EXHIBIT 99.6
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
RECENT EVENTS AND COMPANY OUTLOOK
In February 2003, we outlined our planned business strategy in response to
the events that significantly impacted the energy sector and our company during
late 2001 and much of 2002, including the collapse of Enron and the severe
decline of the telecommunications industry. The plan focused on migrating to an
integrated natural gas business comprised of a strong, but smaller, portfolio of
natural gas businesses; reducing debt; and increasing our liquidity through
asset sales, strategic levels of financing and reductions in operating costs.
The plan was designed to address near-term and medium-term debt and liquidity
issues, to de-leverage the company with the objective of returning to investment
grade status and to develop a balance sheet and cash flows capable of supporting
and ultimately growing our remaining businesses.
As discussed in our Annual Report on Form 10-K for the year ended December
31, 2003, we successfully executed certain critical components of our plan
during 2003. Key execution steps for 2004 and beyond include the following:
- completion of planned asset sales, which are estimated to
generate proceeds of approximately $800 million in 2004;
- additional reductions of our SG&A costs;
- the replacement of our cash-collateralized letter of credit
and revolver facility with facilities that do not encumber
cash; and
- continuation of our efforts to exit from the Power business.
Projected asset sales in 2004 include the Alaska refinery and certain
assets of our Midstream segment including the straddle plants in western Canada.
On March 31, 2004, we completed the sale of our Alaska refinery and related
assets for approximately $304 million (see Note 5 of Notes to Consolidated
Financial Statements).
In April 2004, we entered into two new unsecured credit facilities
totaling $500 million, primarily for the purpose of issuing letters of credit.
During April 2004, use of these facilities released approximately $500 million
of restricted cash, restricted investments and margin deposits. Also, on May 3,
2004, we entered into a new three-year, $1 billion secured revolving credit
facility. The revolving facility is secured by certain Midstream assets and a
guarantee from WGP (see Note 10 of Notes to Consolidated Financial statements).
As part of our planned strategy, on February 25, 2004, our Exploration &
Production segment amended its $500 million secured note facility, which was
originally due May 30, 2007. The amendment provided more favorable terms
including a lower interest rate and an extension of the maturity by one year
(see Note 10 of Notes to Consolidated Financial Statements).
On March 15, 2004, we retired $679 million of senior unsecured 9.25
percent notes due March 15, 2004. The amount represented the outstanding balance
subsequent to the fourth-quarter 2003 tender which retired $721 million of the
original $1.4 billion balance. Long-term debt, excluding the current portion, at
March 31, 2004 was approximately $10.8 billion.
POWER BUSINESS STATUS
Since mid-2002, we have been pursuing a strategy of exiting the Power
business and have worked with financial advisors to assist with this effort. To
date, several factors have contributed to the difficulty of achieving a complete
exit from this business, including the following with respect to the wholesale
power industry:
- oversupply position in most markets expected through the
balance of the decade;
- slow North American gas supply response to high gas prices;
and
- expectations of hybrid regulated/deregulated market structure
for several years.
Management's Discussion & Analysis (Continued)
As a result of these factors and the size of our Power business, the
number of financially viable parties expressing an interest in purchasing the
entire business have been limited. Additionally, the current and near term view
of the wholesale power market, which we interpret as depressed, has strongly
influenced these parties' view of value and related risk associated with this
business.
99.6-1
Management Discussion & Analysis (Continued)
Because market conditions may change, and we cannot determine the impact
of this on a buyer's point of view, amounts ultimately received in any portfolio
sale, contract liquidation or realization may be significantly different from
the estimated economic value or carrying values reflected in the Consolidated
Balance Sheet. In addition, our tolling agreements are not derivatives and thus
have no carrying value in the Consolidated Balance Sheet pursuant to the
application of EITF 02-3. Based on current market conditions, certain of these
agreements are forecasted to realize significant future losses. It is possible
that we may sell contracts for less than their carrying value or enter into
agreements to terminate certain obligations, either of which could result in
significant future loss recognition or reductions of future cash flows.
We continue to evaluate alternatives and discuss our plans and operating
strategy for the Power business with our Board of Directors. As an alternative
to continuing a plan of pursuing a complete exit from the Power business, we are
evaluating whether the benefits of realizing the positive cash flows expected to
be generated by this business through continued ownership exceed the benefits of
a sale at a depressed price. If we pursue this alternative, we expect to
continue our current program of managing this business to minimize financial
risk, generate cash and manage existing contractual commitments.
GENERAL
In accordance with the provisions related to discontinued operations
within Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," the consolidated financial
statements and notes in Item 1 reflect the results of operations, financial
position and cash flows through the date of sale, as applicable, of the
following components as discontinued operations (see Note 5 of Notes to
Consolidated Financial Statements):
- retail travel centers concentrated in the Midsouth, part of
the previously reported Petroleum Services segment;
- refining and marketing operations in the Midsouth, including
the Midsouth refinery, part of the previously reported
Petroleum Services segment;
- Texas Gas Transmission Corporation, previously one of Gas
Pipeline's segments;
- natural gas properties in the Hugoton and Raton basins,
previously part of the Exploration & Production segment;
- bio-energy operations, part of the previously reported
Petroleum Services segment;
- our general partnership interest and limited partner
investment in Williams Energy Partners, previously the
Williams Energy Partners segment;
- the Colorado soda ash mining operations, part of the
previously reported International segment;
- certain gas processing, natural gas liquids fractionation,
storage and distribution operations in western Canada and at a
plant in Redwater, Alberta, previously part of the Midstream
segment;
- refining, retail and pipeline operations in Alaska, part of
the previously reported Petroleum Services segment;
- Gulf Liquids New River Project LLC, previously part of the
Midstream segment; and
- our straddle plants in western Canada, previously part of the
Midstream segment.
Effective June 1, 2004, and due in part to FERC Order 2004, management and
decision - making control of certain regulated gas gathering assets was
transferred from our Midstream segment to our Gas Pipeline segment.
Consequently, the results of operations were similarly reclassified. All prior
periods reflect these classifications.
Unless indicated otherwise, the following discussion and analysis of
results of operations, financial condition and liquidity relates to our current
continuing operations and should be read in conjunction with the consolidated
financial statements and notes thereto included in Item 1 [Exhibit 99.5] of this
document and our 2003 Annual Report on Form 10-K.
