ITEM 2
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 included the
completion of planned asset sales; 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.
Asset sales during 2004 were initially expected to generate proceeds of
approximately $800 million. In first-quarter 2004, we completed the sale of our
Alaska refinery and related assets for approximately $304 million. On July 28,
2004 we completed the sale of three straddle plants in western Canada for
approximately $536 million. In addition to these transactions, we currently
expect to generate additional proceeds from the sale of assets of approximately
$50 to $100 million.
In April 2004, we entered into two new unsecured credit facilities
totaling $500 million, primarily for 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 12 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 12 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.
In May 2004, we made cash tender offers for approximately $1.34 billion
aggregate principal amount of a specified series of our outstanding notes and
debentures. As of the June 8, 2004 tender offer expiration date, we accepted for
purchase $1.17 billion of the notes for purchase. In May 2004, we also
repurchased debt of approximately $255 million of various maturities on the open
market (see Note 12 in Notes to Consolidated Financial Statements). Our
repurchase of these notes served to decrease debt and will result in reduced
annual interest expense and reduced administrative costs associated with the
various debt issues.
Long-term debt, excluding the current portion, at June 30, 2004 was
approximately $9.5 billion.
We are seriously considering the possibility of creating a public
master limited partnership (MLP) that would own and operate certain Midstream
assets. Initial operations would include various NGL storage, fractionation and
transportation assets most of which we had previously considered selling due to
the strong interest from existing MLP's in this sector.
99.6-1
Management's Discussion and Analysis (Continued)
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.
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 has 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.
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.
99.6-2
Management's Discussion and Analysis (Continued)
GENERAL
In accordance with the provisions related to discontinued operations
within Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," the consolidated financial
statements and notes in Item 1 [Exhibit 99.5] 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 6 of Notes to
Consolidated Financial Statements).
During second-quarter 2004, our Board of Directors approved a plan
authorizing management to negotiate and facilitate a sale of the straddle plants
in western Canada, which were part of the Midstream segments. As a result, these
assets and their related income and cash flows are now reported as discontinued
operations. In addition, the following components are included as discontinued
operations:
- 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.
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, as restated and amended.
99.6-3
Management's Discussion and Analysis (Continued)
RESULTS OF OPERATIONS
CONSOLIDATED OVERVIEW
The following table and discussion is a summary of our consolidated results
of operations for the three and six months ended June 30, 2004. The results of
operations by segment are discussed in further detail following this
consolidated overview discussion.
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
----------------------------------- --------------------------------------
% CHANGE
% CHANGE FROM
2004 2003 FROM 2003(1) 2004 2003 2003 (1)
-------- -------- ---------- -------- ------- ----------
(MILLIONS) (MILLIONS)
Revenues $3,048.7 $3,612.3 -16% $6,114.2 $8,388.4 -27%
Costs and expenses:
Costs and operating expenses 2,658.3 3,024.8 +12% 5,348.2 7,448.4 +28%
Selling, general and administrative expenses 81.9 115.4 +29% 166.3 221.0 +25%
Other (income) expense - net 23.0 (225.3) NM 31.4 (224.6) NM
General corporate expenses 28.3 21.8 -30% 60.3 44.7 -35%
-------- -------- -------- --------
Total costs and expenses 2,791.5 2,936.7 +5% 5,606.2 7,489.5 +25%
-------- -------- -------- --------
Operating income 257.2 675.6 -62% 508.0 898.9 -43%
Interest accrued - net (221.6) (394.6) +44% (460.9) (735.5) +37%
Interest rate swap income (loss) 6.8 (6.1) NM (1.3) (8.9) +85%
Investing income (loss) 11.7 (43.2) NM 22.0 3.1 NM
Early debt retirement costs (96.8) -- NM (97.3) -- NM
Minority interest in income of consolidated
subsidiaries (6.0) (6.0) -- (10.8) (9.5) -14%
Other income (expense) - net 13.4 13.9 -4% 14.8 36.0 -59%
-------- -------- -------- --------
Income (loss) from continuing operations before
income taxes and cumulative effect of change in
accounting principles (35.3) 239.6 NM (25.5) 184.1 NM
Provision (benefit) for income taxes (17.3) 125.9 NM (6.0) 113.5 NM
-------- -------- -------- --------
Income (loss) from continuing operations (18.0) 113.7 NM (19.5) 70.6 NM
Income (loss) from discontinued operations (.2) 156.0 NM 11.2 145.9 -92%
-------- -------- -------- --------
Income (loss) before cumulative effect of change
in accounting principles (18.2) 269.7 NM (8.3) 216.5 NM
Cumulative effect of change in accounting
principles -- -- -- -- (761.3) +100%
-------- -------- -------- --------
Net income (loss) (18.2) 269.7 NM (8.3) (544.8) +98%
Preferred stock dividends -- 22.7 +100% -- 29.5 +100%
-------- -------- -------- --------
Income (loss) applicable to common stock $ (18.2) $ 247.0 NM $ (8.3) $ (574.3) +99%
======== ======== ======== ========
(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.
99.6-4
Management's Discussion and Analysis (Continued)
Three Months Ended June 30, 2004 vs. Three Months Ended June 30, 2003
Our revenues decreased $563.6 million due primarily to decreased
revenues at our Power segment, slightly offset by increased revenues at our
Midstream segment. Power revenues decreased approximately $569.8 million due
primarily to lower power sales volumes and decreased net unrealized gains on
power and natural gas derivative contracts due primarily to the impact of a
lesser increase in forward natural gas prices in second-quarter 2004. Partially
offsetting these decreases were increased crude and refined product revenues
resulting from increased sales to optimize pipeline and storage capacity as well
as increased realized interest rate revenues due to higher interest rates in
2004. Midstream's revenues increased $128.3 million due primarily to higher
product sales for natural gas liquids (NGLs) and olefins resulting from
increased production volumes and higher market prices, and increased fee revenue
from deepwater assets. The increases at Midstream were partially offset by the
sale of our wholesale propane business in fourth-quarter 2003.
Costs and operating expenses decreased $366.5 million due primarily to
decreased costs and operating expenses at Power, slightly offset by increased
costs at Midstream. The decrease at Power is due primarily to lower power
purchase volumes, partially offset by increased crude and refined product costs.
The increase at Midstream is due primarily to higher natural gas and ethane
purchases required to produce NGL and olefins. The increases were offset by
lower natural gas liquids trading purchases due to the 2003 sale of our
wholesale propane business.
Selling, general and administrative expenses decreased $33.5 million.
This cost reduction is due primarily to reduced staffing levels at Power
reflective of our strategy to exit this business.
Other (income) expense - net in 2004 includes an $11.3 million loss
provision related to an ownership dispute on prior period production included in
the Exploration & Production segment and a $9 million write-off of
previously-capitalized costs on an idled segment of Northwest's system. Other
(income) expense - net in 2003 includes a $175 million gain from the sale of a
Power contract and $91.5 million in net gains from the sale of Exploration &
Production's interests in natural gas properties. Partially offsetting these
gains in 2003 was a $25.5 million charge at Northwest to write off capitalized
software development costs and a $20 million charge related to a settlement by
Power with the CFTC (see Note 13 of Notes to Consolidated Financial Statements).
General corporate expenses increased $6.5 million due primarily to
increased third-party costs associated with compliance activities and with
efforts to evaluate and implement certain cost reduction strategies through
internal initiatives and outsourcing of certain services.
Interest accrued - net decreased $173 million due primarily to:
- $117 million lower interest expense and fees at Exploration &
Production, due primarily to the May 2003 prepayment of the
RMT note payable;
- $24 million lower amortization expense related to deferred
debt issuance costs, due primarily to the reduction of debt;
and
- a $24 million decrease reflecting lower average borrowing
levels.
We entered into interest rate swaps with external counterparties
primarily in support of the energy-trading portfolio (see Note 15 of Notes to
Consolidated Financial Statements). The change in fair market value of these
swaps was $12.9 million more favorable in 2004 than 2003. The total notional
amount of these swaps was approximately $300 million at June 30, 2004 and June
30, 2003.
