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| WMB > SEC Filings for WMB > Form 10-Q on 6-Aug-2009 | All Recent SEC Filings |
6-Aug-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 12 of Notes to Consolidated Financial Statements).
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.
Management's Discussion and Analysis (Continued)
Overview of Six Months Ended June 30, 2009
Income from continuing operations attributable to The Williams Companies,
Inc., for the six months ended June 30, 2009, decreased by $698 million compared
to the six months ended June 30, 2008.
This decrease is reflective of:
• The overall unfavorable commodity price environment in the first six months
of 2009 as compared to 2008;
• The absence of a $148 million pre-tax gain recorded in the first six months 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 six months ended
June 30, 2009, decreased $632 million compared to the six months ended June 30,
2008, primarily due to the decrease in our operating results. See additional
discussion in Management's Discussion and Analysis of Financial Condition and
Liquidity.
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. An offer to exchange these notes for substantially
identical new notes that are registered under the Securities Act of 1933, as
amended, was commenced in July 2009 and is expected to be completed in early
August 2009.
In April 2009, Midstream announced its plan to build a 261-mile natural gas
liquid pipeline in Canada at an estimated cost of $283 million. Construction is
expected to begin in 2010 with completion expected in 2012.
In May 2009, certain of Midstream's Venezuela operations were expropriated by
the Venezuelan government. As a result, these operations are now reflected as
discontinued operations and have been deconsolidated. (See Note 3 of Notes to
Consolidated Financial Statements.)
In June 2009, Midstream finalized the formation of a new joint venture in the
Marcellus Shale located in southwest Pennsylvania. (See Results of Operations -
Segments, Midstream Gas & Liquids).
In June 2009, Exploration & Production entered into an agreement to develop
properties in the Marcellus Shale located in southwest Pennsylvania. (See
Results of Operations - Segments, Exploration & Production.)
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 annual
consolidated financial statements and notes thereto in Exhibit 99.1 of our Form
8-K dated May 28, 2009.
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 June 30, 2009, 31 percent of the total assets and 8 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 for our assets and liabilities also
incorporates the time value of money and various credit risk factors which can
include the credit standing of the counterparties involved, master netting
Management's Discussion and Analysis (Continued)
arrangements, the impact of credit enhancements (such as cash collateral posted
and letters of credit), and our nonperformance risk on our liabilities. The
determination of the fair value of our liabilities does not consider noncash
collateral credit enhancements. For net derivative assets, we 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 in 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 June 30, 2009, the credit reserve is $1 million on our net
derivative assets and $5 million on our net derivative liabilities. Considering
these factors and that we do not 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 June 30, 2009, 91 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 June 30, 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 total other comprehensive 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 six months ended June 30, 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 10 of Notes to
Consolidated Financial Statements.)
Management's Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results
of operations for the three and six months ended June 30, 2009, compared to the
three and six months ended June 30, 2008. The results of operations by segment
are discussed in further detail following this consolidated overview discussion.
Three months ended Six months ended
June 30, June 30,
2009 2008 $ Change* % Change* 2009 2008 $ Change* % Change*
(Millions) (Millions)
Revenues $ 1,909 $ 3,657 -1,748 -48 % $ 3,831 $ 6,821 -2,990 -44 %
Costs and expenses:
Costs and operating
expenses 1,392 2,697 +1,305 +48 % 2,836 5,030 +2,194 +44 %
Selling, general and
administrative
expenses 129 131 +2 +2 % 254 242 -12 -5 %
Other
(income) expense -
net (1 ) (32 ) -31 -97 % 32 (146 ) -178 NM
General corporate
expenses 38 42 +4 +10 % 78 84 +6 +7 %
Total costs and
expenses 1,558 2,838 3,200 5,210
Operating income 351 819 631 1,611
Interest accrued -
net (145 ) (145 ) - - (287 ) (297 ) +10 +3 %
Investing income
(loss) 24 54 -30 -56 % (37 ) 109 -146 NM
Other income
(expense) - net 1 - +1 NM (1 ) 4 -5 NM
Income from
continuing
operations before
income taxes 231 728 306 1,427
Provision for income
taxes 80 257 +177 +69 % 136 508 +372 +73 %
Income from
continuing
operations 151 471 170 919
Income (loss) from
discontinued
operations 18 29 -11 -38 % (225 ) 120 -345 NM
Net income (loss) 169 500 (55 ) 1,039
Less: Net income
(loss) attributable
to non-controlling
interests 27 63 +36 +57 % (25 ) 102 +127 NM
Net income (loss)
attributable to The
Williams Companies,
Inc. $ 142 $ 437 $ (30 ) $ 937
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* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator, or a percentage change greater than 200.
