Add
WMB to Portfolio
Set Alert
Email to a
Friend
| |||
|
|
Quotes & Info
|
| WMB > SEC Filings for WMB > Form 10-Q on 29-Oct-2009 | All Recent SEC Filings |
29-Oct-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).
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.
Overview of Nine Months Ended September 30, 2009
Income from continuing operations attributable to The Williams Companies,
Inc., for the nine months ended September 30, 2009, decreased by $917 million
compared to the nine months ended September 30, 2008.
This decrease is reflective of:
• The overall unfavorable commodity price environment in the first nine months
of 2009 as compared to 2008;
• The absence of a $148 million pre-tax gain recorded in the first nine months of 2008 associated with the sale of Exploration & Production's Peru interests.
• A $75 million pre-tax impairment charge in the first quarter of 2009 related to Midstream's Venezuelan investment in Accroven. (See Note 4 of Notes to Consolidated Financial Statements).
See additional discussion in Results of Operations.
Our net cash provided by operating activities for the nine months ended
September 30, 2009, decreased $848 million compared to the nine months ended
September 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. In August 2009, we completed an exchange of these
notes for substantially identical new notes that are registered under the
Securities Act of 1933, as amended.
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. (See Results of
Operations - Segments, Exploration & Production.)
In September 2009, Exploration & Production completed the purchase of
additional properties in the Piceance basin of Colorado for $255 million. (See
Results of Operations - Segments, Exploration & Production.)
In September 2009, Gas Pipeline received approval from the FERC to begin
construction of the 85 North expansion project at an estimated cost of
$241 million. (See Results of Operations - Segments, Gas Pipeline.)
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
Management's Discussion and Analysis (Continued)
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 August 27, 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 September 30, 2009, less than 1 percent of the total assets and 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.
As of September 30, 2009, Level 2 includes option contracts that hedge future
sales of production from our Exploration & Production segment; these options are
structured as costless collars and are financially settled. They are valued
using an industry standard Black-Scholes option pricing model. Prior to the
third quarter of 2009, these options were included in Level 3 as a significant
input to the model, implied volatility by location, was considered unobservable.
However, due to increased transparency over the past several quarters, we now
consider this input to be observable and have included these options in Level 2.
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
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 September 30, 2009, the credit reserve is less than
$1 million on our net derivative assets and $4 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 September 30, 2009, 85 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 September 30, 2009, consist of natural
gas liquids swaps for our Midstream segment as well as natural gas index
transactions that are used to manage the physical requirements of our
Exploration & Production segment and our Midstream segment. The change in the
overall fair value of instruments included in Level 3 primarily results from
changes in commodity prices.
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 nine months ended September 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 nine months ended September 30, 2009, compared
to the three and nine months ended September 30, 2008. The results of operations
by segment are discussed in further detail following this consolidated overview
discussion.
Three months ended Nine months ended
September 30, September 30,
2009 2008 $ Change* % Change* 2009 2008 $ Change* % Change*
(Millions) (Millions)
Revenues $ 2,098 $ 3,201 -1,103 -34 % $ 5,929 $ 10,022 -4,093 -41 %
Costs and expenses:
Costs and operating
expenses 1,537 2,344 +807 +34 % 4,373 7,374 +3,001 +41 %
Selling, general and
administrative
expenses 126 133 +7 +5 % 380 375 -5 -1 %
Other
(income) expense -
net 1 1 - - 33 (145 ) -178 NM
General corporate
expenses 40 34 -6 -18 % 118 118 - -
Total costs and
expenses 1,704 2,512 4,904 7,722
Operating income 394 689 1,025 2,300
Interest accrued -
net (153 ) (146 ) -7 -5 % (440 ) (443 ) +3 +1 %
Investing income 39 65 -26 -40 % 2 174 -172 -99 %
Other income
(expense) - net (1 ) 2 -3 NM (2 ) 6 -8 NM
Income from
continuing
operations before
income taxes 279 610 585 2,037
Provision for income
taxes 87 199 +112 +56 % 223 707 +484 +68 %
Income from
continuing
operations 192 411 362 1,330
Income (loss) from
discontinued
operations 2 10 -8 -80 % (223 ) 130 -353 NM
Net income 194 421 139 1,460
Less: Net income
attributable to
noncontrolling
interests 51 55 +4 +7 % 26 157 +131 +83 %
Net income
attributable to The
Williams Companies,
Inc. $ 143 $ 366 $ 113 $ 1,303
|
* + = 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 September 30, 2009 vs. three months ended September 30,
2008
The decrease in revenues is primarily due to decreased realized revenue at
Gas Marketing primarily reflecting a decrease in average natural gas prices as
well as lower NGL and olefin production revenues, and lower NGL, olefin and
crude marketing 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 primarily due to decreased
costs at Gas Marketing primarily reflecting a decrease in average natural gas
prices as well as decreased costs associated with our olefin production
business, NGL, olefin and crude marketing purchases and decreased costs
associated with our NGL production business at Midstream.