Investing income (loss) increased $54.9 million due primarily to the
absence in 2004 of the following 2003 charges, partially offset by a $10.8
million impairment of our investment in equity securities of Longhorn Partners
Pipeline LP (Longhorn):
- a $42.4 million 2003 impairment of our investment in equity
and debt securities of Longhorn;
- a $13.5 million impairment of a cost-based investment in a
company holding phosphate reserves; and
- an $8.5 million impairment of our investment in Aux Sable.
99.6-5
Management's Discussion and Analysis (Continued)
Early debt retirement costs for 2004 includes premiums, fees and
expenses related to the debt repurchase and the debt tender offer and consent
solicitations that we completed in the second quarter.
Other income (expense) - net, below operating income in 2004, includes
a $4.1 million net gain in 2004 and a $7.9 million net gain in 2003 related to a
foreign currency transaction gain or loss on a Canadian dollar denominated note
receivable and an offsetting derivative gain or loss on a forward contract to
fix the U.S. dollar principal cash flows from the note receivable. The note
receivable was repaid in July 2004 with proceeds from the sale of the Canadian
straddle plants and the related forward contract was terminated.
The provision (benefit) for income taxes was favorable by $143.2
million due primarily to a pre-tax loss in 2004 as compared to a pre-tax income
for 2003. The effective income tax rate for 2004 is greater than the federal
statutory rate due primarily to the effect of state income taxes, partially
offset by net foreign operations and an accrual for income tax contingencies.
The effective income tax rate for 2003 is greater than the federal statutory
rate due primarily to the financial impairment of certain investments, capital
losses generated, for which valuation allowances were established, nondeductible
expenses and an accrual for income tax contingencies.
Income (loss) from discontinued operations decreased $156.2 million
from an income position in 2003 of $156 million to a loss position in 2004 of
$.2 million (see Note 6 of Notes to Consolidated Financial Statements). The
decrease in the operating results from discontinued operations activities from
an income position in 2003 to a loss position in 2004 is reflective of income
(loss) from discontinued operations for the following operations:
- the absence of $9.3 million income from discontinued
operations at Texas Gas;
- the absence of $8.3 million income from discontinued
operations at Williams Energy Partners as well as a $5.1
million loss from discontinued operations in 2004 which
includes the settlement related to the environmental
indemnifications;
- the absence of $7.9 million income from discontinued
operations from Raton Basin and Hugoton Embayment natural gas
exploration and production properties; and
- a $9.6 million decrease in loss from discontinued operations
for Gulf Liquids New River Project LLC (Gulf Liquids).
The 2003 gain on sale of discontinued operations of $232.9 million includes:
- a $11.1 million impairment of the soda ash mining facility
located in Colorado;
- a $24.7 million gain on the sale of an earn-out agreement that
we retained following the first quarter 2003 sale of a
refinery located in Memphis, Tennessee;
- a $39.9 million gain on sale of natural gas exploration and
production properties;
- a $275.6 million gain on the sale of our 100 percent general
partnership interest and 54.6 percent limited partner
investment in Williams Energy Partners; and
- a $92.6 million impairment of Gulf Liquids New River Project
LLC.
In June 2003, we redeemed all of our outstanding 9.875 percent
cumulative-convertible preferred shares. Thus, no preferred dividends were paid
in 2004.
Six Months Ended June 30, 2004 vs. Six Months Ended June 30, 2003
Our revenues decreased approximately $2.3 billion due primarily to
decreased revenues at our Power, Midstream and Exploration & Production
segments. Power revenues decreased approximately $2.1 billion due primarily to
lower power and crude and refined products sales volumes and decreased net
unrealized gains on natural gas derivative contracts due primarily to the impact
of forward natural gas prices. Midstream's revenues decreased $109.8 million due
primarily to the sale of our wholesale propane business in the fourth quarter of
2003. Largely offsetting this decrease at Midstream were higher product sales
for NGLs and olefins resulting from higher production volumes and higher market
prices. In addition, Exploration & Production's revenues decreased $89.9 million
due primarily to lower domestic production revenues from lower net realized
average prices and lower production volumes as a result of 2003 property sales,
lower gas management revenues, lower income from the utilization of excess
transportation capacity and lower income on derivative instruments that did not
qualify for hedge accounting.
99.6-6
Management's Discussion and Analysis (Continued)
Costs and operating expenses decreased $2.1 billion due primarily to
decreased costs and operating expenses at Power and Midstream. The decrease at
Power is due primarily to lower power purchase volumes and lower crude and
refined products costs. In addition, costs at Midstream were impacted by the
sale of our wholesale propane business offset by higher NGL and olefins
production costs.
Selling, general and administrative expenses decreased $54.7 million,
due primarily to reduced staffing levels at Power reflective of our strategy to
exit this business. Also contributing to the decrease at Power was the absence
of $12.6 million of expense related to the accelerated recognition of deferred
compensation during 2003.
Other (income) expense - net, within operating income, in 2004 includes
an $11.3 million loss provision related to an ownership dispute on prior period
production included in the Exploration & Production segment; a $9 million
write-off of previously-capitalized costs on an idled segment of Northwest's
system; and $6.1 million in fees related to the sale of certain receivables to a
third party. Other expense - net in 2003 includes a $175 million gain from the
sale of a Power contract and $91.5 million in net gains from the sale of
Exploration & Production's interests in certain natural gas properties.
Partially offsetting these gains in 2003 was a $25.5 million charge at Northwest
to write-off capitalized software development costs for a service delivery
system and a $20 million charge related to a settlement by Power with the CFTC
(see Note 13 of Notes to Consolidated Financial Statements).
General corporate expenses increased $15.6 million due primarily to
increased third-party costs associated with compliance activities and with
efforts to evaluate and implement certain cost reduction strategies through
internal initiatives and outsourcing of certain services.
Interest accrued - net decreased $274.6 million due primarily to:
- $203 million lower interest expense and fees at Exploration &
Production due primarily to the May 2003 prepayment of the RMT
note payable;
- $34 million lower amortization expense related to deferred
debt issuance costs, primarily due to the reduction of debt;
- a $28 million decrease reflecting lower average borrowing
levels;
- a $10 million decrease reflecting lower average interest rates
on long-term debt;
- the absence in 2004 of $12 million of interest expense within
Power related to a FERC ruling in 2003; and
- an $18.5 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 15 of Notes to
Consolidated Financial Statements). The change in fair market value of these
swaps was $7.6 million more favorable in 2004 than 2003. The total notional
amount of these swaps was approximately $300 million at June 30, 2004 and June
30, 2003.
Investing income increased $18.9 million due primarily to:
- the absence in 2004 of a $42.4 million impairment of our
investment in equity and debt securities of Longhorn in 2003,
partially offset by $6.5 million net unreimbursed Longhorn
recapitalization advisory fees in 2004;
- the absence in 2004 of a $12 million impairment of our
cost-based investments in Algar Telecom S.A. and a $13.5
million impairment of a cost-based investment in a company
holding phosphate reserves;
- $13.9 million higher equity earnings from Discovery due
primarily to the absence of unfavorable accounting adjustments
recorded at the partnership in 2003;
99.6-7
Management's Discussion and Analysis (Continued)
- the absence in 2004 of a $8.5 million impairment of our -
investment in Aux Sable;
- $41 million lower interest income at Power due primarily to a
favorable adjustment in 2003 resulting from certain 2003 FERC
proceedings;
- $10 million lower interest income on advances to Longhorn that
were subsequently exchanged for preferred stock; and
- a $10.8 million impairment of our investment in equity
securities of Longhorn in 2004.
Early debt retirement costs for 2004 include premiums, fees and
expenses related to the May 2004 debt repurchase and the debt tender offer and
consent solicitations that we completed in the second quarter.
Other income (expense) - net, below operating income includes a $6.7
million net gain in 2004 and a $20.4 million net gain in 2003 related to a
foreign currency transaction gain or loss on a Canadian dollar denominated note
receivable and an offsetting derivative gain or loss on a forward contract to
fix the U.S. dollar principal cash flows from the note receivable. The note
receivable was repaid in July 2004 with proceeds from the sale of the Canadian
straddle plants and the related forward contract was terminated.