99.6-2
Management's Discussion & Analysis (Continued)
RESULTS OF OPERATIONS
CONSOLIDATED OVERVIEW
The following table and discussion is a summary of our consolidated
results of operations for the three months ended March 31, 2004. The results of
operations by segment are discussed in further detail following this
consolidated overview discussion.
THREE MONTHS ENDED MARCH 31,
------------------------------------
% CHANGE FROM
2004 2003 2003 (1)
-------- -------- -------------
(MILLIONS)
Revenues $3,065.5 $4,776.1 -36%
Costs and expenses:
Costs and operating expenses 2,689.9 4,423.6 +39%
Selling, general and
administrative expenses 84.4 105.6 +20%
Other expense - net 8.4 .7 NM
General corporate expenses 32.0 22.9 -40%
-------- --------
Total costs and expenses 2,814.7 4,552.8 +38%
Operating income 250.8 223.3 +12%
Interest accrued - net (239.3) (340.9) +30%
Interest rate swap loss (8.1) (2.8) -189%
Investing income 10.3 46.3 -78%
Minority interest in income of
consolidated subsidiaries (4.8) (3.5) -37%
Other income - net .9 22.1 -96%
-------- --------
Income (loss) from continuing
operations before income
taxes and cumulative effect
of change in accounting
principles 9.8 (55.5) NM
Provision (benefit) for income
taxes 11.3 (12.4) NM
-------- --------
Loss from continuing operations (1.5) (43.1) +97%
Income (loss) from discontinued
operations 11.4 (10.1) NM
-------- --------
Income (loss) before cumulative
effect of change in
accounting principles 9.9 (53.2) NM
Cumulative effect of change in
accounting principles - (761.3) NM
-------- --------
Net income (loss) 9.9 (814.5) NM
Preferred stock dividends - 6.8 NM
-------- --------
Income (loss) applicable to
common stock $ 9.9 $ (821.3) NM
======== ========
(1) + = Favorable Change; - = Unfavorable Change; NM = A percentage
calculation is not meaningful due to change in signs, a zero-value
denominator or a percentage change greater than 200.
99.6-3
Management's Discussion & Analysis (Continued)
Three Months Ended March 31, 2004 vs. Three Months Ended March 31, 2003
Our revenues decreased $1,710.6 million due primarily to decreased
revenues at our Power segment, our Midstream segment, and our Exploration &
Production segment. Power revenues decreased approximately $1.5 billion due
primarily to lower power, natural gas and crude and refined products sales
volumes. Midstream's revenues decreased $238.1 million due primarily to the sale
of our wholesale propane business in fourth-quarter 2003, which resulted in
lower product sales for natural gas liquids trading activities. In addition,
Exploration & Production's revenues decreased $78.7 million due primarily to
lower production revenues from lower net realized average prices and lower
production volumes as a result of property sales.
Costs and operating expenses decreased $1,733.7 million due primarily to
decreased costs and operating expenses at Power and Midstream. The decrease at
Power is due primarily to lower power, natural gas and crude and refined
products purchase volumes. The decrease at Midstream is due primarily to the
2003 sale of our wholesale propane business.
Selling, general and administrative expenses decreased $21.2 million. This
cost reduction is due primarily to reduced staffing levels at Power, reflective
of our strategy to exit this business. Also contributing to the decrease was the
absence of $11.8 million of expense related to the accelerated recognition of
deferred compensation during 2003.
Other expense - net, within operating income, in 2004 includes $6.1
million in fees related to the sale of PG&E receivables to Bear Stearns.
General corporate expenses increased $9.1 million due primarily to
increased third-party costs associated with the implementation of the
Sarbanes-Oxley Act of 2002 and with efforts to evaluate and implement certain
cost reduction strategies through internal initiatives and the potential
outsourcing of certain services.
Interest accrued - net decreased $101.6 million due primarily to:
- $89.4 million lower interest expense and fees related to the
RMT note payable, which was prepaid in May 2003 and partially
refinanced at market rates;
- $10.3 million lower amortization expense related to deferred
debt issuance costs, primarily due to the reduction of debt;
- a $3 million decrease reflecting lower average borrowing
levels;
- a $6 million decrease reflecting lower average interest rates
on long-term debt; and
- a $7.9 million decrease in capitalized interest, which offsets
interest accrued, due primarily to completion of certain
Midstream projects in the Gulf Coast Region.
We entered into interest rate swaps with external counterparties primarily
in support of the energy-trading portfolio (see Note 13 of Notes to Consolidated
Financial Statements). The change in market value of these swaps was $5.3
million less favorable in 2004 than 2003. The total notional amount of these
swaps was approximately $300 million at March 31, 2004 and March 31, 2003.
Investing income decreased $36 million due primarily to:
- $39.4 million lower interest income at Power as a result of
2003 accrual adjustments associated with certain 2003 FERC
proceedings;
- a $12 million impairment of a cost based investment related to
Algar Telecom S.A. recognized in 2003;
- $9.2 million higher equity earnings from Discovery Pipeline
due primarily to the absence of unfavorable audit adjustments
recorded at the partnership in 2003;
- $6.5 million net unreimbursed Longhorn recapitalization
advisory fees; and
- $3.6 million of impairments during 2004 of certain
international cost-based investments.
Other income - net, below operating income, includes a $2.6 million net
gain in 2004 and a $12.5 million net gain in 2003. The net gain in 2004 consists
of a $2.5 million foreign currency transaction loss on a Canadian dollar
denominated note receivable, more than
99.6-4
Management Discussion & Analysis (Continued)
offset by a $5.1 million derivative gain on a forward contract to fix the U.S.
dollar principal cash flows from the note receivable. In 2004, the gain from the
forward contract exceeds the foreign currency translation loss from the note as
the note balance was substantially reduced in 2003 but the size of the related
forward contract was unchanged. The net gain in 2003 consists of a $29.2 million
foreign currency transaction gain on the same note, offset by a $16.7 million
derivative loss on the forward contract.
The provision (benefit) for income taxes was unfavorable by $23.7 million
due primarily to a pre-tax income in 2004 as compared to a pre-tax loss for
2003. The effective income tax rate for 2004 is greater than the federal
statutory rate due primarily to an accrual for income tax contingencies, net
foreign operations and state income taxes. The effective income tax rate for
2003 is less than the federal statutory rate (less tax benefit) due primarily to
an accrual for income tax contingencies and state income taxes.
