WILLIAMS COMPANIES, INC.
10-Qs and 10-Ks
PROXIES
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2011
or
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _____________ to _____________
Commission file number 1-4174
THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)
| DELAWARE | 73-0569878 | |
| (State or other jurisdiction of incorporation or organization) | (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
NO CHANGE
(Former name, former address and former fiscal year, if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes
þ
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
þ
Yes
o
No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large
accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
| (Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act.) Yes
o
No
þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as
of the latest practicable date.
| Class | Outstanding at May 2, 2011 | |
| Common Stock, $1 par value | 588,146,154 Shares |
The Williams Companies, Inc.
Index
Index
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Part I. Financial Information
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Item 1. Financial Statements
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| 3 | ||||||||
| 4 | ||||||||
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| 6 | ||||||||
| 7 | ||||||||
| 27 | ||||||||
| 47 | ||||||||
| 49 | ||||||||
| 49 | ||||||||
| 49 | ||||||||
| 50 | ||||||||
| 51 | ||||||||
| EX-12 | ||||||||
| EX-31.1 | ||||||||
| EX-31.2 | ||||||||
| EX-32 | ||||||||
| EX-101 INSTANCE DOCUMENT | ||||||||
| EX-101 SCHEMA DOCUMENT | ||||||||
| EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
| EX-101 LABELS LINKBASE DOCUMENT | ||||||||
| EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
| EX-101 DEFINITION LINKBASE DOCUMENT | ||||||||
Certain matters contained in this report include “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial
performance, management’s plans and objectives for future operations, business prospects, outcome
of regulatory proceedings, market conditions and other matters. We make these forward-looking
statements in reliance on the safe harbor protections provided under the Private Securities
Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that
address activities, events or developments that we expect, believe or anticipate will exist or may
occur in the future, are forward-looking statements. Forward-looking statements can be identified
by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,”
“continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,”
“targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions.
These forward-looking statements are based on management’s beliefs and assumptions and on
information currently available to management and include, among others, statements regarding:
| • | Amounts and nature of future capital expenditures; | ||
| • | Expansion and growth of our business and operations; | ||
| • | Financial condition and liquidity; | ||
| • | Business strategy; | ||
| • | Estimates of proved gas and oil reserves; | ||
| • | Reserve potential; | ||
| • | Development drilling potential; | ||
| • | Cash flow from operations or results of operations; | ||
| • | Seasonality of certain business segments; | ||
| • | Natural gas, natural gas liquids, and crude oil prices and demand. |
1
Table of Contents
Forward-looking statements are based on numerous assumptions, uncertainties and risks that
could cause future events or results to be materially different from those stated or implied in
this report. Many of the factors that will determine these results are beyond our ability to
control or predict. Specific factors that could cause actual results to differ from results
contemplated by the forward-looking statements include, among others, the following:
| • | Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices, and the availability and cost of capital; | ||
| • | Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers); | ||
| • | The strength and financial resources of our competitors; | ||
| • | Development of alternative energy sources; | ||
| • | The impact of operational and development hazards; | ||
| • | Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation, and rate proceedings; | ||
| • | Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; | ||
| • | Changes in maintenance and construction costs; | ||
| • | Changes in the current geopolitical situation; | ||
| • | Our exposure to the credit risk of our customers; | ||
| • | Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit; | ||
| • | Risks associated with future weather conditions; | ||
| • | Acts of terrorism; | ||
| • | Additional risks described in our filings with the Securities and Exchange Commission. |
Given the uncertainties and risk factors that could cause our actual results to differ
materially from those contained in any forward-looking statement, we caution investors not to
unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to
update the above list or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to
below may cause our intentions to change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our results to differ. We may change our
intentions, at any time and without notice, based upon changes in such factors, our assumptions, or
otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are
important factors, in addition to those listed above, that may cause actual results to differ
materially from those contained in the forward-looking statements. For a detailed discussion of
those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year
ended December 31, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.
