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| WMB > SEC Filings for WMB > Form 10-Q on 30-Apr-2009 | All Recent SEC Filings |
30-Apr-2009
Quarterly Report
Continuing to invest in our natural gas production development, although at a lower level than in recent years;
Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions, as well as seizing attractive opportunities.
Potential risks and/or obstacles that could impact the execution of our plan
include:
Lower than anticipated commodity prices;
Lower than expected levels of cash flow from operations;
Availability of capital;
Counterparty credit and performance risk;
Decreased drilling success at Exploration & Production;
Decreased drilling success or abandonment of projects by third parties served by Midstream and Gas Pipeline;
Additional general economic, financial markets, or industry downturn;
Changes in the political and regulatory environments;
Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 14 of Notes to Consolidated Financial Statements).
Management's Discussion and Analysis (Continued)
We continue to address these risks through utilization of commodity hedging
strategies, focused efforts to resolve regulatory issues and litigation claims,
disciplined investment strategies, and maintaining at least $1 billion in
liquidity from cash and cash equivalents and unused revolving credit facilities.
In addition, we utilize master netting agreements and collateral requirements
with our counterparties.
Income (loss) from continuing operations attributable to The Williams
Companies, Inc., for the three months ended March 31, 2009, changed unfavorably
by $581 million compared to the three months ended March 31, 2008. This decrease
is reflective of:
A net after-tax loss of $246 million related to impairments and other
charges associated with our Venezuela operations and investments (see Note 3
of Notes to Consolidated Financial Statements);
The overall unfavorable commodity price environment in the first quarter of 2009 as compared to 2008;
The absence of a $118 million pre-tax gain recorded in the first quarter of 2008 associated with the sale of our Peru interests.
See additional discussion in Results of Operations.
Our net cash provided by operating activities for the three months ended
March 31, 2009, decreased $281 million compared to the three months ended
March 31, 2008, primarily due to the decrease in our operating results. See
additional discussion in Management's Discussion and Analysis of Financial
Condition.
Recent Events
In March 2009, we issued $600 million aggregate principal amount of
8.75 percent senior unsecured notes due 2020 to certain institutional investors
in a private debt placement. (See Note 10 of Notes to Consolidated Financial
Statements.)
In April 2009, we announced the formation of a new midstream venture in the
Marcellus Shale located in southwest Pennsylvania. (See Note 17 of Notes to
Consolidated Financial Statements.)
General
Unless indicated otherwise, the following discussion and analysis of Results
of Operations and Financial Condition relates to our current continuing
operations and should be read in conjunction with the Consolidated Financial
Statements and notes thereto included in Item 1 of this document and our 2008
Annual Report on Form 10-K.
Fair Value Measurements
Certain of our energy derivative assets and liabilities and other assets
trade in markets with lower availability of pricing information requiring us to
use unobservable inputs and are considered Level 3 in the fair value hierarchy.
At March 31, 2009, 35 percent of the total assets and 4 percent of the total
liabilities measured at fair value on a recurring basis are included in Level 3.
For Level 2 transactions, we do not make significant adjustments to observable
prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value also incorporates the time value of money and
credit risk factors including the credit standing of the counterparties
involved, the existence of master netting arrangements, the impact of credit
enhancements (such as cash deposits and letters of credit) and our
nonperformance risk on our liabilities. Currently, our approach is to apply a
credit spread, based on the credit rating of the counterparty, against the net
derivative asset with that counterparty. For net derivative liabilities we apply
our own credit rating. We derive the credit spreads by using the corporate
industrial credit curves for each rating category and building a curve based on
certain points through time for each rating category. The spread comes from the
discount factor of the individual corporate curves versus the discount factor of
the LIBOR curve. At March 31, 2009, the credit reserve is $11 million on our net
derivative assets and $15 million on our net derivative liabilities. Considering
these factors and that we do not
Management's Discussion and Analysis (Continued)
have significant risk from our net credit exposure to derivative counterparties,
the impact of credit risk is not significant to the overall fair value of our
derivatives portfolio.
As of March 31, 2009, 80 percent of our derivatives portfolio expires in the
next 12 months and more than 99 percent of our derivatives portfolio expires in
the next 36 months. Our derivatives portfolio is largely comprised of
exchange-traded products or like products where price transparency has not
historically been a concern. Due to the nature of the markets in which we
transact and the relatively short tenure of our derivatives portfolio, we do not
believe it is necessary to make an adjustment for illiquidity. We regularly
analyze the liquidity of the markets based on the prevalence of broker pricing
and exchange pricing for products in our derivatives portfolio.
