UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 4, 2005
The Williams Companies, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 1-4174 | 73-0569878 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(I.R.S. Employer Identification No.) |
| One Williams Center, Tulsa, Oklahoma | 74172 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: 918/573-2000
Not Applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy
the filing obligation of the registrant under any of the following provisions:
| o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240-14a-12) |
| o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02. Results of Operations and Financial Condition.
On August 4, 2005, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press
release announcing its financial results for the quarter ended June 30, 2005. A copy of the press
release and its accompanying reconciliation schedules are furnished as a part of this current
report on Form 8-K as Exhibit 99.1 and is incorporated herein in its entirety by reference.
The press release and accompanying reconciliation schedules are being furnished pursuant to
Item 2.02, Results of Operations and Financial Condition. The information furnished is not deemed
“filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not
subject to the liabilities of that section and is not deemed incorporated by reference in any
filing under the Securities Act of 1933, as amended.
Item 8.01. Other Events.
Williams wishes to disclose for Regulation FD purposes its slide presentation, furnished
herewith as Exhibit 99.2, to be utilized during a public conference call and webcast on the morning
of August 4, 2005.
On August 4, 2005, Williams also issued a press release announcing that it has increased the
company’s total proved, probable and possible domestic reserves to an estimated 8.5 trillion cubic
feet equivalent (“Tcfe”) – an increase of 21 percent from the previous estimate of 7 Tcfe. A copy
of the press release is furnished as a part of this current report on Form 8-K as Exhibit 99.3.
The slide presentation and press release are being furnished pursuant to Item 8.01, Other
Events. The information furnished is not deemed “filed” for purposes of Section 18 of the
Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and
is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.
Item 9.01. Financial Statements and Exhibits.
| (a) | None | ||
| (b) | None | ||
| (c) | Exhibits |
Exhibit 99.1
|
Copy of Williams’ press release dated August 4, 2005, publicly announcing its second quarter 2005 financial results. | |
Exhibit 99.2
|
Copy of Williams’ slide presentation to be utilized during the August 4, 2005, public conference call and webcast. | |
Exhibit 99.3
|
Copy of Williams’ press release dated August 4, 2005, publicly announcing its increase in domestic reserves. |
Pursuant to the requirements of the Securities Exchange Act of 1934, Williams has duly caused
this report to be signed on its behalf by the undersigned hereunto duly authorized.
2
| THE WILLIAMS COMPANIES, INC. |
||||
| Date: August 4, 2005 | /s/ Donald R. Chappel | |||
| Name: | Donald R. Chappel | |||
| Title: | Senior Vice President and Chief Financial Officer | |||
3
INDEX TO EXHIBITS
| EXHIBIT | ||
| NUMBER | DESCRIPTION | |
Exhibit 99.1
|
Copy of Williams’ press release dated August 4, 2005, publicly announcing its second quarter 2005 financial results. | |
Exhibit 99.2
|
Copy of Williams’ slide presentation to be utilized during the August 4, 2005, public conference call and webcast. | |
Exhibit 99.3
|
Copy of Williams’ press release dated August 4, 2005, publicly announcing its increase in domestic reserves. |
4
EXHIBIT 99.1
|
 |
NYSE: WMB
Date: Aug. 4, 2005
Date: Aug. 4, 2005
Williams Reports Second-Quarter 2005 Financial Results
| • | E&P Segment Profit Increases More Than 100% for Quarter and 6-Months | |
| • | Natural Gas Production Climbs 20% During First Half of Year | |
| • | NGL Sales Volumes Increase 12% for 6-Month Period | |
| • | Quarter Produces $488.9 Million in Net Cash From Operations | |
| • | Business Growth Opportunities Continue to Increase |
Summary Financial Information
| 2Q 2005 | 2Q 2004 | ||||||||||||||||
| millions | per share | millions | per share | ||||||||||||||
Income (loss) from continuing operations |
$ | 40.7 | $ | 0.07 | $ | (18.5 | ) | $ | (0.03 | ) | |||||||
Income from discontinued operations |
0.6 | $ | 0.00 | 0.3 | $ | 0.00 | |||||||||||
Net income (loss) |
$ | 41.3 | $ | 0.07 | $ | (18.2 | ) | $ | (0.03 | ) | |||||||
Recurring income from continuing operations* |
$ | 65.9 | $ | 0.11 | $ | 53.7 | $ | 0.10 | |||||||||
After-tax mark-to-market adjustments |
33.6 | $ | 0.06 | (35.7 | ) | $ | (0.06 | ) | |||||||||
Recurring income from continuing operations
— after mark-to-market adjustment* |
$ | 99.5 | $ | 0.17 | $ | 18.0 | $ | 0.04 | |||||||||
| * | A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations and mark-to-market adjustments (non-GAAP measures) is available on Williams’ web site at www.williams.com and as an attachment to this press release. |
TULSA, Okla.
— Williams (NYSE:WMB) today announced second-quarter 2005 unaudited net
income of $41.3 million, or 7 cents per share on a diluted basis, compared with a net loss of $18.2
million, or a loss of 3 cents per share, for second-quarter 2004.
Year-to-date through June 30, Williams reported net income of $242.4 million, or 41 cents per
share on a diluted basis, compared with a loss of $8.3 million, or a loss of 2 cents per share, for
the first half of 2004.
For second-quarter 2005, the company reported income from continuing operations of $40.7
million, or 7 cents per share on a diluted basis, compared with a loss of $18.5 million, or a loss
of 3 cents per share, for second-quarter 2004 on a restated basis.
The improvement in continuing operations over last year’s quarter reflects the benefit of
increased levels of natural gas production and higher net realized average prices; the continuation
of favorable natural gas processing margins and higher gathering volumes; and lower interest
expense and debt-retirement costs.
Those factors were offset partially by a $47.7 million reduction in forward unrealized
mark-to-market gains and $38 million in higher impairments of a petroleum pipeline equity
investment.
For the first six months of 2005, Williams reported income from continuing operations of
$242.9 million, or 41 cents per share on a diluted basis, compared with a loss of $18.5 million, or
a loss of 4 cents per share, on a restated basis for the same period in 2004.
CEO Perspective
“Our businesses are producing the strong cash flows and improved profitability that we
expect,” said Steve
Malcolm, chairman, president and chief executive officer.
“We are especially delighted with the rapid volume growth we’re seeing in our natural gas
production business. Our total production is up 20 percent compared with the first half of last
year.
“And during the quarter, we raised our total estimated domestic reserves by 21 percent
following a careful study that added 1,600 new drilling locations in the Piceance valley.
“In E&P, we also entered the Fort Worth Basin and reduced our risk around natural gas prices
by executing additional hedges. Our entry into the new basin gives Williams another long-term,
value-creating growth opportunity,” Malcolm added.
“We’re also continuing to realize strong results in our gathering and processing business, as
well as solid performance in Gas Pipeline and performance as planned in Power.”
Recurring Results
Recurring income from continuing
operations — which excludes items of income or loss that the
company characterizes as unrepresentative of its ongoing operations — was $65.9 million, or 11
cents per share, for the second quarter of 2005.
In last year’s second quarter, Williams reported recurring income of $53.7 million, or 10
cents per share, on a restated basis.
The improvement in recurring income is primarily attributable to the benefit of increased
levels of natural gas production and higher net realized average prices for production sold; the
continuation of favorable natural gas processing margins and higher gathering volumes; and reduced
interest expense. The improvement was offset partially by lower forward unrealized mark-to-market
gains.
For the first half of this year, recurring income from continuing operations was $264.3
million, or 45 cents per share, compared with $57.7 million, or 11 cents per share, for the first
six months of 2004 on a restated basis.
Williams moved upward its expectation for 2005 recurring income from continuing operations to
a range of 62 cents to 82 cents per share. In early May, the company’s guidance for this measure
was 54 cents to 80 cents per share.
The increase in guidance principally resulted from a forecast of improved results in Midstream
and Exploration & Production, along with increased mark-to-market gains in Power for the first half
of the year.
A
reconciliation of the company’s income from continuing
operations — a generally accepted
accounting principles measure — to its recurring results accompanies this news release.
Recurring Results Adjusted for Effect of Mark-to-Market Accounting
To provide an added level of disclosure and transparency, Williams continues to provide an
analysis of recurring earnings adjusted for all mark-to-market effects. Williams introduced this
measure last year when it reported third-quarter results.
Recurring
income from continuing operations — after adjusting for the mark-to-market impact to
reflect income as though mark-to-market accounting had never been applied to Power’s designated
hedges and other derivatives — was $99.5 million, or 17 cents per share, for the second quarter of
2005. In last year’s second quarter, the adjusted recurring income was $18 million, or 4 cents per
share.
The improvement is primarily the result of increased natural gas production volumes; higher
net realized average prices; favorable natural gas liquids processing margins and volumes; and
lower interest expense.
For
the first six months of the year, recurring income from continuing operations — after
adjusting for the mark-to-market impact to reflect income as though mark-to-market accounting had
never been applied to Power’s designated hedges and other
derivatives — was $232 million, or 39
cents per share, compared with $90 million, or 17 cents per share, for the first six months of
2004.
Williams
has updated its expectation for 2005 recurring income from continuing operations — on
a basis adjusted for the impact of mark-to-market accounting. On that basis, the company now
expects 70 cents to 90 cents per share. The company’s prior guidance for that measure, issued early
in May, was 65 cents to 90 cents per share.
A reconciliation of the company’s income from continuing operations on a recurring basis to
its recurring results that have been adjusted for the effect of mark-to-market accounting
accompanies this news release.
Business Segment Performance
Williams’
primary businesses — Exploration & Production, Midstream Gas & Liquids, Gas Pipeline
and Power — reported combined segment profit of $316.9 million in the second quarter of 2005.
In the second quarter a year ago, these businesses reported combined segment profit of $318.4
million on a restated basis.
For the first half of 2005, the four major businesses reported combined segment profit of
$830.7 million compared with $595.4 million for the same period last year on a restated basis.
The improvement in segment profit for the first half of 2005 is
attributable primarily to increased natural gas production volumes and higher net realized average
prices; favorable natural gas liquids margins and increased sales volumes; higher natural gas
gathering volumes; and higher forward unrealized mark-to-market gains.
Williams continues to expect $1.3 billion to $1.585 billion in consolidated segment profit for
2005, as reported at the end of the first quarter. This guidance includes results for the Other
segment, which includes certain equity investments.