2
Table of Contents
The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)
| Three months ended March 31, | ||||||||
| (Millions, except per-share amounts) | 2011 | 2010 | ||||||
|
Revenues:
|
||||||||
|
Williams Partners
|
$ | 1,579 | $ | 1,490 | ||||
|
Exploration & Production
|
989 | 1,157 | ||||||
|
Midstream Canada & Olefins
|
316 | 272 | ||||||
|
Other
|
6 | 6 | ||||||
|
Intercompany eliminations
|
(315 | ) | (334 | ) | ||||
|
|
||||||||
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Total revenues
|
2,575 | 2,591 | ||||||
|
|
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|
|
||||||||
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Segment costs and expenses:
|
||||||||
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Costs and operating expenses
|
1,908 | 1,917 | ||||||
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Selling, general, and administrative expenses
|
137 | 111 | ||||||
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Other (income) expense — net
|
(1 | ) | (1 | ) | ||||
|
|
||||||||
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Total segment costs and expenses
|
2,044 | 2,027 | ||||||
|
|
||||||||
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General corporate expenses
|
51 | 85 | ||||||
|
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||||||||
|
|
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Operating income (loss):
|
||||||||
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Williams Partners
|
412 | 398 | ||||||
|
Exploration & Production
|
45 | 148 | ||||||
|
Midstream Canada & Olefins
|
74 | 20 | ||||||
|
Other
|
— | (2 | ) | |||||
|
General corporate expenses
|
(51 | ) | (85 | ) | ||||
|
|
||||||||
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Total operating income (loss)
|
480 | 479 | ||||||
|
|
||||||||
|
Interest accrued
|
(158 | ) | (164 | ) | ||||
|
Interest capitalized
|
9 | 17 | ||||||
|
Investing income — net
|
51 | 39 | ||||||
|
Early debt retirement costs
|
— | (606 | ) | |||||
|
Other income (expense) — net
|
4 | (7 | ) | |||||
|
|
||||||||
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Income (loss) from continuing operations before income taxes
|
386 | (242 | ) | |||||
|
Provision (benefit) for income taxes
|
(6 | ) | (94 | ) | ||||
|
|
||||||||
|
|
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Income (loss) from continuing operations
|
392 | (148 | ) | |||||
|
Income (loss) from discontinued operations
|
(8 | ) | 2 | |||||
|
|
||||||||
|
Net income (loss)
|
384 | (146 | ) | |||||
|
Less: Net income attributable to noncontrolling interests
|
63 | 47 | ||||||
|
|
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Net income (loss) attributable to The Williams Companies, Inc.
|
$ | 321 | $ | (193 | ) | |||
|
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Amounts attributable to The Williams Companies, Inc.:
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Income (loss) from continuing operations
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$ | 329 | $ | (195 | ) | |||
|
Income (loss) from discontinued operations
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(8 | ) | 2 | |||||
|
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Net income (loss)
|
$ | 321 | $ | (193 | ) | |||
|
|
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|
Basic earnings (loss) per common share:
|
||||||||
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Income (loss) from continuing operations
|
$ | .56 | $ | (.33 | ) | |||
|
Income (loss) from discontinued operations
|
(.01 | ) | — | |||||
|
|
||||||||
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Net income (loss)
|
$ | .55 | $ | (.33 | ) | |||
|
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Weighted-average shares (thousands)
|
586,977 | 583,929 | ||||||
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Diluted earnings (loss) per common share:
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||||||||
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Income (loss) from continuing operations
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$ | .55 | $ | (.33 | ) | |||
|
Income (loss) from discontinued operations
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(.01 | ) | — | |||||
|
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Net income (loss)
|
$ | .54 | $ | (.33 | ) | |||
|
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Weighted-average shares (thousands)
|
596,567 | 583,929 | ||||||
|
Cash dividends declared per common share
|
$ | .125 | $ | .11 | ||||
See accompanying notes.
3
Table of Contents
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
| March 31, | December 31, | |||||||
| (Dollars in millions, except per-share amounts) | 2011 | 2010 | ||||||
|
ASSETS
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Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 923 | $ | 795 | ||||
|
Accounts and notes receivable (net of allowance of $18 at March 31, 2011
and $15 at December 31, 2010)
|
850 | 859 | ||||||
|
Inventories
|
264 | 302 | ||||||
|
Derivative assets
|
301 | 400 | ||||||
|
Other current assets and deferred charges
|
167 | 174 | ||||||
|
|
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Total current assets
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2,505 | 2,530 | ||||||
|
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Investments
|
1,381 | 1,344 | ||||||
|
|
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Property, plant, and equipment, at cost
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30,816 | 30,365 | ||||||
|
Accumulated depreciation, depletion, and amortization
|
(10,475 | ) | (10,144 | ) | ||||
|
|
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Property, plant, and equipment — net
|
20,341 | 20,221 | ||||||
|
Derivative assets
|
167 | 173 | ||||||
|
Other assets and deferred charges
|
689 | 704 | ||||||
|
|
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Total assets
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$ | 25,083 | $ | 24,972 | ||||
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LIABILITIES AND EQUITY
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Current liabilities:
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Accounts payable
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$ | 913 | $ | 918 | ||||
|
Accrued liabilities
|
872 | 1,002 | ||||||
|
Derivative liabilities
|
141 | 146 | ||||||
|
Long-term debt due within one year
|
532 | 508 | ||||||
|
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Total current liabilities
|
2,458 | 2,574 | ||||||
|
|
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Long-term debt
|
8,577 | 8,600 | ||||||
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Deferred income taxes
|
3,448 | 3,448 | ||||||
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Derivative liabilities
|
158 | 143 | ||||||
|
Other liabilities and deferred income
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1,563 | 1,588 | ||||||
|
Contingent liabilities and commitments (Note 11)
|
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|
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Equity:
|
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Stockholders’ equity:
|
||||||||
|
Common stock (960 million shares authorized at $1 par value;
622 million shares issued at March 31, 2011 and 620 million shares
issued at December 31, 2010)
|
622 | 620 | ||||||
|
Capital in excess of par value
|
8,302 | 8,269 | ||||||
|
Retained earnings (deficit)
|
(230 | ) | (478 | ) | ||||
|
Accumulated other comprehensive income (loss)
|
(116 | ) | (82 | ) | ||||
|
Treasury stock, at cost (35 million shares of common stock)
|
(1,041 | ) | (1,041 | ) | ||||
|
|
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Total stockholders’ equity
|
7,537 | 7,288 | ||||||
|
Noncontrolling interests in consolidated subsidiaries
|
1,342 | 1,331 | ||||||
|
|
||||||||
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Total equity
|
8,879 | 8,619 | ||||||
|
|
||||||||
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Total liabilities and equity
|
$ | 25,083 | $ | 24,972 | ||||
|
|
||||||||
See accompanying notes.