The provision (benefit) for income taxes was favorable by $119.5
million due primarily to a pre-tax loss in 2004 as compared to a pre-tax income
for 2003. The effective income tax rate for 2004 is less than the federal
statutory rate due primarily to net foreign operations and an accrual for income
tax contingencies, partially offset by the effect of state income taxes. The
effective income tax rate for 2003 is greater than the federal statutory rate
due primarily to the financial impairment of certain investments, capital losses
generated, for which valuation allowances were established, nondeductible
expenses and an accrual for income tax contingencies.
Income (loss) from discontinued operations decreased $134.7 million
(see Note 6 of Notes to Consolidated Financial Statements). The decrease in the
operating results from discontinued operations activities is reflective of
income (loss) from discontinued operations for the following operations:
- the absence of $58.5 million income from discontinued
operations at Texas Gas;
- the absence of $28.5 million income from discontinued
operations at Alaska refining, retail and pipeline;
- the absence of $22.1 million of income from discontinued
operations at Williams Energy Partners which was sold in 2003;
- a $5.6 million loss from discontinued operations at Williams
Energy Partners which includes the settlement related to the
environmental indemnifications;
- the absence of $20.1 million income from discontinued
operations from Raton Basin and Hugoton Embayment natural gas
exploration and production properties;
- a $26.8 million decrease in loss from discontinued operations
for Gulf Liquids; and
- an $8.8 million increase in income from discontinued
operations for Canadian straddle plants.
The 2003 gain on sale of discontinued operations of $115.6 million includes:
- a $109 million impairment of Texas Gas Transmission;
- an $8 million impairment of the Alaska refinery, retail and
pipeline assets;
- a $16.1 million impairment of the soda ash mining facility
located in Colorado;
- a $29.4 million gain on the sale of a refinery and other
related operations located in Memphis, Tennessee, of which
$24.7 million relates to the sale of an earn-out agreement
that we retained following the sale of the assets;
99.6-8
Management's Discussion and Analysis (Continued)
o a $39.9 million gain on sale of certain natural gas
exploration & production properties;
o a $6.4 million loss on sale of our Bio-energy operations;
o a $275.6 million gain on the sale of Williams Energy Partners;
and
o a $92.6 million impairment of Gulf Liquids.
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. Thus, no preferred dividends were paid
in 2004.
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 15 of Notes to Consolidated Financial Statements).
Prior period amounts have been restated to reflect these segment changes.
The following discussions relate to the results of operations of our segments.
POWER
OVERVIEW OF SIX MONTHS ENDED JUNE 30, 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 operating results for the
first half of 2004.
In the first half 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 portfolios.
The decrease in revenues, costs and selling, general and administrative expenses
reflect our efforts to exit the Power business.
Key factors that influence Power's financial condition and operating
performance include the following:
o prices of power and natural gas, including changes in the
margin between power and natural gas prices;
o changes in market liquidity, including changes in the ability
to economically hedge the portfolio;
o changes in power and natural gas price volatility;
o changes in interest rates;
o changes in the regulatory environment; and
o changes in power and natural gas supply and demand.
99.6-9
Management's Discussion and Analysis (Continued)
OUTLOOK FOR THE REMAINDER OF 2004
In the remainder of 2004, we anticipate further variability in Power's
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. The negative fair value of these tolling contracts may result in
future accrual losses. Continued efforts to sell all or a portion of these
contracts 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.
PERIOD-OVER-PERIOD RESULTS
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ----------------------
2004 2003 2004 2003
---------- ---------- ---------- ---------
(MILLIONS) (MILLIONS)
Segment revenues $ 2,353.7 $ 2,923.5 $ 4,628.5 $ 6,699.1
========== ========== ========== ==========
Segment profit $ 43.8 $ 335.9 $ 11.8 $ 198.9
========== ========== ========== ==========
Three months ended June 30, 2004 vs. three months ended June 30, 2003
The $569.8 million decrease in revenues includes a $407.4 million
decrease in realized revenues and a $162.4 million decrease in net unrealized
gains.
Realized revenues represent 1) revenue from sale of commodities or
completion of energy-related services and 2) gains and losses from the net
financial settlement of derivative contracts. The $407.4 million decrease in
realized revenues is primarily due to a decrease in power and natural gas
realized revenues of $536.3 million, partially offset by a $58.9 million
increase in crude and refined products realized revenues and a $70 million
increase in interest rate portfolio realized revenues.
Power and natural gas revenues decreased primarily due to a 42 percent
decrease in power sales volumes. Sales volumes decreased because Power did not
replace certain long-term physical 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. Also, during the second quarter of 2003, Power
corrected the accounting treatment previously applied to certain third party
derivative contracts during 2002 and 2001, resulting in the recognition of $93
million in revenue that was attributable to prior periods. Refer to Note 1 of
Notes to Consolidated Financial Statements for further information. The general
decrease in power and natural gas realized revenues is partially offset by
increased intercompany revenue from Midstream. Sales to Midstream have increased
from the prior period as a result of higher processing margins, reflecting
increased demand for natural gas used at its gas processing plants.
Crude and refined products realized revenues increased primarily as a
result of increased refined products sales made in order to optimize pipeline
and storage capacity that Power expects to sell in 2004.
The increase in realized revenues from Power's interest rate portfolio
reflects the impact of a second-quarter 2004 rise in interest rates in contrast
to a second quarter 2003 decline in rates.
Unrealized gains and losses represent changes in the fair value of
derivative contracts with a future settlement or delivery date. The $162.4
million decrease in net unrealized gains is primarily due to a $183.8 million
decrease in net unrealized gains on power and natural gas derivative contracts,
partially offset by an $18.9 million increase in unrealized gains on interest
rate derivatives.
The decrease in power and natural gas net unrealized gains is largely
due to a lesser increase in forward natural gas prices in second-quarter 2004
compared to the same period in 2003. Interest rate unrealized gains (losses)
increased due to an increase in forward interest rates in 2004 compared to a
decrease in forward interest rates in 2003.
99.6-10
Management's Discussion and Analysis (Continued)
Power's costs represent purchases of commodities and fees paid for
energy related services. Costs decreased $413.9 million primarily due to a
$457.4 million decrease in power and natural gas costs offset by a $43.5 million
increase in crude and refined products costs. Power and natural gas costs
decreased largely due to a 44 percent decrease in power purchase volumes due
largely to the expiration or termination of certain long-term physical contracts
in 2003. This decrease was partially offset by the effect of an approximate 17
percent increase in the average price for natural gas purchases. Second-quarter
2004 reductions to liabilities associated with power marketing activities in
California during 2000 and 2001 primarily resulting from recent contract
agreements resulted in gains of $10.4 million, which contributed to the decrease
in costs discussed above. Crude and refined products costs increased due to
increased refined products purchases made in order to optimize pipeline and
storage capacity that Power expects to sell in 2004.
Selling, general and administrative expenses decreased $24 million.
Compensation expense declined in 2004 as a result of staff reductions in prior
years combined with the accelerated recognition in 2003 of certain deferred
compensation arrangements. Power employed approximately 235 employees at June
30, 2004 compared to 265 employees at June 30, 2003. Additionally, a $6.5
million increase in bad debt reserves associated with a contract termination
settlement in 2003 also contributed to the decrease.
Other (income) expense - net in 2003 includes a $175 million gain from
the sale of an energy-trading contract partially offset by a $20 million charge
for a settlement with the CFTC in 2003.
Six months ended June 30, 2004 vs. six months ended June 30, 2003
The $2.1 billion decrease in revenues includes a $2.0 billion decrease
in realized revenues and a $98.4 million decrease in unrealized gains (losses).
The $2 billion decrease in realized revenues is primarily due to a $1.5
billion decrease in power and natural gas realized revenues and a $524 million
decrease in crude and refined products realized revenues, partially offset by a
$55.5 million increase in interest rate portfolio realized revenues.
Power and natural gas realized revenues decreased primarily due to a 45
percent decrease in power sales volumes. Also, during the second quarter of
2003, Power corrected the accounting treatment previously given to certain third
party derivative contracts during 2002 and 2001, resulting in the recognition of
approximately $107 million in revenues in the second quarter of 2003
attributable to prior periods. Refer to Note 1 of Notes to Consolidated
Financial Statements for further information. Power and natural gas revenues in
2003 include a $37 million loss for increased power rate refunds owed to the
state of California as the result of FERC rulings, which partially offsets the
general decrease discussed above.