On a basis adjusted for the effect of mark-to-market accounting, the company continues to
expect $1.375 billion to $1.660 billion in segment profit, as reported at the end of the first
quarter. This guidance includes results for the Other segment, as noted above.
Exploration & Production: Volumes Up 20 Percent for First Half of Year
Exploration & Production, which includes natural gas production and development in the U.S.
Rocky Mountains, San Juan Basin and Midcontinent, and oil and gas development in South America,
reported second-quarter 2005 segment profit of $118.3 million.
In the second quarter a year ago, the business reported segment profit of $43.3 million. The
improvement reflects the benefit of significant increases in both production volumes and net
realized average prices for production sold.
For the first six months of 2005, Exploration & Production reported segment profit of $222.0
million compared with $94.8 million for the same period last year. The increase is primarily a
result of the same factors listed above.
Through June 30, average daily production from domestic and international interests was
approximately 633 million cubic feet of gas equivalent (MMcfe), compared with 528 MMcfe in the
first half of 2004 — an increase of approximately 20 percent.
Average daily production solely from domestic volumes for the second quarter of 2005 was 604
MMcfe. That was 18 percent higher than domestic volumes of 511 MMcfe from the same quarter a year
ago. Increased production primarily reflects higher volumes in the Piceance and San Juan basins.
Year-over-year, the business has benefited this year from higher domestic production prices.
Last year’s sales prices were affected by lower contracted hedged prices on a greater share of
production volumes. During the second quarter of 2005, Williams realized net domestic average
prices of $4.16 per thousand cubic feet equivalent (Mcfe) compared with $3.09 per Mcfe in the
second quarter a year ago — an increase of approximately 35 percent.
Earlier today, Williams announced that the company has raised its estimate of total proved,
probable and possible domestic reserves from 7 trillion cubic feet equivalent (Tcfe) to an
estimated 8.5 Tcfe — an increase of 21 percent.
The reserves addition was made following an internal review of potential well sites in the
Piceance Basin of western Colorado. Williams now projects 4,600 drilling locations in the Piceance
— an increase of approximately 50 percent compared with previous estimates of 3,000 locations. The
4,600 drilling locations are for operations solely in the valley area of the Piceance. The new
estimate does not include potential locations from other company projects in the Piceance Basin
such as Trail Ridge, Ryan Gulch and Red Point.
As previously announced, Williams continues to expect to drill approximately 300 wells in
the Piceance Basin this year; up to 450 wells in the Piceance in 2006; and up to 500 wells in the
Piceance in 2007.
Williams also executed natural gas price hedges in the form of collars in the second quarter
for certain amounts of its production in the Rockies and San Juan basins for periods through 2007.
Collars use derivative instruments to set a floor for a minimum price and a ceiling that sets a
maximum price to be received by Williams for hedged volumes. Pricing and volume details for the
hedge collars are listed in the second-quarter investor presentation.
On May 11, Williams acquired properties in the Barnett Shale play in the Fort Worth Basin of
north Texas from an undisclosed seller. The area is consistent with Williams’ experience in tight
sands, shale and coalbed methane developments.
The properties include interests in approximately 13,000 net acres of leasehold, subject to
final closing adjustments, located primarily in Denton, Johnson and Parker counties. Williams’
engineers estimate proved reserves of 17 billion cubic feet equivalent (Bcfe) and additional
probable and possible reserves of 40 to 50 Bcfe. Williams expects to grow daily net production from
the Barnett Shale to more than 20 million cubic feet equivalent during the next two years.
As a result of development costs related to the newly acquired properties in the Barnett
Shale, Williams plans to increase its capital spending in E&P by a total of approximately $80
million to $90 million during the next two to three years, including $35 million in 2005.
For the full year, including acquisition and development costs, Williams now plans to spend
between $605 million to $680 million in its Exploration & Production business, compared with
previous guidance of $530 million to $605 million.
Williams has increased its expectation for segment profit from Exploration & Production in
2005. The company now expects $410 million to $485 million in segment profit, which includes $8
million of non-recurring income. That expectation is up from its previous guidance of $400 million
to $475 million for that measure. The increase is the result of the Fort Worth Basin entry and the
floor price of new hedge collars which are above the company’s assumed unhedged prices.
Midstream Gas & Liquids: Continues to See Strong Margins and Sales Volumes
Midstream, which provides gathering, processing, natural gas liquids fractionation and storage
services, reported second-quarter 2005 segment profit of $109.1 million.
In the second quarter a year ago, the business reported segment profit of $98.5 million on a
restated basis.
The quarterly improvement primarily reflects a $16 million increase in natural gas liquids
production margins in the West and the Gulf Coast and a $9 million increase in gathering revenues
and processing fees. These factors were offset partially by lower revenue associated with the
Devils Tower facilities following a correction in revenue-recognition
methodology in third-quarter 2004. The correction
resulted in the deferral of $16.5 million of revenues recognized in second-
quarter 2004. The change had no impact on cash flows.
For the first six months of 2005, Midstream reported segment profit of $237.7 million compared
with a restated $208.6 million for the same period last year.
Williams has benefited from favorable natural gas liquids (NGL) margins in both periods,
particularly in its western U.S. natural gas processing operations in areas such as Opal and
Wamsutter in Wyoming. The current year has further benefited from increased gas gathering and NGL
sales volumes, partially offset by lower deepwater asset revenues.
Through June 30, Midstream has sold 737.0 million gallons of NGL equity volumes, an increase
of approximately 12 percent compared with equity sales of 655.4 million gallons for the first half
of 2004. These gallons are retained by Williams as payment-in-kind under the terms of certain
processing contracts and then marketed for sale.
Gathering and processing volumes increased modestly year-over-year. Gathering volumes were
639.1 trillion British thermal units (TBtu) in the first half of 2005 compared with 615.5 TBtu in
the 2004 period — an increase of approximately 4 percent. Processing volumes in the first half of
2005 were 365.5 TBtu compared with 360.3 TBtu in the first six months of 2004.
Williams has moved upward its expectation for segment profit in 2005 from Midstream. The
company now expects $400 million to $470 million in segment profit from this business, up from its
previous expectation of $370 million to $450 million. The increase is principally the result of
stronger net liquids margins and higher volumes than previously expected.
Gas Pipeline: Pursuing Expansions in Northeast and Mid-Atlantic Growth Markets
Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in
Florida and in the Northwest, reported second-quarter 2005 segment profit of $164.5 million.
In the second quarter a year ago, the business reported segment profit of $132.8 million on a
restated basis.
The increase in second-quarter 2005 segment profit compared with a year ago is primarily
attributable to the benefit of a $17.1 million reduction to pension expense associated with
actuarial corrections to 2003-2004 pension obligations, $5 million in liability reductions
associated with prior periods, and the absence of a $9 million write-off of capitalized costs in
2004.
For the first six months of 2005, Gas Pipeline reported segment profit of $331.9 million
compared with a restated $280.2 million for the same period last year. The increase for the
six-month period in 2005 is primarily the result of the benefit of the second-quarter pension
expense correction; approximately $18 million in liability reductions associated with prior
periods; $11 million in higher equity earnings from Gulfstream Natural Gas System, L.L.C., a joint
venture in which Williams owns a 50 percent interest; and the absence of a $9 million write-off of
capitalized costs in 2004.
Gulfstream is benefiting from several recently executed transportation agreements for a total
of 400,000 dekatherms per day, serving customers in central Florida. In June, Gulfstream commenced
incremental
transportation service on its 110-mile Phase II expansion. Approximately two-thirds of
Gulfstream’s 1.1 billion dekatherms of total capacity is now contracted on a firm basis.
Subsequent to the close of the second quarter, Williams’ Transco pipeline began constructing
an expansion to add 105,000 dekatherms of new firm service in central New Jersey and initiated an
open season for up to 150,000 dekatherms per day of incremental firm transportation service to
the greater Washington, D.C., area. The central New Jersey project is expected
to be placed into service in November. The new service to D.C. is anticipated to be available in
November 2007, subject to Federal Energy Regulatory Commission approval.
Transco also continues to proceed with permitting its Leidy-to-Long Island expansion project
to transport 100,000 dekatherms of natural gas per day. This project is expected to be placed into
service in November 2007.
Williams has increased its expectation for 2005 segment profit from Gas Pipeline. The company
now expects $590 million to $615 million in segment profit from this business, which includes $35
million of non-recurring, prior-period items. The company’s previous expectation for this measure
was $555 million to $585 million. The increase is largely due to non-recurring items recorded in
the first half of the year.
Power: Continues Cash-Flow Positive Year-to-Date
Power manages an approximate 7,000-megawatt power portfolio and provides services that
support Williams’ natural gas businesses.
Power Recurring Segment Profit Adjusted for Mark-to-Market Impact
| 2Q '05 | 2Q '04 | ||||||||
| (millions) | (millions) | ||||||||
Segment profit (loss) |
$ | (75.0 | ) | $ | 43.8 | ||||
Non-recurring adjustments |
13.1 | — | |||||||
Recurring segment profit (loss) |
(61.9 | ) | 43.8 | ||||||
Mark-to-market adjustments — net |
54.8 | (58.5 | ) | ||||||
Recurring segment profit after mark-to-market adjustments |
$ | (7.1 | ) | $ | (14.7 | ) | |||
Power reported a second-quarter 2005 segment loss of $75.0 million, down from a segment profit
for the same quarter a year ago of $43.8 million on a restated basis. The change is primarily the
result of $47.7 million in lower forward unrealized mark-to-market gains; the absence of $34
million in income from the interest-rate portfolio in the 2004 period; and a $13.1 million accrual
for litigation contingencies in the 2005 period.
Power reported a recurring segment loss on a basis adjusted for the effect of mark-to-market
accounting of $7.1 million in second-quarter 2005, compared with a loss of $14.7 million a year ago. The
year-over-year improvement primarily reflects improvements in the power and natural gas portfolio,
offset by the absence of gains from the interest-rate portfolio, which was liquidated in
fourth-quarter 2004.
In the second quarter of 2005, Power generated approximately $37 million in cash flow from
operations, largely the result of changes in working capital.
For the first six months of 2005, Power reported a segment profit of $39.1 million compared
with segment profit of $11.8 million for the first half of 2004 on a restated basis. That change is
primarily the result of $149.7 million higher forward unrealized mark-to-market gains this year,
which was partially offset by the absence of a legacy natural gas portfolio that liquidated in the
first quarter last year.