4
Table of Contents
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
(Unaudited)
| Three months ended March 31, | ||||||||||||||||||||||||
| 2011 | 2010 | |||||||||||||||||||||||
| The Williams | Noncontrolling | The Williams | Noncontrolling | |||||||||||||||||||||
| Companies, Inc. | Interests | Total | Companies, Inc. | Interests | Total | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
|
Beginning balance
|
$ | 7,288 | $ | 1,331 | $ | 8,619 | $ | 8,447 | $ | 572 | $ | 9,019 | ||||||||||||
|
Comprehensive income (loss):
|
||||||||||||||||||||||||
|
Net income (loss)
|
321 | 63 | 384 | (193 | ) | 47 | (146 | ) | ||||||||||||||||
|
Other comprehensive income (loss), net of tax:
|
||||||||||||||||||||||||
|
Net change in cash flow hedges
|
(62 | ) | — | (62 | ) | 147 | 2 | 149 | ||||||||||||||||
|
Foreign currency translation adjustments
|
22 | — | 22 | 19 | — | 19 | ||||||||||||||||||
|
Pension and other postretirement
benefits — net
|
6 | — | 6 | 5 | — | 5 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total other comprehensive income (loss)
|
(34 | ) | — | (34 | ) | 171 | 2 | 173 | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total comprehensive income (loss)
|
287 | 63 | 350 | (22 | ) | 49 | 27 | |||||||||||||||||
|
Cash dividends — common stock
|
(73 | ) | — | (73 | ) | (64 | ) | — | (64 | ) | ||||||||||||||
|
Dividends and distributions to noncontrolling
interests
|
— | (52 | ) | (52 | ) | — | (32 | ) | (32 | ) | ||||||||||||||
|
Stock-based compensation, net of tax
|
35 | — | 35 | 12 | — | 12 | ||||||||||||||||||
|
Change in Williams Partners L.P. ownership
interest (Note 2)
|
— | — | — | (454 | ) | 454 | — | |||||||||||||||||
|
|
||||||||||||||||||||||||
|
Ending balance
|
$ | 7,537 | $ | 1,342 | $ | 8,879 | $ | 7,919 | $ | 1,043 | $ | 8,962 | ||||||||||||
|
|
||||||||||||||||||||||||
See accompanying notes.
5
Table of Contents
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
| Three months ended March 31, | ||||||||
| (Millions) | 2011 | 2010 | ||||||
|
OPERATING ACTIVITIES:
|
||||||||
|
Net income (loss)
|
$ | 384 | $ | (146 | ) | |||
|
Adjustments to reconcile to net cash provided by operating activities:
|
||||||||
|
Depreciation, depletion, and amortization
|
381 | 361 | ||||||
|
Provision (benefit) for deferred income taxes
|
(10 | ) | 29 | |||||
|
Provision for loss on investments, property and other assets
|
31 | 4 | ||||||
|
Amortization of stock-based awards
|
14 | 14 | ||||||
|
Early debt retirement costs
|
— | 606 | ||||||
|
Cash provided (used) by changes in current assets and liabilities:
|
||||||||
|
Accounts and notes receivable
|
6 | 2 | ||||||
|
Inventories
|
38 | — | ||||||
|
Margin deposits and customer margin deposits payable
|
(19 | ) | 11 | |||||
|
Other current assets and deferred charges
|
28 | 21 | ||||||
|
Accounts payable
|
46 | (13 | ) | |||||
|
Accrued liabilities
|
(65 | ) | (280 | ) | ||||
|
Changes in current and noncurrent derivative assets and liabilities
|
17 | (8 | ) | |||||
|
Other, including changes in noncurrent assets and liabilities
|
(40 | ) | 16 | |||||
|
|
||||||||
|
Net cash provided by operating activities
|
811 | 617 | ||||||
|
|
||||||||
|
|
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|
FINANCING ACTIVITIES:
|
||||||||
|
Proceeds from long-term debt
|
75 | 3,749 | ||||||
|
Payments of long-term debt
|
(75 | ) | (3,407 | ) | ||||
|
Dividends paid
|
(73 | ) | (64 | ) | ||||
|
Dividends and distributions paid to noncontrolling interests
|
(52 | ) | (32 | ) | ||||
|
Payments for debt issuance costs
|
— | (65 | ) | |||||
|
Premiums paid on early debt retirements
|
— | (574 | ) | |||||
|
Other — net
|
21 | (12 | ) | |||||
|
|
||||||||
|
Net cash provided (used) by financing activities
|
(104 | ) | (405 | ) | ||||
|
|
||||||||
|
|
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|
INVESTING ACTIVITIES:
|
||||||||
|
Capital expenditures*
|
(526 | ) | (428 | ) | ||||
|
Purchases of investments/advances to affiliates
|
(42 | ) | (13 | ) | ||||
|
Other — net
|
(11 | ) | 6 | |||||
|
|
||||||||
|
Net cash used by investing activities
|
(579 | ) | (435 | ) | ||||
|
|
||||||||
|
Increase (decrease) in cash and cash equivalents
|
128 | (223 | ) | |||||
|
Cash and cash equivalents at beginning of period
|
795 | 1,867 | ||||||
|
|
||||||||
|
Cash and cash equivalents at end of period
|
$ | 923 | $ | 1,644 | ||||
|
|
||||||||
|
|
||||||||
|
______________
|
||||||||
|
|
||||||||
|
* Increases to property, plant, and equipment
|
$ | (482 | ) | $ | (410 | ) | ||
|
Changes in related accounts payable and accrued liabilities
|
(44 | ) | (18 | ) | ||||
|
|
||||||||
|
Capital expenditures
|
$ | (526 | ) | $ | (428 | ) | ||
|
|
||||||||
See accompanying notes.
