EXHIBIT 99.2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW OF 2003
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 2002, including the collapse of Enron and the severe decline of
the telecommunications industry. The plan focused upon 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
provided us with a clear strategy 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 capable of supporting and
ultimately growing our remaining businesses. A component of our plan was to
reduce the risk and liquidity requirements of the Power segment while realizing
the value of Power's portfolio.
COMPANY RESTRUCTURING
During 2003, we successfully executed the following critical components of
our restructuring plan:
- generated cash proceeds of approximately $3 billion from the
sale of assets;
- sustained core business earnings capacity through completed
system expansions at Gas Pipeline, continued drilling activity
at Exploration & Production and continued investment in
deepwater activities within Midstream;
- repaid $3.2 billion of debt through scheduled maturities and
early extinguishment of debt and accessed the public debt
markets available to us primarily to refinance $2 billion of
higher cost debt; and
- continued rationalization of our cost structure, including a
28 percent reduction in selling, general and administrative
(SG&A) costs from continuing operations and a 39 percent
reduction in general corporate expenses.
ADDRESSING LIQUIDITY
Through these efforts, we satisfied key liquidity issues facing us in the
form of scheduled debt maturities. These were primarily the Williams Production
RMT Company (RMT) note payable (RMT Note) of approximately $1.15 billion
(including certain contractual fees and deferred interest) due on July 25, 2003,
and $1.4 billion of senior unsecured 9.25 percent notes due March 15, 2004. As a
result of the proceeds generated from asset sales and proceeds from the issuance
of $500 million of long-term debt, we prepaid the RMT Note in May 2003. During
the fourth quarter, we completed tender offers that prepaid approximately $721
million of the senior unsecured 9.25 percent notes and approximately $230
million of other notes and debentures. With approximately $2.3 billion available
cash on hand at the end of 2003, we have the capacity to pay the $679 million
balance of the senior unsecured 9.25 percent notes upon their maturity.
During 2004, we expect to maintain cash/liquidity levels of at least $1
billion in excess of our immediate needs. While improved during 2003, we have
limited access to the capital markets and must maintain liquidity at a level to
manage our operations and meet unforeseen or extraordinary calls on cash.
Additionally, we will pursue establishing new revolving and letter of credit
facilities to reduce cash requirements associated with our current facility.
EXITING THE POWER BUSINESS
We are pursuing a strategy of exiting the Power business. However, market
conditions have contributed to the difficulty of, and could delay, a full,
immediate exit from this business. In 2003, we generated in excess of $600
million from the sale, termination or liquidation of Power contracts and assets.
During the year, we continued to manage our portfolio to reduce risk, to
generate cash and to fulfill contractual commitments. We are also pursuing our
goal to resolve the remaining legal and regulatory issues associated with the
business.
During 2003, we engaged financial advisors to assist and advise with this
effort. 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 Emerging Issues Task Force (EITF) Issue No. 02-3 (EITF 02-3).
Based on current market
99.2-1
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.
On a consolidated basis, the net book value at December 31, 2003 of
Power's portfolio and other long-lived assets were in excess of $800 million,
while other net assets of Power, including net working capital, were in excess
of $400 million.
OUTLOOK FOR 2004
Entering 2004, our plan is focused upon the following objectives:
- Sustain solid core business performance, including increased
capital allocated to Exploration & Production.
We expect cash flow from operations to be sufficient to meet our 2004
capital spending plan of $700 to $800 million and to generate additional
cash to be available for debt reduction.
- Continue reduction of debt and selective refinancing of
certain instruments.
We expect to aggressively reduce debt in 2004. We have approximately $936
million in scheduled maturities coming due throughout the year and
anticipate using available cash flow, proceeds from assets sales and the
release of collateral from credit facilities to further reduce debt
levels.
- Maintain investment discipline.
We have implemented the Economic Value Added(R) (EVA(R)) financial
management system as a financial framework for use in evaluating our
business decisions and as a major component for determining incentive
compensation. We will invest selectively in those projects that are
projected to add value to the company through EVA(R) improvement.
Key execution steps will include the completion of planned asset sales,
which are estimated to generate proceeds of approximately $800 million in 2004,
additional reduction of SG&A costs, replacing our cash-collateralized letter of
credit and revolver facility with facilities that do not encumber cash and
continued efforts to exit the power business. Some factors that present
obstacles that could prevent us from achieving these objectives include:
- volatility of commodity prices;
- ongoing shareholder and Power-related litigation;
- lower than expected cash flow from continuing operations;
- general economic and industry downturn; and
- unfavorable capital market conditions.
We continue to address these risks through utilization of commodity
hedging strategies, focused efforts to resolve and/or respond to litigation
claims, managing our business with an emphasis upon generating cash and
retaining and developing those business operations serving key economic and
energy needs.
CRITICAL ACCOUNTING POLICIES & ESTIMATES
Our financial statements reflect the selection and application of
accounting policies which require management to make significant estimates and
assumptions. The selection of these has been discussed with our Audit Committee.
We believe that the following are the more critical judgment areas in the
application of our accounting policies that currently affect our financial
condition and results of operations.
99.2-2
REVENUE RECOGNITION -- DERIVATIVES
We hold a substantial portfolio of derivative contracts for a variety of
purposes. Many of these are designated in hedge positions; hence, changes in
their fair value are not reflected in earnings until the associated hedged item
impacts earnings. Others have not been designated as hedges or do not qualify
for hedge accounting. The net change in fair value of these contracts represents
unrealized gains and losses and is recognized in income currently
(marked-to-market). The fair value for each of these derivative contracts is
determined based on the nature of the transaction and the market in which
transactions are executed. We also incorporate assumptions and judgments about
counterparty performance and credit considerations in our determination of fair
value. Certain contracts are executed in exchange traded or over-the-counter
markets where quoted prices in active markets may exist. Transactions are also
executed in exchange-traded or over-the-counter markets for which market prices
may exist, but which may be relatively inactive with limited price transparency.
Hence, the ability to determine the fair value of the contract is more
subjective than if an independent third party quote were available. A limited
number of transactions are also executed for which quoted market prices are not
available. Determining fair value for these contracts involves assumptions and
judgments when estimating prices at which market participants would transact if
a market existed for the contract or transaction. We estimate the fair value of
these various derivative contracts by incorporating information about commodity
prices in actively quoted markets, quoted prices in less active markets, and
other market fundamental analysis. The estimated fair value of all these
derivative contracts is continually subject to change as the underlying energy
commodity market changes and as management's assumptions and judgments change.
Additional discussion of the accounting for energy contracts at fair value
is included in Note 1 of Notes to Consolidated Financial Statements, Energy
Trading Activities, and Item 7A -- Qualitative and Quantitative Disclosures
About Market Risk [Exhibit 99.3].
VALUATION OF DEFERRED TAX ASSETS AND TAX CONTINGENCIES
We have deferred tax assets resulting from certain investments and
businesses that have a tax basis in excess of the book basis and from tax
carry-forwards generated in the current and prior years. We must evaluate
whether we will ultimately realize these tax benefits and establish a valuation
allowance for those that may not be realizable. This evaluation considers tax
planning strategies, including assumptions about the availability and character
of future taxable income. At December 31, 2003, we have $700 million of deferred
tax assets for which a $68 million valuation allowance has been established.
When assessing the need for a valuation allowance, we considered forecasts of
future company performance, the estimated impact of potential asset dispositions
and our ability and intent to execute tax planning strategies to utilize tax
carryovers. Based on our projections, we believe that it is probable that we can
utilize our year-end 2003 federal tax carryovers prior to their expiration. See
Note 5 of Notes to Consolidated Financial Statements for additional information
regarding the tax carryovers. The ultimate realized amount of deferred tax
assets could be materially different from those recorded, as influenced by
potential changes in jurisdictional income tax laws and the circumstances
surrounding the actual realization of these assets.
We frequently face challenges from domestic and foreign tax authorities
regarding the amount of taxes due. These challenges include questions regarding
the timing and amount of deductions and the allocation of income among various
tax jurisdictions. In evaluating the liability associated with our various
filing positions, we record a liability for probable tax contingencies. The
ultimate disposition of these contingencies could have a material impact on net
cash flows. To the extent we were to prevail in matters for which accruals have
been established or required to pay amounts in excess of our accrued liability,
our effective tax rate in a given financial statement period may be materially
impacted.
99.2-3
IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS
We evaluate our long-lived assets and investments for impairment when we
believe events or changes in circumstances indicate that we may not be able to
recover the carrying value of certain long-lived assets or the decline in
carrying value of an investment is other-than-temporary. In addition to those
long-lived assets and investments for which impairment charges were recorded
(see Notes 2, 3 and 4 of Notes to Consolidated Financial Statements), many
others were reviewed for which no impairment was required. Our computations
utilized judgments and assumptions in the following areas:
- the probability that we would sell an asset or continue to
hold and use it;
- undiscounted future cash flows if an asset is held for use;
- estimated fair value of the asset;
- estimated sales proceeds if an asset is sold;
- form and timing of the asset disposition; and
- counterparty performance considerations under contracted sales
transactions.
Our Alaska refining, retail and pipeline operations are classified as
"held for sale" at December 31, 2003. They are currently under contract to be
sold as a single disposal group. This sale is expected to close during the first
quarter of 2004. These assets were written down to fair value less cost to sell
during 2003 based on the assumption that they would be sold as one disposal
group. If events were to occur that caused us to divide this disposal group or
to separately evaluate the individual assets within the disposal group for
impairment, certain assets within that group could require an additional
impairment.
We have entered into a structured sales transaction for our investment in
a foreign telecommunications company. In our review of this investment for
potential impairment, we assumed that the counterparty would perform under the
agreement. If the counterparty is unable to fully perform, an impairment of up
to $22 million could be necessary.
We own an equity investment in Longhorn Partners Pipeline L.P., a
petroleum products pipeline still under development. During 2003, we recognized
an impairment of a portion of our investment based on the terms of a
recapitalization plan that closed in February 2004. We estimated the fair value
of our remaining equity investment based on discounted future cash flows from
the project. Because the pipeline is not yet operational, this estimate involved
significant judgment, including:
- expected in service date;
- duration of operational ramp up;
- ultimate annual volume throughput;
- ability to obtain external debt financing in the future;
- risk-weighted discount rate; and
- cash flow projections.
A decrease of 10 percent in our estimate of fair value of this investment
would result in an additional impairment of approximately $8 million.
We own a 14.6 percent equity interest in Aux Sable Liquid Products LP, a
natural gas liquids extraction and fractionation facility. During 2003, we
performed an impairment review of our investment in Aux Sable as current
operating results and cash flow projections suggested that a decline in the fair
value of this investment below our carrying value could exist. We estimated the
fair value of our investment based on a projection of discounted cash flows of
Aux Sable. Based upon our analysis we concluded that the estimated fair value of
our investment was below the carrying value with little likelihood that the
value would recover above our carrying value over the near term. As a result,
during 2003 we recorded a $14.1 million impairment of this investment to its
estimated fair value. Our projections are highly sensitive to changes in volumes
and commodity pricing projections. An additional 10 percent decline in the
projected fair value of this investment could result in an additional $4 million
charge against our operating results if that decline was determined to be other
than temporary.
99.2-4
Our Gulf Liquids New River Project LLC (Gulf Liquids) operations are
classified as "held for sale" at December 31, 2003. These assets were written
down to fair value less costs to sell during 2003. We estimated fair value based
on probability-weighted analysis that considered sales price negotiations,
salvage value estimates, and discounted future cash flows. This estimate
involved significant judgment, including:
- commodity pricing;
- probability weighting of the different scenarios; and
- range of estimated sales proceeds, salvage value and future
cash flows.
The estimated cash flows from the various scenarios ranged approximately $15
million above and below our estimated fair value.
We evaluated certain asset groups not yet held for sale for impairment
because of the possibility that we could dispose of these assets pursuant to our
strategy to sell additional assets in 2004. Our current estimates of the
recoverability of these assets indicate that no impairment is necessary. A
significant assumption in the evaluation of one asset group in this analysis is
the probability associated with selling the asset group versus continuing to
hold it for use. We currently believe we are more likely to continue to hold
this asset group than sell it; however, if the probability associated with
selling it were increased to approximately 90 percent, these assets may not be
recoverable. If our recoverability estimates had resulted in a determination
that these assets were not recoverable, based on our current estimates of fair
value, we would have recognized an impairment loss of approximately $40 million
to $70 million in the year ended December 31, 2003.
Our current estimate of recoverability for certain Canadian gas processing
assets indicated that they were not recoverable due to management's expectation
that these assets would be sold at a price less than their current carrying
value. As a result, we recognized impairment charges of $41.7 million during
2003. We estimated fair market value using an earnings multiple applied to
projected operating results. We validated this estimate of fair value with
discounted future cash flows ranging from approximately $10 million above and
$25 million below our estimated fair value.
CONTINGENT LIABILITIES
We record liabilities for estimated loss contingencies when we assess that
a loss is probable and the amount of the loss can be reasonably estimated.
Revisions to contingent liabilities are reflected in income in the period in
which new or different facts or information become known or circumstances change
that affect the previous assumptions with respect to the likelihood or amount of
loss. Liabilities for contingent losses are based upon our assumptions and
estimates, and advice of legal counsel or other third parties regarding the
probable outcomes of the matter. As new developments occur or more information
becomes available, it is possible that our assumptions and estimates in these
matters will change. Changes in our assumptions and estimates or outcomes
different from our current assumptions and estimates could materially affect
future results of operations for any particular quarterly or annual period. See
Note 16 of Notes to Consolidated Financial Statements.
OIL AND GAS PRODUCING ACTIVITIES
We use the successful efforts method of accounting for our oil and gas
producing activities. Estimated natural gas and oil reserves and/or forward
market prices for oil and gas are a significant part of our financial
calculations. Following are examples of how these estimates affect financial
results:
- An increase (decrease) in estimated proved oil and gas
reserves can reduce (increase) our unit of production
depletion rate.
- Changes in oil and gas reserves and forward market prices both
impact projected future cash flows from our oil and gas
properties. These projected future cash flows are used:
- to estimate the fair value of oil and gas properties for
purposes of assessing them for impairment; and
- to estimate the fair value of the Exploration &
Production reporting unit for purposes of assessing its
goodwill for impairment.
- Certain estimated reserves are used as collateral to secure
financing.
99.2-5
The process of estimating natural gas and oil reserves is very complex,
requiring significant judgement in the evaluation of all available geological,
geophysical, engineering and economic data. After being estimated internally,
virtually all of our reserve estimates are either audited or prepared by
independent experts. The data may change substantially over time as a result of
numerous factors, including additional development activity, evolving production
history and a continual reassessment of the viability of production under
changing economic conditions. As a result, material revisions to existing
reserve estimates could occur from time to time. A reasonably likely revision of
our reserve estimates is not expected to result in an impairment of our oil and
gas properties or goodwill. However, reserve estimate revisions would impact our
depreciation and depletion expense prospectively. For example, a change of
approximately 10 percent in oil and gas reserves for each basin would change our
annual depreciation, depletion and amortization expense between approximately
$15 million and $20 million. The actual impact would depend on the specific
basins impacted.
Forward market prices include estimates of prices for periods that extend
beyond those with quoted market prices. This forward market price information is
consistent with that generally used in evaluating drilling decisions and
acquisition plans. These market prices for future periods impact the production
economics underlying oil and gas reserve estimates. The prices of natural gas
and oil are volatile and change from period to period thus impacting our
estimates. A reasonably likely unfavorable change in the forward price curve is
not expected to result in an impairment of our oil and gas properties or
goodwill.
GENERAL
In accordance with the provisions related to discontinued operations
within Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," the consolidated financial
statements and notes in Item 8 reflect our results of operations, financial
position and cash flows through the date of sale, as applicable, of certain
components as discontinued operations (see Note 2 of Notes to Consolidated
Financial Statements).
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 8 [Exhibit 99.4] of this
document.
99.2-6
RESULTS OF OPERATIONS
CONSOLIDATED OVERVIEW
The following table and discussion is a summary of our consolidated
results of operations for the three years ended December 31, 2003. The results
of operations by segment are discussed in further detail following this
Consolidated Overview discussion.