In addition to the operating results from activities included in
discontinued operations (see Note 5 of Notes to Consolidated Financial
Statements), the 2004 gain from discontinued operations includes a pre-tax gain
of $3.6 million on the sale of the Alaska refinery, retail and pipeline assets
and an adjustment to increase the gain on the sale of our 100 percent general
partnership interest and 54.6 percent limited partner investment in Williams
Energy Partners recorded in June 2003 by $3.3 million. The 2003 loss from
discontinued operations includes $117.3 million of pre-tax impairments, offset
by a gain on sale as follows:
- a $109 million impairment of Texas Gas Transmission;
- an $8 million impairment of the Alaska refinery, retail and
pipeline assets;
- a $5 million impairment of the soda ash mining facility
located in Colorado; and
- a $4.7 million gain on the sale of a refinery and other
related operations located in Memphis, Tennessee.
The cumulative effect of change in accounting principles reduced net
income for 2003 by $761.3 million due to a $762.5 million charge related to the
adoption of EITF 02-3, slightly offset by $1.2 million related to the adoption
of SFAS No. 143, "Accounting for Asset Retirement Obligations" (see Note 3 of
Notes to Consolidated Financial Statements).
In June 2003, we redeemed all of our outstanding 9.875 percent
cumulative-convertible preferred shares.
RESULTS OF OPERATIONS - SEGMENTS
We are currently organized into the following segments: Power, Gas
Pipeline, Exploration & Production, Midstream and Other. Other primarily
consists of corporate operations and certain continuing operations previously
reported within the International and Petroleum Services segments. Our
management currently evaluates performance based on segment profit (loss) from
operations (see Note 13 of Notes to Consolidated Financial Statements).
Prior period amounts have been restated to reflect these changes. The
following discussions relate to the results of operations of our segments.
99.6-5
Management Discussion & Analysis (Continued)
POWER
OVERVIEW OF THREE MONTHS ENDED MARCH 31, 2004
As described below, the continued effort to exit from the Power business,
combined with liquidity constraints, and the effect of price changes on
derivative contracts significantly influenced Power's first-quarter 2004
operating results.
In the first quarter of 2004, Power continued to focus on 1) terminating
or selling all or portions of the portfolio, 2) maximizing cash flow, 3)
reducing risk, and 4) managing existing contractual commitments. These efforts
are consistent with our 2002 decision to sell all or portions of Power's power,
natural gas, and crude and refined products portfolios. The decrease in
revenues, costs and selling, general and administrative expenses reflect our
efforts to exit the Power business.
Lack of liquidity in long-term power and natural gas markets also caused a
decrease in power revenues and costs. Due to this lack of liquidity, we were not
able to replace certain long-term power and natural gas contracts that expired
or were terminated in 2003.
Lower interest rates caused losses on derivative contracts, which are
reflected as a decrease in revenues. Increased natural gas prices primarily
caused an increase in the fair value of gas derivative contracts, which is
reflected as an increase in revenues.
Key factors that influence Power's financial condition and operating
performance include the following:
- prices of power and natural gas, including changes in the
margin between power and natural gas prices;
- changes in market liquidity, including changes in the ability
to economically hedge the portfolio;
- changes in power and natural gas price volatility;
- changes in the regulatory environment; and
- changes in power and natural gas supply and demand.
OUTLOOK FOR THE REMAINDER OF 2004
In the remainder of 2004, Power anticipates further variability in
earnings due in part to the difference in accounting treatment of derivative
contracts at fair value and the underlying non-derivative contracts on an
accrual basis. This difference in accounting treatment combined with the
volatile nature of energy commodity markets could result in future operating
gains or losses. Some of Power's tolling contracts have a negative fair value,
which is not reflected in the financial statements since these contracts are not
derivatives. These tolling contracts may result in future accrual losses.
Continued efforts to sell all or a portion may also have a significant impact on
future earnings as proceeds may differ significantly from carrying values. The
inability of counterparties to perform under contractual obligations due to
their own credit constraints could also affect future operations.
THREE MONTHS ENDED MARCH 31, 2004 VS. THREE MONTHS ENDED MARCH 31, 2003
THREE MONTHS ENDED
MARCH 31,
------------------------
2004 2003
----------- -----------
(MILLIONS)
Segment revenues $ 2,274.8 $ 3,775.6
=========== ===========
Segment loss $ (32.7) $ (136.4)
=========== ===========
99.6-6
Management Discussion & Analysis (Continued)
Revenues
Power's revenues reflect the following:
- gains and losses from changes in fair value of derivative
contracts with a future settlement or delivery date;
- revenue from sales of commodities or completion of
energy-related services; and
- gains and losses from net financial settlement of derivative
contracts.
Power's revenues decreased $1.5 billion, or 40 percent. Of this decrease,
$890.2 million represents decreased power and natural gas revenues, $582.7
million represents decreased crude and refined products revenues and $27.9
million represents decreased interest rate portfolio revenues.
A decrease in power and natural gas sales volumes primarily caused the
decrease in power and natural gas revenues. Sales volumes decreased because
Power did not replace certain long-term physical power and natural gas contracts
that expired or were terminated in 2003, primarily due to a lack of market
liquidity and efforts to reduce our commitment to the Power business. An
increase in net unrealized revenue on natural gas derivatives partially offset
the decrease in revenue. The impact of a greater increase in forward natural gas
prices in 2004 on certain natural gas positions compared to the prior year
caused this increase. In addition, power and natural gas revenues increased due
to the absence of unrealized losses of approximately $70 million recorded in
2003 on contracts for which we elected the normal purchases and sales exception
in second-quarter 2003. We now account for these contracts on an accrual basis.
Finally, power and natural gas revenues in 2003 include a $37 million loss for
increased power rate refunds owed to the state of California because of FERC
rulings, which also partially offset the decrease in revenues.
Crude and refined products revenues declined from lower sales volumes,
reflecting our efforts to exit this line of business. A decrease in purchase
volumes largely offset the effect of the decrease in sales volumes.
Revenues reflect a net realized and unrealized loss of $43.5 million on
interest rate derivatives in first-quarter 2004 compared to a net realized and
unrealized loss of $15.6 million in first-quarter 2003. A greater decrease in
interest rates in 2004 compared to the prior year caused this decrease in
revenues from our interest rate portfolio.
Costs
Power's costs represent purchases of commodities and fees paid for
energy-related services. Power's costs decreased $1.6 billion or 41 percent. Of
this decrease, $1.0 billion represents decreased power and natural gas costs and
$579.9 million represents decreased crude and refined products costs.