Crude and refined products revenues decreased primarily due to the sale
of the crude gathering business in 2003 and the continued efforts to exit this
line of business.
The increase in realized revenues from Power's interest rate portfolio
reflects the impact of a rise in interest rates during the first six months of
2004 in contrast to a decline in rates over the same period during 2003.
Unrealized revenues decreased primarily as a result of a decrease in
natural gas unrealized revenues of $106.7 million, largely due to changes in the
forward prices of natural gas. Because Power holds fixed price forward purchase
contracts for natural gas, an increase in the forward natural gas price results
in unrealized gains. However, the increase in the forward price of natural gas
for the first six months of 2004 was not as significant as the increase in the
same period in 2003. Thus, total unrealized gains related to natural gas
derivatives decreased. Offsetting the decrease was the absence of unrealized
losses of approximately $70 million recorded in first-quarter 2003 on contracts
for which we elected the normal purchases and sales exception in second-quarter
2003.
Power's costs decreased $2 billion due to a decrease in power and
natural gas costs of $1.5 billion and a decrease in crude and refined products
costs of $536.4 million. Power and natural gas costs decreased largely due to a
45 percent decrease in power purchase volumes. Second-quarter 2004 reductions to
liabilities associated with power marketing activities in California during 2000
and 2001 resulted in gains of $10.4 million, which contributed to the decrease
in costs discussed above. Costs in 2004 also reflect a $13 million payment made
to terminate a non-derivative power sales contract, which partially offsets the
decrease in power and natural gas costs. Crude and refined products costs
decreased largely due to the sale of the crude gathering business in 2003 and
the continued efforts to exit this line of business.
99.6-11
Management's Discussion and Analysis (Continued)
Selling, general and administrative expenses decreased $44.3 million.
Compensation expense declined in 2004 as a result of staff reductions in prior
years combined with the accelerated recognition in 2003 of certain deferred
compensation arrangements. A $6.3 million reversal of bad debt reserve resulting
from the first-quarter 2004 settlement with certain California utilities and the
absence of a $6.5 million increase to bad debt reserves associated with a
termination settlement in second-quarter 2003 also contributed to the decrease.
Other (income) expense - net in 2003 includes a $175 million gain from
the sale of an energy-trading contract partially offset by a $20 million charge
for a settlement with the CFTC. Other (income) expense - net in 2004 includes
$6.1 million in fees related to the sale of certain receivables to a third
party.
GAS PIPELINE
OVERVIEW OF SIX MONTHS ENDED JUNE 30, 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,
Northwest made additional progress towards repairing and restoring a segment of
its natural gas pipeline system in western Washington.
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.
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
to date. Primarily because of customer market profiles prior to the summer
months, we have been able to meet firm service requirements through our parallel
pipeline in the same corridor.
We have successfully hydrotested and returned to service 111 miles of
the 268 miles of pipe affected by the ACAO. That effort has restored 131
MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate
to meet most market conditions. The restored facilities will be monitored and
tested as necessary until they are ultimately replaced. Total estimated testing
and remediation costs are between $40 and $50 million, including approximately
$9 million related to one segment of pipe that we recently determined not to
return to service and is thus being expensed in the second quarter.
As currently required by OPS, we plan to replace the pipeline's entire
capacity by November 2006 to meet long-term demands. We conducted a reverse open
season to determine whether any existing customers were willing to relinquish or
reduce their capacity commitments to allow us to reduce the scope of pipeline
replacement facilities. That resulted in 13 MDth/day of capacity being
relinquished and incorporated into the replacement project. The total costs of
the capacity replacement project are expected to be in the range of
approximately $310 million to $360 million. The majority of these costs will be
spent in 2005 and 2006. We anticipate filing a rate case to recover the
capitalized costs relating to restoration and replacement of facilities
following the in-service date of the replacement facilities.
99.6-12
Management's Discussion and Analysis (Continued)
PERIOD-OVER-PERIOD RESULTS
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------- ---------------------------
2004 2003 2004 2003
------------- ------------- ----------- -----------
(MILLIONS) (MILLIONS)
Segment revenues $ 331.0 $ 330.7 $ 690.0 $ 670.3
======== ======== ======== ========
Segment profit $ 132.8 $ 115.5 $ 280.2 $ 265.8
======== ======== ======== ========
Three months ended June 30, 2004 vs. three months ended June 30, 2003
The $300,000 increase in Gas Pipeline revenues is due primarily to $14
million of higher transportation revenues associated with expansion projects.
The $14 million consists of $10 million at Northwest from an expansion project
that became operational in October 2003 (Evergreen) and $4 million higher demand
revenues on the Transco system resulting primarily from new expansion projects
that became operational in May 2003 (Momentum Phase I), November 2003
(Trenton-Woodbury) and February 2004 (Momentum Phase II). Partially offsetting
these increases were $7 million lower revenues from the sale of environmental
mitigation credits and $5 million lower transportation revenues ($3 million due
to lower short-term firm on Northwest and $2 million due to lower gathering
revenue on Transco).
Costs and operating expenses increased $2 million, or one percent, due
primarily to a $4 million increase in non-income related taxes, $2 million
higher fuel expense at Transco, reflecting a reduction in pricing differentials
on the volumes of gas used in operations as compared to 2003. These increases
were partially offset by $4 million reduction of depreciation, depletion and
amortization expense related to environmental mitigation credits.
Other (income) expense - net in 2004 includes a $9 million charge for
the write-off of previously-capitalized costs incurred on an idled segment of
Northwest's system that we recently determined will not be returned to service.
Other (income) expense - net in 2003 includes a $25.5 million charge at
Northwest to write off capitalized software development costs for a service
delivery system following a decision not to implement.
The $17.3 million, or 15 percent, increase in Gas Pipeline segment
profit is due primarily to the absence of the $25.5 million charge in 2003
discussed above and $3.2 million higher equity earnings (included in Investing
income (loss)). These items were partially offset by the $9 million charge
discussed above and the $2 million increase in costs and operating expenses. The
increase in equity earnings includes a $3 million increase in earnings from our
investment in Gulfstream Natural Gas System (Gulfstream).
Six months ended June 30, 2004 vs. six months ended June 30, 2003
The $19.7 million, or three percent, increase in Gas Pipeline revenues
is due primarily to $32 million higher transportation revenues associated with
expansion projects. The $32 million consists primarily of $20 million at
Northwest from an expansion project that became operational in October 2003
(Evergreen) and $12 million higher demand revenues on the Transco system
resulting from new expansion projects that became operational in May 2003
(Momentum Phase I), November 2003 (Trenton-Woodbury) and February 2004 (Momentum
Phase II). Revenues also increased due to $17 million higher gas exchange
imbalance settlements (offset in costs and operating expenses). Partially
offsetting these increases were $9 million lower revenues associated with
tracked costs, which are passed through to customers (substantially offset in
costs and operating expenses), $8 million lower revenues from the sale of
environmental mitigation credits and $8 million lower transportation revenues
($5 million due to lower short-term firm on Northwest and $3 million due to
lower gathering revenues on Transco).
Costs and operating expenses increased $26 million, or eight percent,
due primarily to $17 million higher gas exchange imbalance settlements (offset
in revenues), $11 million higher fuel expense at Transco, reflecting a reduction
in pricing differentials on the volumes of gas used in operations as compared to
2003 and $7 million higher expenses related to operations and maintenance
expenses. These increases were partially offset by $8 million lower recovery of
tracked costs which are passed through to customers (offset in revenues), a $5
million reduction of depreciation, depletion and amortization expense related to
environmental mitigation credits and a $4 million reduction of expense in
first-quarter 2004 related to an adjustment to depreciation recognized in a
prior period.
99.6-13
Management's Discussion and Analysis (Continued)
Other (income) expense - net in 2004 includes a $9 million charge for
the write-off of previously-capitalized costs incurred on an idled segment of
Northwest's system that we recently determined will not be returned to service.