YEARS ENDED DECEMBER 31,
------------------------------------------------------------
% CHANGE % CHANGE
FROM FROM
2003 2002(1) 2002 2001(1) 2001
---------- ------- ---------- ------- ----------
(MILLIONS) (MILLIONS) (MILLIONS)
Revenues ........................................................ $16,644.7 +390% $ 3,393.9 -31% $ 4,899.5
Costs and expenses:
Costs and operating expenses ................................. 14,989.7 -675% 1,934.3 +8% 2,111.2
Selling, general and administrative expenses ................. 407.1 +28% 564.0 +14% 655.5
Other (income) expense -- net ................................ (130.2) NM 240.1 NM (12.4)
General corporate expenses ................................... 87.0 +39% 142.8 -15% 124.3
--------- --------- ---------
Total costs and expenses ..................................... 15,353.6 -433% 2,881.2 - 2,878.6
Operating income ................................................ 1,291.1 +152% 512.7 -75% 2,020.9
Interest accrued -- net ......................................... (1,240.6) -10% (1,132.1) -73% (654.9)
Investing income (loss) ......................................... 73.1 NM (113.2) +34% (172.6)
Interest rate swap loss ......................................... (2.2) +98% (124.2) NM -
Minority interest in income and preferred returns of
consolidated subsidiaries ................................... (19.4) +54% (41.8) +42% (71.7)
Other income (expense) -- net ................................... (26.1) NM 24.3 -8% 26.4
--------- --------- ---------
Income (loss) from continuing operations before income taxes .... 75.9 NM (874.3) NM 1,148.1
(Provision) benefit for income taxes ............................ (47.7) NM 277.2 NM (507.6)
--------- --------- ---------
Income (loss) from continuing operations ........................ 28.2 NM (597.1) NM 640.5
Income (loss) from discontinued operations ...................... 240.9 NM (157.6) +86% (1,118.2)
--------- --------- ---------
Net income (loss) before cumulative effect of change in
accounting principle ........................................ 269.1 NM (754.7) -58% (477.7)
Cumulative effect of change in accounting principles ............ (761.3) NM - NM -
--------- --------- ---------
Net loss ........................................................ (492.2) +35% (754.7) -58% (477.7)
--------- --------- ---------
Preferred stock dividends ....................................... 29.5 +67% 90.1 NM -
--------- --------- ---------
Loss applicable to common stock ................................. $ (521.7) +38% $ (844.8) -77% $ (477.7)
========= ========= =========
- ------------
(1) + = Favorable Change; - = Unfavorable Change
NM = A percentage calculation is not meaningful due to change in signs or a
zero-value denominator.
99.2-7
2003 vs. 2002
Our revenue increased $13.3 billion due primarily to increased revenues at
our Williams Power Company segment (Power) and our Midstream Gas and Liquids
segment (Midstream) as a result of the January 1, 2003 adoption of EITF 02-3,
which requires that revenues and costs of sale from non-derivative contracts and
certain physically settled derivative contracts be reported on a gross basis
(see Note 1 of Notes to Consolidated Financial Statements for a discussion of
the impact on our financial statements as a result of applying this consensus).
Prior to the adoption of EITF 02-3, revenues and costs of sales related to non-
derivative contracts and certain physically settled derivative contracts were
reported in revenues on a net basis. As permitted by EITF 02-3, prior year
amounts have not been restated. Power's external revenues increased $11.5
billion and Midstream's external revenues increased $1.6 billion due primarily
to the effect of EITF 02-3. The increase in revenues also includes $220 million
due primarily to higher natural gas liquids (NGL) revenues at our Midstream
segment's gas processing plants as a result of moderate market price increases,
partially offset by lower NGL production volumes.
Results for 2003 include approximately $117 million of revenue related to
the correction of the accounting treatment previously applied to certain third
party derivative contracts during 2002 and 2001. This matter was initially
disclosed in our Form 10-Q for the second quarter of 2003. Income from
continuing operations before income taxes and cumulative effect of change in
accounting principles in 2003 was $51.6 million. Absent the corrections, we
would have reported a pretax loss from continuing operations in 2003.
Approximately $83 million of this revenue relates to a correction of net energy
trading assets for certain derivative contract terminations occurring in 2001.
The remaining $34 million relates to net gains on certain other derivative
contracts entered into in 2002 and 2001 that we now believe should not have been
deferred as a component of other comprehensive income due to the incorrect
designation of these contracts as cash flow hedges. Our management, after
consultation with our independent auditor, concluded that the effect of the
previous accounting treatment was not material to 2003 and prior periods and the
trend of earnings.
Costs and operating expenses increased $12.9 billion due primarily to the
effect of reporting certain costs gross at Power and Midstream, as discussed
above. Costs increased $12.9 billion at Power and $1.8 billion at Midstream due
primarily to the effect of EITF 02-3. Contributing to the increase at our
Midstream segment is $113 million attributable to rising market prices for
natural gas used to replace the heating value of NGLs extracted at their gas
processing facilities. The cost increases at these operating units were
partially offset by $1.7 billion higher intercompany eliminations resulting
primarily from intercompany costs that were previously netted in revenues prior
to the adoption of EITF 02-3.
Selling, general and administrative expenses decreased $156.9 million due
primarily to reduced staffing levels at Power reflective of our strategy to exit
this business. Also contributing to the decrease was the absence of $22 million
of costs related to an enhanced benefit early retirement option offered to
certain employee groups in 2002. We expect continued declines in these costs as
we continue to exit the power business and complete our planned asset sales.
Other (income) expense -- net, within operating income, in 2003 includes a
$188 million gain from the sale of a Power contract, $96.7 million in net gains
from the sale of our Exploration & Production segment's interests in certain
natural gas properties in the San Juan basin, a $16.2 million gain from
Midstream's sale of the wholesale propane business, and a $12.2 million gain on
foreign currency exchange at Power. Partially offsetting these gains was a $45
million goodwill impairment at Power, a $44.1 million impairment of the Hazelton
generation plant at Power, a $25.6 million charge to write-off capitalized
software development costs at Northwest Pipeline, a $20 million charge related
to a settlement by Power with the Commodity Futures Trading Commission (see Note
16 of Notes to Consolidated Financial Statements) and a $19.5 million accrual at
Power related to an adjustment of California rate refund and other related
accruals. Other (income) expense -- net, within operating income, in 2002
includes $244.6 million of impairment charges, loss accruals, and write-offs
within Power, including a partial impairment of goodwill, $141.7 million in net
gains from the sale of Exploration & Production's interests in natural gas
properties and $78.2 million of impairment charges related to Midstream's
Canadian olefin assets.
General corporate expenses decreased $55.8 million. During 2002, we
incurred $24 million of various restructuring costs associated with the
liquidity and business issues addressed beginning third-quarter 2002. We also
incurred $19 million higher advertising and branding costs in 2002 (due
primarily to golf events and other advertising campaigns that were not continued
in 2003). In 2004, we will continue efforts to further reduce our corporate cost
structure following the recent and anticipated divestitures. We could also
experience additional decreases in costs related to our health care plan for
retirees as a result of the passage of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003.
99.2-8
Interest accrued -- net increased $108.5 million, or 10 percent, due
primarily to:
- $48.1 million higher interest expense and fees primarily
related to the RMT note payable, which was prepaid in May 2003
(see Note 11 of Notes to Consolidated Financial Statements);
- an $18.2 million increase in capitalized interest, which
offsets interest accrued, due primarily to Midstream's
projects in the Gulf Coast Region;
- $25 million higher amortization expense related to deferred
debt issuance costs including a $14.5 million write-off of
accelerated amortization of costs from the termination of a
revolving credit agreement in June 2003 (see Note 11 of Notes
to Consolidated Financial Statements);
- a $43 million increase reflecting higher average interest
rates on long-term debt;
- a $15 million decrease reflecting lower average borrowing
levels; and
- $14.3 million of interest expense of Power as a result of
certain 2003 FERC proceedings.
We expect interest expense to decrease in 2004 due to reduced averaged
borrowing levels and lower average interest rates.
In 2002, we began entering into interest rate swaps with external counter
parties primarily in support of the energy-trading portfolio (see Note 19 of
Notes to Consolidated Financial Statements). The change in market value of these
swaps was $122 million more favorable in 2003 than 2002, due largely to a
reduction in overall swap positions during the second half of 2002. The total
notional amount of these swaps is approximately $300 million at December 31,
2003.
Investing income increased to $73.1 million in 2003 compared to a $113.2
million loss in 2002. As detailed in Note 3 of Notes to Consolidated Financial
Statements, investing income (loss) in 2003 includes:
- $52.1 million lower equity earnings from Gulfstream Natural
Gas System LLC, primarily resulting from the absence in 2003
of a $27.4 million contractual construction completion fee
received in 2002;
- $33.6 million higher net interest income at Power as a result
of certain 2003 FERC proceedings; and
- a $43.1 million impairment related to our investment in
Longhorn Partners Pipeline L.P.
Investing income (loss) in 2002 includes a $268.7 million loss provision
relating to the estimated recoverability of receivables from WilTel
Communications Group, Inc. (WilTel), a former subsidiary, partially offset by
equity earnings and a $58.5 million gain on the sale of all of our interest in a
Lithuanian oil refinery, pipeline and terminal complex.
Minority interest in income and preferred returns of consolidated
subsidiaries in 2003 is lower than 2002 due primarily to the absence of
preferred returns totaling $25 million on the preferred interests in Castle
Associates L.P., Piceance Production Holdings L.L.C., and Williams Risk Holdings
L.L.C., which were modified and reclassified as debt in third-quarter 2002, and
Arctic Fox, L.L.C., which was modified and reclassified as debt in April 2002.
See Note 12 of Notes to Consolidated Financial Statements.
Other income -- net, below operating income, in 2003 includes debt tender
and related costs of $66.8 million, which were incurred in 2003 related to the
third quarter 2003 tender offers and consent solicitations (see Note 11 of Notes
to Consolidated Financial Statements). We may pursue additional debt tender
offers in 2004. In addition, $84.7 million of foreign currency transaction gains
on a Canadian dollar denominated note receivable are included. Partially
offsetting these gains were $79.8 million of derivative losses on a forward
contract to fix the U.S. dollar principal cash flows from this note. In 2004,
these may be less offsetting since the note receivable balance was substantially
reduced in the last half of 2003.
The provision (benefit) for income taxes was unfavorable by $324.9 million
due primarily to pre-tax income in 2003 as compared to a pre-tax loss in 2002.
The effective income tax rate for 2003 is significantly higher than the federal
statutory rate due primarily to non-deductible impairment of goodwill,
non-deductible expenses, an accrual for tax contingencies, and the effect of
state income taxes, somewhat offset by the tax benefit of capital losses. The
effective income tax rate for 2002 is less than the federal statutory rate due
primarily to the tax benefit of capital losses and the effect of state income
taxes, somewhat offset by the effect of taxes on foreign operations,
non-deductible impairment of goodwill, an accrual for tax contingencies, and
income tax credit recapture that reduced the tax benefit of the pre-tax loss.
99.2-9
In addition to the operating results from activities included in
discontinued operations (see Note 2 of Notes to Consolidated Financial
Statements), the 2003 loss from discontinued operations includes pre-tax gains
and losses on sales, net of impairments, totaling $169.0 million. The $169.0
million consists primarily of the following:
- a $310.8 million gain on sale of Williams Energy Partners;
- a $92.1 million gain on sale of Canadian liquids operations;
- a $39.7 million gain on sale of natural gas properties in the
Raton Basin in southern Colorado and the Hugoton Embayment in
southwestern Kansas;
- a $108.7 million impairment of Gulf Liquids;
- a $106.2 million impairment (net of a $2.8 million gain on
sale) of Texas Gas Transmission;
- a $41.7 million impairment on the Canadian straddle plants;
and
- a $21.6 million loss on sale and impairment on assets of the
soda ash mining facility located in Colorado.
The 2002 loss from discontinued operations includes pre-tax impairments and
losses totaling $567.8 million (see the 2002 vs. 2001 discussion below).
The cumulative effect of change in accounting principles reduces net
income for 2003 by $761.3 million due to a $762.5 million charge related to the
adoption of EITF 02-3 (see Note 1 of Notes to Consolidated Financial
Statements), slightly offset by $1.2 million related to the adoption of SFAS No.
143, "Accounting for Asset Retirement Obligations" (see Note 1 of Notes to
Consolidated Financial Statements).
In June 2003, we redeemed all of our outstanding 9.875 percent
cumulative-convertible preferred shares for approximately $289 million, plus
$5.3 million for accrued dividends (see Note 13 of Notes to Consolidated
Financial Statements). Preferred stock dividends in 2002 reflects the
first-quarter 2002 impact of recording a $69.4 million non-cash dividend
associated with the accounting for a preferred security that contained a
conversion option that was beneficial to the purchaser at the time the security
was issued.
2002 vs. 2001
Our revenue decreased approximately $1.5 billion, or 31 percent, due
primarily to lower revenues associated with energy risk management and trading
activities at Power and the absence of $184 million of revenue related to the
198 convenience stores sold in May 2001 within our previously reported Petroleum
Services segment (Petroleum Services). Partially offsetting these decreases was
the impact of an increase in net production volumes within Exploration &
Production partly due to the August 2001 acquisition of Barrett Resources
Corporation (Barrett). As permitted by EITF 02-3, discussed above, 2002 and 2001
revenues were not restated for the adoption of EITF 02-3 in January 2003.
Costs and operating expenses decreased $176.9 million, or 8 percent, due
primarily to the absence of the 198 convenience stores sold in May 2001.
Slightly offsetting these decreases are increased depletion, depreciation and
amortization and lease operating expenses at Exploration & Production due
primarily to the addition of the former Barrett operations.
Selling, general and administrative expenses decreased $91.5 million due
primarily to lower variable compensation levels at Power. Selling, general and
administrative expenses for 2002 also include approximately $22 million of early
retirement costs, $9 million of employee-related severance costs and
approximately $5 million related to early payoff of employee stock ownership
plan expenses.
Other (income) expense -- net, within operating income, in 2002 includes
$244.6 million of impairment charges and loss accruals within Power comprised of
$138.8 million of impairments and loss accruals for commitments for certain
power assets associated with terminated power projects, $61.1 million goodwill
impairments and a $44.7 million impairment charge related to the Worthington
generation facility sold in January 2003. Included in Other (income) expense --
net, within operating income, in 2002 is a $78.2 million impairment charge
related to Midstream's Canadian olefin assets. Partially offsetting these
impairment charges and accruals are $141.7 million of net gains on sales of
natural gas production properties at Exploration & Production in 2002. Other
(income) expense -- net, within operating income, in 2001 includes a $75.3
million gain on the May 2001 sale of the convenience stores and impairment
charges of $13.8 million and $12.1 million within Midstream and the former
Petroleum Services segment, respectively (see Note 4 of Notes to Consolidated
Financial Statements).
99.2-10
General corporate expenses increased $18.5 million, or 15 percent, due
primarily to approximately $24 million of various restructuring costs associated
with the liquidity and business issues addressed beginning third-quarter 2002,
$6 million of expense related to the enhanced-benefit early retirement program
offered to certain employee groups and $6 million of expense related to employee
severance costs. Partially offsetting these increases were lower charitable
contributions and advertising costs.
Operating income decreased $1,508.2 million, or 75 percent, due primarily
to lower net revenues associated with energy risk management and trading
activities at Power and the impairment charges and loss accruals noted above.
Partially offsetting these decreases are the gains from the sales of natural gas
production properties and the impact of increased net production volumes at
Exploration & Production, higher demand revenues and the effect of the
reductions in rate refund liabilities associated with rate case settlements at
Gas Pipeline, and higher equity earnings.
Interest accrued -- net increased $477.2 million, or 73 percent, due
primarily to $154 million related to interest expense, including amortization of
fees, on the RMT note payable (see Note 11 of Notes to Consolidated Financial
Statements), the $76 million effect of higher average interest rates, the $222
million effect of higher average borrowing levels and $41 million of higher debt
issuance cost amortization expense.
In 2002, we entered into interest rate swaps with external counter parties
primarily in support of the energy trading portfolio. The swaps resulted in
losses of $124.2 million (see Note 19 of Notes to Consolidated Financial
Statements).