Three months ended June 30, 2009 vs. three months ended June 30, 2008
The decrease in revenues is primarily due to decreased realized revenue at
Gas Marketing primarily due to a decrease in average natural gas prices as well
as lower natural gas liquid (NGL), olefin and crude marketing revenues and lower
NGL and olefin production revenues at Midstream. In addition, Exploration &
Production revenues decreased primarily due to lower net realized average
prices, partially offset by higher production volumes sold.
The decrease in costs and operating expenses is due primarily to decreased
costs at Gas Marketing primarily due to a decrease in average natural gas prices
as well as decreased NGL, olefin and crude marketing purchases and decreased
costs associated with our NGL and olefin production businesses at Midstream.
Other (income) expense - net within operating income in 2008 includes a
$30 million gain on the sale of our Peru interests at Exploration & Production.
The decrease in operating income reflects an overall unfavorable energy
commodity price environment in the second quarter of 2009 compared to the same
period in 2008.
The unfavorable change in investing income (loss) is primarily due to lower
equity earnings at Midstream and a decrease in interest income largely resulting
from lower average interest rates in 2009 compared to 2008.
Management's Discussion and Analysis (Continued)
Provision for income taxes decreased primarily due to lower pre-tax income.
See Note 5 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 3 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
reflecting the decline in Williams Partners L.P.'s operating results primarily
driven by lower NGL margins.
Six months ended June 30, 2009 vs. six months ended June 30, 2008
The decrease in revenues is due primarily to decreased realized revenue at
Gas Marketing primarily due to a decrease in average natural gas prices as well
as lower NGL, olefin and crude marketing revenues and lower NGL and olefin
production revenues at Midstream . In addition, Exploration & Production
revenues decreased primarily due to lower net realized average prices, partially
offset by higher production volumes sold.
The decrease in costs and operating expenses is due primarily to decreased
costs at Gas Marketing primarily due to a decrease in average natural gas prices
as well as decreased NGL, olefin and crude marketing purchases and decreased
costs associated with our NGL and olefin production businesses at Midstream.
Other (income) expense - net within operating income in 2009 includes
$32 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 $148 million on the sale of our Peru interests at Exploration & Production.
The decrease in operating income reflects an overall unfavorable energy
commodity price environment in the first half of 2009 compared to the first half
of 2008, the absence of a $148 million gain on the sale of 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, partially
offset by higher interest expense primarily associated with our March 2009 debt
issuance.
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 4 of Notes to Consolidated Financial Statements.) A decrease in
interest income, primarily due to lower average interest rates in 2009 compared
to 2008, and decrease in equity earnings, primarily at Midstream, also
contributed to the unfavorable change in investing income (loss).
Provision for income taxes decreased primarily due to lower pre-tax income.
See Note 5 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 3 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
reflecting the first-quarter 2009 impairments and related charges associated
with Midstream's discontinued Venezuela operations (see Note 3 of Notes to
Consolidated Financial Statements) and the decline in Williams Partners L.P.'s
operating results primarily driven by lower NGL margins.