The instruments included in Level 3 at March 31, 2009, predominantly consist
of options that hedge future sales of production from our Exploration &
Production segment, are structured as costless collars and are financially
settled. The options are valued using an industry standard Black-Scholes option
pricing model. Certain inputs into the model are generally observable, such as
commodity prices and interest rates, whereas a significant input, implied
volatility by location, is unobservable. The impact of volatility on changes in
the overall fair value of the options structured as collars is mitigated by the
offsetting nature of the put and call positions. The change in the overall fair
value of instruments included in Level 3 primarily results from changes in
commodity prices. The hedges are accounted for as cash flow hedges where net
unrealized gains and losses from changes in fair value are recorded, to the
extent effective, in other comprehensive income (loss) and subsequently impact
earnings when the underlying hedged production is sold.
Exploration & Production has an unsecured credit agreement through
December 2013 with certain banks that, so long as certain conditions are met,
serves to reduce our usage of cash and other credit facilities for margin
requirements related to instruments included in the facility.
For the three months ended March 31, 2009, we have recognized impairments of
certain assets that have been measured at fair value on a nonrecurring basis.
These impairment measurements are included within Level 3 as they include
significant unobservable inputs, such as our estimate of future cash flows and
the probabilities of alternative scenarios. (See Note 12 of Notes to
Consolidated Financial Statements.)
Critical Accounting Estimates
Impairment of Goodwill
We have goodwill of approximately $1 billion at Exploration & Production
related to its domestic operations (the reporting unit) primarily resulting from
a 2001 acquisition. As disclosed in our 2008 Annual Report on Form 10-K, we
perform interim assessments of goodwill if an indicator of impairment is
present. One example of an impairment indicator is a decline in total market
capitalization below our total stockholders' equity. As of March 31, 2009, our
total market capitalization is below our total stockholders' equity balance.
Because quoted market prices are not available for the reporting unit,
management applied a range of reasonable judgments in estimating its fair value.
We estimated the fair value of the reporting unit on a stand-alone basis and
also considered our market capitalization in corroborating our estimate of the
fair value of the reporting unit. As of March 31, 2009, the estimated fair value
of the reporting unit exceeds its carrying value, including goodwill, indicating
no impairment of Exploration & Production's goodwill.
We estimated the fair value of the reporting unit on a stand-alone basis
primarily by valuing proved and unproved reserves. We used an income approach
(discounted cash flows) for valuing reserves. The significant inputs into the
valuation of proved reserves included reserve quantities, forward natural gas
prices, anticipated drilling and operating costs, anticipated production curves
and appropriate discount rates. Unproved reserves were valued using similar
assumptions adjusted further for the uncertainty associated with these reserves.
In estimating the inputs, management must make assumptions that require
judgments and are subject to change in response to changing market conditions
and other future events. Significant assumptions in valuing proved reserves
included prior year-end reserve quantities updated for first-quarter 2009
production, natural gas prices, adjusted for locational differences, averaging
approximately $5.77 per Mcfe, and a pre-tax discount rate of 15 percent. Our
discount rate was developed considering the risk inherent in the cash flows of
an exploration and production business, recognizing that market participants may
use varying discount factors when evaluating the fair value of a comparable
business portfolio.
Management's Discussion and Analysis (Continued)
We further reviewed the fair value of the reporting unit estimated on a
stand-alone basis, by considering our market capitalization in a reconciliation
of the fair values of all our businesses, including the reporting unit. In this
reconciliation, we determined our market capitalization, including a control
premium, and estimated the fair values of all our businesses considering certain
financial performance metrics. The range of control premiums that we considered
were consistent with historical market sales transactions and also considered
the current market environment. Market capitalization was based on our traded
stock price for a reasonably short period of time before and after March 31,
2009. This analysis allowed management to consider market expectations in
corroborating the reasonableness of the estimated fair value of the reporting
unit.
We cannot predict future market conditions and events that might adversely
affect the estimated fair value of the Exploration & Production reporting unit
and possibly the reported value of goodwill. The estimated fair value of the
reporting unit is significantly affected by natural gas prices, reserve
quantities and market expectations for required rates of return. Further
declines in natural gas prices would lower our estimates of fair value. There
are numerous uncertainties inherent in estimating quantities of reserves that
could affect our reserve quantities. Low prices for natural gas, regulatory
limitations, or the lack of available capital for projects could adversely
affect the development and production of additional reserves. Given the
significant challenges affecting our businesses and the energy industry in 2009,
these factors could impact us and require us to assess goodwill for possible
impairment again during 2009.