6
Table of Contents
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
Note 1. General
Our accompanying interim consolidated financial statements do not include all the notes in our
annual financial statements and, therefore, should be read in conjunction with the consolidated
financial statements and notes thereto in our Annual Report on Form 10-K. The accompanying
unaudited financial statements include all normal recurring adjustments that, in the opinion of our
management, are necessary to present fairly our financial position at March 31, 2011, results of
operations, changes in equity, and cash flows for the three months ended March 31, 2011 and 2010.
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
On
February 16, 2011, we announced that our Board of Directors
approved our reorganization plan to divide our business into two
separate, publicly traded corporations. On April 29, 2011, our wholly owned subsidiary, WPX Energy,
Inc. (WPX), filed a registration statement with the SEC with respect to an initial public offering
of its equity securities. This is the first step in our reorganization plan, which calls for a
separation of our exploration and production business through an initial public offering
and a tax-free spin-off of our remaining interest in WPX to our
shareholders.
We retain the discretion to determine whether and when to complete these transactions.
Note 2. Basis of Presentation
Beginning with the first quarter of 2011, we changed our segment reporting structure to
present our Canadian midstream and domestic olefins operations as a separate segment, Midstream
Canada & Olefins. This change reflects the expected growth in this business and our chief operating
decision maker’s increased focus on these operations, which were previously reported within Other.
Prior periods have been recast to reflect this revised segment presentation.
Our operations are located principally in the United States and are organized into the
following reporting segments: Williams Partners, Exploration & Production and Midstream Canada &
Olefins. All remaining business activities are included in Other.
Williams Partners consists of our consolidated master limited partnership, Williams Partners
L.P. (WPZ) and includes our gas pipeline and domestic midstream businesses. The gas pipeline
businesses include 100 percent of Transcontinental Gas Pipe Line Company, LLC (Transco), 100
percent of Northwest Pipeline GP (Northwest Pipeline), and 24.5 percent of Gulfstream Natural Gas
System, L.L.C. (Gulfstream). WPZ’s midstream operations are composed of significant, large-scale
operations in the Rocky Mountain and Gulf Coast regions, operations in Pennsylvania’s Marcellus
Shale region, and various equity investments in domestic processing, fractionation, and natural gas
liquid (NGL) transportation assets. WPZ’s midstream assets also include substantial operations and
investments in the Four Corners and Gulf Coast regions, as well as an NGL
fractionator and storage facilities near Conway, Kansas.
Exploration & Production includes the natural gas development, production and gas management
activities, with operations primarily in the Rocky Mountain and Mid-Continent regions of the United States, natural
gas development activities in the northeastern portion of the United States, oil and natural gas
interests in South America, and oil development activities in the northern United States. The gas
management activities include procuring fuel and shrink gas for our midstream businesses and
providing marketing to third parties, such as producers. Additionally, gas management activities
include managing various natural gas related contracts such as transportation, storage, and
related hedges.
7
Table of Contents
Notes (Continued)
Our Midstream Canada & Olefins segment includes our oil sands off-gas processing plant near
Fort McMurray, Alberta, our NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta, our NGL light-feed olefins cracker in Geismar, Louisiana
along with associated ethane and propane pipelines, and our refinery grade splitter in Louisiana.
Other includes other business activities that are not operating segments, primarily a 25.5
percent interest in Gulfstream, as well as corporate operations.
During fourth-quarter 2010, we contributed a business represented by certain gathering and
processing assets in Colorado’s Piceance basin to WPZ. The transaction was accounted for as a
combination of entities under common control whereby the assets and liabilities sold were recorded
by WPZ at their historical amounts. The operations of this business and the related assets and
liabilities were previously reported through our Exploration & Production segment, however they are
now reported in our Williams Partners segment. Prior period segment
disclosures have been recast
for this transaction.