A decrease in power and natural gas purchase volumes primarily contributed
to the decrease in power and natural gas costs. Purchase volumes decreased
because Power did not replace certain long-term physical power and natural gas
contracts that expired or were terminated in 2003. Decreased purchase volumes
also caused the decrease in crude and refined products costs. Our efforts to
exit this line of business caused the decrease in purchase volumes.
Costs in 2004 reflect a $13 million payment made to terminate a
non-derivative power sales contract.
99.6-7
Management Discussion & Analysis (Continued)
Gross Margin
The gross margin loss of $2 million in first quarter 2004 declined $89.1
million, or 98 percent, from the gross margin loss in 2003. An increase in power
and natural gas gross margin of $119.8 million primarily caused this
improvement. The following factors, as discussed in the previous two sections,
primarily caused the increase in power and natural gas gross margin:
- the increase in net unrealized revenue on natural gas
derivatives;
- unrealized losses in 2003 of approximately $70 million on
derivative contracts, which we treated on an accrual basis
under the normal purchases and sales exception in 2004; and
- the $37 million loss resulting from FERC rulings recognized in
2003.
The $13 million payment made to terminate a non-derivative power sales contract
in the first quarter of 2004, as discussed above, partially offsets the increase
in power and natural gas gross margin.
A $27.9 million increase in the interest rate portfolio margin loss
partially offsets the increase in power and natural gas gross margin. As
discussed in the "Revenues" section above, a decrease in the fair value of
interest rate derivatives primarily caused this increased interest rate
portfolio margin loss.
Selling, General and Administrative Expenses
Selling, general and administrative expenses decreased $20.2 million, or
56 percent, primarily due to staff reductions. Power employed approximately 245
employees at March 31, 2004 compared with approximately 327 at March 31, 2003.
The staff reductions coincided with our efforts to exit the Power business.
Segment Profit
Power's segment profit increased $103.7 million, or 76 percent. An
increase in power and natural gas gross margins, partially offset by a decrease
in interest rate portfolio gross margin, contributed to the increase in segment
profit. A decrease in selling, general and administrative expenses as discussed
above also contributed to the increase in segment profit.
GAS PIPELINE
OVERVIEW OF THREE MONTHS ENDED MARCH 31, 2004
In February 2004, Transco placed an expansion into service increasing
capacity on its natural gas system by 54,000 Dth/d. As discussed below, Gas
Pipeline made additional progress towards repairing and restoring a segment of
our natural gas pipelines in western Washington.
OUTLOOK FOR THE REMAINDER OF 2004
In December 2003, we received an Amended Corrective Action Order (ACAO)
from the U.S. Department of Transportation's Office of Pipeline Safety (OPS)
regarding a segment of one of our natural gas pipelines in western Washington.
The pipeline experienced two breaks in 2003 and we subsequently idled the
pipeline segment until its integrity could be assured. The decision to idle the
pipeline has not had a significant impact on our ability to meet market demand,
primarily because we have a parallel pipeline in the same corridor. We have
initiated an extensive testing program on the pipeline, including internal
inspection and hydrostatic testing. As of the end of the day on May 4, 2004,
approximately 85 miles have been hydrotested, representing approximately
seventy-seven percent of the testing that is planned to restore portions of the
exiting pipeline to temporary service by this summer. In the course of this
extensive testing, one leak has been discovered, which will be remediated prior
to returning that portion of the line to service. We will be requesting approval
from OPS on a segment-by-segment basis upon completion of the testing program.
On April 19, 2004, OPS approved returning the first 17-mile segment to service.
We have determined that we must restore portions of the existing pipeline to
temporary service to ensure our ability to meet customer short-term demands. As
currently required by OPS, we
99.6-8
Management Discussion & Analysis (Continued)
plan to then replace the pipeline's entire capacity to meet long-term demands.
The total costs are expected to be in the range of approximately $350 million to
$410 million over the period 2003 to 2006, including approximately $9 million
spent in 2003. The majority of these costs will be spent in 2005 and 2006. We
expect to have adequate financial resources to comply with the order and replace
the capacity, if required. We anticipate filing a rate case to recover these
costs following the in-service date of the replacement facilities.
THREE MONTHS ENDED MARCH 31, 2004 VS. THREE MONTHS ENDED MARCH 31, 2003
THREE MONTHS ENDED
MARCH 31,
--------------------
2004 2003
-------- --------
(MILLIONS)
Segment revenues $ 359.0 $ 339.6
======== ========
Segment profit $ 147.4 $ 150.3
======== ========
The $19.4 million, or six percent, increase in Gas Pipeline revenues is
due primarily to $18 million of higher transportation revenues associated with
expansion projects. The $18 million consists of $10 million at Northwest
Pipeline from an expansion project that became operational in October 2003
(Evergreen) and $8 million higher demand revenues on the Transco system
resulting from new expansion projects (Trenton-Woodbury, November 2003 and
Momentum Phases 1 & 2, May 2003 and February 2004). Revenue also increased due
to $10 million higher gas exchange imbalance settlements (substantially offset
in costs and operating expenses). Partially offsetting these increases were $3
million lower short term firm revenues and $2 million lower revenues associated
with tracked costs, which are passed through to customers (offset in costs and
operating expenses).
Costs and operating expenses increased $24 million, or 15 percent, due
primarily to $9 million higher fuel expense at Transco reflecting a reduction in
pricing differentials on the volumes of gas used in operation as compared to
2003 and $9 million higher gas exchange imbalance settlements (offset in
revenues). Costs and operating expenses also increased due to $6 million higher
depreciation expense related to additional property, plant and equipment placed
into service and $4 million higher expenses associated with non-capitalized
maintenance projects. These increases were partially offset by a $5 million
reduction of expense in first-quarter 2004 related to an adjustment to
depreciation previously recognized and $2 million lower recovery of tracked
costs, which are passed through to customers (offset in revenues).
The $2.9 million, or 2 percent, decrease in Gas Pipeline segment profit is
due to the $24 million higher costs and operating expenses partially offset by
$19.4 million higher revenues and $2.0 million higher equity earnings (included
in Investing income (loss)). The increase in equity earnings includes a $2.3
million increase in earnings from our investment in Gulfstream.
EXPLORATION & PRODUCTION
OVERVIEW OF THE THREE MONTHS ENDED MARCH 31, 2004
Production volumes in the first quarter increased, but the benefit of
those higher volumes was largely offset by lower contracted hedged prices. In
the first quarter of 2004, average daily production was approximately 501
million cubic feet of gas equivalent, up from 491 million cubic feet in the
fourth quarter of 2003.