The 2002 investing loss decreased $59.4 million as compared to the 2001
investing loss. Investing loss for 2002 and 2001 consisted of the following
components:
YEARS ENDED
DECEMBER 31
-----------------
2002 2001
------- -------
(MILLIONS)
Equity earnings* ................................... $ 73.0 $ 22.7
Income from investments* ........................... 42.1 4.2
Write-down of WilTel common stock investment ....... -- (95.9)
Loss provision for WilTel receivables .............. (268.7) (188.0)
Interest income and other .......................... 40.4 84.4
------- -------
Investing loss ..................................... $(113.2) $(172.6)
======= =======
- ----------
* These items are also included in the measure of segment profit (loss).
The equity earnings increase includes a $27.4 million benefit reflecting a
contractual construction completion fee received by an equity method investment
(see Note 3 of Notes to Consolidated Financial Statements) and $4 million of
earnings in 2002 versus $20 million of losses in 2001 from the Discovery
pipeline project, partially offset by an equity loss in 2002 of $13.8 million
from our investment in Longhorn Partners Pipeline LP. Income (loss) from
investments in 2002 includes a $58.5 million gain on the sale of our equity
interest in a Lithuanian oil refinery, pipeline and terminal complex, which was
included in the Other segment, a gain of $8.7 million related to the sale of our
general partner interest in Northern Borders Partners, L.P., a $12.3 million
write-down of an investment in a pipeline project which was canceled and a $10.4
million net loss on the sale of our equity interest in a Canadian and U.S. gas
pipeline. Income (loss) from investments in 2001 includes a $27.5 million gain
on the sale of our limited partner equity interest in Northern Border Partners,
L.P. offset by a $23.3 million loss from other investments, both of which were
determined to be other than temporary. See Note 2 of Notes to Consolidated
Financial Statements for a discussion of the losses related to WilTel. Interest
income and other decreased due to a $22 million decrease in interest income
related to margin deposits, a $4.9 million decrease in dividend income primarily
as a result of the second-quarter 2001 sale of Ferrellgas Partners L.P. senior
common units and write-downs of certain foreign investments.
Other income (expense) -- net, below operating income, decreased $2.1
million due primarily to an $11 million gain in second-quarter 2002 at our Gas
Pipeline segment associated with the disposition of securities received through
a mutual insurance company reorganization, a $13 million decrease in losses from
the sales of receivables to special purpose entities (see Note 15 of Notes to
Consolidated Financial Statements) and the absence in 2002 of a 2001 $10 million
payment to settle a claim for coal royalty payments relating to a discontinued
activity. Partially offsetting these increases was an $8 million loss related to
early retirement of remarketable notes in first-quarter 2002.
99.2-11
The provision (benefit) for income taxes was favorable by $784.8 million
due primarily to a pre-tax loss in 2002 as compared to pre-tax income in 2001.
The effective income tax rate for 2002 is less than the federal statutory rate
due primarily to the tax benefit of capital losses and the effect of state
income taxes, somewhat offset by the effect of taxes on foreign operations,
non-deductible impairment of goodwill, an accrual for tax contingencies, and
income tax credits recapture that reduced the tax benefit of the pre-tax loss.
The effective income tax rate for 2001 is greater than the federal statutory
rate due primarily to an accrual for tax contingencies, the effect of state
income taxes, and valuation allowances associated with the tax benefits for
investing losses, for which no tax benefits were provided.
In addition to the operating results from activities included in
discontinued operations (see Note 2 of Notes to Consolidated Financial
Statements), the 2002 loss from discontinued operations includes pre-tax
impairments and losses totaling $567.8 million. The $567.8 million consists of
$240.8 million of impairments related to the Memphis refinery, $195.7 million of
impairments related to bio-energy, $146.6 million of impairments related to
travel centers, $133.5 million of impairments related to the soda ash
operations, a $91.3 million loss on sale related to the Central natural gas
pipeline system, a $36.8 million impairment related to the Canadian straddle
plants, $18.4 million of impairments related to the Alaska refinery and a $6.4
million loss on sale related to the Kern River natural gas pipeline system.
Partially offsetting these impairments and losses was a pre-tax gain of $301.7
million related to the sale of the Mid-America and Seminole pipelines. Loss from
discontinued operations in 2001 includes a $1.84 billion pre-tax charge for loss
accruals related to guarantees and payment obligations for WilTel and $184.8
million of other pre-tax charges for impairments and loss accruals, including a
$170 million pre-tax impairment charge related to the soda ash mining facility.
Income (loss) applicable to common stock in 2002 reflects the impact of
the $69.4 million associated with accounting for a preferred security that
contains a conversion option that was beneficial to the purchaser at the time
the security was issued. The weighted-average number of shares in 2002 for the
diluted calculation (which is the same as the basic calculation since we
reported a loss from continuing operations) increased approximately 16 million
from December 31, 2001. The increase is due primarily to the 29.6 million shares
issued in the Barrett acquisition in August 2001.
RESULTS OF OPERATIONS -- SEGMENTS
We are currently organized into the following segments: Power (formerly
named Energy Marketing & Trading), Gas Pipeline, Exploration & Production,
Midstream and Other. The Petroleum Services segment is now reported within Other
as a result of the Alaska refinery and related assets being reflected as
discontinued operations. 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 19 of Notes to
Consolidated Financial Statements).
Prior period amounts have been restated to reflect these changes. The
following discussions relate to the results of operations of our segments.
POWER
OVERVIEW OF 2003
As described below, a strategic change in business focus and a required
change in accounting principles significantly influenced Power's 2003 operating
results.
In June 2002, we announced our intent to exit our Power business and
reduce our financial commitment to the Power segment. Prior to this point, Power
focused on originating short-term and long-term contracts that it considered
profitable based on its view of the market. Beginning in mid-2002, Power now
focuses on 1) terminating or selling all or portions of the portfolio, 2)
maximizing cash flow, 3) reducing risk, and 4) managing existing contractual
commitments, many of which are long-term. We initiated efforts to sell all or
portions of Power's power, natural gas, and crude and refined products
portfolios in mid-2002. Based on bids received in these sales efforts, Power
recognized impairments for certain assets and capital projects in 2002. In 2003,
we continued our efforts to exit this business. In 2003, proceeds from contract
sales and terminations exceeded carrying values, resulting in gains. The
decision to exit the Power business also resulted in decreased selling, general
and administrative expense. Segment profit was unfavorably impacted in 2003 as a
result of reduced origination of long-term energy-related transactions.
As discussed further in Note 1 of Notes to the Consolidated Financial
Statements, in 2003, Power adopted EITF 02-3, which changed the classification
of certain revenues and costs in the statement of operations and the accounting
method for non-derivative energy and energy-related contracts. Decreased power
prices and increased natural gas prices primarily caused an increase in the fair
value of power and gas derivative contracts, which is reflected as an increase
in earnings. Due to the change in accounting method
99.2-12
discussed further below, the related change in fair value of non-derivative
contracts was not recognized in earnings during 2003 since non-derivative
contracts are no longer marked to market. However, accrual losses on power and
gas non-derivative contracts were recognized in 2003.
Power considers key factors that influence its financial condition and
operating performance to include the following:
- prices of power and natural gas, including changes in the
margin between power and natural gas prices,
- changes in market liquidity, including changes in the ability
to economically hedge the portfolio,
- changes in power and natural gas price volatility,
- changes in the regulatory environment, and
- changes in power and natural gas supply and demand.
OUTLOOK FOR 2004
In 2004, Power anticipates further variability in earnings due in part to
the difference in accounting treatment of derivative contracts at fair value and
our underlying non-derivative contracts on an accrual basis. This difference in
accounting treatment combined with the volatile nature of energy commodity
markets could result in future operating gains or losses. Some of Power's
tolling contracts have a negative fair value, which is not reflected in the
financial statements since these contracts are not derivatives. These tolling
contracts may result in future accrual losses. Continued efforts to sell all or
a portion of the portfolio 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.
The following risks and challenges also impact how Power manages its
business and affect its operating results:
- unresolved litigation,
- regulatory changes and oversight,
- lack of liquidity, and
- key employee retention.
YEAR-OVER-YEAR OPERATING RESULTS
YEARS ENDED DECEMBER 31,
----------------------------------
2003 2002 2001
--------- --------- ---------
(MILLIONS)
Segment revenues ............. $13,192.6 $ (85.2) $ 1,705.6
Segment profit (loss) ........ $ 154.1 $ (624.8) $ 1,270.0
99.2-13
2003 vs. 2002
INCREASE IN REVENUES AND COST OF SALES
EITF 02-3 impacts how Power presents revenues and costs from certain
transactions in the statement of operations. The table below summarizes items
included in revenues and costs before and after January 1, 2003:
BEFORE AFTER
- ------------------------------------------------- -------------------------------------------------
Revenues: Revenues:
- - Gains and losses from changes in fair value - Gains and losses from changes in fair value
of all energy trading contracts with a of only derivative contracts with a future
future settlement or delivery date and from settlement or delivery date
changes in fair value of commodity
inventories - Revenue from sales of commodities or
completion of energy-related services
- - Revenue from sales of commodities or
completion of energy-related services - Gains and losses from net financial
settlement of derivative contracts
- - Gains and losses from net financial
settlement of derivative contracts Costs:
- - Costs from purchases of commodities or fees - Costs from purchases of all commodities and
from energy-related services that were not fees paid for energy-related services
associated with property, plant and
equipment we owned
Costs:
- - Costs from purchases of commodities or fees
for energy-related services for use in
property, plant and equipment that we owned
Revenues increased $13.3 billion and costs increased $12.9 billion from
2002 to 2003 primarily because Power now reports certain purchases in costs
instead of reporting them as reduction of revenues. This change in reporting
does not affect gross margin or segment profit. EITF 02-3 does not require
restatement of prior year amounts. As presented in the table that follows this
section, Power also now accounts for a significant portion of its business
activity using the accrual method of accounting rather than recognizing changes
in fair value through segment profit, or mark-to-market accounting.
INCREASE IN SEGMENT PROFIT
EITF 02-3, which was implemented January 1, 2003, significantly impacted
the increase in segment profit from 2002 to 2003. Before the adoption of EITF
02-3, Power reported the fair value of all its energy contracts, energy-related
contracts and inventory on the balance sheet. Power reported changes in the fair
value of the items from period to period in segment profit. Examples of
derivative and non-derivative contracts are as follows:
DERIVATIVE CONTRACTS NON-DERIVATIVE CONTRACTS
- -------------------------------------------- --------------------------------------------------------
- - Forward purchase and sale contracts - Spot purchase and sale contracts
- - Futures contracts - Transportation contracts
- - Option contracts - Storage contracts
- - Swap agreements - Tolling agreements (power conversion contracts)
- Full requirement or load serving contracts (power
sales contracts in which we supply all of the
customer's requirements for power)
99.2-14
In 2003, Power continues to reflect the changes in fair value of
derivative contracts in segment profit. However, for non-derivative contracts,
Power does not recognize revenue until commodities are delivered or services are
completed. Also, for non-derivative contracts, Power does not recognize costs
until products are received and consumed, services are used, or inventories are
sold. Power is exposed to earnings fluctuations because of these differences in
accounting for derivative and non-derivative contracts within its portfolio. The
following example illustrates this exposure to earnings fluctuations:
Assume there are two contracts. The first is a ten-year contract in which
Power agrees to pay a counterparty a monthly fee for the right to convert
natural gas to power (a tolling contract). Power has the right to sell the
power produced under the tolling contract. The contract is not a
derivative. The second is a derivative contract to sell power in 2008 to
another party for a fixed price, entered into to fix the sales price of
the power produced in 2008 under the tolling contract. Therefore, the
power sales contract economically hedges the forward power price component
of the tolling contract. If power prices fall, the decline in fair value
of the tolling agreement would not be reflected in 2003 segment profit
since the contract is not a derivative. The increase in the fair value of
the power sale contract, however, would be reflected in segment profit
since it is a derivative.
As illustrated in the above example, many of our derivative contracts
serve as economic hedges of our non-derivative positions. We could reduce our
exposure to earnings fluctuations by applying hedge accounting, as provided for
under SFAS No. 133. However, since we have announced our intent to exit the
business, we do not currently meet the criteria to be eligible for hedge
accounting. We reduced our exposure to earnings fluctuations through election of
the normal purchases and sales exception available under SFAS No. 133 for two
significant long-term derivative contracts. These two derivative contracts hedge
a tolling contract. Since the election in the second quarter of 2003, we account
for the two derivative contracts on an accrual basis. However, we remain exposed
to earnings fluctuations from changes in fair value of certain other derivative
positions.
The following table summarizes the major elements impacting segment profit
in 2003 and 2002:
YEARS ENDED
DECEMBER 31,
---------------
2003 2002
------ ------
(MILLIONS)
Accrual earnings (losses) ........................ $(268) $ 11
Mark-to-market earnings (losses) ................. 401 (420)
Interest rate portfolio earnings (losses) ........ (12) 91
Origination ...................................... -- 204
Prior period adjustments ......................... 117 --
----- -----
Gross margin .................................. 238 (114)
----- -----
Operating expenses ............................... 35 40
Selling, general and administrative expenses ..... 124 209
Other income (expense) -- net .................... 75 (262)
----- -----
Segment profit (loss) ......................... $ 154 $(625)
===== =====
INCREASE IN GROSS MARGIN
The impact of the earnings fluctuations discussed in the previous section
is reflected in our 2003 gross margin. Gross margin increased from a margin loss
of $114.2 million in 2002 to a gross margin of $238 million in 2003.
Accrual Earnings: Losses on contracts and assets in 2003 accounted for on
an accrual basis partially offset increases in gross margin from mark-to-market
earnings as discussed in the next section. In 2002, we accounted for revenues
and costs generated only on our owned assets on an accrual basis. These owned
assets resulted in a $10.9 million gross margin in 2002. In 2003, we also
accounted for revenues and costs generated on our non-derivative contracts on an
accrual basis. The owned assets and non-derivative contracts generated a $268.1
million margin loss in 2003.
The $268.1 million margin loss primarily consists of accrual losses of
$246.6 million on non-derivative contracts and owned assets within our power and
natural gas portfolios. As with forward power prices, the increased power supply
in the mid-continent and eastern regions contributed to lower prices received on
power sales in 2003, primarily contributing to the accrual losses. The $246.6
million also includes a $37 million loss from increased power rate refunds owed
to the state of California because of FERC rulings issued and a $13.8 million
loss for other contingencies related to our power marketing activities in the
state of California.
Mark-to-Market Earnings: The difference in accounting for non-derivative
contracts in 2003 compared to 2002 primarily contributed to the increase in
gross margin. In 2002, we recognized mark-to-market losses of $420 million on
derivative contracts and non-derivative contracts, both of which we carried at
fair value, or marked to market, in 2002. In 2003, we recognized mark-to-market
gains of $401.4 million on derivative contracts only. We refer to net realized
and unrealized gains and losses on contracts carried at fair value as
mark-to-market earnings.
99.2-15
Derivative contracts within our power and natural gas portfolios primarily
contributed to the mark-to-market gains in 2003, generating $412.3 million of
the total mark-to-market gains of $401.4 million. Decreased forward power prices
on net power sales contracts and increased forward gas prices on net gas
purchase contracts primarily caused the mark-to-market gains from power and
natural gas derivative contracts. Increased power supply in the mid-continent
and eastern U.S. significantly contributed to the decrease in forward power
prices. A $126.8 million positive valuation adjustment on a terminated
derivative contract also contributed to the 2003 mark-to-market gains on power
and natural gas derivative contracts.