The 2005 period includes forward unrealized mark-to-market gains of $243.2 million, compared
with forward unrealized mark-to-market gains of $93.5 million in the first half of 2004.
For the first six months of 2005, Power reported a recurring segment profit on a basis
adjusted for the effect of mark-to-market accounting of $11 million, compared with $65 million for
the first half of 2004. The year-over-year decline is primarily due to the absence of a legacy
natural gas portfolio that liquidated in the first quarter 2004.
For the first six months of 2005, Power generated approximately $85 million in cash flow from
operations.
For 2005, Williams continues to expect a segment profit range of a $50 million loss to a $50
million profit from Power on a basis that excludes future mark-to-market changes.
Also unchanged is the company’s expectation that Power will generate $50 million to $150
million in 2005 cash flow from operations on a basis that excludes future changes in working
capital used in commodity risk management activity on behalf of all Williams commodity businesses.
On a basis adjusted for the effect of mark-to-market accounting, Williams continues to expect
Power to generate 2005 recurring earnings of $50 million to $150 million.
Cash and Debt: $488.9 Million Net Cash From Operations in Quarter
Net cash provided by operating activities for the second quarter of 2005 was $488.9 million.
Through June 30, net cash provided by operating activities was $793.3 million, compared with $615.1
million in the first half of 2004.
While the company reports that underlying operating cash flows continue to improve, it has
lowered its expectation for 2005 cash flow from operating activities by $150 million to reflect the
effect of a preliminary income tax settlement of $180 million to $200 million, and a forecasting
reclassification of $88 million related to the Grays Harbor contract termination from operating to
investing activities. The company now expects cash flow of $1.15 billion to $1.45 billion for the
year, compared with $1.3 billion to $1.6 billion as projected at the end of the first quarter.
At the end of the second quarter, Williams had total liquidity of approximately $2.15 billion.
This consists of unrestricted cash and cash equivalents of approximately $1.3 billion; other liquid
investments of $94.7 million; and $761 million in unused and available revolving credit facilities.
Williams has reduced its debt by approximately $221 million in 2005 through scheduled
maturities. At June 30, 2005, Williams’ total outstanding debt was approximately $7.74 billion.
Year-to-date, Williams has realized a year-over-year decrease in net interest expense of
approximately $134 million as a result of debt reductions.
Partnership IPO Expected in Third Quarter
Subsequent to the close of the first quarter, Williams Partners L.P. filed a Form S-1
registration with the Securities and Exchange Commission relating to a proposed underwritten
initial public offering for limited partnership interests in this wholly owned Williams entity.
Williams Partners L.P. will own a 40 percent interest in the Discovery natural gas gathering,
transportation, processing and NGL fractionation system that runs from the deepwater Gulf of Mexico
to a location near Paradis, La.; the Carbonate Trend sour-gas gathering pipeline off the coast of
Alabama; three integrated NGL storage facilities near Conway, Kan.; and a 50 percent interest in an
NGL fractionator near Conway.
The registration statement for Williams Partners L.P. has not yet become effective. These
securities may not be sold nor may offers to buy be accepted prior to the time the registration
statement becomes effective.
This news release shall not constitute an offer to sell or the solicitation of an offer to buy
nor shall there be any sale of these securities in any state in which such offer, sale or
solicitation would be unlawful prior to registration or qualification under the securities law in
any such state.
Today’s Analyst Call
Williams’ management will discuss the company’s second-quarter 2005 financial results and
outlook during an analyst presentation to be webcast live beginning at 10 a.m. Eastern today.
Participants are encouraged to access the presentation and corresponding slides via
www.williams.com. A limited number of phone lines also will be available at (800) 946-0713.
International callers should dial (719) 457-2642. Callers should dial in at least 10 minutes prior
to the start of the discussion. Replays will be available at www.williams.com.
Form 10-Q
The company is filing its Form 10-Q today with the Securities and Exchange Commission. The
document will be available on both the SEC and Williams websites.
About Williams (NYSE:WMB)
Williams, through its subsidiaries, primarily finds, produces, gathers, processes and transports
natural gas. The company also manages a wholesale power business. Williams’ operations are
concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern
Seaboard. More information is available at www.williams.com.
| Contact: | Kelly Swan Williams (media relations) (918) 573-6932 Richard George Williams (investor relations) (918) 573-3679 Karl Meyer Williams (investor relations) (918) 573-4395 |
# # #
Williams’ reports, filings, and other public announcements might contain or incorporate by
reference statements that do not directly or exclusively relate to historical facts. Such
statements are “forward-looking statements” within the meaning of Private Securities Litigation
Reform Act of 1995. You typically can identify forward-looking statements by the use of
forward-looking words, such as “anticipate,” “believe,” “could,” “continue,” “estimate,” “expect,”
“forecast,” “may,” “plan,” “potential,” “project,” “schedule,” “will,” and other similar words.
These statements are based on our intentions, beliefs, and assumptions about future events and are
subject to risks, uncertainties, and other factors. Actual results could differ materially from
those contemplated by the forward-looking statements. In addition to any assumptions and other
factors referred to specifically in connection with such statements, other factors could cause our
actual results to differ materially from the results expressed or implied in any forward-looking
statements. Those factors include, among others: changes in general economic conditions and changes
in the industries in which Williams conducts business; changes in federal or state laws and
regulations to which Williams is subject, including tax, environmental and employment laws and
regulations; the cost and outcomes of legal and administrative claims proceedings, investigations,
or inquiries; the results of financing efforts, including our ability to obtain financing on
favorable terms, which can be affected by various factors, including our credit ratings and general
economic conditions; the level of creditworthiness of counterparties to our transactions; the
amount of collateral required to be posted from time to time in our transactions; the effect of
changes in accounting policies; the ability to control costs; the ability of each business unit to
successfully implement key systems, such as order entry systems and service delivery systems; the
impact of future federal and state regulations of business activities, including allowed rates of
return, the pace of deregulation in retail natural gas and electricity markets, and the resolution
of other regulatory matters; changes in environmental and other laws and regulations to which
Williams and its subsidiaries are subject or other external factors over which we have no control;
changes in foreign economies, currencies, laws and regulations, and political climates, especially
in Canada, Argentina, Brazil, and Venezuela, where Williams has direct investments; the timing and
extent of changes in commodity prices, interest rates, and foreign currency exchange rates; the
weather and other natural phenomena; the ability of Williams to develop or access expanded markets
and product offerings as well as their ability to maintain existing markets; the ability of
Williams and its subsidiaries to obtain governmental and regulatory approval of various expansion
projects; future utilization of pipeline capacity, which can depend on energy prices, competition
from other pipelines and alternative fuels, the general level of natural gas and petroleum product
demand, decisions by customers not to renew expiring natural gas transportation contracts; the
accuracy of estimated hydrocarbon reserves and seismic data; and global and domestic economic
repercussions from terrorist activities and the government’s response to such terrorist
activities. In light of these risks, uncertainties, and assumptions, the events described in the
forward-looking statements might not occur or might occur to a different extent or at a different
time that we have described. We undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future events or otherwise.
In regard to the company’s reserves in Exploration & Production, the SEC permits oil and gas
companies, in their filings with the SEC, to disclose only proved reserves. We have used certain
terms in this news release, such as “probable” reserves and “possible” reserves and “new
opportunities potential” reserves that the SEC’s guidelines strictly prohibit us from including in
filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in the future from known reservoirs under the assumed economic conditions. Probable and
possible reserves are estimates of potential reserves that are made using accepted geological and
engineering analytical techniques, but which are estimated with reduced levels of certainty than
for proved reserves. Possible reserve estimates are less certain than those for probable reserves.
New opportunities potential is an estimate of reserves for new areas for which we do not have
sufficient information to date to raise the reserves to either the probable category or the
possible category. New opportunities potential estimates are even less certain that those for
possible reserves. Reference to “total resource portfolio” include proved, probable and possible reserves as well as
new opportunities potential. Investors are urged to closely consider the disclosures and risk
factors in our Forms 10-K and 10-Q, available from our offices or from our website at
www.williams.com.
Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings
(UNAUDITED)
(UNAUDITED)
| 2004 | 2005 | |||||||||||||||||||||||||||||||
| (Dollars in millions, except for per-share amounts) | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | Year | ||||||||||||||||||||||||
Income (loss) from continuing operations available to common stockholders |
$ | 0.0 | $ | (18.5 | ) | $ | 16.2 | $ | 95.5 | $ | 93.2 | $ | 202.2 | $ | 40.7 | $ | 242.9 | |||||||||||||||
Income (loss) from continuing operations — diluted earnings per share |
$ | — | $ | (0.03 | ) | $ | 0.03 | $ | 0.17 | $ | 0.17 | $ | 0.34 | $ | 0.07 | $ | 0.41 | |||||||||||||||
Nonrecurring items: |
||||||||||||||||||||||||||||||||
Power |
||||||||||||||||||||||||||||||||
Accrual for a regulatory settlement (1) |
— | — | — | — | — | 4.6 | — | 4.6 | ||||||||||||||||||||||||
Accrual for litigation contingencies (1) |
— | — | — | — | — | — | 13.1 | 13.1 | ||||||||||||||||||||||||
Prior period correction |
— | — | — | — | — | 6.8 | — | 6.8 | ||||||||||||||||||||||||
Total Power nonrecurring items |
— | — | — | — | — | 11.4 | 13.1 | 24.5 | ||||||||||||||||||||||||
Gas Pipeline |
||||||||||||||||||||||||||||||||
Prior period liability corrections — TGPL |
— | — | — | — | — | (13.1 | ) | (4.6 | ) | (17.7 | ) | |||||||||||||||||||||
Prior period pension adjustment — TGPL |
— | — | — | — | — | — | (17.1 | ) | (17.1 | ) | ||||||||||||||||||||||
Write-off of previously-capitalized costs — idled segment of Northwest’s pipeline |
— | 9.0 | — | — | 9.0 | — | — | — | ||||||||||||||||||||||||
Total Gas Pipeline nonrecurring items |
— | 9.0 | — | — | 9.0 | (13.1 | ) | (21.7 | ) | (34.8 | ) | |||||||||||||||||||||
Exploration & Production |
||||||||||||||||||||||||||||||||
Gain on sale of E&P properties |
— | — | — | — | — | (7.9 | ) | — | (7.9 | ) | ||||||||||||||||||||||
Loss provision related to an ownership dispute |
— | 11.3 | — | 4.1 | 15.4 | 0.3 | — | 0.3 | ||||||||||||||||||||||||
Total Exploration & Production nonrecurring items |
— | 11.3 | — | 4.1 | 15.4 | (7.6 | ) | — | (7.6 | ) | ||||||||||||||||||||||
Midstream Gas & Liquids |
||||||||||||||||||||||||||||||||
La Maquina depreciable life adjustment |
— | — | 6.4 | 1.2 | 7.6 | — | — | — | ||||||||||||||||||||||||
Gain on sale of Louisiana Olefins assets |
— | — | — | (9.5 | ) | (9.5 | ) | — | — | — | ||||||||||||||||||||||
Gulf Liquids arbitration award (Winterthur) |
— | — | — | (93.6 | ) | (93.6 | ) | — | — | — | ||||||||||||||||||||||
Impairment of Discovery |
— | — | — | 16.9 | 16.9 | — | — | — | ||||||||||||||||||||||||
Devil’s Tower revenue correction |
— | (16.5 | ) | 16.5 | — | — | — | — | ||||||||||||||||||||||||
Total Midstream Gas & Liquids nonrecurring items |
— | (16.5 | ) | 22.9 | (85.0 | ) | (78.6 | ) | — | — | — | |||||||||||||||||||||
Other |
||||||||||||||||||||||||||||||||
Impairment of Longhorn |
— | 10.8 | — | — | 10.8 | — | 49.1 | 49.1 | ||||||||||||||||||||||||
Write-off of capitalized project development costs |
— | — | — | — | — | — | 4.0 | 4.0 | ||||||||||||||||||||||||
Augusta environmental reserve |
— | — | — | 11.8 | 11.8 | — | — | — | ||||||||||||||||||||||||
Longhorn recapitalization fee |
6.5 | — | — | — | 6.5 | — | — | — | ||||||||||||||||||||||||
Total Other nonrecurring items |
6.5 | 10.8 | — | 11.8 | 29.1 | — | 53.1 | 53.1 | ||||||||||||||||||||||||
Nonrecurring items included in segment profit (loss) |
6.5 | 14.6 | 22.9 | (69.1 | ) | (25.1 | ) | (9.3 | ) | 44.5 | 35.2 | |||||||||||||||||||||
Nonrecurring items below segment profit (loss) |
||||||||||||||||||||||||||||||||
Impairment of
cost-based investments (Investing income (loss) — Various) |
— | — | 15.7 | 2.3 | 18.0 | — | — | — | ||||||||||||||||||||||||
Write-off of capitalized debt expense (Interest accrued — Corporate) |
— | 3.8 | — | — | 3.8 | — | — | — | ||||||||||||||||||||||||
Premiums, fees and expenses related to the debt repurchase and debt tender offer
(Other income (expense) — net — Corporate and Exploration & Production) |
— | 96.7 | 155.1 | 29.7 | 281.5 | — | — | # - | ||||||||||||||||||||||||
Gulf Liquids arbitration award (Winterthur) — interest income — (Investing
income / loss) — Midstream) |
— | — | — | (9.6 | ) | (9.6 | ) | — | — | — | ||||||||||||||||||||||
Gain on sale of remaining interests in Seminole Pipeline and MAPL
(Investing income / loss — Midstream) |
— | — | — | — | — | — | (8.6 | ) | (8.6 | ) | ||||||||||||||||||||||
Loss provision related to an ownership dispute — interest component
(Interest accrued — Exploration & Production) |
— | 1.9 | — | 2.1 | 4.0 | 2.7 | — | 2.7 | ||||||||||||||||||||||||
| — | 102.4 | 170.8 | 24.5 | 297.7 | 2.7 | (8.6 | ) | (5.9 | ) | |||||||||||||||||||||||
Total nonrecurring items |
6.5 | 117.0 | 193.7 | (44.6 | ) | 272.6 | (6.6 | ) | 35.9 | 29.3 | ||||||||||||||||||||||
Tax effect for above items (1) |
2.5 | 44.8 | 74.1 | (17.1 | ) | 104.3 | (2.8 | ) | 10.7 | 7.9 | ||||||||||||||||||||||
Recurring income from continuing operations available to common stockholders |
$ | 4.0 | $ | 53.7 | $ | 135.8 | $ | 68.0 | $ | 261.5 | $ | 198.4 | $ | 65.9 | $ | 264.3 | ||||||||||||||||
Recurring diluted earnings per common share |
$ | 0.01 | $ | 0.10 | $ | 0.26 | $ | 0.12 | $ | 0.49 | $ | 0.33 | $ | 0.11 | $ | 0.45 | ||||||||||||||||
Weighted-average shares — diluted (thousands) |
519,485 | 521,698 | 529,525 | 586,497 | 535,611 | 599,422 | 578,902 | 602,956 | ||||||||||||||||||||||||
| (1)No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million of the accrual for litigation contingencies in 2nd quarter 2005. |
Note: The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average
number of common shares outstanding.
Adjustment to remove MTM impact
Dollars in millions except for per share amounts
| 2005 | 2004 | ||||||||||||||||||||||||||||||||||||||||
| 1Q | 2Q | 3Q | 4Q | Year | 1Q | 2Q | 3Q | 4Q | Year | ||||||||||||||||||||||||||||||||
Recurring income from cont. ops available to common shareholders |
$ | 198 | $ | 66 | $ | 264 | $ | 4 | $ | 54 | $ | 136 | $ | 68 | $ | 261 | |||||||||||||||||||||||||
Recurring diluted earnings per common share |
$ | 0.33 | $ | 0.10 | $ | 0.44 | $ | 0.01 | $ | 0.10 | $ | 0.26 | $ | 0.12 | $ | 0.49 | |||||||||||||||||||||||||
Mark-to-Market (MTM) adjustments: |
|||||||||||||||||||||||||||||||||||||||||
Reverse forward unrealized MTM gains/losses |
(221 | ) | (22 | ) | (243 | ) | (24 | ) | (70 | ) | (187 | ) | (23 | ) | (304 | ) | |||||||||||||||||||||||||
Add realized gains/losses from MTM previously recognized |
113 | 77 | 190 | 136 | 11 | 45 | (6 | ) | 186 | ||||||||||||||||||||||||||||||||
Total MTM adjustments |
(108 | ) | 55 | (53 | ) | 112 | (59 | ) | (142 | ) | (29 | ) | (118 | ) | |||||||||||||||||||||||||||
Tax effect of total MTM adjustments (at 39%) |
(42 | ) | 21 | (21 | ) | 44 | (23 | ) | (55 | ) | (11 | ) | (46 | ) | |||||||||||||||||||||||||||
After tax MTM adjustments |
(66 | ) | 34 | (32 | ) | 68 | (36 | ) | (87 | ) | (17 | ) | (72 | ) | |||||||||||||||||||||||||||
Recurring income from cont. ops available
to common shareholders after MTM adjust. |
$ | 132 | $ | 100 | $ | 232 | $ | 72 | $ | 18 | $ | 49 | $ | 51 | $ | 189 | |||||||||||||||||||||||||
Recurring diluted earnings per share after MTM adj. |
$ | 0.22 | $ | 0.17 | $ | 0.39 | $ | 0.14 | $ | 0.04 | $ | 0.09 | $ | 0.09 | $ | 0.35 | |||||||||||||||||||||||||
weighted average shares — diluted (thousands) |
599,422 | 578,902 | 602,956 | 519,485 | 521,698 | 529,525 | 586,497 | 535,611 | |||||||||||||||||||||||||||||||||
Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously
recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives.