Impairments of Venezuela Operations and Investments
For the three months ended March 31, 2009, we have recognized significant
impairment charges related to our Venezuela operations and investments. These
impairment measurements required management to evaluate different factors and
scenarios and make considerably subjective estimates and assumptions regarding
matters that are susceptible to change. The use of alternate estimates and/or
assumptions would have resulted in the recognition of different impairment
charges. (See Note 3 of Notes to Consolidated Financial Statements.)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results
of operations for the three months ended March 31, 2009, compared to the three
months ended March 31, 2008. The results of operations by segment are discussed
in further detail following this consolidated overview discussion.
Three months ended
March 31,
2009 2008 $ Change* % Change*
(Millions)
Revenues $ 2,128 $ 3,204 -1,076 -34 %
Costs and expenses:
Costs and operating expenses 1,668 2,353 +685 +29 %
Selling, general and administrative
expenses 123 112 -11 -10 %
Provision for doubtful accounts and
notes 50 (1 ) -51 NM
Other (income) expense - net 270 (117 ) -387 NM
General corporate expenses 40 42 +2 +5 %
Total costs and expenses 2,151 2,389
Operating income (loss) (23 ) 815
Interest accrued - net (146 ) (157 ) +11 +7 %
Investing income (loss) (61 ) 55 -116 NM
Other income (expense) - net (2 ) 5 -7 NM
Income (loss) from continuing operations
before income taxes (232 ) 718
Provision (benefit) for income taxes (15 ) 263 +278 NM
Income (loss) from continuing operations (217 ) 455
Income (loss) from discontinued
operations (7 ) 84 -91 NM
Net income (loss) (224 ) 539
Less: Net income (loss) attributable to
noncontrolling interests (52 ) 39
Net income (loss) attributable to The
Williams Companies, Inc. $ (172 ) $ 500
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* + = Favorable change to net income; - = Unfavorable change to net income; NM = A percentage calculation is not meaningful due to change in signs or a percentage change greater than 200.
Three months ended March 31, 2009 vs. three months ended March 31, 2008 The decrease in revenues is due primarily to lower natural gas liquid (NGL) and olefin production revenues and lower NGL, olefin and crude marketing revenues at Midstream. Additionally, Exploration & Production revenues decreased due to lower net realized average prices, partially offset by increased production volumes sold.
Management's Discussion and Analysis (Continued)
The decrease in costs and operating expenses is due primarily to decreased
NGL, olefin and crude marketing purchases and decreased costs associated with
our olefins production business at Midstream.
The increase in provision for doubtful accounts and notes is due primarily to
the $48 million charge to fully reserve Midstream's receivables from Petr๓leos
de Venezuela S.A. (See Note 3 of Notes to Consolidated Financial Statements.)
Other (income) expense - net within operating income in 2009 includes
$247 million of impairments and related charges associated with Midstream's
Venezuela operations. (See Note 3 of Notes to Consolidated Financial
Statements.) Also included are $34 million of penalties from the early
termination of certain drilling rig contracts at Exploration & Production.
Other (income) expense - net within operating income in 2008 includes a gain
of $118 million on the sale of a contractual right to a production payment on
certain future international hydrocarbon production at Exploration & Production.
Also included are $10 million of net gains on foreign currency exchanges,
primarily at Midstream.
The unfavorable change in operating income (loss) reflects the $295 million
of impairments and related charges associated with Midstream's Venezuela
operations, an overall unfavorable energy commodity price environment in the
first quarter of 2009 compared to the first quarter of 2008, the absence of
$118 million gain on the sale our Peru interests at Exploration & Production in
2008, and other changes as discussed previously.
Interest accrued - net decreased primarily due to an increase in capitalized
interest resulting from ongoing construction projects at Midstream.
The unfavorable change in investing income (loss) is due primarily to a
$75 million impairment of Midstream's Accroven equity investment and an
$11 million impairment of a cost-based investment at Exploration & Production.
(See Note 3 of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed favorably primarily due to the
pre-tax loss associated with the three months ended March 31, 2009. See Note 6
of Notes to Consolidated Financial Statements for a discussion of the effective
tax rates compared to the federal statutory rate for both periods.
See Note 4 of Notes to Consolidated Financial Statements for a discussion of
the items in income (loss) from discontinued operations.
Net income (loss) attributable to noncontrolling interests decreased
primarily due to the impairments and related charges associated with Midstream's
Venezuela operations. (See Note 3 of Notes to Consolidated Financial
Statements.)
Management's Discussion and Analysis (Continued)
Results of Operations - Segments
Exploration & Production
Overview of Three Months Ended March 31, 2009
Segment revenues and segment profit for the first three months of 2009 were
significantly lower than the first three months of 2008 primarily due to the
unfavorable effect of a significant decline in net realized average prices
partially offset by higher production volumes. Additionally, the first three
months of 2009 include expense of $34 million associated with contractual
penalties from the early termination of drilling rig contracts. The first three
months of 2008 include a $118 million gain on sale of our Peru interests.