Of the $420 million in mark-to-market losses in 2002, $320 million related
to the power and natural gas portfolios. The fair value of certain tolling
portfolios decreased as the margin between forward power prices and the
estimated cost to produce the power decreased. The decline in volatility of the
power and natural gas markets also contributed to the decrease in the fair value
of tolling contracts within certain of our tolling portfolios as it does other
option contracts. Tolling contracts possess characteristics of options since we
have the right but not the obligation to request the plant owner to convert
natural gas to power. Valuation methods used in 2002 are discussed in Note 1 of
the Notes to Consolidated Financial Statements. Power and natural gas
mark-to-market losses in 2002 also reflected a $74.8 million valuation
adjustment on certain non-derivative power sale contracts. Quotes received
during sales efforts in 2002 resulted in the valuation adjustment. The favorable
net effect of approximately $85 million resulting from a settlement with the
state of California partially offsets the 2002 mark-to-market losses. The $85
million primarily reflects the increase in fair value on power sales contracts
with the California Department of Water Resources, which resulted from a
restructuring of the contracts and the improved credit standing of the
counterparty.
Interest Rate Portfolio: Differences in the treatment of interest rate
movements in 2003 compared to 2002 also offset the increase in gross margin. The
2002 interest rate earnings of $91 million reflect the impact of decreased
interest rates on power, natural gas and crude and refined derivative and
non-derivative contracts. As interest rates decreased, the overall fair value of
these commodity contracts increased. The increase in the fair value of these
contracts was partially offset by the decrease in the fair value of interest
rate derivatives. Interest rate derivatives hedge the power, natural gas and
crude and refined products contracts on an economic basis. The 2003 interest
rate loss of $12.3 million reflects the mark-to-market loss on interest rate
derivatives only.
Origination: The lack of contract origination in 2003 further offsets the
increase in gross margin. Consistent with our reduced financial commitment to
the Power business, we did not originate long-term energy-related contracts in
2003. In 2002, we recognized $85.1 million of power and natural gas revenues and
$118.8 million of petroleum products revenues by originating new contracts.
Correction of Prior Period Items: Results for 2003 include approximately
$117 million of revenue related to the correction of the accounting treatment
previously applied to certain third party derivative contracts during 2002 and
2001. This matter was initially disclosed in our Form 10-Q for the second
quarter of 2003. See Note 1 of Notes to Consolidated Financial Statements.
DECREASE IN SELLING, GENERAL AND ADMINISTRATIVE EXPENSES
The reduced focus on the Power business resulted in further employee
reductions in 2003. Power employed approximately 250 employees at the end of
2003 compared to approximately 410 at the end of 2002. This decrease in
employees was the primary factor in the $85 million, or 41 percent, decrease in
selling, general, and administrative expenses.
INCREASE IN OTHER INCOME (EXPENSE) -- NET
Other income (expense) -- net improved $337.1 million. Power terminated or
sold certain contracts and other assets, resulting in losses in 2002 and gains
in 2003. In 2002, Power terminated certain power -- related capital projects,
which resulted in $138.8 million of impairments. Power also recorded a $44.7
million impairment in 2002 from the January 2003 sale of the Worthington
generation facility. In 2003, Power sold a non-derivative energy-trading
contract resulting in a $188 million gain on sale. Power also sold an interest
in certain investments accounted for under the cost method in 2003 for a gain of
$13.8 million.
A $45 million goodwill impairment in 2003 compared to a $61.1 million
goodwill impairment in 2002 also contributed to the increase in Other (income)
expense-net. See Note 4 of Notes to Consolidated Financial Statements.
Other factors offset the increase in Other income (expense) -- net. In
2003, Power recognized a $44.1 million impairment on a power generating facility
(see Note 4 of Notes to Consolidated Financial Statements). Power also reached a
settlement with the Commodity Futures Trading Commission as discussed in Note 16
of Notes to Consolidated Financial Statements, resulting in a charge of $20
million. Finally, Power recorded accruals of $19.5 million for power marketing
activities in California during 2000 and 2001 (see Note 16 of Notes to
Consolidated Financial Statements).
99.2-16
2002 vs. 2001
The $1,790.8 million, or 105 percent, decrease in revenues is due
primarily to a $1,783.3 million decrease in risk management and trading
revenues. During 2002, the impact of market movements against Power's portfolio
and a significant reduction in origination activities adversely affected our
results. Power's ability to manage or hedge its portfolio against adverse market
movements was limited by a lack of market liquidity as well as our limited
ability to provide credit and liquidity support.
The decrease in risk management and trading revenues includes the
following:
- $1,901.4 million decrease in natural gas and power revenues,
- $6.3 million increase in petroleum products revenues,
- $12 million increase in European trading revenues, and
- $99.8 million increase in interest rate revenues.
The net impact of interest rate movements, including the impact of
interest derivatives, caused the $99.8 million increase in interest rate
revenues.
The $1,783.3 million decrease in risk management and trading revenues
includes a $205 million decrease in revenues from new transactions originated
and contract amendments as compared to 2001. A decline in natural gas revenues
caused $454.9 million of the $1,901.4 million decline in natural gas and power
revenues. Increasing prices on short natural gas positions during the third
quarter of 2002 primarily caused the decline in natural gas revenues. The
remaining $1,446.5 million decline in natural gas and power revenues relates to
lower revenues from the power portfolio caused primarily by 1) smaller
differences in the margin between forward power prices and the estimated cost to
produce the power on certain power tolling portfolios; 2) lower volatility
compared with 2001; and 3) the net impact of portfolio valuation adjustments
associated with the decline in market liquidity and portfolio liquidation
activities.
Origination activities during the first quarter of 2002 primarily caused
the $6.3 million increase in petroleum products revenues. The commencement of
trading activities in the European office as compared to start-up activities in
2001 principally drove the $12 million increase in European trading revenues.
The European operations were being wound down in 2002.
As a result of our liquidity constraints, we initiated efforts in 2002 to
sell all or portions of Power's portfolio and/or pursue potential joint venture
or business combination opportunities. Portions of Power's portfolio were
recognized at their estimated fair value, which under generally accepted
accounting principles is the amount at which they could be exchanged in a
current transaction between willing parties other than in a forced liquidation
or sale. As a result of information obtained through the portfolio sales efforts
in 2002, Power adjusted the estimated fair value of certain portions of the
portfolio to reflect viable market information received. For those portions of
the portfolio for which no viable market information was received through sales
efforts, Power estimated fair value using other market-based information and
consistent application of valuation techniques. Portfolio valuation adjustments
recognized in 2002 as a result of new market information obtained through sales
efforts resulted in a $74.8 million decrease in segment profit.
Revenues for 2002 also includes the favorable fourth-quarter net effect of
approximately $85 million resulting from the settlement with the state of
California, the restructuring of associated energy contracts, and the related
improved credit situation of the counterparties during the quarter.
Selling, general, and administrative expenses decreased by $124.7 million,
or 37 percent. Lower variable compensation levels and staff reductions primarily
caused this cost reduction.
Other (income) expense -- net in 2002 includes the following:
- Impairments and loss accruals associated with commitments for
certain power projects that have been terminated of $138.8
million;
- Partial impairment of goodwill of $61.1 million, reflecting a
decline in fair value resulting from deteriorating market
conditions during 2002; and
- Impairment charge related to the January 2003 sale of the
Worthington generation facility of $44.7 million.
Other (income) expense -- net in 2001 included a $13.3 million charge due
to a terminated expansion project.
99.2-17
The $1,894.8 million, or 149 percent decrease in Segment profit (loss) is
due primarily to the $1,783.3 million reduction of risk management and trading
revenues and the other (income) expense -- net items, partially offset by the
$124.7 million reduction in selling, general and administrative expenses, and
the $23.3 million charge from the write-downs in 2001 of marketable equity
securities and a cost based investment (see Note 3 of Notes to Consolidated
Financial Statements).
GAS PIPELINE
OVERVIEW OF 2003
Gas Pipeline's interstate transmission and storage activities are subject
to regulation by the FERC and as such, our rates and charges for the
transportation of natural gas in interstate commerce, and the extension,
enlargement or abandonment of jurisdictional facilities and accounting, among
other things, are subject to regulation. The rates are established through the
FERC's rulemaking process. As a result of this regulation, Gas Pipeline's
revenues and operating costs are relatively stable, with fluctuations primarily
driven by the approval by the FERC of new rates, the level of pipeline
transportation capacity used and seasonal demands. Therefore capacity is a
significant factor for revenues and ultimately segment profit.
During 2003, Gas Pipeline completed five major expansion projects. The
combined impact of the completed projects resulted in the following:
Northwest Pipeline:
- Created 450,000 Dth/d of new physical capacity.
- Installed more than 120 miles of new pipeline looping in
Washington, Idaho, and Wyoming.
Transco:
- Increased capacity by 320,000 Dth/d.
- Installed more than 43 miles of new pipeline.
Significant risk factors that could affect the profitability of our Gas
Pipeline segment include:
- legal and regulatory events such as FERC rate authorization
and/or rate case settlements (see Note 16 of Notes to
Consolidated Financial Statements),
- market demand for expansion projects to increase revenue and
segment profit, and
- catastrophic events to our infrastructure such as ruptures to
pipelines.
OUTLOOK FOR 2004
In December 2003, we received an order from the U.S. Department of
Transportation regarding restoration of transportation service on a segment of a
natural gas pipeline in western Washington. The pipeline experienced a line
break in May 2003 and we subsequently received an order to lower pressure by 20
percent and perform an integrity study on the pipeline segment. The pipeline
experienced a second break in the same segment in December 2003. In December, we
idled the pipeline segment until its integrity could be assured. The decision to
idle the pipeline has not had a significant impact on our ability to meet market
demand, primarily because we have a parallel pipeline in the same corridor. We
have, thus far, been able to meet customers' demand including peak loads during
January 2004. But, during the non-peak demands of spring and summer when gas on
gas competition can be strong, customers may have to take gas from other than
preferred sources. If we are unable to meet customers' demand, then we may have
to reduce our billings to them. The future costs to first restore portions of
the existing pipeline to temporary service and then to replace the pipeline's
capacity entirely are expected to be in the range of approximately $365 million
to $430 million over a three-year period, the majority of which will be spent in
2005 and 2006. We expect to have adequate financial resources to comply with the
order and replace the capacity, if required.
In February 2004, Gas Pipeline placed a pipeline expansion into service
increasing capacity on its Transco natural gas system by 54,000 Dth/d. The
completed projects for Northwest Pipeline and Transco are expected to increase
revenues in 2004 by approximately $45 million. The majority of the planned 2004
capital expenditures is expected to be spent on maintenance of the pipelines.
99.2-18
YEAR-OVER-YEAR OPERATING RESULTS
During 2003, we sold Texas Gas Transmission Corporation (Texas Gas). We
received $795 million in cash and the buyer assumed $250 million in debt. During
2002, we sold both our Central and Kern River interstate natural gas pipeline
businesses. The following discussions exclude any gains or losses on such sales
and the results of operations related to Texas Gas, Central, and Kern River,
which are all reported within discontinued operations.
The following discussions relate to the current continuing businesses of
our Gas Pipeline segment which includes Transco, Northwest Pipeline and various
joint venture projects. Certain assets sold during 2002 are included in the 2002
results. These assets include Cove Point, a general partner interest in Northern
Border, and our 14.6 percent interest in Alliance Pipeline. These assets
represented $7.4 million of revenues and $15.7 million of segment profit for the
year ended December 31, 2002.
YEARS ENDED DECEMBER 31,
------------------------------
2003 2002 2001
-------- -------- --------
(MILLIONS)
Segment revenues ... $1,368.3 $1,301.2 $1,243.1
Segment profit ..... $ 555.5 $ 535.8 $ 463.8
2003 vs. 2002
The $67.1 million, or five percent, increase in revenues is due primarily
to $61 million higher demand revenues on the Transco system resulting from new
expansion projects (MarketLink, Momentum and Sundance) and higher rates approved
under Transco's rate proceedings that became effective in late 2002 and $27
million on the Northwest Pipeline system resulting from new projects (Gray's
Harbor, Centralia, and Chehalis). Revenue also increased due to $10 million
higher gathering revenue on Transco. Partially offsetting these increases was
the absence in 2003 of $26 million of revenue from reductions in the rate refund
liabilities and other adjustments associated with a rate case settlement on
Transco in 2002 and $13 million lower storage demand revenues in 2003 due to
lower storage rates in connection with Transco's rate proceedings that became
effective in late 2002.
Cost and operating expenses increased $21 million, or three percent, due
primarily to $25 million higher depreciation expense due to additional property,
plant and equipment placed into service and $12 million higher state sales and
use, ad valorem and franchise taxes. These increases were partially offset by
$15 million lower fuel expense on Transco, resulting primarily from pricing
differentials on the volumes of gas used in operation. Costs and operating
expenses are projected to be approximately $20 million higher in 2004 due
primarily to non-capitalized maintenance projects.
General and administrative costs decreased $32 million, or 20 percent, due
primarily to the absence in 2003 of $23 million of early retirement pension
costs recorded in 2002 and other employee-related benefits costs associated with
reduced employee levels as well as the absence of a $5 million write-off in 2002
of capitalized software development costs resulting from cancellation of a
project. General and administrative costs in 2004 are projected to be consistent
with 2003 amounts.
Other (income) expense -- net in 2003 includes a $25.6 million charge at
Northwest Pipeline to write-off capitalized software development costs for a
service delivery system. Subsequent to the implementation of the same system at
Transco in the second quarter of 2003 and a determination of the unique and
additional programming requirements that would be needed to complete the system
at Northwest Pipeline, management determined that the system would not be
implemented at Northwest Pipeline. Other (income) expense -- net in 2003 also
includes $7.2 million of income at Transco due to a partial reduction of accrued
liabilities for claims associated with certain producers as a result of recent
settlements and court rulings. Other income (expense) -- net in 2002 includes a
$17 million charge associated with a FERC penalty (see Note 16 of Notes to
Consolidated Financial Statements) and a $3.7 million loss on the sale of the
Cove Point facility.
99.2-19
SUMMARIZED CHANGES IN GAS PIPELINE'S SEGMENT PROFIT:
Segment profit, which includes equity earnings and income (loss) from
investments (included in Investing income (loss)), increased $19.7 million, or
four percent, due to the following favorable 2003 items:
- the $67.1 million increase in revenues,
- the $32 million decrease in general and administrative costs,
- the absence of the $17 million FERC charge in 2002 discussed
above; and
- the absence of the $12.3 million write off of Gas Pipeline's
investment in a cancelled pipeline project and a $10.4 million
loss on the sale of Gas Pipeline's 14.6 percent ownership
interest in Alliance Pipeline in 2002. Both items were
included in income (loss) from investment, which is included
in Investing income (loss).
These increases to segment profit were partially offset by the following:
- $73 million lower equity earnings (included in Investing
income (loss)),
- the $25.6 million charge at Northwest Pipeline to write-off
capitalized software costs discussed previously,
- the $21 million higher operating costs, and
- the absence of an $8.7 million gain in 2002 on the sale of our
general partnership interest in Northern Border Partners, L.P.
The $73 million decrease to equity earnings reflects $24 million lower
equity earnings from Gulfstream, the absence of a $27.4 million benefit in 2002
related to the contractual construction completion fee received by an equity
affiliate and the absence of $19 million of equity earnings following the
October 2002 sale of Gas Pipeline's 14.6 percent ownership in Alliance Pipeline.
The lower earnings for Gulfstream were primarily due to the absence in 2003 of
interest capitalized on internally generated funds as allowed by the FERC during
construction. The Gulfstream pipeline was placed into service during
second-quarter 2002.
2002 vs. 2001
The $58.1 million, or five percent, increase in revenues is due primarily
to $67 million higher demand revenues on the Transco system resulting from new
expansion projects and new settlement rates effective September 1, 2001 and $10
million impact of reductions in the rate refund liabilities associated with rate
case settlements on the Transco system. Revenue also increased due to $8 million
higher transportation revenue on the Northwest Pipeline system, $9 million from
environmental mitigation credit sales and services and $4 million higher
revenues associated with tracked costs, which are passed through to customers
(offset in general and administrative expenses). Partially offsetting these
increases were $23 million lower gas exchange imbalance settlements (offset in
costs and operating expenses), $14 million lower storage revenues and $7 million
lower revenues associated with the recovery of tracked costs which are passed
through to customers (offset in costs and operating expenses). The decrease in
storage revenues noted above is primarily due to $9 million lower rates on Cove
Point's short term storage contracts (the Cove Point facility was sold in
September 2002) and a $6 million decrease at Transco due primarily to lower
storage demand.
