTION>
PRO FORMA
<S> <C>
DUKE ENERGY FIELD SERVICES, LLC (THE "COMPANY")
Unaudited Pro Forma Income Statement for the Year Ended
December 31, 1999
Unaudited Pro Forma Income Statement for the Three Month
Period Ended March 31, 2000
Notes to the Unaudited Pro Forma Income Statements
HISTORICAL
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES (THE
"PREDECESSOR COMPANIES")
Independent Auditors' Report
Combined Balance Sheets at December 31, 1998 and 1999
Combined Statements of Income for the Years Ended December
31, 1997, 1998 and 1999
Combined Statements of Equity for the Years Ended December
31, 1997, 1998 and 1999
Combined Statements of Cash Flows for the Years Ended
December 31, 1997, 1998 and 1999
Notes to Combined Financial Statements
Consolidated Balance Sheets as of December 31, 1999 and
March 31, 2000 (Unaudited)
Unaudited Consolidated Statements of Income for the Three
Months Ended March 31, 1999 and 2000
Unaudited Consolidated Statements of Stockholder's Equity
for the Three Months Ended March 31, 2000
Unaudited Consolidated Statements of Cash Flows for the
Three Months Ended March 31, 1999 and 2000
Notes to Unaudited Consolidated Financial Statements
PHILLIPS GAS COMPANY ("GPM")
Report of Independent Auditors
Consolidated Balance Sheets at December 31, 1998 and 1999
Consolidated Statements of Income for the Years Ended
December 31, 1997, 1998 and 1999
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1998 and
1999
Consolidated Statements of Changes in Stockholders' Equity
(Deficit) for the Years Ended December 31, 1997, 1998
and 1999
Notes to Financial Statements
Unaudited Consolidated Statements of Income for the Three
Months Ended March 31, 1999 and 2000
Unaudited Consolidated Statements of Cash Flows for the
Three Months Ended March 31, 1999 and 2000
Notes to Unaudited Consolidated Financial Statements
</TABLE>
<TABLE>
<CAPTION>
HISTORICAL
<S> <C>
UP FUELS DIVISION OF UNION PACIFIC RESOURCES GROUP INC. ("UP
FUELS")
Reports of Independent Auditors
Combined Statements of Income for the Years Ended December
31, 1997 and 1998 and the Quarter Ended March 31, 1999
</TABLE>
115
<PAGE> 116
<TABLE>
<CAPTION>
HISTORICAL
<S> <C>
Combined Statements of Cash Flows for the Years Ended
December 31, 1997 and 1998 and the Quarter Ended March
31, 1999
Notes to Combined Financial Statements
</TABLE>
(b) Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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
10.1(a) -- 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)
10.1(b)** -- First Amendment to Employment Agreement between Duke
Energy Field Services Assets, LLC and Michael J. Panatier
10.2 -- 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)
10.3 -- 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)
10.4 -- 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)
10.5(a) -- 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)
10.5(b) -- 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)
10.6 -- 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)
</TABLE>
116
<PAGE> 117
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.7 -- 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)
10.8(a) -- 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)
10.8(b)* -- 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
10.9(a) -- 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)
10.9(b)** -- First Amendment to Contract for Services between Duke
Energy Field Services Assets, LLC and William W.
Slaughter
10.10 -- 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)
21.1* -- Subsidiaries of the Company
27.1* -- Financial Data Schedule
</TABLE>
---------------
* Filed herewith.
** To be filed by amendment.
117
<PAGE> 118
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act
of 1934, as amended, the registrant has duly caused this Registration Statement
to be signed on its behalf by the undersigned, thereunto duly authorized.
Duke Energy Field Services, LLC
Date: July 20, 2000 By: /s/ DAVID D. FREDERICK
----------------------------------
Name: David D. Frederick
Title: Senior Vice President and
Chief Financial Officer
118
<PAGE> 119
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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
10.1(a) -- 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)
10.1(b)** -- First Amendment to Employment Agreement between Duke
Energy Field Services Assets, LLC and Michael J. Panatier
10.2 -- 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)
10.3 -- 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)
10.4 -- 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)
10.5(a) -- 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)
10.5(b) -- 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)
10.6 -- 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)
10.7 -- 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)
</TABLE>
119
<PAGE> 120
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.8(a) -- 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)
10.8(b)* -- 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
10.9(a) -- 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)
10.9(b)** -- First Amendment to Contract for Services between Duke
Energy Field Services Assets, LLC and William W.
Slaughter
10.10 -- 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)
21.1* -- Subsidiaries of the Company
27.1* -- Financial Data Schedule
</TABLE>
---------------
* Filed herewith.
** To be filed by Amendment.
120