Highlights of the comparative periods include:
For the three months ended March 31,
2009 2008 % Change
Average daily domestic production (MMcfe) (1) 1,225 1,013 +21 %
Average daily total production (MMcfe) 1,278 1,062 +20 %
Domestic net realized average price ($/Mcfe) (2) $ 4.21 $ 6.58 -36 %
Capital expenditures ($ millions) $ 320 $ 391 -18 %
Segment revenues ($ millions) $ 553 $ 728 -24 %
Segment profit ($ millions) $ 78 $ 430 -82 %
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(1) MMcfe is equal to one million cubic feet of gas equivalent.
(2) Mcfe is equal to one thousand cubic feet of gas equivalent.
The increased production is primarily due to continued development within the Piceance, Powder River, and Fort Worth basins.
Net realized average prices include market prices, net of fuel and shrink and hedge gains and losses, less gathering and transportation expenses.
The decrease in capital expenditures reflects our decision to reduce development activities in 2009 because of declining natural gas prices.
Outlook for the Remainder of 2009
Our expectations and objectives for the remainder of the year include:
A reduced development drilling program, as compared to the prior year, in
the Piceance, Powder River, San Juan and Fort Worth basins. Our remaining
projected capital expenditures for 2009 are projected to be between
$630 million and $730 million, which includes the reduction in drilling rigs
deployed.
Slight growth in our annual average daily domestic production level compared to 2008, with fourth quarter 2009 volumes likely to be less than the prior comparable period.
Declines in cost of services and materials associated with development activities as demand for these resources decreases.
Risks to achieving our expectations and objectives include unfavorable
natural gas market price movements which are impacted by numerous factors,
including weather conditions, domestic natural gas production levels and demand,
and the downturn in the global economy. A further decline in natural gas prices
would impact these expectations for the remainder of the year.
In addition, changes in laws and regulations may impact our development
drilling program. For example, the Colorado Oil & Gas Conservation Commission
has enacted new rules effective in April 2009 which will increase
Management's Discussion and Analysis (Continued)
our costs of permitting and environmental compliance and potentially delay
drilling permits. The new rules include additional environmental and operational
requirements as part of permit approvals, tracking of certain chemicals brought
on location, increased wildlife stipulations, new pit and waste management
procedures and increased notifications and approvals from surface landowners.
Commodity Price Risk Strategy
To manage the commodity price risk and volatility of owning producing gas
properties, we enter into derivative forward sales contracts that fix the sales
price relating to a portion of our future production using NYMEX and basis
fixed-price contracts and collar agreements.
For the remainder of 2009, we have the following agreements and contracts for
our daily domestic production, shown at weighted average volumes and basin-level
weighted average prices:
Remainder of 2009
Price ($/Mcf)
Volume Floor-Ceiling for
(MMcf/d) Collars
Collar agreements - Rockies 150 $ 6.11 - $9.04
Collar agreements - San Juan 245 $ 6.58 - $9.62
Collar agreements - Mid-Continent 95 $ 7.08 - $9.73
NYMEX and basis fixed-price 106 $ 3.71
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The following is a summary of our agreements and contracts for daily production for the three months ended March 31, 2009 and 2008:
Three months ended March 31,
2009 2008
Price ($/Mcf) Price ($/Mcf)
Volume Floor-Ceiling for Volume Floor-Ceiling for
(MMcf/d) Collars (MMcf/d) Collars
Collars - Rockies 150 $ 6.11 - $9.04 200 $ 6.33 - $9.41
Collars - San Juan 245 $ 6.58 - $9.62 147 $ 6.26 - $8.78
Collars - Mid-Continent 95 $ 7.08 - $9.73 10 $ 7.12 - $8.67
NYMEX and basis fixed-price 107 $ 3.57 70 $ 3.92
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Additionally, we utilize contracted pipeline capacity through Gas Marketing
Services to move our production from the Rockies to other locations when pricing
differentials are favorable to Rockies pricing. We also expect additional
pipeline capacity to be put into service in late 2009 which will transport gas
into the Midwest.
Period-Over-Period Results
Three months ended
March 31,
2009 2008
(Millions)
Segment revenues $ 553 $ 728
Segment profit $ 78 $ 430
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Three months ended March 31, 2009 vs. three months ended March 31, 2008
Total segment revenues decreased $175 million, or 24 percent, primarily due
to the following:
$138 million, or 22 percent, decrease in domestic production revenues
reflecting $259 million associated with a 36 percent decrease in net
realized average prices, partially offset by an increase of $121 million
associated with a 20 percent increase in production volumes sold. Production
. . .
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