Other (income) expense - net in 2003 includes a $25.5 million charge at
Northwest to write off capitalized software development costs for a service
delivery system following a decision not to implement.
The $14.4 million, or five percent, increase in Gas Pipeline segment
profit is primarily due to the absence of the $25.5 million charge in 2003
discussed above, $19.7 million higher revenues and $5.2 million higher equity
earnings (included in Investment income (loss)). These increases were partially
offset by the $26 million higher costs and operating expenses and the $9 million
charge discussed above. The increase in equity earnings is primarily due to a
$5.4 million increase in earnings from our investment in Gulfstream.
EXPLORATION & PRODUCTION
OVERVIEW OF THE SIX MONTHS ENDED JUNE 30, 2004
Domestic average daily production volumes increased 14 percent from the
beginning of the year. Domestic average daily production was approximately 511
million cubic feet of gas equivalent at June 30, 2004, compared to 450 million
cubic feet at the beginning of the year, and has surpassed production levels
reached prior to the asset sales of 2003. The increase is a result of the
company successfully contracting additional drilling rigs, particularly in the
Piceance basin, to increase our development drilling. Additionally, the Piceance
drilling program has improved the efficiency time to drill a well and start
another one, increasing the number of wells drilled in a particular period of
time and bringing new production on line more quickly. Additional rigs were also
added to the other core areas of San Juan, Arkoma and Powder River basins. The
benefit of these higher volumes was offset by hedge losses and increasing costs,
including a loss provision related to an ownership dispute on prior period
production.
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 beginning of the year production level 15
percent by the end of 2004. Approximately 78 percent of our
forecasted production for the remainder of 2004 is hedged at
prices that average $3.69 per mcfe at a basin level.
The following discussions of the quarter-over-quarter and year-to-date
comparative 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. Those properties consist of
the Uinta and Denver Julesberg basins and certain additional properties in the
Green River and San Juan basins. The operations classified as discontinued
operations are the properties in the Hugoton and Raton basins.
PERIOD-OVER-PERIOD RESULTS
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- ----------------------
2004 2003 2004 2003
--------- --------- -------- ------
(MILLIONS) (MILLIONS)
Segment revenues $ 189.0 $ 200.2 $ 354.2 $ 444.1
======== ======== ======== ========
Segment profit $ 43.3 $ 178.7 $ 94.8 $ 292.5
======== ======== ======== ========
99.6-14
Management's Discussion and Analysis (Continued)
Three months ended June 30, 2004 vs. three months ended June 30, 2003
The $11.2 million, or six percent, decrease in Exploration & Production
revenues is due primarily to lower income on derivative instruments that did not
qualify for hedge accounting, and lower income from the utilization of excess
transportation capacity. These decreases are partially offset by an increase in
revenues from gas management activities.
Domestic production revenues increased slightly from the prior period.
Net realized average prices include the effect of hedge positions. Production
volumes increased slightly from period to period while net realized prices were
lower than the prior period. We expect volumes to continue to increase during
the remainder 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 76 percent of domestic production in the second quarter of 2004
was hedged. These hedging decisions are made considering our overall commodity
risk exposure.
Costs and expenses, including selling, general and administrative
expenses, increased $19 million, primarily reflecting the following:
- $7 million higher lease operating expense associated with the
increase of well maintenance activities, higher labor and fuel
costs and an increase in overhead payments to another
operator;
- $6 million higher gas management expenses associated with the
higher revenues from gas management activities;
- $2 million higher depreciation, depletion, and amortization
expense primarily as a result of higher production volumes;
and
- a $2 million increase in operating taxes primarily as a result
of higher production volumes.
The $135.4 million decrease in segment profit is due primarily to the
gain on the sale of properties of $91.5 million in the second quarter of 2003.
Additionally, there were lower revenues related to excess transportation
capacity and non-hedge derivative income in 2004. In addition, a loss provision
of $11.3 million was recorded to Other (income) expense - net during the second
quarter of 2004 related to an ownership dispute on prior period production.
Six months ended June 30, 2004 vs. six months ended June 30, 2003
The $89.9 million, or 20 percent, decrease in Exploration &
Production's revenues is primarily due to the $45 million lower domestic
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, lower income from the utilization of
excess transportation capacity, and lower income on derivative instruments that
did not qualify for hedge accounting.
The decrease in domestic production revenues reflects $35 million lower
revenues associated with a three percent decrease in net domestic production
volumes and $10 million lower revenues associated with a 12 percent decrease in
net realized average prices for production sold. The decrease in production
volumes primarily results from the sales of properties in 2003, partially offset
by increased production volumes for properties retained.
Costs and expenses, including selling, general and administrative
expenses, decreased $1 million primarily reflecting the following:
- $7 million lower gas management expenses associated with the
lower revenues from gas management activities;
- $3 million lower selling, general and administrative expenses
as a result of assets sold in 2003;
- $2 million lower depreciation, depletion, and amortization
expense as a result of decreased volumes; and
- $8 million higher lease operating expense.
99.6-15
Management's Discussion and Analysis (Continued)
Other (income) expense - net includes $91.5 million in net gains on the
sale of assets during 2003.
The $197.7 million decrease in segment profit is due primarily to the
absence of $92 million in net gains on the sales of assets in 2003, a decrease
in net domestic production volumes resulting from the assets sold in 2003, and
lower net realized average prices. Additionally, a loss provision of $11.3
million was recorded to Other (income) expense - net during the second quarter
of 2004 related to an ownership dispute on prior period production.
MIDSTREAM GAS & LIQUIDS
OVERVIEW OF SIX MONTHS ENDED JUNE 30, 2004
Consistent with our strategy to invest in growth areas where we have
large scale assets 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 deepwater Gulf of Mexico,
the Devils Tower production handling facility, the Canyon Chief gas pipeline,
and the Mountaineer oil pipeline began flowing product in May 2004, while the
Gunnison oil pipeline volumes have been increasing since the first of the year.
These deepwater assets contributed approximately $13 million to segment profit
in the second quarter. Additionally, the Opal expansion began operating in the
first quarter of 2004.
We have made significant progress on our asset sale program. We
recently announced the execution of purchase and sale agreements for the sale of
our western Canadian Straddle Plants and certain South Texas gas pipelines
(owned by Transco Gas Pipeline). These transactions are expected to yield
approximately $565 million in U.S. funds. The Canadian sale closed in July 2004
and the South Texas sale is pending FERC approval and is expected to close in
the fourth-quarter of 2004. We continue to negotiate with counterparties for the
sale of Gulf Liquids and the ethylene distribution business in Louisiana.
99.6-16
Management's Discussion and Analysis (Continued)
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. Revenues related to the
Gunnison and Devils Tower deepwater projects are expected to
continue growing throughout 2004 and make a contribution to
annual segment profit in 2004.
- Our domestic gas processing margins benefited from strong
crude oil prices in the first six months of 2004 and achieved
five-year annual average. Since natural gas and crude oil
markets are highly volatile, our processing margins in the
first half of 2004 are not necessarily indicative of levels
expected for the remainder of 2004.
- 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. 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. The termination of these
short-term contracts could result in lower Gulf Coast
processing revenues.
- We have requested a waiver from the FERC regarding compliance
with FERC Order 2004 for the management of Discovery Gas
Transmission and Black Marlin assets. In July, the FERC
granted a partial waiver allowing our Midstream segment to
continue to manage these assets subject to the remaining
procedural requirements of the FERC order. We continue to
evaluate the details of the partial waiver and our compliance
with the remaining requirements. Transfer of management of
these assets would result in lower segment profit for
Midstream, but Williams consolidated operating profit would
remain unchanged.
- Our Venezuelan assets were constructed and are currently
operated for 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 cash
flows of our facilities to date. However, the upcoming
referendum on the Presidency of Hugo Chavez may create a
higher degree of risk than we have experienced to date. PDVSA
is applying increased pressure on the terms of operating
contracts with vendors like and including ourselves.
During second-quarter 2004, we reclassified the operations of the
Canadian Straddle Plants to discontinued operations. In July 2004, we completed
the sale of these assets for approximately $536 million in U.S. funds. The
estimated pre-tax gain on sale of approximately $190 million will be recorded in
the third quarter of 2004. Additionally, the Canadian liquids system and Gulf
Liquids continue to be classified as discontinued operations. 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.