Master Limited Partnership
At March 31, 2011, we own approximately 75 percent of the interests in WPZ, including the
interests of the general partner, which is wholly owned by us, and incentive distribution rights.
WPZ is self funding and maintains separate lines of bank credit and cash management accounts.
Cash distributions from WPZ to us, including any associated with our incentive distribution rights,
occur through the normal partnership distributions from WPZ to all partners.
The change in WPZ ownership between us and the noncontrolling interests as a result of our
February 2010 strategic restructuring was accounted for as an equity transaction and resulted in a
$454 million decrease to
capital in excess of par value
and a corresponding increase to
noncontrolling interest in consolidated subsidiaries.
For the first quarter of 2010, this amount related to the change between our ownership
interest and the noncontrolling interests resulting from the restructuring was previously reported
as $800 million. During the third quarter of 2010, we determined that this amount was incorrect.
This error resulted in a $346 million overstatement of
noncontrolling interests in consolidated
subsidiaries
and a $346 million understatement of
capital in excess of par value
in the first and
second quarter. The error did not impact
total equity
, key financial covenants, any earnings or
cash flow measures or any other key internal measures. First quarter 2010 amounts have been
adjusted for the correction in the Consolidated Statement of Changes in Equity.
Discontinued operations
The accompanying consolidated financial statements and notes reflect the results of operations
and financial position of Exploration & Production’s Arkoma basin operations as discontinued
operations for all periods. (See Note 3.)
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements
relates to our continuing operations.
8
Table of Contents
Notes (Continued)
Note 3. Discontinued Operations
Summarized Results of Discontinued Operations
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Revenues
|
$ | 3 | $ | 5 | ||||
|
|
||||||||
|
|
||||||||
|
Income (loss) from discontinued operations before impairment and
income taxes
|
$ | (2 | ) | $ | 4 | |||
|
Impairment
|
(9 | ) | — | |||||
|
(Provision) benefit for income taxes
|
3 | (2 | ) | |||||
|
|
||||||||
|
Income (loss) from discontinued operations
|
$ | (8 | ) | $ | 2 | |||
|
|
||||||||
Impairment
in 2011 reflects a write-down to an estimate of fair value less costs to sell
the assets of our Arkoma basin operations that were classified as held for
sale as of March 31, 2011. This nonrecurring fair value measurement, which falls within Level 3 of
the fair value hierarchy, was based on a probability-weighted discounted cash flow analysis that
included offers we have received on the assets.
The assets of our discontinued operations comprise significantly less than 0.5 percent of our
total consolidated assets as of March 31, 2011, and
December 31, 2010, and are reported primarily within
other current assets and deferred charges
and
other assets
and deferred charges,
respectively, on our Consolidated
Balance Sheet. Liabilities of our discontinued operations are insignificant for these periods.
Note 4. Asset Sales and Other Accruals
Other (income) expense — net
within
segment costs and expenses
in 2011 includes $10 million
related to the reversal of project feasibility costs from expense to capital at Williams
Partners, associated with a natural gas pipeline expansion project, upon determining that the related project was probable of development.
These costs will be included in the capital costs of the project,
which we believe are probable of recovery through the project rates.
Additional Items
We completed a strategic restructuring transaction in the first quarter of 2010 that involved
significant debt issuances, retirements and amendments. We incurred significant costs related to
these transactions, as follows:
| • | $606 million of early debt retirement costs consisting primarily of cash premiums; |
| • | $39 million of other transaction costs reflected in general corporate expenses, of which $4 million is attributable to noncontrolling interests; |
| • | $4 million of accelerated amortization of debt costs related to the amendments of credit facilities, reflected in other income (expense) — net below operating income (loss) . |
We recognized an $11 million gain in the first quarter of 2011 on the 2010 sale of our
interest in Accroven SRL, reflecting the receipt of the first quarterly payment, which was
originally due from the buyer in October 2010. This gain is reflected within
investing income —
net
at Other. Payments are recognized as income upon receipt
until such point future collections are reasonably assured.
Note 5. Provision (Benefit) for Income Taxes
The
provision (benefit) for income taxes
includes:
9
Table of Contents
Notes (Continued)
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Current:
|
||||||||
|
Federal
|
$ | 17 | $ | (113 | ) | |||
|
State
|
1 | (14 | ) | |||||
|
Foreign
|
(18 | ) | 5 | |||||
|
|
||||||||
|
|
— | (122 | ) | |||||
|
|
||||||||
|
Deferred:
|
||||||||
|
Federal
|
(8 | ) | 23 | |||||
|
State
|
1 | 3 | ||||||
|
Foreign
|
1 | 2 | ||||||
|
|
||||||||
|
|
(6 | ) | 28 | |||||
|
|
||||||||
|
Total provision (benefit)
|
$ | (6 | ) | $ | (94 | ) | ||
|
|
||||||||
The effective income tax rate on the total benefit for the three months ended March 31, 2011,
is less than the federal statutory rate primarily due to federal settlements, an international
revised assessment and the impact of nontaxable noncontrolling interests, partially offset by the
effect of state income taxes.