OUTLOOK FOR THE REMAINDER OF 2004
Our expectations for the remainder of the year include:
- A continuing development drilling program in our key basins
with an increase in activity in the Piceance basin.
- Increasing our 2003 production level by 10 to 15 percent by
the end of 2004. Approximately 80 percent of our forecasted
production for the remainder of 2004 is hedged at prices that
average $3.66 per mcfe at a basin level.
99.6-9
Management Discussion & Analysis (Continued)
THREE MONTHS ENDED MARCH 31, 2004 VS. THREE MONTHS ENDED MARCH 31, 2003
The following discussions of the quarter-over-quarter results primarily
relate to our continuing operations. However, the results for 2003 include those
operations that were sold during 2003 that did not qualify for discontinued
operations reporting. The operations classified as discontinued operations are
the properties in the Hugoton and Raton basins.
THREE MONTHS ENDED
MARCH 31,
--------------------
2004 2003
-------- --------
(MILLIONS)
Segment revenues $ 165.2 $ 243.9
======== ========
Segment profit $ 51.5 $ 113.8
======== ========
The $78.7 million, or 32 percent decrease in Exploration & Production
revenues is due primarily to $47 million lower production revenues reflecting
lower net realized average prices and lower production volumes. The remainder of
the decrease reflects a reduction in revenues from gas management activities,
$10 million lower income from the utilization of excess transportation capacity
and $7 million lower income on derivative instruments that did not qualify for
hedge accounting.
The decrease in domestic production revenues reflects $33 million
associated with a 20 percent decrease in net realized average prices for
production and $14 million from an eight percent decrease in net domestic
production volumes. Net realized average prices include the effect of hedge
positions. The decrease in production volumes primarily relates to the absence
of volumes associated with properties sold in the second and third quarter of
2003. Production volumes for our core retained properties were consistent from
period to period. We expect volumes to increase towards the end of the year as
our drilling program continues.
To minimize the risk and volatility associated with the ownership of
producing gas properties, we enter into derivative forward sales contracts,
which economically lock in a price for a portion of our future production.
Approximately 83 percent of domestic production in the first quarter of 2004
were hedged. These hedging decisions are made considering our overall commodity
risk exposure.
Costs and expenses, including selling, general and administrative
expenses, decreased $20 million, primarily reflecting the following:
- $13 million lower gas management expenses associated with the
lower revenues from gas management activities mentioned above;
and
- $4 million lower depreciation, depletion and amortization
expense primarily as a result of lower production volumes.
The $62.3 million decrease in segment profit is due primarily to the lower
production revenues as discussed above and the lower revenues related to excess
transportation capacity and non hedge derivative income.
99.6-10
Management Discussion & Analysis (Continued)
MIDSTREAM GAS & LIQUIDS
OVERVIEW OF THREE MONTHS ENDED MARCH 31, 2004
Consistent with our strategy to invest in targeted growth areas and divest
non-core assets, we placed into service additional infrastructure in the
deepwater offshore area of the Gulf of Mexico and expanded the Opal gas
processing facility in Wyoming. In the Gulf of Mexico, the Devils Tower platform
handling facility and the Gunnison pipeline assets were placed into service in
the first quarter of 2004 and are expected to begin contributing to segment
profit in the upcoming quarters. The Opal expansion began operating in March of
2004.
OUTLOOK FOR THE REMAINDER OF 2004
The following factors could impact our business in the remaining quarters
of 2004 and beyond:
- Continued growth in the deepwater areas of the Gulf of Mexico
is expected to contribute to, and become a larger component
of, our future segment revenues and segment profit. We expect
these additional fee-based revenues to lower our overall
exposure to commodity price risks. Incremental revenues
related to the Gunnison and Devils Tower deepwater projects
are expected to continue growing throughout 2004 and make a
significant contribution to total annual segment profit in
2004.
- Our gas processing margins were above the five-year annual
average in the first quarter of 2004. However, we do not
expect the average annual margin for the remainder of 2004 to
exceed this average.
- Beginning in the second quarter of 2003, our Gulf Coast gas
processing plants earned additional fee revenues from
short-term processing agreements contracted in response to gas
merchantability orders from pipeline operators requiring
producers' gas to be processed to achieve pipeline quality
standards. The termination of these short-term contracts could
result in lower Gulf Coast processing revenues. These
contracts could be terminated as a result of a shift in
regulatory policy or a sustained, long-term period of
favorable gas processing margins.
- We continue to evaluate and pursue the sale of various assets.
The completion of certain asset sales may have the effect of
lowering revenues and/or segment profit in the periods
following the sales. We have announced our intent to sell the
following assets:
- Canadian straddle plants (currently reported as
discontinued operations),
- Cameron Meadows/Black Marlin gas gathering and
processing assets,
- Conway NGL fractionator and storage facilities,
- South Texas gas gathering assets,
- Ethylene distribution system (Gulf Coast), and
- Gulf Liquids facility (currently reported as
discontinued operations).
Additional fee-based revenues from our new deepwater assets are expected
to mitigate segment profit decline resulting from these asset sales. As we
continue to evaluate and execute our asset divestiture strategy, certain assets
for sale may meet the requirements to be reported as discontinued operations.
99.6-11
Management Discussion & Analysis (Continued)
THREE MONTHS ENDED MARCH 31, 2004 VS. THREE MONTHS ENDED MARCH 31, 2003
Pursuant to generally accepted accounting principles, we have classified
the operations of Gulf Liquids, West Stoddart, Redwater and the Canadian
straddle plants as discontinued operations. All prior periods reflect this
reclassification.
THREE MONTHS ENDED
MARCH 31,
--------------------
2004 2003
-------- ---------
(MILLIONS)
Segment revenues $ 627.3 $ 865.4
======== =========
Segment profit
Domestic Gathering & Processing $ 78.2 $ 100.6
Venezuela 21.5 13.6
Canada (2.8) (6.7)
Other 11.4 4.7
-------- ---------
Total $ 108.3 $ 112.2
======== =========
The $238.1 million decrease in Midstream's revenues is primarily the
result of lower trading revenues largely due to the fourth quarter 2003 sale of
our wholesale propane business. This decline is partially offset by a $47
million increase as the result of the marketing of natural gas liquids (NGLs) on
behalf of our customers. Before 2004, our purchases of customers' NGLs were
netted within revenues. In 2004, these purchases of customers' NGLs are reported
as a cost of goods sold. In addition, revenues increased $56 million largely due
to higher production volumes at our Gulf Coast gas processing plants and olefins
facilities as well as higher revenues from our Venezuelan facilities.