On July 20, 2004, Wilpro Energy Services (PIGAP II) Limited, one of our
subsidiaries, received a notice of default from the Venezuelan state oil
company, PDVSA, relating to certain operational issues alleging that our
subsidiary is not in compliance under a services agreement. We do not believe a
basis exists for such notice and are contesting the giving of this notice.
Although this notice of default could result in an event of default with respect
to project loans totaling approximately $219 million and could result in an
adverse effect with respect to other of our debt instruments, we believe that we
will be able to resolve any issues arising from the alleged notice of default
without any such results occurring with respect to our other debt instruments.
The lenders under the project loan agreement have confirmed to us in writing
that based on the facts they currently know, they have no intention of
exercising any rights or remedies under the project loan agreement until the
issues raised in the notice and our response are clarified.
99.6-17
Management's Discussion and Analysis (Continued)
PERIOD-OVER-PERIOD RESULTS
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- ------------------------
2004 2003 2004 2003
-------- -------- ---------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ 630.5 $ 502.2 $ 1,257.8 $ 1,367.6
======== ======== ========== ==========
Segment profit (loss)
Domestic Gathering & Processing $ 76.7 $ 59.1 $ 154.9 $ 159.7
Venezuela 19.4 20.0 40.9 33.5
Other 3.4 (21.9) 11.3 (23.2)
-------- -------- ---------- ----------
Total $ 99.5 $ 57.2 $ 207.1 $ 170.0
======== ======== ========== ==========
Three months ended June 30, 2004 vs. three months ended June 30, 2003
The $128.3 million increase in Midstream's revenues is primarily the
result of favorable gas processing and olefins production economics. Revenues
associated with natural gas liquids (NGLs) and olefins products increased $123
million due to significantly higher production volumes and slightly higher
market prices. Included within the $123 million increase are revenues associated
with our deepwater assets, including our recently completed infrastructure,
which generated $18 million in higher fee revenue. In addition, revenues
increased $81 million as the result of marketing 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
in costs and operating expenses which substantially offsets the change in
revenues. These revenue increases are largely offset by lower trading revenues
resulting from the fourth-quarter 2003 sale of our wholesale propane business.
Costs and operating expenses increased $101 million primarily due to
the higher cost of natural gas and ethene required to produce NGL and olefins.
Natural gas purchases used to replace the heating value of NGLs extracted at our
gas processing facilities increased $78 million while feedstock for olefins
production increased $12 million. Higher NGL production volumes also resulted in
$9 million in higher transportation and fractionation expenses. Maintenance
costs, additional depreciation expense, and other product purchases increased
approximately $22 million. With a similar impact to sales, total costs and
operating expenses increased $81 million due to the marketing of NGLs on behalf
of customers. These higher costs and operating expenses are largely offset by
lower trading purchases due to the sale of our wholesale propane business noted
above.
The $42.3 million increase in Midstream segment profit for the second
quarter of 2004 is primarily the result of improved results at our domestic
gathering and processing business and at our olefins facilities. A more detailed
analysis of segment profit of Midstream's various operations is presented below.
Domestic Gathering & Processing: The $17.6 million increase in domestic
gathering and processing segment profit includes an increase of $13.6 million in
the Gulf Coast region's segment profit and a $4.0 million increase in the West
region.
Segment profit for our Gulf Coast region increased $13.6 million as a
result of incremental profits from newly constructed assets in the deepwater
area of the Gulf of Mexico. The Devils Tower production handling facility, the
Canyon Chief gas pipeline, and the Mountaineer oil were all placed into service
at the end of the first quarter of 2004.
Our West Region's segment profit increased $4 million reflecting
improved gas processing margins offset by lower fee revenues and higher
operating expenses. Following are certain material components of the increase:
- Our gas processing margins increased $12 million due to higher
NGL volumes and higher NGL prices supported by significantly
higher crude prices. The increase in NGL revenues was
partially offset by higher natural gas purchases caused by
higher volumes and market prices.
- Fee revenues for gathering and processing services declined $5
million as a result of slightly lower rates and volumes in the
Four Corners area.
- Maintenance expenses increased $5 million primarily due to
additional scheduled maintenance projects at the San Juan and
Wyoming facilities.
99.6-18
Management's Discussion and Analysis (Continued)
Venezuela: Segment profit for our Venezuelan assets in the second
quarter of 2004 remained consistent with the second quarter of 2003.
Other: With improved olefins fractionation margins, results from our
NGL trading, fractionation, and storage business, olefins businesses, and
partnership investments increased $25.3 million. Primary drivers of these
results are as follows:
- Segment profit for our NGL trading, fractionation, and storage
business increased $10 million primarily due to $7 million
higher net trading revenues. The improvement in net trading
revenues is largely due to the absence of charges totaling $5
million recognized in 2003 for inventory hedge losses and
adjustments. Our trading revenues also reflect a $2 million
gain generated by rising NGL market prices while our
production barrels are being transported to market. Selling,
general and administrative expense was $2 million lower in the
second-quarter 2004, primarily as a result of the
fourth-quarter 2003 sale of our wholesale propane business.
- Segment profit for our olefins businesses increased $17
million. Domestic olefins fractionation margins improved $8
million reflecting the significant strengthening of the
ethylene market in 2004 resulting from lower ethylene
inventories and higher demand for olefins products. As a
result, our domestic olefins business increased its volume of
spot sales significantly. In addition, margins were improved
by a new higher fixed margin contract. The $9 million
improvement from our Canadian Olefins group is largely
attributable to $6 million in higher olefins fractionation
margins.
Six months ended June 30, 2004 vs. six months ended June 30, 2003
The $109.8 million decrease in Midstream's revenue is primarily the
result of lower trading revenues primarily due to the fourth-quarter 2003 sale
of our wholesale propane business. This decline was largely offset by higher
revenues from all of Midstream's current businesses. Revenue from the sale of
NGLs and olefins products increased $177 million due to significantly higher
production volumes and slightly higher market prices as a result of improving
market conditions in 2004. Included within the $177 million increase are
revenues associated with our deepwater assets, including our recently completed
infrastructure, which generated $21 million in higher fee revenue. Additionally,
sales of NGLs increased $128 million as a result of marketing of 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 in
costs and operating expenses, which substantially offsets the change in
revenues.
Cost and operating expenses declined $120.9 million primarily as a
result of lower trading costs due to the sale of our wholesale propane business.
This decline was partially offset by higher costs relating to the increase in
NGL and olefins production noted above. Natural gas purchases used to replace
the heating value of NGLs extracted at our gas processing facilities increased
$117 million and feedstock for olefins production increased $39 million. Higher
NGL production volumes also resulted in $8 million in higher transportation and
fractionation expenses. Maintenance costs, additional depreciation expense, and
other product purchases increased approximately $25 million. With a similar
impact to sales, total costs and operating expenses increased $128 million due
to the marketing of NGLs on behalf of customers.
The $37.1 million increase in Midstream segment profit for the first
six months of 2004 is due primarily to improved olefins production margins and
higher deepwater profits. These increases are partially offset by lower gas
processing margins and lower gathering and processing fee income. A more
detailed analysis of segment profit of Midstream's various operations is
presented below.
Domestic Gathering & Processing: The $4.8 million decrease in our
domestic gathering and processing segment profit includes a $20.1 million
decline in the West region partially offset by a $15.3 million increase in our
Gulf Coast region.
99.6-19
Management's Discussion and Analysis (Continued)
Our West region's segment profit declined $20.1 million primarily due
to lower gas processing margins, lower gathering and processing fee revenues,
and higher operating expenses. Following are certain material components of the
decrease.
- Although still above 5-year averages, gas processing margins
in the first six months of 2004 declined $9 million from the
level recorded in the same period in 2003. Higher market
prices for natural gas used to replace the heating value of
NGLs extracted at our processing plants negatively impacted
our processing margins. This increase in natural gas prices is
largely due to the absence of depressed Wyoming natural gas
prices caused by regional transportation constraints in the
first quarter of 2003. This impact of higher natural gas
prices is partially offset by significantly higher NGL prices
in 2004 supported by strong crude prices.