Management's Discussion and Analysis (Continued)
Results of Operations - Segments
Exploration & Production
Overview of Six Months Ended June 30, 2009
Segment revenues and segment profit for the first six months of 2009 were
significantly lower than the first six months of 2008 primarily due to a sharp
decline in net realized average prices partially offset by higher production
volumes. Additionally, the first six months of 2009 include expense of
$32 million associated with contractual penalties from the early termination of
drilling rig contracts. The first six months of 2008 include a $148 million gain
on sale of our Peru interests. Highlights of the comparative periods include:
For the six months ended June 30,
2009 2008 % Change
Average daily domestic production (MMcfe) (1) 1,202 1,061 +13 %
Average daily total production (MMcfe) 1,255 1,110 +13 %
Domestic net realized average price ($/Mcfe) (2) $ 4.08 $ 7.35 -44 %
Capital expenditures incurred ($ millions) $ 519 $ 1,102 -53 %
Segment revenues ($ millions) $ 1,083 $ 1,676 -35 %
Segment profit ($ millions) $ 197 $ 926 -79 %
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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 development within the Piceance, Powder River, and Fort Worth basins. As previously discussed in Company Outlook, we have reduced development activities and related capital expenditures in 2009 which has resulted in production peaking during the first quarter of 2009 then decreasing slightly thereafter.
• Net realized average prices include market prices, net of fuel and shrink and hedge gains and losses, less gathering and transportation expenses.
Significant event
In June 2009, we entered into an agreement that allows us to acquire, through
a "drill to earn" structure, a 50 percent interest in approximately 44,000 net
acres in Pennsylvania's Marcellus Shale. This agreement requires us to fund
$33 million of drilling and completion costs on behalf of our partner and
$41 million of our own costs and expenses prior to the end of 2011 to earn our
50 percent interest. This growth opportunity leverages our experience in
developing non-conventional natural gas reserves.
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
capital expenditures for 2009 are projected to be between $450 million and
$550 million, which is reflective of a first-quarter 2009 reduction in
drilling rigs deployed and any additional capital expenditures to be
incurred in 2009 in Marcellus Shale as a result of the previously described
agreement.
• Slight growth in our annual average daily domestic production level compared to 2008, with fourth quarter 2009 volumes likely to be less than fourth quarter 2008 volumes.
Management's Discussion and Analysis (Continued)
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 condition of the global economy. A further decline in natural gas prices
would impact these expectations for the remainder of the year, although the
impact would be somewhat mitigated by our hedging program, which hedges a
significant portion of our expected production.
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 have increased our costs of
permitting and environmental compliance and could 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.
Our current outlook incorporates these changes, however, the extent and
magnitude of these changes could be greater than our current assumptions.
Commodity Price Risk Strategy
To manage the commodity price risk and volatility of owning producing gas
properties, we enter into derivative contracts for a portion of our future
production. For the remainder of 2009, we have the following 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
Collars - Rockies 150 $ 6.11 - $9.04
Collars - San Juan 245 $ 6.58 - $9.62
Collars - Mid-Continent 95 $ 7.08 - $9.73
NYMEX and basis fixed-price 106 $3.75
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The following is a summary of our contracts for daily production for the three and six months ended June 30, 2009 and 2008:
2009 2008
Price ($/Mcf) Price ($/Mcf)
Volume Floor-Ceiling for Volume Floor-Ceiling for
(MMcf/d) Collars (MMcf/d) Collars
Second Quarter:
Collars - Rockies 150 $ 6.11 - $9.04 160 $ 6.08 - $9.04
Collars - San Juan 245 $ 6.58 - $9.62 220 $ 6.37 - $9.00
Collars - Mid-Continent 95 $ 7.08 - $9.73 80 $ 7.02 - $9.77
NYMEX and basis fixed-price 106 $3.61 70 $4.00
Year-to-Date:
Collars - Rockies 150 $ 6.11 - $9.04 180 $ 6.22 - $9.24
Collars - San Juan 245 $ 6.58 - $9.62 184 $ 6.33 - $8.91
Collars - Mid-Continent 95 $ 7.08 - $9.73 45 $ 7.03 - $9.65
NYMEX and basis fixed-price 107 $3.59 70 $3.96
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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 Six months ended
June 30, June 30,
2009 2008 2009 2008
(Millions) (Millions)
Segment revenues $ 530 $ 948 $ 1,083 $ 1,676
Segment profit $ 119 $ 496 $ 197 $ 926
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Management's Discussion and Analysis (Continued) Three months ended June 30, 2009 vs. three months ended June 30, 2008 . . .
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