Costs and operating expenses decreased $32 million, or five percent, due
primarily to $23 million lower gas exchange imbalance settlements (offset in
revenues), $19 million lower operations and maintenance expense due primarily to
lower professional and other contractual services and telecommunications
expenses, $7 million lower other tracked costs which are passed through to
customers (offset in revenues) and a $5 million franchise tax refund for
Transco. These decreases were partially offset by the $15 million effect in 2001
of a regulatory reserve reversal resulting from the FERC's approval for recovery
of fuel costs incurred in prior periods by Transco, as well as $13 million
higher depreciation expense. The $13 million higher depreciation expense
reflects a $15 million increase due to increased property, plant and equipment
placed into service (including depletion of property held for the environmental
mitigation credit sales), partially offset by a $2 million adjustment related to
the 2002 rate case settlements resulting in lower depreciation rates applied
retroactively.
99.2-20
General and administrative costs increased $17 million, or 12 percent, due
primarily to $10 million higher employee-related benefits expense, including:
- $8 million related to higher pension and retiree medical
expense due to decreases in assumed return on plan assets, and
- approximately $3 million related to expense recognized as a
result of accelerated company contributions to an employee
stock ownership plan.
Also contributing to the increase is $11 million in costs associated with
an early retirement program, a $5 million write-off in 2002 of capitalized
software development costs resulting from cancellation of a project, and $4
million higher tracked costs (offset in revenues). These increases were
partially offset by $12 million lower charitable contributions in 2002.
Other income (expense) -- net in 2002 includes a $17 million charge
associated with a FERC penalty (see Note 16 of Notes to Consolidated Financial
Statements) and a $3.7 million loss on the sale of the Cove Point facility.
Other (income) expense -- net in 2001 includes an $18 million charge resulting
from the unfavorable court decision and resulting settlement in one of Transco's
royalty claims proceedings (an additional $19 million is included in interest
expense).
SUMMARIZED CHANGES IN GAS PIPELINE'S SEGMENT PROFIT
Segment profit, which includes equity earnings and income (loss) from
investments (both included in Investing income (loss)), increased $72 million,
or 16 percent, due primarily to the following:
- $67 million higher demand revenues discussed above,
- $42.1 million higher equity earnings (included in Investing
income (loss)),
- $32 million lower costs and operating expenses discussed
above,
- the effect of the $18 million 2001 charge discussed previously
in Other (income) expense -- net,
- the $10 million effect of rate refund liability reductions
related to the finalization of rate cases during third-quarter
2002, and
- an $8.7 million gain in 2002 on the sale of our general
partnership interest in Northern Border Partners, L.P.
These increases were partially offset by the following items:
- the effect of a $27.5 million gain in 2001 from the sale of
our limited partnership interest in Northern Border Partners,
L.P.,
- the $17 million increase in general and administrative costs
discussed above,
- the $17 million FERC penalty and the $3.7 million loss on the
sale of the Cove Point facility discussed above in Other
income (expense),
- a $12.3 million write-down in 2002 of Gas Pipeline's
investment in a cancelled pipeline project, and
- a loss of $10.4 million on the sale of Gas Pipeline's 14.6
percent ownership interest in Alliance Pipeline.
The $42.1 million increase in equity earnings includes a $27.4 million
benefit in 2002 related to the contractual construction completion fee received
by an equity affiliate. This equity affiliate served as the general contractor
on the Gulfstream pipeline project for Gulfstream Natural Gas System
(Gulfstream), an interstate natural gas pipeline subject to FERC regulation and
an equity affiliate. The fee, paid by Gulfstream and associated with the
completion during the second quarter of 2002 of the construction of Gulfstream's
pipeline, was capitalized by Gulfstream as property, plant and equipment and is
included in Gulfstream's rate base to be recovered in future revenues.
Additionally, the increase in equity earnings reflects an $18 million increase
from Gulfstream, $12 million of which is related to interest capitalized on the
Gulfstream pipeline project in accordance with FERC regulations.
99.2-21
EXPLORATION & PRODUCTION
OVERVIEW OF 2003
Our focus within Exploration & Production is to develop, produce and
explore for natural gas reserves in the Rocky Mountain and Mid-continent
regions. We are currently one of the top producers in the Rocky Mountain region.
Our specialty is extracting natural gas from non-conventional tight sands and
coalbed methane formations. Almost all of our natural gas production is sold to
Williams' Power segment.
We maintain a leadership presence in the following strategic natural gas
basins:
- Piceance Basin in western Colorado;
- Powder River Basin in northeastern Wyoming;
- San Juan Basin, which stretches from northwestern New Mexico
into Colorado; and
- Arkoma Basin in southeastern Oklahoma.
These basins are core to our future success with a large portion of our
proved reserves being undeveloped. Thus, we plan to maintain a significant
drilling program over the next several years. In addition, we manage other oil
and gas interests, including an international oil and gas company, APCO
Argentina, Inc., in which we own an approximate 69 percent interest.
During the first half of 2003, our strategy focused on selling assets and
reducing our development drilling activity in order to raise or preserve cash to
strengthen our balance sheet. In the second half of the year, after we had
successfully paid down or refinanced certain debt, we resumed development
drilling to levels similar to those achieved in 2002. The major accomplishments
for the Exploration & Production segment during 2003 included the following:
- Completed the targeted asset sales of properties located
primarily in Kansas, Colorado, Utah and New Mexico. We
received net proceeds of approximately $465 million resulting
in net pre-tax gains of approximately $134.8 million,
including $39.7 million of pre-tax gains reported in
discontinued operations related to the interests in the Raton
and Hugoton basins.
- Achieved a reserves replacement rate of over 250 percent for
our core retained basins. Overall, our reserves replacement
rate was approximately 30 percent.
- Increased our development drilling program in the latter part
of the year, returning to activity levels reached prior to
2003. Capital expenditures for 2003 were approximately $200
million.
- Decreased our selling, general and administrative costs by $7
million.
OUTLOOK FOR 2004
Our expectations for the Exploration & Production segment in 2004 include:
- A continuing development drilling program in our key basins
with an increase in activity in the Piceance Basin.
- Increasing our current production level of 447 Mmcfe per day
by 10 to 15 percent by the end of 2004. Approximately 80
percent of our forecasted 2004 production is hedged at prices
that average $3.63 per Mcfe at a basin level. Approximately 48
percent of our estimated 2005 production is hedged at prices
that average above $4.00 per Mcfe at the basin level.
Risks that may prevent us from fully accomplishing our objectives include
drilling rig availability, obtaining permits as planned for drilling and any
potential capital constraints.
99.2-22
YEAR-OVER-YEAR OPERATING RESULTS
The following discussions of the year-over-year results primarily relate
to our continuing operations. However, the results do include those operations
that were sold during 2003 or 2002 that did not qualify for discontinued
operations reporting. The operations in the Hugoton and Raton basins qualified
for discontinued operations.
YEARS ENDED DECEMBER 31,
------------------------
2003 2002 2001
----- ------ -------
(MILLIONS)
Segment revenues ... $779.7 $860.4 $603.9
Segment profit ..... $401.4 $508.6 $231.8
2003 vs. 2002
The $80.7 million, or nine percent decrease in revenues is due primarily
to $66 million lower production revenues due to lower production levels as the
result of property sales and reduced drilling activities and $21 million lower
other revenues primarily due to the absence in 2003 of deferred income relating
to transactions in prior years that transferred certain economic benefits to a
third party.
The decrease in domestic production revenues reflects $68 million
associated with an eleven percent decrease in net domestic production volumes,
partially offset by $2 million higher revenues from increased net realized
average prices for production. Net realized average prices include the effect of
hedge positions. The decrease in production volumes primarily results from the
sales of properties in 2002 and 2003 and the impact of reduced drilling
activity. Drilling activity was lower in the January through August period of
2003 due to our capital constraints. During the third quarter, drilling
activities on our retained properties began to increase and by the fourth
quarter of 2003 returned to the levels more consistent with 2002 drilling
levels. This drilling level is expected to increase production volumes in the
future.
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 86 percent of domestic production in 2003 was hedged. These
hedging decisions are made considering our overall commodity risk exposure.
Costs and expenses, including selling, general and administrative
expenses, decreased $11 million, reflecting:
- $17 million lower exploration expenses reflecting the current
focus of the company on developing proved properties while
reducing exploratory activities,
- $10 million lower depreciation, depletion and amortization
expense primarily as a result of lower production volumes,
- $7 million lower selling general and administrative expense,
and
- $19 million higher operating taxes due primarily to higher
market prices.
Other (income) expense -- net in 2003 includes approximately $95.1 million
in net gains on sales of natural gas properties during 2003, which were
discussed previously. Other (income) expense -- net in 2002 includes
approximately $141 million in net gains on sales of natural gas properties
during 2002.
The $107.2 million decrease in segment profit is partially due to $46
million lower net gains on sales of assets in 2003 as compared to 2002, as
discussed above. Additionally, lower production revenues due primarily to lower
production volumes also contributed to the decrease. Segment profit also
includes $18.2 million and $11.8 million related to international activities for
2003 and 2002, respectively. This increase primarily reflects improved operating
results of APCO Argentina.
2002 vs. 2001
The $256.5 million, or 42 percent, increase in revenues is primarily due
to:
- $246 million higher domestic production revenues,
- $27 million in unrealized gains from mark-to-market financial
instruments related to basis differentials on natural gas
production, and
- $28 million lower domestic gas management revenues.
99.2-23
The $246 million increase in domestic production revenues includes $227
million associated with an increase in net domestic production volumes,
resulting primarily from the acquisition in third-quarter 2001 of the former
Barrett operations. The increase in our revenues also includes $19 million from
increased net realized average prices for production (including the effect of
hedge positions). Approximately 88 percent of domestic production in 2002 was
hedged.
Costs and operating expenses, including selling, general and
administrative expenses, increased $112 million, due primarily to the addition
of the former Barrett operations. Increased costs include depreciation,
depletion and amortization, lease operating expenses and selling, general and
administrative expenses. These increases were partially offset by decreased gas
management purchase costs.
Other (income) expense -- net in 2002 includes $120 million and $21
million in gains from the sales of substantially all of our interests in natural
gas production properties in the Jonah field (Wyoming) and in the Anadarko
Basin, respectively.
Segment profit increased $276.8 million due primarily to the gains from
asset sales mentioned in the preceding paragraph, increased production volumes,
and higher net realized average prices. Segment profit also includes $11.8
million and $15.4 million related to international activities for 2002 and 2001,
respectively.
99.2-24
MIDSTREAM GAS & LIQUIDS
OVERVIEW OF 2003
In 2003, we continued to execute our strategy to focus on targeted growth
areas in the Four Corners, Rockies and Gulf Coast production areas. Pursuing our
strategy, we placed into service significant pipeline infrastructure in the
deepwater offshore area of the Gulf of Mexico and added a fourth cryogenic
processing train and a billion cubic feet per day dehydration plant to our Opal
gas processing facility. A third party funded and owns the fourth cryogenic
train mentioned above. The deepwater project contributed to segment profit in
2003 while both Opal expansions will begin contributing in 2004. While
strengthening our positions in these growth areas, we also continued to
rationalize assets by completing sales of various non-core assets. The following
is a list of assets sold during 2003:
- Wholesale propane business, which represents the most
significant portion of our NGL trading activities, and
includes certain supply contracts and seven propane
distribution terminals (fourth quarter).
- Dry Trail gas processing plant located in Texas County,
Oklahoma (fourth quarter).
- West Stoddart gas processing facility and the fractionation,
storage, and distribution system at our Redwater, Alberta
plant in western Canada (third quarter).
- Ownership interest in the following investments: 45 percent
interest in Rio Grande Pipeline (second quarter); 20 percent
interest in the West Texas Pipeline (third quarter); 37.5
percent interest in Wilprise Pipeline (fourth quarter); and
16.67 percent interest in Tri-States NGL Pipeline (fourth
quarter).
OUTLOOK FOR 2004
The following factors could impact our business in 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. These
additional fee- based revenues will lower our relative
exposure to commodity price risks.
- Gas processing margins may not be as favorable as those
realized in 2002 and 2003. Although Wyoming natural gas prices
are historically below natural gas prices in other domestic
markets, the magnitude of this basis differential may be less
in the near future.
- Midstream realized additional product gains related to its gas
gathering systems in 2003. We do not consider these gains to
be recurring in nature.
- In 2003, our Gulf Coast gas processing plants earned
additional fee revenues derived from temporary 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 may terminate if processing economics in this region
were to significantly improve.
- We continue to evaluate and pursue the sale of various assets,
including the assets of our wholly-owned subsidiary Gulf
Liquids New River LLC (Gulf Liquids) and certain Canadian
assets, both currently reported as discontinued operations.
The completion of asset sales may have the effect of lowering
revenues and/or segment profit in the periods following the
sales. The sale of our wholesale propane business mentioned
above will reduce revenues and expenses, but should not have a
material effect on our segment profit. Additional fee-based
revenues from our new deepwater assets are expected to
mitigate segment profit decline resulting from certain asset
sales.
99.2-25
YEAR-OVER-YEAR OPERATING RESULTS
In August 2002, we completed the sale of 98 percent of Mapletree LLC and
98 percent of E-Oaktree, LLC to Enterprise Products Partners L.P. Mapletree
owned all of Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline
system. E-Oaktree owned 80 percent of the Seminole Pipeline, a 1,281-mile
natural gas liquids pipeline system. The gains on the sale of these businesses
and the related results of operations have been reported as discontinued
operations.
Pursuant to generally accepted accounting principles, we have classified
the operations of Gulf Liquids, West Stoddart, Redwater and the Canadian
straddle plants as discontinued operations. All prior periods reflect this
reclassification.
YEARS ENDED DECEMBER 31,
--------------------------------------
2003 2002 2001
----------- ----------- ----------
(MILLIONS)
Segment revenues ....................... $ 2,778.5 $ 1,143.1 $ 1,155.2
Segment profit (loss)
Domestic Gathering & Processing ..... $ 272.9 $ 203.5 *
Venezuela ........................... 74.9 75.4 *
Canada .............................. (37.1) (100.7) *
Other ............................... (1.0) 17.3 *
---------- ---------- ----------
Total ........................... $ 309.7 $ 195.5 $ 169.0
========== ========== ==========
- ----------
* Beginning in the third quarter of 2003, our management discussion and
analysis of operating results was reorganized into major asset groups to
provide additional clarity. The discussion comparing 2002 and 2001 results
was not completed using the same asset groupings.
2003 vs. 2002
Revenues increased $1.6 billion primarily as a result of adopting EITF
02-3, which changed how we report natural gas liquids trading activities. The
costs of such activities are no longer reported as reductions in revenues. EITF
02-3 does not require restatement of prior year amounts. In addition to this
effect, our revenues increased $220 million primarily due to higher natural gas
liquids (NGL) revenues at our gas processing plants as a result of moderate
market price increases, partially offset by lower NGL production volumes.
Additional fee revenues associated with newly constructed deepwater assets and
higher olefins sales also contributed to the revenue increase.
Costs and operating expenses also increased $1.8 billion primarily due to
the adoption of EITF 02-3 as discussed in the previous paragraph. In addition to
this effect, costs and expenses increased $360 million, of which $113 million is
attributable to rising market prices for natural gas used to replace the heating
value of NGLs extracted at our gas processing facilities. Feedstock purchases
for the olefins facilities increased $109 million due to higher NGL and gas
prices as well as higher purchase volumes.
Segment profit increased $114.2 million primarily due to the absence of an
impairment charge of $78.2 million in 2002 relating to the Redwater/Fort
McMurray olefins assets. The remaining $36 million increase is largely
attributable to higher deepwater and other Gulf Coast fee revenues partially
offset by unfavorable results in our Canadian and Gulf olefins operations.
Segment profit benefited from increased processing margins in both 2003 and 2002
due to rising NGL prices coupled with depressed natural gas prices in the
Wyoming area. In contrast, Canadian and Gulf olefins production margins suffered
as market prices for ethane and propane feedstocks increased more than those for
the olefins produced at these facilities, which lowered operating results. In
addition, gains on asset and investment sales, reduced selling, general and
administrative expenses, and gathering system net gains are offset by lower
partnership earnings and higher depreciation expense. A more detailed analysis
of segment profit of our various operations is presented below:
Domestic Gathering & Processing: The $69.4 million increase in domestic
gathering and processing segment profit includes a $76.1 million increase in the
Gulf Coast Region, partially offset by a $6.7 million decline in the West
Region.