- Gathering and processing fee revenues declined $12 million
primarily due to fewer customers electing the fee-based
billing option of processing contracts and slightly lower
rates and volumes in the Four Corners area.
- Maintenance expenses increased $8 million primarily due to
additional scheduled maintenance projects at the San Juan and
Wyoming facilities.
- Other revenues increased $4 million primarily due to higher
gas treating fees on our southwest Wyoming facilities.
Segment profit for our Gulf Coast Region increased $15.3 million
primarily as a result of newly constructed assets in the deepwater area of the
Gulf of Mexico. The Devils Tower production handling facility, the Canyon Chief
gas pipeline, and the Mountaineer oil were all placed into service at the end of
the first quarter of 2004. In addition, gas processing margins increased as a
result of new processing agreements created to allow producers' gas to be
processed to achieve pipeline quality standards.
Venezuela: The $7.4 million increase in segment profit for our
Venezuelan assets is primarily due to the absence of a fire at the El Furrial
facility that reduced revenues by $10 million in the first quarter of 2003. In
addition, lower equity earnings from our investment in the Accroven partnership
and higher currency revaluation expenses negatively impacted segment profit.
Other: As a result of improved olefins fractionation margins, results
from our NGL trading, fractionation, and storage business; olefins businesses;
and partnership investments increased $34.5 million, as follows:
- Segment profit for our NGL trading, fractionation, and storage
business increased $4 million primarily due to $4 million in
lower selling, general and administrative expense resulting
from the fourth-quarter 2003 sale of our wholesale propane
business.
- Segment profit for the olefins businesses increased $24
million. Domestic olefins fractionation margins improved $12
million reflecting the significant strengthening of the
ethylene market in 2004 created as a result of lower ethylene
inventories and higher demand for olefins products. As a
result, our domestic olefins business increased its volume of
spot sales significantly. In addition, margins were improved
by a new higher fixed margin contract. Segment profit from our
Canadian olefins business increased $12 million largely due to
$6 million in higher olefins fractionation margins. Currency
translation adjustments were $4 million favorable as a result
of a strengthening Canadian dollar.
- Our earnings from partially owned domestic assets accounted
for using the equity method increased $6 million largely due
to the absence of items impacting earnings of partnerships in
2003. This 2003 activity includes $12 million in charges
associated with accounting adjustments recorded at the
Discovery partnership, a $5 million gain on the sale of our
investment in Rio Grande Pipeline partnership, and the absence
of approximately $4 million in earnings generated from
investments that were sold after the second quarter of 2003.
99.6-20
Management's Discussion and Analysis (Continued)
OTHER
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- ----------------------
2004 2003 2004 2003
---------- --------- -------- ----------
(MILLIONS) (MILLIONS)
Segment revenues $ 7.0 $ 20.1 $ 19.6 $ 48.1
======== ======== ======== ========
Segment loss $ (14.3) $ (51.7) $ (23.0) $ (46.9)
======== ======== ======== ========
Other segment revenues for the three and six months ended June 30, 2003
includes approximately $8 million and $22 million, respectively, of revenues
related to certain butane blending assets, which were sold during third-quarter
2003.
Other segment loss for the three and six months ended June 30, 2004
includes a $10.8 million impairment of our investment in Longhorn. The charge
reflects management's belief that there was an other than temporary decline in
the fair value of this investment following a determination that additional
funding would be required to commission the pipeline into service. The project
incurred cost overruns in preparation for commissioning, including higher priced
line fill costs and is expected to become operational before the end of 2004.
Other segment loss for the six months ended June 30, 2004 includes $6.5 million
net unreimbursed advisory fees related to the recapitalization of 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.
Other segment loss for the three and six months ended June 30, 2003
includes a $42.4 million impairment related to the investment in equity and debt
securities of Longhorn.
99.6-21
Management's Discussion and Analysis (Continued)
FAIR VALUE OF TRADING DERIVATIVES
The chart below reflects the fair value of derivatives held for trading
purposes as of June 30, 2004. We have presented the fair value of assets and
liabilities by the period in which we expect them to be realized.
ASSETS (LIABILITIES)
-----------------------------------------------------------------------
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)
$ (31) $ 17 $ (8) $ 1 $ (21)
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 June 30, 2004, the fair value of these
non-trading derivative contracts was a net asset of $234 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 June 30, 2004, we held collateral support of
$338 million.
We also enter into netting agreements to mitigate counterparty performance
and credit risk. During second-quarter 2004, we did not incur any significant
losses due to recent counterparty bankruptcy filings.
99.6-22
Management's Discussion and Analysis (Continued)
The gross credit exposure from our derivative contracts as of June 30,
2004 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(A) TOTAL
------------------------------------- ---------- -----------
(MILLIONS)
Gas and electric utilities $ 667.9 $ 780.5
Energy marketers and traders 2,446.9 4,843.7
Financial institutions 1,343.4 1,343.4
Other 434.2 438.5
---------- -----------
$ 4,892.4 7,406.1
==========
Credit reserves (34.2)
-----------
Gross credit exposure from derivatives(b) $ 7,371.9
===========
We assess our credit exposure on a net basis. The net credit exposure
from our derivatives as of June 30, 2004 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(A) TOTAL
------------------------------------- ---------- -----------
(MILLIONS)
Gas and electric utilities $ 130.2 $ 145.5
Energy marketers and traders 527.8 792.3
Financial institutions 191.5 191.5
Other 2.9 3.9
-------- -----------
$ 852.4 1,133.2
========
Credit reserves (34.1)
-----------
Net credit exposure from derivatives(b) $ 1,099.1
===========
(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.
99.6-23
Management's Discussion and Analysis (Continued)
FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY
Overview
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, and our progress to
date, include the following:
1) Completion of planned asset sales, which we estimated would
generate proceeds of approximately $800 million in 2004.
- On March 31, 2004, we completed the sale of our
Alaska refinery and related assets for approximately
$304 million.
- On July 28, 2004, we completed the sale of three
straddle plants in western Canada for approximately
$536 million.
- In addition to these transactions, we expect to
generate additional proceeds from the sale of assets
of approximately $50 to $100 million.
2) Additional reduction of our selling, general and
administrative costs.
- On June 1, 2004, we announced an agreement with IBM
Business Consulting Services (IBM) to aid us in
transforming and managing certain areas of our
accounting, finance and human resources processes. In
addition, IBM will manage key aspects of our
information technology, including enterprise wide
infrastructure and application development. The 7 1/2
year agreement began July 1, 2004 and is expected to
reduce costs in these areas while maintaining a high
quality of service.
3) The replacement of our cash-collateralized letter of credit
and revolver facility with facilities that do not encumber
cash.
- In April 2004, we entered into two unsecured bank
revolving credit facilities totaling $500 million.
These facilities provide for both borrowings and
letters of credit, but are used primarily for issuing
letters of credit. Use of these new facilities
released approximately $500 million of restricted
cash, restricted investments and margin deposits in
the second quarter. 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 and Transco have access
to $400 million each under the facility, which is
secured by certain Midstream assets and a guarantee
from WGP (see Note 12 of Notes to the Consolidated
Financial Statements).
4) Continuation of our efforts to exit from the Power business.
- 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 flow 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.
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 June 30, 2004, we have the following sources of liquidity from cash
and cash equivalents:
- Cash-equivalent investments at the corporate level of
$794 million as compared to $2.2 billion at December
31, 2003.
- Cash and cash-equivalent investments of various
international and domestic entities of $236 million,
as compared to $91 million at December 31, 2003.
99.6-24
Management's Discussion and Analysis (Continued)
At December 31, 2003, we had capacity of $447 million available under
the $800 million revolving and letter of credit facility. This facility was
terminated on May 3, 2004. At June 30, 2004, we have capacity of $11 million
available under the two unsecured revolving credit facilities totaling $500
million and $819 million available under our $1 billion secured revolving
facility. We also have a commitment from our agent bank to expand our credit
facility by an additional $275 million.
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 of our
debt agreements.