Other (income) expense - net within operating income in 2008 includes a
$14 million impairment of certain natural gas producing properties at
Exploration & Production, partially offset by a gain of $10 million on the sale
of certain south Texas assets at Gas Pipeline and $7 million of net gains on
foreign currency exchanges at Midstream.
The decrease in operating income reflects an overall unfavorable energy
commodity price environment in the third quarter of 2009 compared to the same
period in 2008.
The unfavorable change in investing income is primarily due to lower equity
earnings and a decrease in interest income largely resulting from lower average
interest rates in 2009 compared to 2008.
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.
Management's Discussion and Analysis (Continued)
See Note 3 of Notes to Consolidated Financial Statements for a discussion of
the items in income (loss) from discontinued operations.
Nine months ended September 30, 2009 vs. nine months ended September 30, 2008
The decrease in revenues is primarily due to decreased realized revenue at
Gas Marketing primarily reflecting 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 primarily due to decreased
costs at Gas Marketing primarily reflecting a decrease in average natural gas
prices as well as decreased NGL, olefin and crude marketing purchases and
decreased costs associated with our olefin and NGL 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,
$13 million of net gains on foreign currency exchanges at Midstream, and a gain
of $10 million on the sale of certain south Texas assets at Gas Pipeline. These
items are partially offset by $21 million of project development costs at Gas
Pipeline and a $14 million impairment of certain natural gas producing
properties at Exploration & Production.
The decrease in operating income reflects an overall unfavorable energy
commodity price environment in the first nine months of 2009 compared to the
first nine months 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 is due primarily to a $75 million
impairment of Midstream's Accroven 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 equity earnings, primarily at
Midstream, and a decrease in interest income, primarily due to lower average
interest rates in 2009 compared to 2008, also contributed to the unfavorable
change in investing income.
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 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 Nine Months Ended September 30, 2009
Segment revenues and segment profit for the first nine months of 2009 were
significantly lower than the first nine months of 2008 primarily due to a sharp
decline in net realized average prices partially offset by higher production
volumes. Additionally, the first nine months of 2009 include expense of
$32 million associated with contractual penalties from the early termination of
drilling rig contracts. The first nine months of 2008 include a $148 million
gain on sale of our Peru interests. Highlights of the comparative periods
include:
For the nine months ended September 30,
2009 2008 % Change
Average daily domestic production (MMcfe) (1) 1,184 1,073 +10 %
Average daily total production (MMcfe) 1,237 1,122 +10 %
Domestic net realized average price ($/Mcfe) (2) $ 4.11 $ 7.22 -43 %
Capital expenditures incurred ($ millions) $ 1,004 $ 1,902 -47 %
Segment revenues ($ millions) $ 1,605 $ 2,537 -37 %
Segment profit ($ millions) $ 303 $ 1,287 -76 %
|
(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 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 events
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.
In September 2009, we completed the purchase of additional unproved leasehold
acreage and proved properties in the Piceance basin for $255 million, subject to
post closing adjustments.
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 $221 million and
$321 million, which is reflective of a reduction in drilling rigs deployed
and any additional capital expenditures to be incurred in 2009 in Marcellus
Shale and Piceance as a result of the previously described agreement and
acquisition.
• Modest growth in our annual average daily domestic production level compared to 2008, although fourth quarter 2009 volumes are likely to be less than fourth quarter 2008 volumes. As previously discussed, average daily domestic production peaked during the first quarter of 2009.
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
could 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 $3.92
|
The following is a summary of our contracts for daily production for the three and nine months ended September 30, 2009 and 2008:
2009 2008
Price ($/Mcf) Price ($/Mcf)
Volume Floor-Ceiling for Volume Floor-Ceiling for
(MMcf/d) Collars (MMcf/d) Collars
Third 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 $3.59 70 $3.90
. . .
|
|
|