EXHIBIT 99.2
| Williams 2005 2nd Quarter Earnings Release August 4, 2005 |
| Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward-looking words, such as "anticipate," believe," "could," "continue," "estimate," "expect," "forecast," "may," "plan," "potential," "project," "schedule," "will," and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; Our ability to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas; Our gas sales, transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; Electricity, natural gas liquids and gas prices are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses; We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; Our operating results might fluctuate on a seasonal and quarterly basis; Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; Legal proceedings and governmental investigations related to our business; Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; Because we no longer maintain investment grade credit ratings, our counterparties have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; We could be held liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; The continued availability of natural gas reserves to our natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Forward Looking Statements |
| Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable" reserves and "possible" reserves and "new opportunities potential" reserves that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to "total resource portfolio" include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our Web site at www.williams.com. |
| 2Q05 Review Steve Malcolm Chairman, President & CEO |
| Headlines Key performance measures - moving up E&P segment profit - up more than 100% Domestic gas production - up 18% during half-year NGL sales volumes - up 13% for 6-month period Net cash from operations - up 29% during first quarter Recurring after mark-to-market - up more than 100% Overview |
| Other Developments Refined 2Q05 earnings guidance Returning more to investors via dividends Hedging gas production price risk with collars Continuing MLP process Williams Partners LP in SEC registration process Filed 3rd amendment to preliminary registration statement No more details in today's call Attending to legacy issues Proposed tax settlement - previously reserved Longhorn impairment - non-cash Litigation - update in 10-Q Overview |
| Headlines Williams' growth opportunities are growing Exploration & Production Piceance drilling locations and reserves - up significantly Developing new Piceance opportunities Entry into Ft. Worth Basin's Barnett Shale play Expect continued strong production growth Midstream Drilling activity in West boosts demand for services Excellent position to capture new deepwater business Gas Pipeline Seizing opportunities to meet growing demand Returns on growth expected via rate cases Power Growing success in mid-term deals that reduce risk Overview |
| Financial Results and 2005 Outlook Don Chappel CFO |
| Financial Results A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts) 2nd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $40 $(18) $243 $(18) Income (Loss) from Disc. Operations 1 - (1) 10 Net Income (Loss) $41 $(18) $242 $(8) Net Income (Loss)/Share $0.07 ($0.03) $0.41 ($0.02) Recurring Inc. from Cont. Ops./Share $0.11 $0.10 $0.45 $0.11 Recurring Inc. from Cont. Ops. After MTM Adjustments/Share $0.17 $0.04 $0.39 $0.17 Consolidated |
| Recurring Income from Cont. Operations A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Income from Continuing Operations $40 ($18) $243 ($18) Nonrecurring Items Impairments/Losses/Write-offs 53 26 53 26 Expense related to Prior Periods (22) (6) (28) - Gain on Sale of Assets (9) - (17) - Debt Retirement Expense - 97 - 97 Other - Net 14 - 20 Total nonrecurring $36 $117 $29 $123 Tax Effect of Adjustments 10 45 8 47 Recurring Inc. from Cont. Ops. Avail. To Com. $66 $54 $264 $58 Recurring Income from Cont. Ops./Share $0.11 $0.10 $0.45 $0.11 Consolidated |
| 2nd Qtr YTD 2005 2004 2005 2004 Recurring Income from Cont. Operations After Mark-to-Market Adjustments Note: Adjustments have been made to reverse estimated forward unrealized MTM gains and add estimated realized gains from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com. Dollars in millions, except for per-share amounts Recurring Income from Cont. Ops. Avail. To Common $66 $54 $264 $58 Recurring Diluted Earnings per Common Share $0.11 $0.10 $0.45 $0.11 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM gains (22) (69) (243) (93) Add realized gains from MTM previously recognized 77 10 190 146 Total MTM adjustments 55 (59) (53) 53 Tax Effect of Total MTM Adjustments (at 39%) (21) 23 21 (21) After-tax MTM Adjustments 34 (36) (32) 32 Recurring income from Continuing Operations Avail. To Common Shareholders After MTM Adjustments $100 $18 $232 $90 Recurring Diluted Earnings Per Share After MTM adjustments $0.17 $0.04 $0.39 $0.17 Consolidated 2nd Qtr YTD 2005 2004 2005 2004 |
| Net Income Components A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts) Segment Profit $256 $304 $766 $572 Net Interest Expense (163) (222) (327) (461) Debt Retirement expense - (97) - (97) Other Income (Expense) - Net (11) (21) (25) (38) Income from Cont. Ops. Before Tax $82 $(36) $414 $(24) Provision for Income Tax 42 (18) 171 (6) Income (Loss) from Continuing Ops. $40 ($18) $243 ($18) Income (Loss) from Discontinued Ops. 1 - (1) 10 Net Income $41 ($18) $242 ($8) Consolidated 2nd Qtr YTD 2005 2004 2005 2004 |
| Second Quarter Segment Profit A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions Exploration & Production $118 $43 $118 $55 Midstream Gas & Liquids 109 99 109 82 Gas Pipeline 165 133 143 142 Power (75) 44 (62) 44 Other (61) (15) (7) (4) Segment Profit $256 $304 $301 $319 MTM Adjustments - Power 55 (59) Segment Profit after MTM Adjustments $356 $260 Memo: Power after MTM adjustments $(7) $(15) Consolidated Reported Recurring 2Q05 2Q04 2Q05 2Q04 |
| 2005 YTD Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $222 $95 $214 $106 Midstream Gas & Liquids 238 209 238 192 Gas Pipeline 332 280 297 289 Power 39 12 64 12 Other (65) (24) (12) (5) Segment Profit $766 $572 $801 $594 MTM Adjustments (53) 53 Segment Profit after MTM Adjustments $748 $647 Memo: Power after MTM adjustments $11 $651 Dollars in millions Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 1 Includes impact of legacy natural gas portfolio that liquidated in 1Q04. |
| Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 2Q04 $260 Exploration & Production 63 - Higher production volumes +$20million - Higher net realized price +$45 million Midstream 27 - Increased NGL margins +$16 million - Increased Gathering revenues +$9 million - Increase product handling fees +$4 million Gas Pipeline - - Increased Gulfstream earnings +$3 million - Grays Harbor contract termination -4 million Power 8 - Improved Power and Natural Gas Portfolio cash flows +$25 million - Absence of realized gains on interest rate portfolio -$34 million Other (2) Recurring Segment Profit after MTM Adj. 2Q05 $356 Dollars in millions |
| 2Q05 YTD05 Beginning Unrestricted $1,210 $930 Cash flow from Continuing Operations 489 793 Proceeds from Issuing Common1 9 297 Sale of WilTel Note - 55 Contract Termination Payment - 88 Debt Retirements (5) (221) Capital Expenditures (294) (517) Dividends (29) (57) Other-Net (83) (71) Change in Cash and Cash equivalents $87 $367 Ending Unrestricted Cash at 6/30/05 $1,2972 Restricted Cash at 6/30/05 (not included above) $101 Cash Information Dollars in millions Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS 2 Includes international cash ($185), cash to settle legacy matters including tax settlement ($200), AK Quality Bank judgment ($180) and other matters. |
| Debt Balance Scheduled Debt Retirements & Amortization (6) Debt Balance @ 6/30/051 $7,744 7.5% Fixed Rate Debt @ 6/30/05 $7,089 7.7% Variable Rate Debt @ 6/30/05 $655 5.2% Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Consolidated Debt Balance @ 12/31/041 $7,962 7.4% Scheduled Debt Retirements & Amortization (216) Capitalized Lease 4 Debt Balance @ 3/31/051 $7,750 7.4% |
| Business Unit Results |
| Exploration & Production Ralph Hill Senior Vice President |
| Segment Profit Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Segment Profit $118 $43 $222 $95 Nonrecurring: Ownership Issue - 11 - 11 Gain on sale of assets - - (8) - Recurring Segment Profit $118 $551 $214 $106 2Q04 to 2Q05 financial highlights include: Volume increase of 17.5% Net realized price increase of 35% Recurring profit increase of 115% Base business sequential quarter improved Increased recurring segment profit 23% Increased volumes 6% $55.2 million negative hedge impact in 2Q05, $91.5 million year to date Exploration & Production 1 Does not add due to rounding |
| Strong Domestic Production Growth Exploration & Production 2004 2005 |
| Volumes rising in all core basins Big George gross production up to 110 MMcf/d San Juan hits record production Increase in Piceance Valley location inventory and probable reserves 11 rigs operating in Piceance Valley, 4 rigs in Trail Ridge & Ryan Gulch H&P first rig on schedule for Nov 1 Ft. Worth-Barnett Shale entry acquisition Exploration & Production 2nd Quarter and 2005 Accomplishments |
| Piceance Production Growth Up 100 MMcf/d or 48% over a year ago Up 28 MMcf/d or 10% sequentially Exploration & Production |
| Up 48 MMcf/d or 78% over a year ago Up 25 MMcf/d or 29% sequentially Big George production increase offsets Wyodak decline Powder River Basin Big George Coal Area Exploration & Production |
| Updated 3P Reserves 3 Tcf 8.5 Tcf 3P '04 YE 7.0 Tcf 37.5% increase in probable and possible reserves Extensive study of Piceance Valley yielded additional 1,600 locations and ~1.5 Tcf probable and possible reserves Rock quality Land/topography Drilling reach H&P rig capabilities provide access to some of the additional locations Does not include Trail Ridge, Ryan Gulch, Red Point and other new areas under Williams' control Exploration & Production '04 YE Proved '04 YE Proved Existing Proved, Prob. & Poss. |
| Entrance into Ft. Worth Basin Entrance into Ft. Worth Basin Barnett Shale Arkoma Barnett Shale position established: 13,000 net acres Proved reserves of 17 Bcf with 40-50 Bcfe probable and possible High working interest averaging ~90% Utilizes Williams' Mid-continent horizontal drilling expertise Provides numerous bolt-on opportunities Exploration & Production |
| Dollars in millions Exploration & Production 2005-2007 Hedge Update NEW 4Q only 1 Please note basin locations not NYMEX 2005 2006 2007 Fixed Price: 2nd Half NYMEX Volume (MMcfe/d) 283 299 172 Price ($/Mcfe) $4.48 $4.39 $4.18 Collars : NYMEX Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 $6.62 - $8.42 $6.50 - $8.25 Regional NWPL Rockies1 Volume (MMcfe/d) 50 50 50 Price ($/Mcfe) $6.10 - $7.70 $6.05 - $7.90 $5.65 - $7.45 EPNG San Juan1 Volume (MMcfe/d) 50 Price ($/Mcfe) $5.65 - $7.45 |