In addition, our wholly owned subsidiaries Northwest and Transco have
outstanding registration statements filed with the Securities and Exchange
Commission. As of June 30, 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 six months of 2004, we satisfied liquidity needs with:
- $304 million in cash generated from the sale of the Alaska
refinery and related assets, and
- $603.6 million in cash generated from operating activities of
continuing operations, including the release of approximately
$500 million of restricted cash, restricted investments and
margin deposits previously used to collateralize certain
credit facilities.
Credit ratings
As part of executing the business plan announced in February, 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 or otherwise eliminating these
commitments, obtaining an investment grade rating may be further delayed. See
Note 1 of Notes to Consolidated Financial Statements for a further discussion on
the status of the Power business.
On July 30, 2004, Standard & Poor's raised our debt ratings outlook to
stable from negative citing our debt reductions efforts. If we continue to
reduce debt in line with forecasts, our rating could improve over the three-year
horizon of the outlook. An improved rating could result in lower borrowing
costs. However, if financial ratios fall considerably below expectations, the
outlook and the rating could decline.
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 funding bank syndicated its
associated credit risk into the institutional investor market via a Rule 144A
offering, which allows for the sale of certain restricted securities only to
qualified institutional buyers. Upon the occurrence of certain credit events,
letters of credit outstanding under the agreement become cash collateralized,
creating a borrowing under the facilities. Concurrently the bank can deliver the
facilities to the institutional investors, whereby the investors replace the
bank as lender under the facilities.
To facilitate the syndication of the facilities, the bank established
trusts funded by the institutional investors. 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 the second quarter, use of these
new facilities released approximately $500 million of restricted cash,
restricted investments and margin deposits (see Note 12 of Notes to the
Consolidated Financial Statements).
99.6-25
Management's Discussion and Analysis (Continued)
OPERATING ACTIVITIES
For the six months ended June 30, 2004, we recorded approximately $30
million in Provision for loss on investments, property and other assets
consisting primarily of a $10.8 million impairment of our investment in Longhorn
and a $9 million write off of previously-capitalized costs incurred on an idled
segment of Northwest's system.
For the six months ended June 30, 2003, we recorded approximately $121
million in Provision for loss on investments, property and other assets
consisting primarily of a $42.4 million impairment of our investment in
Longhorn, a $25.5 million write-off of software development costs at Northwest,
a $13.5 million impairment of an investment in a company holding phosphate
reserves and a $12 million impairment of Algar Telecom S.A.
The net gain on disposition of assets in second quarter 2003 primarily
consists of the gains on the sales of natural gas properties.
In 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.
In the first quarter of 2004, we recognized net cash used by operating
activities of discontinued operations in the Consolidated Statement of Cash Flow
of $47.1 million. Included in this amount was approximately $70 million in use
of funds related to the timing of settling working capital issues of the Alaska
refinery and related assets. In the second quarter of 2004, we received the
proceeds from the collection of approximately $58 million in trade receivables
related to the Alaska refinery and related assets.
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.
In May 2004, we made cash tender offers for approximately $1.34 billion
aggregate principal amount of a specified series of our outstanding notes and
debentures. As of the June 8, 2004, tender offer expiration date, we accepted
for purchase tenders of notes and debentures with an aggregate principal amount
of approximately $1.17 billion. The payment of these notes and debentures in
second-quarter 2004 is recorded as Payments of long term debt on the
Consolidated Statement of Cash Flows. In May 2004, we also repurchased on the
open market debt of approximately $255 million of various notes with maturity
dates ranging from 2006 to 2011. In conjunction with the tendered notes, related
consents, and the debt repurchase, we paid premiums of approximately $79
million. The premiums, as well as related fees and expenses, together totaling
$96.8 million, were recorded in Early debt retirement costs.
In June 2004, we made a payment of approximately $109 million for
accrued interest, short-term payables, and long-term debt to repurchase certain
receivables from the California Power Exchange that were previously sold to a
third party. Approximately $79 million of the payment is included in payments of
long-term debt on the Consolidated Statement of Cash Flows. In July 2004, we
received payment of approximately $104 million from the California Power
Exchange which will be reported in cash flows from operations in the third
quarter.
For a discussion of other borrowings and repayments in 2004, see Note
12 of Notes to Consolidated Financial Statements.
Dividends paid on common stock are currently $.01 per common share on a
quarterly basis and totaled $10.4 million for the six months ended June 30,
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.
99.6-26
Management's Discussion and Analysis (Continued)
INVESTING ACTIVITIES
During the first four months of 2004, we purchased $471.8 million of
restricted investments comprised of U.S. Treasury notes and received proceeds on
maturity of $851.4 million of such investments on their scheduled maturity date.
We made these purchases to satisfy the 105 percent cash collateralization
requirement in the $800 million revolving credit facility. This facility was
terminated May 3, 2004, subsequent to us entering into the $1 billion secured
revolving credit facility (see Note 12 of Notes to Consolidated Financial
Statements).
During February 2004, we participated in a recapitalization plan
completed by 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 sales in the first half of 2004 and in 2003 provided
significant proceeds and may include various adjustments subsequent to the
actual date of sale.
In 2004:
- $304 million related to the sale of Alaska refinery, retail
and pipeline and related assets.
In 2003:
- $793 million related to the sale of Texas Gas Transmission
Corporation,
- $431 million (net of cash held by Williams Energy Partners)
related to the sale of our general partnership interest and
limited partner investment in Williams Energy Partners,
- $452 million related to the sale of the Midsouth refinery,
- $417 million related to certain natural gas exploration and
production properties in Kansas, Colorado and New Mexico,
- $188 million related to the sale of the Williams travel
centers,
- $60 million related to the sale of our equity interest in
Williams Bio-Energy L.L.C., 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.
99.6-27
Management's Discussion and Analysis (Continued)
During the first six months of 2004, the amount of our contractual
obligations changed significantly due to the following:
- On March 15, 2004, we retired the remaining $679 million
outstanding balance of the 9.25 percent senior unsecured notes
due March 15, 2004.
- In May 2004, we made cash tender offers for approximately
$1.34 billion aggregate principal amount of our specified
series of outstanding notes and debentures. As of the June 8,
2004, tender offer expiration date, we had accepted for
purchase tenders of notes and debentures with an aggregate
principal amount of approximately $1.17 billion.
- In May 2004, we repurchased debt of approximately $255 million
of various notes with maturity dates ranging from 2006 to
2011.
- On May 27, 2004, we were released from certain historical
indemnities, primarily related to environmental remediation,
for an agreement to pay $117.5 million (see Note 13 of Notes
to Consolidated Financial Statements). We had previously
deferred $113 million of a gain on sale in anticipation of
costs related to these indemnities. At June 30, 2004, the net
present value of this settlement is $107.5 million. Of this
amount, $35 million is classified as current and was
subsequently paid on July 1, 2004. The remaining amount will
be paid in three installments of $27.5 million, $20 million,
and $35 million in 2005, 2006, and 2007, respectively.
- Power's physical and financial derivative obligations
decreased by approximately $1.2 billion. The decrease is due
to normal trading and market activity and the expiration of
certain long-term power contracts in the first six 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.
OUTLOOK FOR THE REMAINDER OF 2004
We estimate capital and investment expenditures will be approximately
$775 million to $875 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. In
first-quarter 2004, we completed the sale of our Alaska refinery and related
assets for approximately $304 million. On July 28, 2004, we completed the sale
of three straddle plants in western Canada for approximately $536 million. In
addition to these transactions, we currently expect to generate additional
proceeds from the sale of assets of approximately $50 to $100 million. We also
expect to generate $1 to $1.3 billion in cash flow from continuing operations.
In the remainder of 2004, we expect to make 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 liquidity levels of at
least $1 billion. Through debt tenders, open market repurchases and scheduled
maturities, we have reduced our debt to $9.8 billion at June 30, 2004, a
reduction of over $2.2 billion for the year-to-date. Primarily through
additional debt tenders, we expect to further reduce debt to a level of
approximately $9 billion by the end of 2004. While our access to the capital
markets continues to improve, one of our indentures, and our two unsecured
revolving credit facilities, 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. Our
secured revolving credit facility has a covenant restricting our ability to
issue new debt if, after giving effect to the issuance, we were to fail to meet
the associated consolidated debt to consolidated net worth ratio.
99.6-28