The effective income tax rate on the total benefit for the three months ended March 31, 2010,
is greater than the federal statutory rate primarily due to the effect of state income taxes and
the impact of nontaxable noncontrolling interests, partially offset by the reduction of tax
benefits on the Medicare Part D federal subsidy due to enacted healthcare legislation.
During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain
contested matters with the Internal Revenue Service (IRS) and also received a revised assessment on
an international matter. These settlements and revised assessment resulted in a tax benefit of
approximately $124 million during the first quarter of 2011. As a result of these settlements and
revised assessment, we have decreased our unrecognized tax benefits by approximately $62 million.
We anticipate making approximately $140 million to $145 million of cash payments (net of refunds)
to taxing authorities related to these items in 2011.
During the next twelve months, we do not expect ultimate resolution of any uncertain tax
position will result in a significant increase or decrease of
our unrecognized tax benefit.
10
Table of Contents
Notes (Continued)
Note 6. Earnings (Loss) Per Common Share from Continuing Operations
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Dollars in millions, except per-share | ||||||||
| amounts; shares in thousands) | ||||||||
|
Income (loss) from continuing operations attributable to The Williams
Companies, Inc. available to common stockholders for basic and
diluted earnings (loss) per common share (1)
|
$ | 329 | $ | (195 | ) | |||
|
|
||||||||
|
Basic weighted-average shares
|
586,977 | 583,929 | ||||||
|
Effect of dilutive securities:
|
||||||||
|
Nonvested restricted stock units
|
4,125 | — | ||||||
|
Stock options
|
3,464 | — | ||||||
|
Convertible debentures
|
2,001 | — | ||||||
|
|
||||||||
|
Diluted weighted-average shares
|
596,567 | 583,929 | ||||||
|
|
||||||||
|
Earnings (loss) per common share from continuing operations:
|
||||||||
|
Basic
|
$ | .56 | $ | (.33 | ) | |||
|
Diluted
|
$ | .55 | $ | (.33 | ) | |||
| (1) | The three-month period ended March 31, 2011 includes $0.2 million of interest expense, net of tax, associated with our convertible debentures. This amount has been added back to income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders to calculate diluted earnings per common share. |
For the three months ended March 31, 2010, 3.3 million weighted-average nonvested restricted
stock units and 3.2 million weighted-average stock options have been excluded from the computation
of diluted earnings per common share as their inclusion would be antidilutive due to our loss from
continuing operations attributable to The Williams Companies, Inc.
Additionally, for the three months ended March 31, 2010, 2.3 million weighted-average shares
related to the assumed conversion of our convertible debentures, as well as the related interest,
net of tax, have been excluded from the computation of diluted earnings per common share. Inclusion
of these shares would have an antidilutive effect on the diluted earnings per common share. We
estimate that if
income (loss) from continuing operations attributable to The Williams Companies,
Inc. available to common stockholders
was $54 million of income for the three months ended March
31, 2010, then these shares would become dilutive.
The table below includes information related to stock options that were outstanding at March
31 of each respective year but have been excluded from the computation of weighted-average stock
options due to the option exercise price exceeding the first quarter weighted-average market price
of our common shares.
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Options excluded (millions)
|
3.0 | 2.4 | ||||||
|
Weighted-average exercise price of options excluded
|
$ | 31.50 | $ | 32.40 | ||||
|
Exercise price ranges of options excluded
|
$ | 28.30 - $40.51 | $ | 22.25 - $40.51 | ||||
|
First quarter weighted-average market price
|
$ | 28.27 | $ | 22.18 | ||||
11
Table of Contents
Notes (Continued)
Note 7. Employee Benefit Plans
Net periodic benefit expense
is as follows:
| Other Postretirement | ||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| Three months ended March 31, | Three months ended March 31, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Components of net periodic benefit expense:
|
||||||||||||||||
|
Service cost
|
$ | 10 | $ | 8 | $ | 1 | $ | 1 | ||||||||
|
Interest cost
|
17 | 16 | 4 | 4 | ||||||||||||
|
Expected return on plan assets
|
(19 | ) | (18 | ) | (3 | ) | (3 | ) | ||||||||
|
Amortization of prior service credit
|
— | — | (3 | ) | (3 | ) | ||||||||||
|
Amortization of net actuarial loss
|
9 | 9 | 1 | — | ||||||||||||
|
|
||||||||||||||||
|
Net periodic benefit expense (income)
|
$ | 17 | $ | 15 | $ | — | $ | (1 | ) | |||||||
|
|
||||||||||||||||
During the three months ended March 31, 2011, we contributed $17 million to our pension plans
and $4 million to our other postretirement benefit plans. We presently anticipate making additional
contributions of approximately $51 million to our pension plans and approximately $12 million to
our other postretirement benefit plans in the remainder of 2011.