| 2005 2006 2007 Segment profit $410 - 4851 $520 - 595 $595 - 720 Annual DD&A 235 - 265 295 - 335 365 - 415 Segment profit + DD&A $645 - 750 $815 - 930 $960 - 1,135 Capital spending $605 - 680 $760 - 860 $735 - 885 Production (MMcfe/d) 625 - 700 740 - 840 850 - 950 Unhedged Price Assumption (NYMEX, $/Mcf) $6.34 $5.96 $5.75 Dollars in millions Exploration & Production 2005-2007 Guidance 280 - 320 350 - 400 400 - 475 480 - 555 550 - 675 530 - 605 725 - 825 725 - 875 600 - 700 720 - 820 825 - 925 635 - 740 760 - 875 900 - 1,075 1 Includes YTD nonrecurring adjustments which increase reported earnings by $8 million A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com Note: If guidance has changed, previous guidance from 5/5/2005 is shown in italics directly below |
| Delivering meaningful volume growth through expanded development drilling activity -- Piceance is primary growth driver Experienced and talented workforce Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Maintaining top quartile cost and efficiency position Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles Exciting new opportunities Trail Ridge, Ryan Gulch, Red Point, Ft. Worth Basin, and Caney Shale Strategy remains rapid development of our premier drilling inventory Key Points Exploration & Production |
| Midstream Alan Armstrong Senior Vice President |
| Segment Profit Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Segment Profit $109 $99 $238 $209 Nonrecurring: Devils Tower Revenue Recognition1 (17) (17) Recurring Segment Profit $109 $82 $238 $192 2Q04 to 2Q05 financial highlights include: $16 million - Increase in domestic NGL margins $9 million - Increase in gathering and processing fees $4 million - Increase in production handling fees YTD 2004 to YTD 2005 include: $35 million - Increase in domestic NGL margins $8 million - Increase in domestic NGL volume $12 million - Increase in gathering and processing fees 1 Prior period item Midstream |
| 2nd Quarter and 2005 Accomplishments 2Q05 vs 2Q04: Gathering volumes up 5% Organic Growth: Quintana Mesa Wamsutter Phase 1 Raised $55 million in asset sales 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2004 150 127 172 197 2005 175 155 0 0 Recurring Segment Profit + Depreciation Midstream |
| 2005 2006 2007 Segment Profit $400-470 $400-500 $400-520 Annual DD&A 180-190 185-195 190-200 Segment Profit + DDA $580-660 $585-695 $590-720 Capital Spending $120-140 $110-130 $100-130 Note: If guidance has changed, previous guidance from 5/5/2005 is shown in italics directly below Midstream 2005-2007 Guidance Dollars in millions $370 - $450 Major Growth Projects Not Included Gathering and processing expansions in the West Footprint expansion of deepwater infrastructure $550 - $640 |
| Deepwater Activity Midstream |
| Key Points Strong earnings and cash flows Raising 2005 segment profit guidance, again Capturing growth opportunities Organic growth around our Western assets Footprint expansion in the deepwater One-two punch Premier assets in growth basins Attracting volumes through reliability Midstream |
| Gas Pipeline Phil Wright Senior Vice President |
| Segment Profit Dollars in millions Gas Pipeline Segment Profit $165 $133 $332 $280 Nonrecurring Pension expense reduction1 (17) - (17) - Adjustment to carrying value of certain liabilities1 (5) - (18) - Write-off hydrostatic testing - 9 - 9 Recurring Segment Profit $143 $142 $297 $289 2Q04 to 2Q05 financial highlights include: $3 million - Increased earnings at Gulfstream $(4) million - Grays Harbor contract termination 1 Prior period items |
| Northwest's 26" Replacement - FERC issues preliminary Order Construction began in July for Central New Jersey expansion project Gulfstream Phase II began flowing volumes under two new long term firm contracts totaling 400MDt/d Transco holds open season for the Potomac Expansion project 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 213 210 211.7 223.9 2005 220.7 208 0 0 Gas Pipeline 2nd Quarter and 2005 Accomplishments |
| 2005 2006 2007 Segment Profit $590 - 6151 $500 - 5652 $585 - 655 Annual DD&A 270 - 280 290 - 300 300 - 310 Segment Profit + DDA $860 - 895 $790 - 865 $885 - 965 Capital Spending $370 - 420 $600 - 700 $250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 5/05/05 is shown in italics directly below Gas Pipeline 1 Includes YTD nonrecurring adjustments which increase reported earnings by $35 million A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams Web site at www.williams.com. 2 Assumes as of 1/1/06 refinancing of $230 million of debt and additional financing of $470 million for Gulfstream ($700 million total) is reflected in these amounts. Impact of Pipeline Safety Improvement Act accounting rule not reflected 555 - 585 835 - 875 280 - 290 475 - 550 565 - 635 865 - 945 |
| 2005-2007 Capital Spending Detail $250 - 325 $600 - 700 $370 - 420 Total 70 - 90 10 - 20 20 - 30 2 276 48 $180 - 235 $310 - 400 $305 - 335 Normal Maintenance/ Compliance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion Note: Sum of ranges may not add due to rounding Gas Pipeline 475 - 550 190 - 245 |
| Key Points Another strong quarter; operationally and financially Strong free cash flow generator Increased 2005 guidance due to strong YTD recurring earnings and impacts of prior period items Increased 2007 guidance as higher capital expected to be recovered through rates Guidance not reflective of impact related to accounting ruling on PSIA Continued progress in compliance and reliability projects Expansion development opportunities continue Gas Pipeline |
| Power Bill Hobbs Senior Vice President |
| Segment Profit Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Gross Margin (Includes MTM) $(35) $72 $105 $71 SG&A (17) (20) (33) (36) Operating & Other Inc. / (Expense) (23) (8) (33) (23) Segment Profit/(Loss) (Includes MTM) $(75) $44 $39 $12 MTM Adjustments 55 (59) (53) 53 Segment Profit/(Loss) After MTM Adjustments $(20) $(15) $(14) $65 Segment Profit/(Loss) (Includes MTM) $(75) $44 $39 $12 Nonrecurring: Expense related to prior period 0 0 8 0 Expense related to Settlements and Litigation Contingencies 13 0 17 0 Recurring Segment Profit/(Loss) $(62) $44 $64 $12 MTM Adjustments 55 (59) (53) 53 Recurring Segment Profit/(Loss) After MTM Adjustments $(7) $(15) $11 $651 Power 1 Includes impact of legacy natural gas portfolio that liquidated in 1Q04. |
| Power 1 Includes YTD nonrecurring adjustments which decrease reported earnings by $25 million. Power Segment Standalone CFFO would be $25 million higher on a recurring basis. A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com. YTD - Segment Profit to Cash Flow Dollars in Millions Power & Natural Gas Other Total YTD Gross Margin $105 $105 SG&A & Other Inc/(Exp) (66) (66) Segment Profit/(Loss)1 39 0 39 MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (243) (243) Add Realized Gains from MTM previously recognized 190 190 Segment Profit/(Loss) after MTM Adjustments1 (14) 0 (14) Total Working Capital Change 99 99 Power Segment CFFO (14) 99 85 Est. Working Capital Used for Other BU's (55) (55) Power Segment Standalone CFFO ($14) $44 $30 |
| 2005 2006 2007 5/05/05 Segment Profit Guidance ($50) - 50 ($250) - (100) ($200) - (50) MTM Earnings (2Q05) 22 Est. Forward Impact of 2Q05 MTM 4 (20) (18) YTD Non-Recurring (25 ) - - Total Impact 1 (20) (18) Change in Segment Profit Guidance - (20) (20) Segment Profit Guidance (50) - 50 (270) - (120) (220) - (70) MTM Adjustments 75 320 270 100 300 250 Reported Segment Profit after MTM Adj 25 - 125 50 - 200 50 - 200 50 - 150 Unchanged Non-Recurring 25 0 0 Recurring Segment Profit after MTM Adj 50 - 150 50 - 200 50 - 200 Unchanged Unchanged Capital Expenditures - - - Dollars in millions 2005-2007 Guidance Power Note: If guidance has changed, previous guidance from 5/05/05 is shown in italics directly below Cash Flow from Operations 50 - 150 50 - 200 50 - 200 |
| Cash Flow Analysis Undiscounted dollars in millions (GAAP Measure) Note: 2Q05 forecast estimated as of 12/30/04. 2Q05 actual cash flows agree in total with Power's Cash Flow Statement; however the allocation of actual cash flows to the various deal types is based on estimates. The YTD05 forecasted "Merchant Cash Flows" represents both the "Estimated Hedged Tolling Revenues" and "Merchant Cash Flows" in the forecast. Note: Sum of ranges for each business line does not necessarily match total range. Power Combined Power Portfolio Actual v. Forecast 2Q05 Q1'05A Q2'05A Q2'05F YTD05A YTD05F Tolling Demand Payment Obligations ($89) ($99) ($98) ($188) ($188) Resale of Tolling 41 41 33 82 73 Full Requirements (2) 7 7 5 6 Long-term Physical Forward Power Sales 22 21 23 43 44 OTC Hedges 34 38 29 72 70 Estimated Merchant Cash Flows 15 28 42 43 52 Total Cash Flows 21 36 35 57 58 NG & Other Commodity 11 (16) (15) (5) 0 SG&A and Other (26) (40) (18) (66) (36) Working Capital & Other 42 57 (35) 98 22 Estimated Cash Flows 48 37 (34) 85 45 Est. Working Capital Used for Other BU's 13 (68) 0 (55) 0 Power Standalone Cash Flows $61 ($31) ($34) $30 $45 |
| Key Points Recurring results on target CFFO YTD positive and on target Seasonal cash flows - 3rd quarter is historically best quarter for merchant power Full year recurring segment profit guidance remains unchanged Deal flow is increasing Application of FAS133 reduces 2Q05 earnings volatility Market outlook for 2006-2007 improving Power |
| 2005-2007 Consolidated Outlook Don Chappel CFO |
| Segment profit before MTM adjustment $1,300 - $1,585 $1,275 - $1,575 Net Interest Expense (650) - (670) (630) - (665) Other (Primarily General Corp. Costs) (70) - (100) (80) - (110) Pretax Income 580 - 815 565 - 800 Provision for Income Tax (220) - (335) (235) - (320) Income from Continuing Ops 360 - 480 330 - 480 Income/(Loss) from Discontinued Ops (10) - 0 (10) - 0 Net Income $350 - 480 $320 - 480 Diluted EPS $0.58 - $0.79 $0.53 - $0.80 Recurring Income from Cont. Ops $377 - $497 $326 - $476 Diluted EPS - Recurring $0.62 - $0.82 $0.54 - $0.80 Diluted EPS- Recurring After MTM Adjustments1 $0.70 - $0.90 $0.65 - $0.90 1 Includes MTM adjustment of $75 million (pretax) in Aug 4 guidance and $100 million (pretax) in May 5 guidance Note: Fully diluted shares of 605 million used in Aug 4 guidance and 599 million used in May 5 guidance Dollars in millions, except per-share amounts Aug 4 Guidance Consolidated 2005 Forecast Guidance May 5 Guidance |