Cost and operating expenses declined $222 million as a result of lower
trading costs largely due to the sale of our wholesale propane business. This
decline is partially offset by the increase in costs related to the increase in
NGLs marketed on behalf of customers, as noted above. Also, costs and operating
expenses increased as a result of $39 million in higher domestic natural gas
purchases used to replace the heating value of NGLs extracted at our gas
processing facilities. Also, feedstock purchases at our Gulf Coast olefins
facility rose as a result of higher production volumes and market prices.
Total Midstream segment profit for the first quarter of 2004 decreased
$3.9 million compared to the first quarter of 2003. Results from our domestic
gathering and processing business declined as a result of lower processing
margins caused by rising natural gas prices in the West Region. Improved results
at our Canadian and Venezuelan facilities as well as the absence of audit
adjustments recorded in the first quarter 2003 to our Discovery partnership
investment offset lower domestic margins. A more detailed analysis of segment
profit of our various operations is presented below.
Domestic Gathering & Processing: The $22.4 million decrease in domestic
gathering and processing segment profit includes a $24 million decline in the
West Region while the Gulf Coast Region's segment profit increased $2 million.
The $24 million decline in the West Region's segment profit is primarily
due to a $21 million decline in gas processing margins highlighting the impact
of more favorable margins realized during the first quarter of 2003. Both
quarters experienced strong NGL prices supported by high crude prices. In the
first quarter of 2003, our West Region plants yielded very favorable gas
processing margins as transportation constraints created downward price pressure
on Wyoming natural gas prices. During that period, gas prices were 64 percent of
those in the Gulf Coast area. However, with the additional pipeline capacity
provided by the completion of the Kern River Pipeline system, Wyoming's gas
prices rebounded in the first quarter of 2004 to 89 percent of Gulf Coast area
prices.
Segment profit for our Gulf Coast Region increased slightly compared to
the first quarter of 2003. Gas processing margins improved $2 million due to
significantly higher production volumes stemming from new processing agreements
created to allow producers' gas to be processed to achieve pipeline quality
standards. In addition, we resolved a 1999 gas measurement contingent liability
resulting in a $3 million favorable impact to segment profit. Offsetting these
increases is $3 million in depreciation expense relating to the Devils Tower and
Gunnison projects. These projects will not begin to contribute material revenues
until the second quarter of 2004.
Venezuela: Segment profit for our Venezuelan assets increased $7.9 million
as a result of a fire at the El Furrial facility that reduced revenues by $10
million in the first quarter of 2003. Partially offsetting this increase was
lower equity earnings from our investment in the Accroven partnership and higher
currency revaluation expenses. Our Venezuelan assets are currently operated for
99.6-12
Management Discussion & Analysis (Continued)
the exclusive benefit of Petroleos de Venezuela S.A. (PDVSA), the state owned
Petroleum Corporation of Venezuela. The Venezuelan economic and political
environment can be volatile, but has not significantly impacted the operations
and cash flows of our facilities.
Effective February 7, 2004, the Venezuelan government revalued the fixed
exchange rate for their local currency from 1,600 Bolivars to the dollar to
1,920 Bolivars to the dollar. This effect of this Bolivar devaluation was
recorded in the first quarter of 2004 as a $1.3 million charge to earnings.
Canada: Segment profit for our Canadian operations improved $3.9 million
as a result of lower operating expenses and currency translation adjustments.
General and administrative expenses were $2 million less due to the effect of
the 2003 asset sales. In addition, currency translation adjustments were also
favorable by $2 million as a result of a strengthening Canadian dollar. These
favorable variances are partially offset by $1 million lower olefins production
margins at our Redwater/Fort McMurray facility.
Other: The $6.7 million increase in segment profit for our other
operations is primarily due to higher domestic olefins margins and favorable
partnership earnings, as follows:
- Segment profit for our Domestic Olefins operations increased
$4 million primarily as a result of improved olefins
fractionation prices attributed to lower ethylene supplies and
higher demand for olefins products. Ethylene production
volumes increased 40 percent compared to the first quarter of
2003 primarily due to a new contract with a major customer.
- Earnings from partially owned domestic assets accounted for
using the equity method are $9 million higher due to $8
million in prior period accounting adjustments on the
Discovery partnership recorded during the first quarter of
2003.
- Segment profit for our Trading, Fractionation, and Storage
group declined $6 million primarily due to $10 million lower
net trading revenues caused by the sale of our wholesale
propane business in the fourth quarter of 2003 and the
quarterly lower of cost or market valuation of NGL line fill
inventories. Lower selling, general and administrative
expenses and other charges comprise the remaining offsetting
variance.
OTHER
THREE MONTHS ENDED
MARCH 31,
-------------------
2004 2003
------- -------
(MILLIONS)
Segment revenues $ 12.6 $ 28.0
======= =======
Segment profit (loss) $ (8.7) $ 4.8
======= =======
Other segment revenues for first-quarter 2003 include approximately $14
million of revenues related to certain butane blending assets, which were sold
during third-quarter 2003.
Other segment loss for 2004 includes $6.5 million net unreimbursed
advisory fees related to the recapitalization of Longhorn Partners Pipeline,
L.P. (Longhorn) in February 2004. If the project achieves certain future
performance measures, the unreimbursed fees may be recovered. As a result of
this recapitalization, we sold a portion of our equity investment in Longhorn
for $11.4 million, received $58 million in repayment of a portion of our
advances to Longhorn and converted the remaining advances, including accrued
interest, into preferred equity interests in Longhorn. These preferred equity
interests are subordinate to the preferred interests held by the new investors.
Other than the unreimbursed fees, no gain or loss was recognized on this
transaction.
99.6-13
Management's Discussion & Analysis (Continued)
FAIR VALUE OF TRADING DERIVATIVES
The chart below reflects the fair value of derivatives held for trading
purposes as of March 31, 2004. We have presented the fair value of assets and
liabilities by the period in which we expect them to be realized.