Note 8. Inventories
| March 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Natural gas liquids and olefins
|
$ | 97 | $ | 87 | ||||
|
Natural gas in underground storage
|
52 | 93 | ||||||
|
Materials, supplies, and other
|
115 | 122 | ||||||
|
|
||||||||
|
|
$ | 264 | $ | 302 | ||||
|
|
||||||||
Note 9. Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our assets and
liabilities that are measured at fair value on a recurring basis.
| March 31, 2011 | December 31, 2010 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
| (Millions) | (Millions) | |||||||||||||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||||||||||||||
|
Energy derivatives
|
$ | 58 | $ | 407 | $ | 3 | $ | 468 | $ | 96 | $ | 475 | $ | 2 | $ | 573 | ||||||||||||||||
|
ARO Trust investments
(see Note 10)
|
38 | — | — | 38 | 40 | — | — | 40 | ||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Total assets
|
$ | 96 | $ | 407 | $ | 3 | $ | 506 | $ | 136 | $ | 475 | $ | 2 | $ | 613 | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||||||||||
|
Energy derivatives
|
$ | 54 | $ | 242 | $ | 3 | $ | 299 | $ | 78 | $ | 210 | $ | 1 | $ | 289 | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Total liabilities
|
$ | 54 | $ | 242 | $ | 3 | $ | 299 | $ | 78 | $ | 210 | $ | 1 | $ | 289 | ||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
Energy derivatives include commodity based exchange-traded contracts and over-the-counter
(OTC) contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts
include forwards, swaps and options.
12
Table of Contents
Notes (Continued)
The instruments included in our Level 1 measurements primarily consist of energy derivatives
that are exchange-traded and a portfolio of mutual funds. Exchange-traded contracts include New
York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted
prices in these active markets.
The instruments included in our Level 2 measurements consist primarily of OTC instruments.
Forward, swap, and option contracts included in Level 2 are valued using an income approach
including present value techniques and option pricing models. Option contracts, which hedge future
sales of production from our Exploration & Production segment, are structured as costless collars
and are financially settled. They are valued using an industry standard Black-Scholes option
pricing model. Significant inputs into our Level 2 valuations include commodity prices, implied
volatility by location, and interest rates, as well as considering executed transactions or broker
quotes corroborated by other market data. These broker quotes are based on observable market prices
at which transactions could currently be executed. In certain instances where these inputs are not
observable for all periods, relationships of observable market data and historical observations are
used as a means to estimate fair value. Where observable inputs are available for substantially the
full term of the asset or liability, the instrument is categorized in Level 2.
The instruments in our Level 3 measurements primarily consist of natural gas index
transactions that are used to manage the physical requirements of our Exploration & Production
segment. These instruments are valued with a present value technique using inputs that may not be
readily observable or corroborated by other market data. These instruments are classified within
Level 3 because these inputs have a significant impact on the measurement of fair value. As the
fair value of natural gas index transactions is primarily driven by the typically nominal
differential transacted and the market price, these transactions do not have a material impact on
our results of operations or liquidity.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like
products and the tenure of our derivatives portfolio is relatively short with more than 99 percent
of the value of our derivatives portfolio expiring in the next 21 months. Due to the nature of the
products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on
a daily basis and is formally validated with broker quotes and documented on a monthly basis.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value
hierarchy, if applicable, are made at the end of each quarter. No significant transfers between
Level 1 and Level 2 occurred during the period ended March 31, 2011 or 2010. During the period
ended March 31, 2011, certain NGL swaps that originated during the first quarter of 2011 were
transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3
due to a lack of observable third-party market quotes. Due to an increase in exchange-traded transactions
and greater visibility from OTC trading,
we transferred these instruments to Level 2.
The following table presents a reconciliation of changes in the fair value of our net energy
derivatives classified as Level 3 in the fair value hierarchy.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Beginning balance
|
$ | 1 | $ | 2 | ||||
|
Realized and unrealized gains (losses):
|
||||||||
|
Included in income (loss) from continuing operations
|
(1 | ) | — | |||||
|
Included in other comprehensive income (loss)
|
(1 | ) | 4 | |||||
|
Settlements
|
— | (1 | ) | |||||
|
Transfers into Level 3
|
— | — | ||||||
|
Transfers out of Level 3
|
1 | — | ||||||
|
|
||||||||
|
Ending balance
|
$ | — | $ | 5 | ||||
|
|
||||||||
|
Unrealized gains (losses) included in income (loss) from continuing operations
relating to instruments still held at March 31
|
$ | (2 | ) | $ | — | |||
|
|
||||||||
13
Table of Contents
Notes (Continued)
Realized and unrealized gains (losses) included in
income (loss) from continuing
operations
for the above periods are reported in
revenues
or
costs and operating expenses
in our
Consolidated Statement of Operations.
Note 10. Financial Instruments, Derivatives, Guarantees, and Concentration of Credit Risk
Financial Instruments
Fair-value methods
We use the following methods and assumptions in estimating our fair-value disclosures for
financial instruments:
Cash and cash equivalents and restricted cash
: The carrying amounts reported in the
Consolidated Balance Sheet approximate fair value due to the short-term maturity of these
instruments. Current and noncurrent restricted cash is included in
other current assets and
deferred charges
and
other assets and deferred charges
, respectively, in the Consolidated Balance
Sheet, based on the term of the related restriction.