The Gulf Coast Region's $76 million improvement is largely attributable to
$42 million of incremental segment profit associated with new infrastructure in
the deepwater area of the Gulf of Mexico. The Canyon Station production
platform, Seahawk gas gathering pipeline, and Banjo oil transportation system
were placed into service during the latter half of 2002 and each contributed to
Midstream's segment profit. The remaining Gulf Coast gathering and processing
assets provided approximately $34 million in additional net revenues, primarily
from $12 million in higher processing margins and $23 million in higher
fee-based revenues. A portion of this increase relates to the temporary
processing agreements which allow producers' gas to be processed to achieve
pipeline quality standards.
99.2-26
The West Region's $6.7 million segment profit decline reflects the
absence of $7 million in operating profit associated with the Kansas Hugoton
gathering system sold in August 2002. Although 2003 segment profit is comparable
to 2002, the West Region's segment results were impacted by several offsetting
factors discussed below:
- Gas processing margins declined $10 million compared to margins
experienced in 2002. Throughout 2002 and the first quarter of
2003, rising NGL prices and depressed Wyoming natural gas prices
yielded very favorable processing margins. Wyoming natural gas
prices rebounded at the end of the first quarter 2003 as the
completion of the Kern River Pipeline system added
transportation capacity relieving downward price pressure.
Margins recovered somewhat in the fourth quarter as Wyoming gas
prices lagged behind the increases in other energy commodities.
- Gathering and processing fee revenues declined $11 million
primarily due to fewer customers electing the fee-based billing
option of processing contracts.
- Non-reimbursed fuel expenses declined $8 million, largely
attributed to favorable adjustments in the annual fuel
reimbursement rates. This favorable variance is not likely to
continue in 2004.
- We realized $17 million in non-recurring net product gains
related to our gas gathering system. These gains represent less
than one-third of one percent of total gas gathered and are
within industry standards. Historically our gathering system
realizes net gains and losses, and therefore, we do not consider
these gains to be recurring in nature.
- Depreciation expense was $10 million higher in large part due to
additional investments in the West.
Venezuela: Segment profit for our Venezuelan assets remained virtually
unchanged. Higher compression rates in 2003 and the 2002 currency exchange loss
resulted in $11 million higher profits at the PIGAP gas compression facility.
These higher profits were partially offset by an $8 million decrease in the El
Furrial operating margins attributed to plant downtime caused by a fire that
occurred in the first quarter of 2003. Also offsetting the increase in PIGAP
operating profit is a $4 million decline resulting from the termination of the
Jose Terminal operations contract in December 2002. 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 operations and cash flows of our facilities.
Effective February 7, 2004, the Venezuelan government revalued the fixed
exchange rate for their local currency from 1,600 Bolivars to the dollar to
1,920 Bolivars to the dollar. This effect of this currency devaluation will be
recorded in the first quarter of 2004 but should not have a significant impact
on our first quarter segment profit.
Canada: The $63.6 million increase in segment profit for our Canadian
assets is primarily due to the absence of an impairment charge of $78.2 million
in 2002 relating to the Redwater/Fort McMurray olefins assets. The offsetting
$14.6 million decline is primarily attributable to declining olefins production
margins and higher operating expenses related to the Redwater/Fort McMurray
olefins facility that became operational in April 2002.
Other: The $18.3 million decline in segment profit for Midstream's other
operations is attributed to lower domestic olefins margins and unfavorable
partnership earnings, partially offset by the gain on sale of our wholesale
propane operations.
- Segment profit for our domestic Olefins group declined $14
million primarily as a result of reduced olefins fractionation
margins as the price of ethane and propane feedstock increased
more than the price of olefins products. Higher maintenance
expenses also contributed to the decline in segment profit.
Olefins production margins continue to be impacted by weak
consumer demand for products produced by petrochemical
facilities.
- Our earnings from partially owned domestic assets accounted for
using the equity method declined $18 million largely due to $13
million in prior period accounting adjustments recorded on the
Discovery partnership, the 2003 sale of other investments that
generated positive earnings in 2002 and $14 million of
impairment charges associated with the Aux Sable partnership
investment. These unfavorable results were partially offset by
net gains totaling approximately $20 million from the sale of
our interests in the West Texas, Rio Grande, Wilprise, and
Tri-states liquids pipeline partnerships.
- Segment profit for our Trading, Fractionation, and Storage group
increased $14 million primarily due to a $16 million gain on the
fourth-quarter 2003 sale of our wholesale propane business
consisting of certain supply contracts and seven propane
distribution terminals. Our NGL trading operations activities
were substantially curtailed in 2003, resulting in $11 million
lower selling, general, and administrative costs partially
offset by $8 million in lower net trading revenues. In addition,
NGL service fees declined $5 million due to the sale of several
NGL terminals in 2002.
99.2-27
2002 vs. 2001
Our revenues decreased $12.1 million as a result of:
- a $23.0 million increase in domestic gathering, processing,
transportation and liquid product sales revenues,
- a $48.7 million increase in Venezuelan revenues,
- a $33.5 million increase in Canadian revenues, and
- a $117 million decline in domestic petrochemical and trading
revenues.
The $23 million increase in domestic gathering, processing,
transportation, storage, fractionation and liquid product sales revenues
resulted from a $34 million increase in liquid sales and a $10 million increase
in transportation revenues, partially offset by a $14 million decrease in
gathering revenues primarily due to the third-quarter 2002 sale of the
Kansas-Hugoton gathering system, a $2 million decrease in storage revenues and a
$4 million decrease in fractionation revenues. The increase in liquid sales
reflects a $67 million increase in gulf coast liquid sales resulting primarily
from higher production at existing processing facilities, and the September 2001
completion of a new processing facility that processes natural gas gathered from
deepwater projects off the coast of Texas.
The increase in Gulf Coast liquid sales was partially offset by a $33
million decline in liquid sales in the west, primarily caused by a decline in
average liquid sales prices. The $10 million increase in transportation revenues
reflects the results of a new deepwater oil and gas transportation system which
was completely operational by mid-year 2002.
The $117 million decline in petrochemicals and trading revenues is due
largely to a September 2001 change in the reporting of certain petrochemical and
liquid product trading transactions from a gross revenue basis to a net revenue
basis combined with lower natural gas liquid trading margins.
The $48.7 million increase in Venezuelan revenues reflects a full year of
results from a new gas compression facility that began operations in August
2001.
The increase in Canadian revenues results from a $34 million increase in
olefins sales due primarily to the Canadian olefins facility being placed
into service in April 2002.
Costs and operating expenses decreased $64 million, or 6 percent,
primarily reflecting a decline in fuel and product shrink costs at our domestic
processing facility of $21 million. This decrease reflects the impact of lower
average natural gas prices in Wyoming, offset by higher volumes and prices in
the Gulf Coast. The lower average gas prices in Wyoming during 2002 reflect a
favorable differential between gas prices in Wyoming and the Gulf as a result of
limited transportation capacity from Wyoming to other markets. This favorable
basis differential had the effect of lower shrink costs and increasing liquid
sales margins from Wyoming processing plants and is not expected to continue
once take away transportation capacity within this region has been expanded.
Costs and operating expenses also reflect a $92 million decline in petrochemical
and trading costs resulting from the September 2001 change in reporting certain
product trading classifications. These decreases are partially offset by $14
million higher transportation, fractionation, and marketing costs. Operations
and maintenance expenses were relatively unchanged on a segment basis. A $32
million decline in costs in the west primarily, resulting from lower maintenance
spending, was offset by a corresponding increase in the Gulf, Canada and
Venezuela. The increase in these areas was largely associated with higher
maintenance costs resulting from the new Venezuelan gas compression facility,
Canadian olefins facility and new deepwater offshore operations.
Selling, general and administrative costs were relatively unchanged on a
segment basis.
Other (income) expense-net within segment costs and expense for 2002
includes a $78 million impairment associated with the Canadian olefin extraction
assets (see Note 4 of Notes to Consolidated Financial Statements) and a $6
million impairment associated with the sale of the Kansas Hugoton gathering
system in the third quarter. Reflected in 2001 are $13.8 million of impairments
associated with certain south Texas non-regulated gathering and processing
assets (see Note 4 of Notes to Consolidated Financial Statements).
Segment profit increased $26.5 million from 2001. This increase reflects a
$96 million increase in domestic operations, a $20 million increase in
Venezuelan operations and an $89 million decrease in Canadian operations.
99.2-28
Domestic segment profit reflects a $45 million increase in liquid sales
margins resulting from the low fuel and shrink costs in the west reflecting the
wide basis differential for natural gas prices in Wyoming. Domestic segment
profit also increased $31 million due to income from equity investments
primarily related to significant improvements in the operations of Discovery
pipeline following new supply connections that resulted in higher transportation
and liquid volumes. Domestic segment profit was also impacted by a $16 million
increase in profits from an increase in deepwater operations.
The decrease in segment profit from Canadian operations primarily relates
to the $78.2 million impairment discussed above.
Segment profit from Venezuelan operations reflects an increase resulting
from a full year of results following the completion of a new gas compression
facility in August 2001.
OTHER
OVERVIEW OF 2003
During 2003, we began reporting the Petroleum Services segment within
Other as a result of a significant portion of the Petroleum Services assets
being reflected as discontinued operations. Other now includes corporate
operations, certain international activities and the remaining continuing
operations of Petroleum Services.
OUTLOOK FOR 2004
During February 2004, we were a party to a recapitalization plan completed
by Longhorn Partners Pipeline, L.P. (Longhorn). As a result of this plan, we
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. No gain or loss was recognized on
this transaction.
YEAR-OVER-YEAR OPERATING RESULTS
YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 2001
------- ------- -------
(MILLIONS)
Segment revenues........................................................... $ 72.0 $ 124.1 $ 319.3
Segment profit (loss)...................................................... $ (50.5) $ 14.1 $ 37.5
2003 vs. 2002
Other segment loss for 2003 includes a $43.1 million impairment related to
our investment in Longhorn. The impairment resulted from our assessment that
indicated there had been an other than temporary decline in the fair value of
this investment. Longhorn equity earnings increased $15.7 million during 2003
from a loss of $13.8 million in 2002. The 2002 segment profit includes a $58.5
million gain on the sale of our 27 percent ownership interest in the Lithuanian
operations partially offset by a $12.6 million equity loss for those operations.
2002 vs. 2001
The $195.2 million, or 61 percent, decrease in revenues is due primarily
to $184 million lower convenience store revenues after the sale in May 2001 of
198 convenience stores.
Other segment profit in 2002 includes a $58.5 million gain from the
September 2002 sale of our 27 percent ownership interest in the Lithuanian
refinery, pipeline and terminal complex and a $9.5 million decrease in equity
losses from the Lithuanian operations for the period. We received proceeds of
approximately $85 million from the sale of this investment. In addition, we sold
our $75 million note receivable from the Lithuanian operations at face value.
Equity losses related to Longhorn increased $13.9 million from 2001 to 2002.
Included in 2001 segment profit is a $75.3 million gain on the sale of 198
convenience stores.
99.2-29
ENERGY TRADING ACTIVITIES
As of December 31, 2002, we carried energy and energy-related contracts on
the Consolidated Balance Sheet at fair value. We held all of these energy and
energy-related contracts for trading purposes. As of December 31, 2002, we
reported net assets of approximately $1,632 million related to the fair value of
energy risk management and trading contracts. Of this value, approximately
$1,193 million pertained to non-derivative energy contracts, which were
reflected at fair value under EITF Issue No. 98-10. On October 25, 2002 in Issue
No. 02-3, the EITF rescinded Issue No. 98-10. With the adoption of EITF 02-3 on
January 1, 2003, we reversed this non-derivative fair value through a cumulative
adjustment from a change in accounting principle. These contracts are now
accounted for under the accrual method. Effective January 1, 2003, only energy
contracts meeting the definition of a derivative are reflected at fair value on
the Consolidated Balance Sheet.
FAIR VALUE OF TRADING DERIVATIVES
Consistent with our announcement to exit the merchant power and generation
business, in 2003 we assessed which derivative contracts we held for trading
purposes and which we held for non-trading purposes. We consider trading
derivatives to be those held to provide price risk management services to
third-party customers. The chart below reflects the fair value of derivatives
held for trading purposes as of December 31, 2003. We have presented the fair
value of assets and liabilities by period in which they are expected to be
realized.
TO BE TO BE TO BE TO BE
REALIZED IN REALIZED IN REALIZED IN REALIZED IN
1-12 MONTHS 13-36 MONTHS 37-60 MONTHS 61-120 MONTHS TOTAL FAIR
(YEAR 1) (YEARS 2-3) (YEARS 4-5) (YEARS 6-10) VALUE
- ----------- ------------ ------------ ------------- ----------
(MILLIONS)
$ (3) $ 25 $ 22 $ (5) $ 39
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 positions 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 December 31, 2003, the fair value of these
non-trading derivative contracts was a net asset of $435 million.
METHODS OF ESTIMATING FAIR VALUE
Most of the derivatives we hold settle in active periods and markets in
which quoted market prices are available. Quoted market prices in active markets
are readily available for valuing forward contracts, futures contracts, swap
agreements and purchase and sales transactions in the commodity and capital
markets in which we transact. While an active market may not exist for the
entire period, quoted prices can generally be obtained for the following:
- natural gas through 2013,
- power through 2007,
- crude and refined products through 2005,
- natural gas liquids through 2004, and
- interest rates through 2033.
These prices reflect the economic and regulatory conditions that currently
exist in the marketplace and are subject to change in the near term due to
changes in market conditions. The availability of quoted market prices in active
markets varies between periods and commodities based upon changes in market
conditions. The ability to obtain quoted market prices also varies greatly from
region to region. The time periods noted above are an estimation of aggregate
liquidity. We use prices of current transactions to further validate price
estimates. However, the decline in overall market liquidity since 2002 has
limited our ability to validate prices.
We estimate energy commodity prices in illiquid periods by incorporating
information about commodity prices in actively quoted markets, quoted prices in
less active markets, and other market fundamental analysis.
99.2-30
Due to the adoption of EITF 02-3, modeling and other valuation techniques
are not used significantly in determining the fair value of our derivatives.
Such techniques were primarily used in previous years for valuing non-derivative
contracts, which are no longer reported at fair value, such as transportation,
storage, full requirements, load serving, transmission and power tolling
contracts (see Note 1 of Notes to Consolidated Financial Statements).
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 December 31, 2003, we held collateral
support of $342 million.
We also enter into netting agreements to mitigate counterparty performance
and credit risk. In 2002 and 2003, we closed out various trading positions.
During 2003, we did not incur any significant losses due to recent counterparty
bankruptcy filings.
The gross credit exposure from our derivative contracts as of December 31,
2003 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(a) TOTAL
- ----------------------------------------------------------------------------------- ---------- --------
(MILLIONS)
Gas and electric utilities......................................................... $ 988.2 $1,045.9
Energy marketers and traders....................................................... 1,317.2 3,118.5
Financial Institutions............................................................. 918.5 918.5
Other.............................................................................. 609.8 619.3
--------- --------
$ 3,833.7 5,702.2
=========
Credit reserves.................................................................... (39.8)
--------
Gross credit exposure from derivatives(b).......................................... $5,662.4
========
We assess our credit exposure on a net basis. The net credit exposure from
our derivatives as of December 31, 2003 is summarized below.
INVESTMENT
COUNTERPARTY TYPE GRADE(a) TOTAL
- ----------------------------------------------------------------------------------- ---------- --------
(MILLIONS)
Gas and electric utilities...................................................... $ 606.1 $ 629.4
Energy marketers and traders.................................................... 52.1 376.3
Financial Institutions.......................................................... 160.4 160.4
Other........................................................................... -- .2
--------- --------
$ 818.6 1,166.3
=========
Credit reserves................................................................. (39.8)
--------
Net credit exposure from derivatives(b)......................................... $1,126.5
========
(a) We determine investment grade primarily using publicly available credit
ratings. We included counterparties with a minimum Standard & Poor's
rating of BBB -- or Moody's Investors Service rating of Baa3 in
investment grade. We also classify counterparties that have provided
sufficient collateral, such as cash, standby letters of credit,
adequate parent company guarantees, and property interests, as
investment grade.