| Dollars in millions 2005-2007 Segment Profit - Reported Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. 20051 2006 Consolidated $410 - 485 400 - 470 590 - 615 (50) - 50 (50) - (35)2 $1,300 - 1,585 75 $1,375 - 1,660 $520 - 595 400 - 500 500 - 565 (270) - (120) 45 - (45) $1,195 - 1,495 320 $1,515 - 1,815 Note: If guidance has changed, previous guidance from 5/5/05 is shown in italics directly below 1 Includes YTD nonrecurring adjustments which decrease reported earnings by $35 million 2 Includes effects of impairments of $53 million 2007 $595 - 720 400 - 520 585 - 655 (220) - (70) 10 - (30) $1,370 - 1,795 270 $1,640 - 2,065 400 - 475 480 - 555 550 - 675 370 - 450 555 - 585 (200) - (50) 1,275 - 1,575 300 250 1,675 1,475 - 1,775 1,575 - 2,000 1,175 - 1,475 1,325 - 1,750 (250) - (100) 565 - 635 0 - 15 100 |
| Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. Reported Consolidated $410 - 485 400 - 470 590 - 615 (50) - 50 (50) - (35) $1,300 - 1,585 75 $1,375 - 1,660 YTD Non-Recurring ($8) - - (35) 25 53 $35 - - $35 Recurring $402 - 477 400 - 470 555 - 580 (25) - 75 3 - 18 $1,335 - 1,620 75 $1,410 - 1,695 Power After MTM Adj. $25 - 125 $25 $50 - 150 2005 Segment Profit - Recurring Note: Sum of ranges for each business line does not necessarily match total range. |
| 2005 2006 2007 Exploration & Prod. $605 - 680 $760 - 860 $735 - 885 Midstream 120 - 140 110 - 130 100 - 130 Gas Pipeline 370 - 420 600 - 700 250 - 325 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,100 - 1,300 $1,525 - 1,750 $1,100 - 1,300 Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 5/5/05 is shown in italics directly below Consolidated 2005-2007 Capital Expenditures 530 - 605 725 - 825 725 - 875 475 - 550 1,025 - 1,225 1,350 - 1,550 |
| 1 Includes non-recurring adjustments of $35 million 2 Operating free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 5/5/05 is shown in italics directly below Dollars in millions 2005-2007 Outlook Consolidated Segment Profit1 Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Operating Free Cash Flow2 2005 $1,300 - 1,585 75 $1,375 - 1,660 700 - 775 1,150 - 1,450 1,100 - 1,300 50 - 150 2006 $1,195 - 1,495 320 $1,515 - 1,815 770 - 870 1,550 - 1,850 1,525 - 1,750 25 - 100 2007 $1,370 - 1,795 270 $1,640 - 2,065 840 - 940 1,650 - 1,950 1,100 - 1,300 550 - 650 1,275 - 1,575 100 300 250 1,675 1,475 - 1,775 1,575 - 2,000 1,175 - 1,475 1,325 - 1,750 750 - 850 800 - 900 1,025 - 1,225 1,350 - 1,550 275 - 375 100 - 200 1,300 - 1,600 1,450 - 1,750 1,600 - 1,900 500 - 600 |
| Dollars in millions 2005-2007 Guidance Reconciliation Consolidated Capital Expenditures May 5 Guidance E&P: Ft. Worth Basin Entry / Drilling Gas Pipes: New 2006 Projects Other Misc / Rounding Aug. 4 Guidance 2005 $1,025 - 1,225 75 - - - - $1,100 - 1,300 2006 $1,350 - 1,550 35 125 - 150 15 $1,525 - 1,750 2007 $1,100 - 1,300 - - - - - - $1,100 - 1,300 Segment Profit 1 May 5 Guidance - Reported E&P: Ft. Worth Basin Entry / Drilling Hedge Collars Midstream: Margins Gas Pipes: New 2006 Projects 2 Q Nonrecurring Items Other Misc / Rounding Aug. 4 Guidance - Reported $1,375 - 1,675 5 5 30 - 20 - - (44) 4 - (1) $1,375 - 1,660 $1,475 - 1,775 20 20 - - - - - - - - $1,515 - 1,815 $1,575 - 2,000 20 25 - - 20 - - - - $1,640 - 2,065 1 Segment Profit After MTM Adjustment |
| Dollars in millions 2005-2007 Guidance Reconciliation Consolidated Cash Flow from Operations (CFFO): May 5 Guidance Tax Settlement Reclassification to "Investing"1 E&P Segment Profit Increase Midstream Segment Profit Increase Other Increases - net Aug. 4 Guidance 2005 $1,300 - 1,600 (180) - (200) (88) 10 30-20 78 - 108 $1,150 - 1,450 2006 $1,450 - 1,750 20 - - 40 - - 40 $1,550 - 1,850 2007 $1,600 - 1,900 25 - - 45 - - (20) $1,650 - 1,950 1 Contract termination payment previously included in CFFO |
| Strong Operating Cash Flow Growth & Increasing Investment Opportunities . . . Consolidated 2003 2004 2005 2006 2007 Cap Ex-Low 790 1100 1525 1100 Cap Ex-High 790 1300 1750 1300 CFFO-Low 588 1482 1150 1550 1650 CFFO-High 588 1473 1450 1850 1950 Debt to Cap 0.75 0.623 0.58 0.57 0.54 0.75 0.623 0.59 0.58 0.56 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,473 $1,150 to $1,450 $1,550 to $1,850 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% 58% to 59% 57% to 58% 54% to 56% $1,650 to $1,950 75% $588 $1,100 to $1,300 $1,525 to $1,750 $1,100 to $1,300 $790 Cap Ex Increasing Cash Flow Declining Debt / Cap % Opportunity Rich |
| Segment Profit Guidance Trend Consolidated 2004 2005 2006 2007 SPAM Low 1263 1375 1515 1640 SPAM High 1263 1660 1815 2065 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1100 1525 1100 Cap Ex-High 790 1300 1750 1300 $ Millions $1,375 to $1,660 $1,515 to $1,815 $1,640 to $2,065 $1,263 (recurring) * Includes MTM adjustments of ($118) in 2004, $75 in 2005, $320 in 2006, and $270 in 2007 Segment Profit After MTM Adjustments * (1-Yr CAGR) 13.6% 14.8% 20.2% (2-Yr CAGR) (3-Yr CAGR) |
| Drive/enable sustainable growth in EVA(r)/shareholder value Maintain a cash/liquidity cushion of $1.0 billion plus Continue to steadily improve credit ratios/ratings; ultimately achieving investment grade ratios Reduce risk in Power segment Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA-adding opportunities may require new capital If new capital is needed, choose optimal sources of capital Combination of growth in operating cash flows and EVA drives value creation Financial Strategy/Key Points Consolidated |
| Summary Steve Malcolm Chairman, President & CEO |
| Hitting on all cylinders Business segment performance Consolidated earnings Cash from operations Growth opportunities growing Growth activity moving key performance measures up Seizing rich opportunities to grow shareholder value Key Points Summary |
| Q&A |
| Non-GAAP Reconciliations |
| Non-GAAP Disclaimer This presentation includes certain financial measures, EBITDA, recurring earnings, free cash flow and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. EBITDA represents the sum of net income (loss), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Recurring earnings and recurring segment profit provide investors meaningful insight into the Company's results from ongoing operations. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Company's assets and the cash that the business is generating. Neither EBITDA nor recurring earnings and recurring segment profit are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. Certain financial information in this presentation is also shown including Power mark-to-market adjustments. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Previously the Company did not qualify for hedge accounting with respect to its Power segment as a result of the Company's stated intent to exit the Power business. The Company ceased efforts to market the sale of Power during the third quarter 2004, and now qualifies for hedge accounting. Hedge accounting reduces earnings volatility associated with Power's portfolio of certain derivative hedging instruments. Prior to the adoption of hedge accounting, these derivative hedging instruments were accounted for on a mark-to-market basis with the change in fair value recognized in earnings each period. Management uses the mark-to-market adjustments to better reflect Power's results on a basis that is more consistent with Power's portfolio cash flows and to aid investor understanding. The adjustments reverse forward unrealized mark-to- market gains or losses from derivatives and add realized gains or losses from derivatives for which mark-to-market income has been previously recognized, with the effect that the resulting adjusted segment profit is presented as if mark-to-market accounting had never been applied to designated hedges or other derivatives. The measure is limited by the fact that it does not reflect potential unrealized future losses or gains on derivative contracts. However, management compensates for this limitation since reported earnings do reflect unrealized gains and losses of derivative contracts. Overall, management believes the mark-to-market adjustments provide an alternative measure that more closely matches realized cash flows for the Power segment. |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation |
| EBITDA Reconciliation 178 DD&A 42 Provision for Income Taxes 163 Net Interest Expense $41 Net Income $423 EBITDA (1) (Income) Loss from Disc. Operations Non-GAAP Reconciliation 2Q05 Dollars in millions YTD $242 1 327 356 171 $1,097 |
| * Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Total Segment Profit (Loss) $256 DD&A 178 Segment Profit before DDA $434 General Corporate Expense (36) Investing Income* 21 Other Income 4 TOTAL $423 Gas Pipeline $109 46 $155 Corp/Other ($58) ($61) 3 $231 $177 E&P Midstream $165 $118 66 59 $(71) Power $(75) 4 2Q 2005 Segment Contribution Non-GAAP Reconciliation |
| Net Income $350 - 480 $320 - 480 (Income) Loss from Disc. Ops. 10 - 0 10 - 0 Net Interest 650 - 670 630 - 665 DD&A 700 - 775 700 - 775 Provision for Income Taxes 220 - 335 235 - 320 Other/Rounding - (20) - (15) EBITDA - Reported $1,930 - 2,260 $1,875 - 2,225 MTM Adjustments 75 100 EBITDA - Reported after MTM Adj. $2,005 - 2,335 $1,975 - 2,325 Dollars in millions Consolidated Aug 4 Guidance May 5 Guidance 2005 Forecast EBITDA Reconciliation |
| 2005 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 $(50) - 50 10 - 20 $(40) - 70 Gas Pipeline $590 - 615 270 - 280 $860 - 895 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) TOTAL REPORTED E&P $410 - 485 235 - 265 $645 - 750 Midstream $400 - 470 180 - 190 $580 - 660 Total * $1,300 - 1,585 700 - 775 $2,000 - 2,360 (70) - (100) $1,930 - 2,260 Corp/ Other $(50) - (35) 5 - 20 $(45) - (15) Dollars in millions 1 Segment Profit is on a reported basis and prior to MTM adjustments |
| Net Income $350 - 480 $320 - 480 Discontinued Operations 10 - 0 10 - 0 Income from Continuing Ops $360 - 480 $330 - 480 Non-Recurring Items (Pretax) 23 (7) Less Taxes @ Approx. 39% (6) 3 Non-Recurring After Tax 17 (4) Recurring Income from Cont. Ops $377 - 497 $326 - 476 Recurring EPS $0.62 - $0.82 $0.54 - $0.80 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Inc. from Cont. Ops after MTM Adj. Inc. from Cont. Ops after MTM Adj. EPS 75 (29) 46 $423 - 543 $0.70 - $0.90 100 (39) 61 $387 - 537 $0.65 - $0.90 2005 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts Aug 4 Guidance May 5 Guidance |
| Appendix |
| Consolidated EPS $0.34 $0.07 - - $0.41 Recurring EPS 0.33 0.11 - - 0.45 Rec. EPS after MTM Adj. 0.22 0.17 - - 0.39 Average Shares (MM) 599 579 - - 603 2005 1Q 2Q 3Q 4Q Total EPS $0.02 ($0.03) $0.19 $0.13 $0.31 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS Metrics |
| Interest on Long-Term Debt $575 - 585 Amortization Discount/Premium and other Debt Expense 25 Credit Facilities: (incl. Commitment Fees plus LC Usage) 32 - 40 Interest on other Liabilities 23 - 30 Interest Expense $655 - 680 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $650 - 670 Dollars in millions 2005 Consolidated 2005 Interest Expense Guidance |