TO BE TO BE TO BE TO BE REALIZED
REALIZED IN REALIZED IN REALIZED IN IN 61-120
1-12 MONTHS 13-36 MONTHS 36-60 MONTHS MONTHS TOTAL FAIR
(YEAR 1) (YEARS 2-3) (YEARS 4-5) (YEARS 6-10) VALUE
- ----------- ------------ ------------ -------------- ----------
(MILLIONS)
$ (63) $ 8 $ (14) $ (2) $ (71)
As the table above illustrates, we are not materially engaged in trading
activities. However, we hold a substantial portfolio of non-trading derivative
contracts. Non-trading derivative contracts are those that hedge or could
possibly hedge Power's long-term structured contract position and the activities
of our other segments on an economic basis. Certain of these economic hedges
have not been designated as or do not qualify as SFAS No. 133 hedges. As such,
changes in the fair value of these derivative contracts are reflected in
earnings. We also hold certain derivative contracts, which do qualify as SFAS
No. 133 cash flow hedges, which primarily hedge Exploration & Production's
forecasted natural gas sales. As of March 31, 2004, the fair value of these
non-trading derivative contracts was a net asset of $281 million.
COUNTERPARTY CREDIT CONSIDERATIONS
We include an assessment of the risk of counterparty non-performance in
our estimate of fair value for all contracts. Such assessment considers 1) the
credit rating of each counterparty as represented by public rating agencies such
as Standard & Poor's and Moody's Investors Service, 2) the inherent default
probabilities within these ratings, 3) the regulatory environment that the
contract is subject to and 4) the terms of each individual contract.
Risks surrounding counterparty performance and credit could ultimately
impact the amount and timing of expected cash flows. We continually assess this
risk. We have credit protection within various agreements to call on additional
collateral support if necessary. At March 31, 2004, we held collateral support
of $426 million.
We also enter into netting agreements to mitigate counterparty performance
and credit risk. During first-quarter 2004, we did not incur any significant
losses due to recent counterparty bankruptcy filings.
The gross credit exposure from our derivative contracts as of March 31,
2004 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(a) TOTAL
----------------- ---------- -----------
(MILLIONS)
Gas and electric utilities $ 1,219.4 $ 1,361.9
Energy marketers and traders 2,559.6 4,989.1
Financial institutions 1,117.2 1,117.2
Other 3.7 8.6
---------- -----------
$ 4,899.9 7,476.8
==========
Credit reserves (52.9)
-----------
Gross credit exposure from derivatives(b) $ 7,423.9
===========
99.6-14
Management's Discussion & Analysis (Continued)
We assess our credit exposure on a net basis. The net credit exposure from
our derivatives as of March 31, 2004 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(a) TOTAL
----------------- -------- ----------
(MILLIONS)
Gas and electric utilities $ 593.5 $ 604.6
Energy marketers and traders 60.6 434.1
Financial institutions 175.0 175.0
Other 2.4 2.7
-------- ----------
$ 831.5 1,216.4
========
Credit reserves (52.9)
----------
Net credit exposure from derivatives(b) $ 1,163.5
==========
(a) We determine investment grade primarily using publicly available credit
ratings. We included counterparties with a minimum Standard & Poor's
rating of BBB- or Moody's Investors Service rating of Baa3 in investment
grade. We also classify counterparties that have provided sufficient
collateral, such as cash, standby letters of credit, adequate parent
company guarantees, and property interests, as investment grade.
(b) One counterparty within the California power market represents more than
ten percent of the derivative assets and is included in investment grade.
Standard & Poor's and Moody's Investors Service do not currently rate this
counterparty. We included this counterparty in the investment grade column
based upon contractual credit requirements in the event of assignment or
substitution of a new obligation for the existing one.
99.6-15
Management's Discussion & Analysis (Continued)
FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY
Overview
Entering 2003, we faced significant liquidity challenges with sizeable
maturing debt obligations and limited financial flexibility. In February 2003,
we outlined our planned business strategy to address these challenges, which
included reducing debt and increasing our liquidity through asset sales,
strategic levels of financing and reductions of operating costs.
As discussed in our Annual Report on Form 10-K for the year ended December
31, 2003, we successfully executed certain critical components of our plan
during 2003. Key execution steps for 2004 and beyond include the following:
- completion of planned asset sales, which are estimated to
generate proceeds of approximately $800 million in 2004;
- additional reductions of our SG&A costs;
- the replacement of our cash-collateralized letter of credit
and revolver facility with facilities that do not encumber
cash; and
- continuation of our efforts to exit from the Power business.
Sources of liquidity
Our liquidity is derived from both internal and external sources. Certain
of those sources are available to us (at the parent level) and others are
available to certain of our subsidiaries.
At March 31, 2004, we have the following sources of liquidity:
- Cash-equivalent investments at the corporate level of $1.7
billion as compared to $2.2 billion at December 31, 2003.
- Cash and cash-equivalent investments of various international
and domestic entities of $259 million, as compared to $91
million at December 31, 2003.
At March 31, 2004, we have capacity of $532 million available under our
$800 million revolving and letter of credit facility compared to $447 million at
December 31, 2003. In June 2003, we entered into this revolving and letter of
credit facility, which is used primarily for issuing letters of credit and must
be collateralized at 105 percent of the level utilized (see Note 10 of Notes to
Consolidated Financial Statements).
We have an effective shelf registration statement with the Securities and
Exchange Commission that authorizes us to issue an additional $2.2 billion of a
variety of debt and equity securities. However, the ability to utilize this
shelf registration for debt securities is restricted by certain covenants
associated with our $800 million 8.625 percent senior unsecured notes.
In addition, our wholly owned subsidiaries Northwest Pipeline and Transco
have outstanding registration statements filed with the Securities and Exchange
Commission. As of March 31, 2004, approximately $350 million of shelf
availability remains under these registration statements. However, the ability
to utilize these registration statements is restricted by certain covenants
associated with our $800 million 8.625 percent senior unsecured notes. Interest
rates, market conditions, and industry conditions will affect amounts raised, if
any, in the capital markets.
During the first three months of 2004, we satisfied liquidity needs with:
- $279 million in cash generated from the sale of the Alaska
refinery and related assets, and
- $149.9 million in cash generated from cash flows of continuing
operations.
99.6-16
Management's Discussion & Analysis (Continued)
Outlook for the remainder of 2004
We estimate capital and investment expenditures will be approximately $725
million to $825 million for 2004. During the remainder of 2004, we expect to
fund capital and investment expenditures, debt payments and working-capital
requirements through (1) cash and cash equivalent investments on hand, (2) cash
generated from operations, and (3) cash generated from the sale of assets. We
expect to realize approximately $800 million from asset sales in 2004 (including
the $279 million of cash received from the March 31, 2004 sale of the Alaska
refinery) and expect to generate $1.0 to $1.3 billion in cash flow from
continuing operations.