(b) One counterparty within the California power market represents more
than ten percent of the derivative assets and is included in investment
grade. Standard & Poor's and Moody's Investors Service do not currently
rate this counterparty. We included this counterparty in the investment
grade column based upon contractual credit requirements in the event of
assignment or substitution of a new obligation for the existing one.
99.2-31
FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY
Overview of 2003
Entering 2003, we faced significant liquidity challenges with sizeable
maturing debt obligations and limited financial flexibility due in part to
covenants arising from 2002 short-term financings. Our plan to address these
issues, announced in February 2003, required immediate execution of significant
levels of asset sales to meet maturing obligations in excess of $1 billion by
mid-year.
Through June 30, we were successful in generating approximately $2.4
billion of net proceeds from the sale of assets. With sufficient liquidity in
hand, we prepaid the RMT Note totaling $1.15 billion. During the same period, we
enhanced overall liquidity through the following actions:
- obtained a new $800 million revolving and letter of credit
facility that is collateralized by cash and/or government
securities, but allows operation with minimal covenants, none
of which contain financial ratios;
- issued $800 million of 8.625 percent senior unsecured notes
due 2010, which provided added liquidity in advance of
remaining asset sales and flexibility to use funds to retire
the $1.4 billion senior unsecured 9.25 percent notes maturing
in March 2004;
- redeemed the $275 million 9.875 percent cumulative-convertible
preferred shares through the issuance of $300 million of 5.5
percent junior subordinated convertible debentures;
- through our RMT subsidiary, obtained a new $500 million term
loan at market rates and collateralized by RMT assets, the
proceeds of which were used together with other funds to repay
the RMT Note; and
- through our Northwest Pipeline subsidiary, issued $175 million
of 8.125 percent senior unsecured notes due 2010, which
enabled Northwest Pipeline to fund capital expenditures
without borrowing cash from our parent company.
During the fourth quarter of 2003, we continued the execution of our plan
to reduce debt with available funds by tendering for and retiring debt of nearly
$1 billion. Of this total, $721 million was comprised of the 9.25 percent notes
due March 2004, leaving $679 million outstanding.
During 2003, we generated net cash proceeds from asset sales of
approximately $3.0 billion. We expect to realize approximately $800 million from
additional asset sales in 2004. The remaining expected asset sales include our
Alaska refinery and related operations, which are currently under contract for
sale, and certain Midstream assets. Our 2003 cash flow from operations of $770
million funded a large portion of our capital spending requirements for the
year. At December 31, 2003, we have available unrestricted cash on hand of
approximately $2.3 billion.
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 December 31, 2003, we have the following sources of liquidity:
- Cash-equivalent investments at the corporate level of $2.2
billion as compared to $1.3 billion at December 31, 2002.
- Cash and cash-equivalent investments of various international
and domestic entities of $91 million, as compared to $352
million at December 31, 2002.
At December 31, 2003, we have capacity of $447 million available under our
current revolving and letter of credit facility. In June 2003, we entered into
this revolving and letter of credit facility which is used primarily for issuing
letters of credit and must be collateralized at 105 percent of the level
utilized (see Note 11 of Notes to Consolidated Financial Statements). As
discussed below in the Outlook for 2004 section, we intend to replace this
facility in 2004 with facilities that do not require cash collateralization. In
contrast, at December 31, 2002 we had a combined $466 million available under
the previous revolver and letter of credit facilities.
99.2-32
In addition to these sources of liquidity described above, we have an
effective shelf registration statement with the Securities and Exchange
Commission that authorizes us to issue an additional $2.2 billion of a variety
of debt and equity securities. However, the ability to utilize this shelf
registration for debt securities is restricted by certain covenants associated
with our $800 million 8.625 percent senior unsecured notes (see Note 11 of Notes
to Consolidated Financial Statements).
In addition, our wholly owned subsidiaries Northwest Pipeline and Transco
have outstanding registration statements filed with the Securities and Exchange
Commission. As of December 31, 2003, 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. On March 4, 2003, Northwest Pipeline completed an
offering of $175 million of 8.125 percent senior notes due 2010. These notes
contain covenants similar to those of the $800 million 8.625 percent senior
unsecured notes discussed above. The $350 million of shelf availability
mentioned above was not utilized for this offering.
During 2003, we supplied liquidity needs with:
- Cash generated from the sale of assets -- In 2003, we
generated approximately $3.0 billion in net proceeds from
asset sales and expect to realize approximately $800 million
from additional asset sales in 2004.
- Cash generated from operations -- In 2003, we generated $607.9
million in cash flow from continuing operations and expect to
generate $1.0 to $1.3 billion in 2004.
We estimate approximately $700 million to $800 million for 2004 capital
and investment expenditures. 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.
Outlook for 2004
In 2004, we expect to make significant additional progress towards debt
reduction while maintaining appropriate levels of cash and other forms of
liquidity. To manage our operations and meet unforeseen or extraordinary calls
on cash, we expect to maintain cash and/or liquidity levels of at least $1
billion. While access to the capital markets continues to improve, one of our
indentures has a covenant that restricts 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. The covenant does not
prohibit us from replacing our existing revolving and letter of credit facility
with new facilities. Several of our indentures contain covenants restricting our
ability to grant liens securing debt, but such covenants all contain significant
exceptions allowing us to incur secured debt without granting similar liens to
the holders of notes under those indentures. In determining the appropriate
level of liquidity, we have considered the potential impact of significant
swings in commodity prices, contract margin requirements, unplanned calls on
capital spending and the need for a reserve for near term scheduled debt
payments.
During 2004, we expect to reduce long term debt, including scheduled
maturities of approximately $936 million, based on the following assumptions:
- generation of approximately $800 million from additional asset
sales,
- generation of cash flow from operations by our businesses in
excess of capital spending levels,
- replacement of our revolving and letter of credit facility
with facilities that do not require cash collateralization,
and
- utilization of available cash on hand in excess of minimum
liquidity levels.
Successful execution of this plan does not require us to incur new debt.
99.2-33
Potential risks associated with achieving this objective include:
- Lower than expected levels of cash flow from operations.
To mitigate this exposure, Exploration & Production has
hedged the price of natural gas for approximately 80
percent of its expected 2004 production. Power estimates
that it has hedged revenues, of varying degrees of
certainty, covering approximately 98 percent of its
fixed demand obligations through 2010.
- Delays in asset sales or lower than expected proceeds.
Approximately one-third of the remaining asset sales are
currently under contract and expected to close during
the first quarter. If these sales do not close, we will
not be precluded from meeting our operating commitments.
- Sensitivity of margin requirements associated with our
marginable commodity contracts.
As of February 2004, we estimate our exposure to
additional margin requirements over the next 360 days to
be as much as $350 million.
- Exposure associated with our efforts to resolve regulatory and
litigation issues arising from the Power business and the
ongoing defense of certain shareholder litigation (see Note 16
of Notes to Consolidated Financial Statements).
- Ability to replace our revolver and letter of credit facility
on satisfactory terms.
Based on our available cash on hand and expected cash flows from
operations, we believe we have, or have access to, the financial resources and
liquidity necessary to meet future cash requirements and maintain a sufficient
level of liquidity to reasonably protect against unforeseen circumstances
requiring the use of funds.
Credit ratings
During 2002, our credit ratings were downgraded to below investment grade
and remained below investment grade throughout 2003. As a result, Power's
participation in energy risk management and trading activities requires
alternate credit support under certain agreements. In addition, we are required
to fund margin requirements pursuant to industry standard derivative agreements
with cash, letters of credit or other negotiable instruments. Currently, we are
effectively required to post margins of 100 percent or more on forward contracts
in a loss position. Future liquidity requirements relating to these instruments
will be based on changes in their value resulting from changes in factors such
as price and volatility.
As part of the plan announced in February of 2003, we established a goal
of returning to investment grade status. While reduction of debt is viewed as a
key contributor towards this goal, certain of the key credit rating agencies
have imputed the financial commitments associated with our long-term tolling
agreements within the Power business as debt. If we are unable to achieve our
goal of exiting the Power business and/or the elimination of these commitments,
receiving an investment grade rating may be further delayed.
Off-balance sheet financing arrangements and guarantees of debt or other
commitments to third parties
At December 31, 2001, we had operating lease agreements with special
purpose entities (SPE's) relating to certain of our travel center stores
(included in discontinued operations), offshore oil and gas pipelines and an
onshore gas processing plant. As a result of changes to the leases in
conjunction with the secured financing facilities completed in July 2002, they
no longer qualified for operating lease treatment. The operating leases for the
offshore oil and gas pipelines and onshore gas processing plant were recorded as
capital leases within long-term debt at that time and were repaid in May 2003.
The travel center lease was reported in liabilities of discontinued operations
and was repaid in March 2003 pursuant to the travel centers sale.
We had agreements to sell, on an ongoing basis, certain of our accounts
receivable to qualified special-purpose entities. On July 25, 2002, these
agreements expired and were not renewed.
In May 2002, we provided a guarantee of approximately $127 million towards
project financing of energy assets owned and operated by Discovery Producer
Services LLC (Discovery) in which we own a 50 percent interest. This obligation
was not consolidated in our balance sheet as we account for our interest under
the equity method of accounting. The guarantee was scheduled to expire at the
end of 2003. However, in December 2003, we made an additional $127 million
investment in Discovery which was
99.2-34
used to fully repay maturing debt satisfying the guarantee obligation. All
owners contributed amounts equal to their ownership percentage. (See the
Investing Activities section for discussion of additional investment).
We have provided guarantees in the event of nonpayment by WilTel on
certain of its lease performance obligations that extend through 2042 and have a
maximum potential exposure of approximately $51 million and $53 million at
December 31, 2003 and 2002, respectively. Our exposure declines systematically
throughout the remaining lease terms. The recorded carrying value of these
guarantees was $46 million and $48 million at December 31, 2003 and 2002
respectively.
In addition to these guarantees, we have issued guarantees and other
similar arrangements with off-balance sheet risk as discussed under Guarantees
in Note 15 of Notes to Consolidated Financial Statements.
OPERATING ACTIVITIES
The increase in cash flow from operations from 2002 levels is primarily
due to the following:
- improvement in Income (loss) from continuing operations by
$625.3 million,
- the absence of $753.9 million in payment of guarantees and
payment obligations related to WilTel,
- the reduction of margin funding requirements of $885.6
million, and
- the increase in cash flow due to changes in accounts and notes
receivable of $425 million.
The increase in Income (loss) from continuing operations is reflective of
the overall improvement in the performance of our operating units. However, the
noted improvement in Income (loss) from continuing operations had a lesser
impact on cash flow from operations because Income (loss) from continuing
operations in 2002 included higher non-cash expenses of $167.2 million for
losses on property and other assets and the $268.7 million provision for
uncollectible accounts from WilTel. The improvement in margin funding
requirements is a result of our decreased activity in the Power business. We
expect a continued decrease in margin funding requirements in 2004 as we
continue to manage our current positions to reduce risk and exit other
positions, which reduces our overall activity. The increase in operating cash
flow related to decreased accounts receivable is a reflection of the continued
decrease in activity in the Power business in 2003. Cash flow from operations
for 2004 is expected to be sufficient to fund the projected 2004 capital
expenditures of $700 million to $800 million.
In March 2002, WilTel exercised its option to purchase certain network
assets under the ADP transaction for which we had previously provided a
guarantee. On March 29, 2002, as guarantor under the agreement, we paid $753.9
million related to WilTel's purchase of these network assets. In 2002, we
recorded in continuing operations additional pre-tax charges of $268.7 million
related to the settlement of these receivables and claims. In 2001, we had
recorded a $188 million charge related to estimated recovery of amounts from
WilTel (see Note 2 of Notes to Consolidated Financial Statements).
The increase in net income and other increases in cash flows from
operations were offset by:
- a $929.5 million decrease in derivative and energy risk
management and trading net assets and liabilities; and
- a $265.0 million payment on deferred set-up fee and fixed rate
interest on the RMT note payable.
The decrease in funds associated with derivative and energy risk
management and trading assets and liabilities during 2003 is a result of the
decline in the activity of the Power business. As we continue to reduce our
activity in the Power business, the cash requirements tied to working capital
and margin deposits will continue to decrease.
During 2003, we recorded approximately $231.9 million in provisions for
losses on property and other assets and a net gain on disposition of assets of
$142.8 million (see Notes 3 and 4 of Notes to Consolidated Financial
Statements).
The accrual for fixed rate interest included in the RMT Note on the
Consolidated Statement of Cash Flows represents 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 (see Note 11 of Notes to Consolidated Financial Statements).
99.2-35
FINANCING ACTIVITIES
During 2003, we made significant progress in executing our business plan.
We retired $3.2 billion in debt, redeemed $275 million in preferred stock, and
issued $2 billion in debt at more favorable market rates. In 2004, we plan to
further reduce debt with funding from (1) available cash on hand, (2) cash from
asset sales, (3) operating cash flow after capital expenditures, and (4) the
release of cash currently used as collateral. As discussed in the Outlook
section, we plan to replace our existing revolver and letter of credit facility
with new credit facilities that do not require cash collateralization.
Significant borrowings and repayments during 2003 included the following:
- On March 4, our Northwest Pipeline subsidiary completed an
offering of $175 million of 8.125 percent senior notes due
2010. Proceeds from the issuance were used for general
corporate purposes, including the funding of capital
expenditures.
- On May 28, we issued $300 million of 5.5 percent junior
subordinated convertible debentures due 2033. The proceeds
were used to redeem all of the outstanding 9.875 percent
cumulative-convertible preferred shares (see Note 13 of Notes
to Consolidated Financial Statements).
- In May, we repaid the RMT note payable of Williams Production
RMT Company totaling $1.15 billion, which included certain
contractual fees and deferred interest.
- On May 30, a subsidiary in our Exploration & Production
segment entered into a $500 million secured note due May 30,
2007, at a floating interest rate of LIBOR plus 3.75 percent.
This loan refinances a portion of the RMT Note discussed
above. On February 25, 2004 we completed an amendment that
provided more favorable terms including a lower interest rate
and an extension of the maturity by one year (see Note 11 of
Notes to Consolidated Financial Statements).
- On June 6, we entered into a two-year $800 million revolving
and letter of credit facility, primarily for the purpose of
issuing letters of credit. Along with our subsidiaries
Northwest Pipeline and Transco, we have access to all
unborrowed amounts under the facility. The facility must be
secured by cash and/or acceptable government securities with a
market value of at least 105 percent of the then outstanding
aggregate amount available for drawing under all letters of
credit, plus the aggregate amount of all loans then
outstanding.
- On June 10, we issued $800 million of 8.625 percent senior
unsecured notes due 2010. The notes were issued under our $3
billion shelf registration statement. See Note 11 of Notes to
Consolidated Financial Statements for a description of the
terms and covenants related to this issuance. The proceeds
were used to improve corporate liquidity, general corporate
purposes, and payment of maturing debt obligations.
- On June 10, we also redeemed all the outstanding 9.875 percent
cumulative-convertible preferred shares for approximately $289
million, plus $5.3 million for accrued dividends.
- On October 8, we announced a cash tender offer for any and all
of our $1.4 billion senior unsecured 9.25 percent notes due in
March 2004, as well as cash tender offers and consent
solicitations for approximately $241 million of additional
notes and debentures. At the expiration of the offers, we
received tenders of debt securities with an aggregate
principal amount of approximately $951 million. In conjunction
with the tendered notes and related consents, we paid premiums
of approximately $58 million. The premiums, as well as related
fees and expenses, together totaling $66.8 million, were
recorded in fourth-quarter 2003 as a pre-tax charge to
earnings.