| Drivers Consolidated Dollars in millions Segment (Based on Guidance Midpoints) Profit CFFO 2004 1,381 1 1,473 Interest Savings - - 245 Tax Settlement - - (200) 2005 Longhorn Impairment (50) - - Gas Pipes - Lower Grays Harbor (15) (18) - 2005 Non Recurring Items 41 - - - Remove 2004 One Time Gains (9) - Remove 2004 DD&A Adjust. 10 - Gulfstream Higher Firm Transportation 16 - - Midstream - Lower NGL Margins (40) - - - Deepwater Increase - - 40 Changes in Power 2 (75) 100 Margins / Adequacy Assurances - - (565) E&P - Price Changes 115 115 - Volume Increases 100 125 Other (32) (15) 2005 1,443 1,300 Interest Savings - - 5 Tax Settlement - - 200 2005 Longhorn Impairment 50 - - Gas Pipes - Remove 2005 Non Recurring Items (41) - - - Higher Costs (30) - - Changes in Power (195) 25 Midstream - NGL Margins (30) - - - Deepwater Increase 80 35 E&P - Price Changes (25) (25) - Volume Increases 135 155 Other (42) 5 2006 1,345 1,700 Interest Savings - - 5 Changes in Power 50 - - Increase in Gas Pipes 106 111 Midstream - Deepwater Increase 15 15 E&P - Price Changes (50) (50) - Volume Increases 150 170 Other (34) (151) 2007 1,583 1,800 1 Recurring |
| Dollars in millions 2005-2007 Maintenance vs. Growth Capital Note: Sum of ranges for each business line does not necessarily match total range Explor. & Prod. Growth Maintenance Total Midstream Growth Maintenance Total Gas Pipeline Growth Maintenance Total Power Other/Corp - Maint. Total: Growth Maintenance Total $415 - 470 190 - 210 $605 - 680 60 - 75 60 - 65 $120 - 140 20 - 30 350 - 390 $370 - 420 - $10 - 30 495 - 575 610 - 695 $1,100 - 1,300 $550 - 630 210 - 230 $760 - 860 60 - 75 50 - 55 $110 - 130 10 - 20 590 - 680 $600 - 700 - $10 - 30 620 - 725 860 - 995 $1,525 - 1,750 $505 - 635 230 - 250 $ 735 - 885 50 - 70 50 - 60 $100 - 130 70 - 90 180 - 235 $250 - 325 - $10 - 30 625 - 795 470 - 575 $1,100 - 1,300 2005 2006 2007 Consolidated |
| 2005 Effective Tax Rates Dollars in millions Consolidated FIrst Quarter 2005 Federal 115 35% State 14 4% Foreign (5) - -2% Other 5 2% Tax Provision 129 $ 39% Second Quarter 2005 Federal 29 35% State 1 3% Foreign 5 6% Other 7 7% Tax Provision 42 $ 51% Year-to-Date 2005 Federal 145 35% State 16 4% Foreign 0 0% Other 10 2% Tax Provision 171 $ 41% Effective Tax Rate Guidance 1 Cash Tax Rate Guidance 2 Note 1: An additional $25 million income tax expense is forecast in 2006 & 2007. Note 2: We have reached preliminary settlement with the Internal Revenue Service relating to an outstanding tax issue associated with prior years. As a result of the preliminary settlement, we expect to make a payment totaling approximately $180-$200 million in the last half of 2005, all of which is accrued at June 30, 2005. The expected settlement is subject to the approval of the Joint Committee on Taxation. Note 3: Discontinued operations in 2005 have less than $1 million tax impact. 3-5% 4-8% 5-10% 2005 See Above 2006 39% Continuing Operations 3 2007 39% |
| 2Q 2005 Net Realized Price Calculation Exploration & Production 2Q05 Unhedged Hedge Market Price: NYMEX including collars $6.60 - $6.80 $4.60 Basis Differential (0.50 - 0.70) (0.48) Net basin market price $5.90 - $6.30 $4.12 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $4.90 - $5.50 $3.12 - $3.32 Quarter Volume Totals (qtr daily volumes (qtr daily qtr daily hedged volumes) hedge volumes) x (91/1000) x (91/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price) |
| 2005 Price Modeling Unhedged Price (NYMEX) $6.34 $5.96 $5.75 2005 2006 2007 Note: Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes Exploration & Production 2nd Half 2005 2005 Unhedged Hedge Market Price: NYMEX $6.10 - $6.50 $4.48 Basis Differential (0.50 - 0.70) (0.45) Net basin market price $5.40 - $6.00 $4.03 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $4.40 - $5.20 $3.03 - $3.23 Year Volume Totals (Bcfe) (total daily vols (daily hedge - - daily hedge vols) volumes) x x (183/1000) (183/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price) |
| Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2000-2004. Midstream Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) 0 5 10 15 20 25 Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Q1'05 Q2'05 0 100 200 300 400 500 600 700 Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin |
| Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 718 812 823 Commodity 301 237 200 200 Note: Total revenues less cost of goods sold. Reflects 5 year average (Jan '00-Dec '04) margins in 2006-2007 at mid-point of range. Midstream 30% 70% 25% 21% 20% 75% 79% 80% |
| Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted average margin. Midstream 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2004 Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Strong Free Cash Flow |
| Gas Pipeline Dollars in millions Strong Free Cash Flow 2003 2004 2005 2006 2007 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion Maintenance Mandatory Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2005 - 2007. |
| Margins & Ad. Assur. $6 - $53 - $59 Prepayments - 1 34 - 35 Subtotal $6 $1 $87 - $94 Letters of Credit 469 183 270 92 1,013 Total as of 6/30/05 $475 $184 $357 $92 $1,107 Total as of 3/31/05* $566 $169 $311 $90 $1,136 Change ($91) $15 $46 $2 ($29) Corp./ E&P Midstream Power Other Total Dollars in millions As of 6/30/05 *Note: The allocation of LC's between business units as of 3/31 has been adjusted from that previously reported. Total 3/31/05 LC's reported is unchanged. WMB Collateral Outstanding |
| Margin volatility (1% chance of exceeding) - - Potential incremental collateral requirement 6/30/05 3/31/05 30 days ($178) ($124) 180 days ($458) ($328) 360 days ($351) ($341) Assumption: The margin numbers above consist of only the forward marginable position values, starting from August 2005. Dollars in millions WMB Collateral Sensitivity |
EXHIBIT 99.3
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NYSE: WMB
Date: Aug. 4, 2005
Williams Increases Total Estimated Domestic Reserves by 21 Percent
Growth Comes From an Increase in Piceance Basin Drilling Locations
Growth Comes From an Increase in Piceance Basin Drilling Locations
TULSA, Okla. — Williams (NYSE:WMB) announced today that is has increased the company’s
total proved, probable and possible domestic reserves to an estimated 8.5 trillion cubic feet
equivalent (Tcfe) — an increase of 21 percent from the previous estimate of 7 Tcfe.
The increase in estimated reserves is based on results from a review of Williams’ assets in
the Piceance Basin. Williams considers the Piceance as its cornerstone property for production
growth.
“We are actively developing our reserves base, which continues to grow primarily through the
drill bit,” said Steve Malcolm, chairman, president and chief executive officer. “As we’ve said,
the experience and expertise we’ve established in our core basins enhances our ability to capture
existing and new opportunities for reserves additions.”
During the second quarter, Williams conducted an internal review of potential well sites in
the Piceance Basin of western Colorado.
The company examined topography, recent drilling results, current economic conditions and
geological data in light of the upcoming deployment of 10 new FlexRig4® drilling rigs from
Helmerich & Payne. Williams expects to receive one new rig per month, beginning in November.
The rigs are designed to drill up to 22 wells — in an underground spoke formation — from
a single surface location that is half the size of traditional drilling sites. This should dramatically reduce both
the number and the size of surface locations needed to drill wells.
Williams now projects as many as 4,600 drilling locations in the Piceance — an increase of
approximately 50 percent compared with previous estimates of 3,000 locations.
The 4,600 drilling locations are for operations solely in the valley area of the Piceance.
The new estimate excludes potential locations from other company projects in the Piceance Basin such as Trail Ridge,
Ryan Gulch and Red Point.
Based on this data, Williams raised its estimate of total probable and possible domestic
reserves from 4 Tcfe to 5.5 Tcfe.
Coupled with the company’s year-end 2004 proved U.S. reserves of 3 Tcfe, Williams now has
total proved, probable and possible domestic reserves of an estimated 8.5 Tcfe.
About Williams (NYSE:WMB)
Williams, through its subsidiaries, primarily finds, produces, gathers, processes and transports natural gas. The company also manages a wholesale power business. Williams’ operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard. More information is available at www.williams.com.
Williams, through its subsidiaries, primarily finds, produces, gathers, processes and transports natural gas. The company also manages a wholesale power business. Williams’ operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard. More information is available at www.williams.com.
Contact:
|
Kelly Swan | |
| Williams (media relations) | ||
| (918) 573-6932 | ||
| Richard George | ||
| Williams (investor relations) | ||
| (918) 573-3679 | ||
| Karl Meyer | ||
| Williams (investor relations) | ||
| (918) 573-4395 |
# # #
Portions of this document may constitute “forward-looking statements” as defined by federal
law. Although the company believes any such statements are based on reasonable assumptions, there
is no assurance that actual outcomes will not be materially different. Any such statements are made
in reliance on the “safe harbor” protections provided under the Private Securities Reform Act of
1995. Additional information about issues that could lead to material changes in performance is
contained in the company’s annual reports filed with the Securities and Exchange Commission.
In regard to the company’s reserves in Exploration & Production, the SEC permits oil and gas
companies, in their filings with the SEC, to disclose only proved reserves. We have used certain
terms in this news release, such as “probable” reserves and “possible” reserves and “new
opportunities potential” reserves that the SEC’s guidelines strictly prohibit us from including in
filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of
potential reserves that are made using accepted geological and engineering analytical techniques,
but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve
estimates are less certain than those for probable reserves. New opportunities potential is an
estimate of reserves for new areas for which we do not have sufficient information to date to raise
the reserves to either the probable category or the possible category. New opportunities potential
estimates are even less certain that those for possible reserves.
Reference to “total resource portfolio” include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at www.williams.com.
Reference to “total resource portfolio” include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at www.williams.com.