In April 2004, we entered into two unsecured bank revolving credit
facilities totaling $500 million. These facilities provide for borrowings and
letters of credit, but will be used primarily for issuing letters of credit.
During April 2004, use of these new facilities released approximately $500
million of restricted cash, restricted investments and margin deposits. Also, on
May 3, 2004 we entered into a new three-year, $1 billion secured revolving
credit facility which is available for borrowings and letters of credit.
Northwest Pipeline and Transco have access to $400 million each under the
facility. The new facility is secured by certain Midstream assets and a
guarantee from WGP (see Note 10 of Notes to the Consolidated Financial
Statements).
In the remainder of 2004, we expect to make significant additional
progress towards debt reduction while maintaining management's estimate of
appropriate levels of cash and other forms of liquidity. To manage our
operations and meet unforeseen or extraordinary calls on cash, we expect to
maintain cash and/or liquidity levels of at least $1 billion. While our access
to the capital markets continues to improve, one of our indentures, as well as
the two unsecured facilities closed in April, have covenants that restrict our
ability to issue new debt, with minimal exceptions, until a certain fixed charge
coverage ratio is achieved. We expect to satisfy this requirement by the end of
2005.
Credit ratings
As part of executing the business plan announced in February of 2003, we
established a goal of returning to investment grade status. While reduction of
debt is viewed as a key contributor towards this goal, certain of the key credit
rating agencies have imputed the financial commitments associated with our
long-term tolling agreements within the Power business as debt. If we are unable
to achieve our goal of exiting the Power business and/or the elimination of
these commitments, receiving an investment grade rating may be further delayed.
See Note 1 of Notes to Consolidated Financial Statements for a further
discussion on the Power business status.
Off-balance sheet financing arrangements and guarantees of debt or other
commitments to third parties
As discussed previously, in April 2004, we entered into two unsecured bank
revolving credit facilities totaling $500 million. We were able to obtain the
unsecured credit facilities because the bank syndicated its associated credit
risk into the institutional investor market via a 144A offering. Upon the
occurrence of certain credit events, outstanding letters of credit become cash
collateralized creating a borrowing under the facilities, and concurrently the
bank can deliver the facilities to the institutional investors, whereby the
investors replace the bank as lender under the facilities.
The bank established trusts funded by the institutional investors, whereby
the assets of the trusts serve as collateral to reimburse the bank for our
borrowings in the event the facilities are delivered to the investors. We have
no asset securitization or collateral requirements under the new facilities.
During April 2004, use of these new facilities released approximately $500
million of restricted cash, restricted investments and margin deposits (see Note
10 of Notes to the Consolidated Financial Statements).
OPERATING ACTIVITIES
In the first quarter of 2003, we recorded an accrual for fixed rate
interest included in the RMT Note on the Consolidated Statement of Cash Flows
representing the quarterly non-cash reclassification of the deferred fixed rate
interest from an accrued liability to the RMT Note. The amortization of deferred
set-up fee and fixed rate interest on the RMT Note relates to amounts recognized
in the income statement as interest expense, which were not payable until
maturity. The RMT Note was repaid in May 2003.
Items reflected as discontinued operations within operating activities in
the Consolidated Statement of Cash Flows include approximately $70 million in
use of funds related to the timing of settling working capital issues of the
Alaska refinery and related assets. We expect to receive the proceeds from the
collection of approximately $58 million in trade receivables related to the
Alaska refinery and related assets in the second quarter.
99.6-17
Management's Discussion & Analysis (Continued)
FINANCING ACTIVITIES
On March 15, 2004, we retired the remaining $679 million obligation
pertaining to the outstanding balance of the 9.25 percent senior unsecured Notes
due March 15, 2004. The $679 million represented the remaining amount of the
Notes subsequent to the fourth-quarter 2003 tender which retired $721 million of
the original $1.4 billion balance.
For a discussion of other borrowings and repayments in 2004, see Note 10
of Notes to Consolidated Financial Statements.
Dividends paid on common stock are currently $.01 per common share on a
quarterly basis and totaled $5.2 million for the three months ended March 31,
2004. One of the covenants under the indenture for the $800 million senior
unsecured notes due 2010 currently limits our quarterly common stock dividends
to not more than $.02 per common share. This restriction will be removed in the
future if certain requirements in the covenants are met.
INVESTING ACTIVITIES
During the first quarter of 2004, we purchased $235.9 million of
restricted investments comprised of U.S. Treasury notes and retired $331.2
million on their scheduled maturity date. We made these purchases to satisfy the
105 percent cash collateralization covenant in the $800 million revolving credit
facility (see Note 10 of Notes to Consolidated Financial Statements).
During February 2004, we were a party to a recapitalization plan completed
by Longhorn Partners Pipeline, L.P. (Longhorn). As a result of this plan, we
received $58 million in repayment of a portion of our advances to Longhorn and
converted the remaining advances, including accrued interest, into preferred
equity interests in Longhorn. The $58 million received is included in Proceeds
from dispositions of investments and other assets.
The following first-quarter sales provided significant proceeds from sales
and may include various adjustments subsequent to the actual date of sale.
In 2004:
- $279 million of cash proceeds related to the sale of Alaska
refinery, retail and pipeline and related assets.
In 2003:
- $453 million related to the sale of the Midsouth refinery;
- $188 million related to the sale of the Williams travel
centers; and
- $40 million related to the sale of the Worthington facility.
CONTRACTUAL OBLIGATIONS
As discussed in our Annual Report on Form 10-K for the year ended December
31, 2003, we had certain contractual obligations at December 31, 2003, with
various maturity dates, related to the following:
- notes payable;
- long-term debt;
- capital and operating leases;
- purchase obligations; and
- other long-term liabilities, including physical and financial
derivatives.
99.6-18
Management's Discussion & Analysis (Continued)
During the first-quarter 2004, the amount of our contractual obligations
changed significantly due to the following:
- On March 15, 2004, we retired the remaining $679 million
obligation pertaining to the outstanding balance of the 9.25
percent senior unsecured Notes due March 15, 2004.
- Power's physical and financial derivative obligations
decreased by approximately $483 million. The decrease is due
to normal trading and market activity and the expiration of
obligations related to the first three months of 2004.
- As part of the sale of the Alaska refinery, we terminated a
$385 million crude purchase contract with the state of Alaska.
99.6-19