- In October, our PIGAP high-pressure gas compression project in
Venezuela obtained $230 million in non-recourse financing. We
own a 70 percent interest in the project and, therefore, the
debt is reflected on our Consolidated Balance Sheet ($22
million in current portion of long-term debt, $208 million in
long-term debt). Proceeds from the loan were used to repay us
for notes due and the other owner for a portion of the initial
funding of construction-related costs. Upon the execution of
the loan, the project made additional cash distributions to
the owners based on their respective ownership interests. We
received approximately $183 million in cash proceeds, net of
amounts paid relating to an up front premium, the purchase of
an interest rate lock and cash used to fund a debt service
reserve.
For a discussion of other borrowings and repayments in 2003, see Note 11
of Notes to Consolidated Financial Statements.
99.2-36
In 2002, notes payable payments were $1.1 billion net of notes payable
proceeds while long-term debt proceeds was $945.3 million net of long term debt
payments. Significant borrowings and repayments in 2002 included the following:
- On January 14, we completed the sale of 44 million publicly
traded units, commonly known as FELINE PACS, that include a
senior debt security and an equity purchase contract, for net
proceeds of approximately $1.1 billion (see Note 13 of Notes
to Consolidated Financial Statements).
- On March 19, we issued $850 million of 30-year notes with an
interest rate of 8.75 percent and $650 million of 10-year
notes with an interest rate of 8.125 percent. The proceeds
were used to repay approximately $1.4 billion outstanding
commercial paper, provide working capital and for general
corporate purposes.
- In May, Power entered into an agreement which transferred the
rights to certain receivables, along with risks associated
with that collection, in exchange for cash. Due to the
structure of the agreement, Power accounted for this
transaction as debt collateralized by the claims. The $79
million of debt at December 31, 2003 and 2002 is classified as
current on the Consolidated Balance Sheet. The debt is
classified as current because if at any time the value of the
underlying receivables decreases or becomes questionable, the
liability will be required to be paid.
- RMT entered into a $900 million credit agreement dated as of
July 31, 2002. As discussed previously, this amount was repaid
in May 2003.
Dividends paid on common stock are currently $.01 per common share on a
quarterly basis and totaled $20.8 million for the year ended December 31, 2003.
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 (see Note 11 of Notes to
Consolidated Financial Statements). In 2003, we also paid $32.6 million in
accrued dividends on the 9.875 percent cumulative-convertible preferred shares
that were redeemed in June 2003. The $32.6 million of deferred dividends paid
includes the 2003 payment of $6.8 million in dividends accrued at December 31,
2002. The $29.5 million of preferred stock dividends reported on the
Consolidated Statement of Operations also includes $3.7 million of issuance
costs.
In December 2001, we received net proceeds of $95.3 million from the sale
of a non-controlling preferred interest in Piceance Production Holdings LLC
(Piceance) to an outside investor. During 2000, we received net proceeds
totaling $546.8 million from the sale of a preferred return interest in Snow
Goose Associates, L.L.C. (Snow Goose) to an outside investor (see Note 12 of
Notes to Consolidated Financial Statements). During 2002, changes to these
limited liability company member interests and interests in Castle Associates
L.P. (Castle) required classification of these outside investor interests as
debt. The changes to the Snow Goose structure also included the repayment of the
investor's preferred interest in installments. During 2002, approximately $558
million was repaid related to these interests and is included in the payments of
long-term debt. During 2003, the remaining balances associated with the above
interests were paid. Approximately $323 million of payments were made and are
included in payments of long-term debt for 2003 (see Note 12 of Notes to
Consolidated Financial Statements.)
In third-quarter 2002, the downgrade of our senior unsecured rating below
BB by Standard & Poor's, and Ba1 by Moody's Investors Service, resulted in the
early retirement of an outside investor's preferred ownership interest for $135
million (see Note 12 of Notes to Consolidated Financial Statements).
In December 1999, we formed Williams Capital Trust I, which issued $175
million in our zero-coupon obligated, mandatorily-redeemable preferred
securities. In April 2001, we redeemed our obligated, mandatorily-redeemable
preferred securities for $194 million. We used proceeds from the sale of the
Ferrellgas senior common units for this redemption.
Long-term debt, including debt due within one year was $12.0 billion at
December 31, 2003 compared to $12.2 billion at December 31, 2002.
99.2-37
Significant items reflected as discontinued operations within financing
activities in the Consolidated Statement of Cash Flows, including the cash
provided by financing activities, included the following items:
2002
- Proceeds from long-term debt of Williams Energy Partners LP
related to financing entered into in 2002 of $489 million.
- Net proceeds from issuance of common units by Williams Energy
Partners LP in 2002 of $279 million.
2001
- Proceeds from issuance of $1.4 billion of WCG Note Trust Notes
for which we provided indirect credit support. WilTel retained
all of the proceeds from this issuance (see Note 2 of Notes to
Consolidated Financial Statements).
INVESTING ACTIVITIES
Capital expenditures by segment are presented below.
CAPITAL EXPENDITURES
SEGMENT 2003 2002 2001
- ------------------------------------------------------------------------ -------- --------- --------
(MILLIONS)
Power................................................................... $ 1.0 $ 135.8 $ 103.7
Gas Pipeline............................................................ 497.6 672.0 535.5
E&P..................................................................... 202.0 364.1 202.6
Midstream............................................................... 252.9 432.8 554.9
Other................................................................... 2.5 57.3 60.4
-------- --------- ---------
TOTAL............................................................. $ 956.0 $ 1,662.0 $ 1,457.1
======== ========= =========
- Power made capital expenditures in 2002 and 2001 primarily to
purchase power-generating turbines.
- Gas Pipeline made capital expenditures in 2001 through 2003
primarily to expand deliverability into the east and west
coast markets. Planned expenditures for 2004 are primarily for
pipeline maintenance.
- Exploration & Production made capital expenditures in 2001
through 2003 primarily for continued development of our
natural gas reserves through the drilling of wells. Planned
expenditures for 2004 are expected to be for similar
activities.
- Midstream made capital expenditures in 2001 through 2003
primarily to acquire, expand, develop and modernize gathering
and processing facilities and terminals. Included in capital
expenditures are the following amounts related to the
deepwater project: 2003 -- $189 million; 2002 -- $343 million;
and 2001 -- $136 million. Planned expenditures for 2004 are
expected to be for similar activities.
The acquisition of businesses in 2001 reflects our June 11, 2001,
acquisition of 50 percent of Barrett's outstanding common stock in a cash tender
offer of $73 per share for a total of approximately $1.2 billion. On August 2,
2001, we completed the acquisition of Barrett by issuing 29.6 million shares of
our common stock in exchange for the remaining Barrett shares.
Purchase of investments/advances to affiliates in 2003 consists primarily
of $127 million of additional investment by Midstream in Discovery. The cash
investment was used by Discovery to pay maturing debt (see Note 3 of Notes to
Consolidated Financial Statements). Purchases in 2002 include approximately $234
million towards the development of the Gulfstream joint venture project, one of
our equity method investments. In 2001, we contributed $437 million toward the
development of our joint interest in the Gulfstream project.
In 2003, we purchased $739.9 million of restricted investments comprised
of U.S. Treasury notes. We sold $10 million of these notes and retired $341.8
million on their scheduled maturity date. We made these purchases and sales to
satisfy the 105 percent cash collateralization covenant in the $800 million
revolving credit facility (see Note 11 of Notes to Consolidated Financial
Statements).
99.2-38
In 2003 and 2002, we realized significant cash proceeds from asset
dispositions, the sales of businesses, and the disposition of investments as
part of our overall plan to increase liquidity and reduce debt. The following
sales provided significant proceeds from sales and include various adjustments
subsequent to the actual date of sale:
In 2003:
- $803 million related to the sale of Texas Gas Transmission
Corporation;
- $465 million related to the sale of certain natural gas
exploration and production properties in Kansas, Colorado, New
Mexico and Utah;
- $452 million related to the sale of the Midsouth refinery;
- $455 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;
- $246 million related to the sale of certain natural gas
liquids assets in Redwater, Alberta, Canada; and
- $188 million related to the sale of the Williams travel
centers.
In 2002:
- $1.15 billion related to the sale of Mid-American and Seminole
Pipeline;
- $464 million related to the sale of Kern River;
- $380 million related to the sale of Central;
- $326 million related to the sale of properties in the Jonah
Field and the Anadarko Basin;
- $229 million related to the sale of the Cove Point LNG
facility; and
- $173 million related to the sale of our interest in Alliance
Pipeline.
Proceeds received from disposition of investments and other assets in 2001
reflect our sale of the Ferrellgas senior common units to an affiliate of
Ferrellgas for proceeds of $199 million in April 2001 and our sale of certain
convenience stores for approximately $150 million in May 2001.
We received $180 million in cash proceeds from the sale of notes
receivable from WilTel to Leucadia in fourth-quarter 2002. See Note 2 of Notes
to Consolidated Financial Statements for further discussion of WilTel items and
amounts.
In 2001, Purchase of assets subsequently leased to seller reflects our
purchase of the Williams Technology Center, other ancillary assets and three
corporate aircraft for $276 million. These assets were sold to WilTel in 2002.
Significant items reflected as discontinued operations within investing
activities on the Consolidated Statement of Cash Flows include the following:
- capital expenditures and purchases of investments by WilTel,
totaling $1.5 billion in 2001;
- capital expenditures of Kern River, primarily for expansion of
its interstate natural gas pipeline system, of $134 million in
2001; and
- capital expenditures of Texas Gas, primarily for expansion of
its interstate natural gas pipeline system, of $41.9 million
and $106.2 million in 2002 and 2001, respectively.
99.2-39
CONTRACTUAL OBLIGATIONS
The table below summarizes the maturity dates of our contractual
obligations by period.
2005- 2007-
2004 2006 2008 THEREAFTER TOTAL
------- ------- ------- ---------- -------
(MILLIONS)
Notes payable ......................................... $ 3 $ - $ - $ - $ 3
Long-term debt, including current portion:
Principal ........................................... 933 1,219 2,405(1) 7,448 12,005
Interest ............................................ 856 1,548 1,253 6,449 10,106
Capital leases ........................................ - - - - -
Operating leases(2) ................................... 57 69 44 68 238
Purchase obligations:
Fuel conversion and other service contracts(3) ...... 391 797 814 4,669 6,671
Other ............................................... 807(4) 412 226 387(5) 1,832
Other long-term liabilities, including current portion:
Physical & financial derivatives:(6) ................ 1,844 1,048 381 623 3,896
Other ............................................... 33 97 35 30 195
------- ------- ------- ------- -------
Total ................................................. $ 4,924 $ 5,190 $ 5,158 $19,674 $34,946
======= ======= ======= ======= =======
- ----------
(1) Includes $1.1 billion of 6.5 percent notes payable in 2007 which are
subject to remarketing in 2004 (FELINE PACS). These FELINE PACS include
equity forward contracts attached which require the holder to purchase
shares of our common stock in 2005. If the 2004 remarketing is
unsuccessful and a second remarketing in 2005 is also unsuccessful, then
we could exercise our right to foreclose on the notes in order to satisfy
the obligation of the holders of the equity forward contracts requiring
the holder to purchase our common stock. This would be a non-cash
transaction.
(2) Total operating lease payments include $26 million related to discontinued
operations.
(3) Power has entered into certain contracts giving us the right to receive
fuel conversion services as well as certain other services associated with
electric generation facilities that are currently in operation throughout
the continental United States.
(4) Includes $385 million for a crude purchase contract with the state of
Alaska which expires in September 2004. It is anticipated that the
expected sale of the Alaska refinery in the first quarter of 2004 will
result in the cancellation of our obligations under this contract.
(5) Includes one year of annual payments totaling $3 million for contracts
with indefinite termination dates.
(6) Although the amounts presented represent expected cash outflows, a portion
of those obligations have previously been paid in accordance with third
party margining agreements. As of December 31, 2003, we have paid $571
million in margins, adequate assurance, and prepays related to the
obligations included in this disclosure. In addition, expected offsetting
cash inflows resulting from product sales or net positive settlements are
not reflected in these amounts. The offsetting expected cash inflows as of
December 31, 2003 are $5.8 billion. In addition, the obligations for
physical and financial derivatives are based on market information as of
December 31, 2003. Because market information changes daily and has the
potential to be volatile, significant changes to the values in this
category may occur.
EFFECTS OF INFLATION
Our cost increases in recent years have benefited from relatively low
inflation rates during that time. Approximately 50 percent of our gross
property, plant and equipment is at Gas Pipeline and approximately 50 percent is
at other operating units. Gas Pipeline is subject to regulation, which limits
recovery to historical cost. While amounts in excess of historical cost are not
recoverable under current FERC practices, we anticipate being allowed to recover
and earn a return based on increased actual cost incurred to replace existing
assets. Cost based regulation, along with competition and other market factors,
may limit our ability to recover such increased costs. For the other operating
units, operating costs are influenced to a greater extent by specific price
changes in oil and natural gas and related commodities than by changes in
general inflation. Crude, refined product, natural gas, natural gas liquids and
power prices are particularly sensitive to OPEC production levels and/or the
market perceptions concerning the supply and demand balance in the near future.
99.2-40
ENVIRONMENTAL
We are a participant in certain environmental activities in various stages
involving assessment studies, cleanup operations and/or remedial processes at
certain sites, some of which we currently do not own (see Note 16 of Notes to
Consolidated Financial Statements). We are monitoring these sites in a
coordinated effort with other potentially responsible parties, the U.S.
Environmental Protection Agency (EPA), or other governmental authorities. We are
jointly and severally liable along with unrelated third parties in some of these
activities and solely responsible in others. Current estimates of the most
likely costs of such cleanup activities are approximately $74 million, all of
which is accrued at December 31, 2003. We expect to seek recovery of
approximately $28 million of the accrued costs through future natural gas
transmission rates. The remainder of these costs will be funded from operations.
During 2003, we paid approximately $18 million for cleanup and/or remediation
and monitoring activities. We expect to pay approximately $24 million in 2004
for these activities. Estimates of the most likely costs of cleanup are
generally based on completed assessment studies, preliminary results of studies
or our experience with other similar cleanup operations. At December 31, 2003,
certain assessment studies were still in process for which the ultimate outcome
may yield significantly different estimates of most likely costs. Therefore, the
actual costs incurred will depend on the final amount, type and extent of
contamination discovered at these sites, the final cleanup standards mandated by
the EPA or other governmental authorities, and other factors.
We are subject to the federal Clean Air Act and to the federal Clean Air
Act Amendments of 1990 which require the EPA to issue new regulations. We are
also subject to regulation at the state and local level. In September 1998, the
EPA promulgated rules designed to mitigate the migration of ground-level ozone
in certain states. We anticipate that during 2004, the EPA will promulgate
additional rules regarding hazardous air pollutants. We estimate that capital
expenditures necessary to install emission control devices on our Transco system
over the next five years to comply with rules will be between $230 million and
$260 million. The actual costs incurred will depend on the final implementation
plans developed by each state to comply with these regulations. We consider
these costs on our Transco system associated with compliance with these
environmental laws and regulations to be prudent costs incurred in the ordinary
course of business and, therefore, recoverable through its rates.
In December 1999, standards promulgated by the EPA for tailpipe emissions
and the content of sulfur in gasoline were announced. Our estimation is that
capital expenditures necessary to bring our refinery into compliance over the
next five years will be approximately $50 million. We anticipate that, if the
sale of the refinery is completed (see Note 2 of Notes to Consolidated Financial
Statements), the purchaser would be responsible for these compliance
expenditures. The actual costs incurred will depend on the final implementation
plans.
On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from our pipelines,
pipeline systems, and pipeline facilities used in the movement of oil or
petroleum products, during the period July 1, 1998 through July 2, 2001. In
November 2001, we furnished our response. This matter has not become an
enforcement proceeding. On March 11, 2004, the Department of Justice (DOJ)
invited the new owner of the pipeline to enter into negotiations regarding
alleged violations of the Clean Water Act and to sign a tolling agreement. No
penalty has been assessed by the EPA; however, the DOJ stated in its letter that
the maximum possible penalties were approximately $22 million for the alleged
violations. It is anticipated that by providing additional clarification and
through negotiations with the EPA and DOJ, that any proposed penalty will be
reduced. We have indemnity obligations to the new owner related to this matter.
99.2-41