ARO Trust investments:
Transco deposits a portion of its collected rates, pursuant to
its 2008 rate case settlement, into an external trust (ARO Trust) specifically designated
to fund future asset retirement obligations. The ARO Trust invests in a portfolio of mutual funds
that are reported at fair value in
other assets and deferred charges
in the Consolidated Balance
Sheet and are classified as available-for-sale. However, both realized and unrealized gains and
losses are ultimately recorded as regulatory assets or liabilities.
Long-term debt
: The fair value of our publicly traded long-term debt is determined
using indicative period-end traded bond market prices. At both March 31, 2011 and December 31,
2010, approximately 100 percent of our long-term debt was publicly traded.
Guarantee
: The
guarantee
represented in the following table consists of a guarantee
we have provided in the event of nonpayment by our previously owned communications subsidiary,
Williams Communications Group (WilTel), on a lease performance obligation. To estimate the fair
value of the guarantee, the estimated default rate is determined by obtaining the average
cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current
owner and the term of the underlying obligation. The default rates are published by Moody’s
Investors Service. Guarantees, if recognized, are included in
accrued liabilities
in the
Consolidated Balance Sheet.
Other
: Includes current and noncurrent notes receivable, margin deposits, customer
margin deposits payable, and cost-based investments.
Energy derivatives
: Energy derivatives include futures, forwards, swaps, and options.
These are carried at fair value in the Consolidated Balance Sheet. See Note 9 for a discussion of
the valuation of our energy derivatives.
Carrying amounts and fair values of our financial instruments
| March 31, 2011 | December 31, 2010 | |||||||||||||||
| Carrying | Carrying | |||||||||||||||
| Asset (Liability) | Amount | Fair Value | Amount | Fair Value | ||||||||||||
| (Millions) | ||||||||||||||||
|
Cash and cash equivalents
|
$ | 923 | $ | 923 | $ | 795 | $ | 795 | ||||||||
|
Restricted cash (current and noncurrent)
|
$ | 27 | $ | 27 | $ | 28 | $ | 28 | ||||||||
|
ARO Trust investments
|
$ | 38 | $ | 38 | $ | 40 | $ | 40 | ||||||||
|
Long-term debt, including current portion (a)
|
$ | (9,105 | ) | $ | (10,101 | ) | $ | (9,104 | ) | $ | (9,990 | ) | ||||
|
Guarantee
|
$ | (35 | ) | $ | (33 | ) | $ | (35 | ) | $ | (34 | ) | ||||
|
Other
|
$ | (5 | ) | $ | (6 | )(b) | $ | (23 | ) | $ | (25 | )(b) | ||||
|
Net energy derivatives:
|
||||||||||||||||
|
Energy commodity cash flow hedges
|
$ | 168 | $ | 168 | $ | 266 | $ | 266 | ||||||||
|
Other energy derivatives
|
$ | 1 | $ | 1 | $ | 18 | $ | 18 | ||||||||
| (a) | Excludes capital leases. |
14
Table of Contents
Notes (Continued)
| (b) | Excludes certain cost-based investments in companies that are not publicly traded and therefore it is not practicable to estimate fair value. The carrying value of these investments was $1 million and $2 million at March 31, 2011 and December 31, 2010, respectively. |
Energy Commodity Derivatives
Risk management activities
We are exposed to market risk from changes in energy commodity prices within our operations.
We manage this risk on an enterprise basis and may utilize derivatives to manage our exposure to
the variability in expected future cash flows from forecasted purchases and sales of natural gas
and NGLs attributable to commodity price risk. Certain of these derivatives utilized for risk
management purposes have been designated as cash flow hedges, while other derivatives have not been
designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future
cash flows on an economic basis.
We produce, buy, and sell natural gas at different locations throughout the United States. We
also enter into forward contracts to buy and sell natural gas to maximize the economic value of
transportation agreements and storage capacity agreements. To reduce exposure to a decrease in
revenues or margins from fluctuations in natural gas market prices, we enter into natural gas
futures contracts, swap agreements, and financial option contracts to mitigate the price risk on
forecasted sales of natural gas. We have also entered into basis swap agreements to reduce the
locational price risk associated with our producing basins. Those designated as cash flow hedges
are expected to be highly effective in offsetting cash flows attributable to the hedged risk during
the term of the hedge. However, ineffectiveness may be recognized primarily as a result of
locational differences between the hedging derivative and the hedged item. Our financial option
contracts are either purchased options or a combination of options that comprise a net purchased
option or a zero-cost collar. Our designation of the hedging relationship and method of assessing
effectiveness for these option contracts are generally such that the hedging relationship is
considered perfectly effective and no ineffectiveness is recognized in earnings. Hedges for storage
contracts have not been designated as cash flow hedges, despite economically hedging the expected
cash flows generated by those agreements.
We produce and sell NGLs and olefins at different locations throughout North America. We also
buy natural gas to satisfy the required fuel and shrink needed to generate NGLs and olefins. To
reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in
costs and operating expenses from fluctuations in natural gas and NGL market prices, we may enter
into NGL or natural gas swap agreements, financial forward contracts, and financial option
contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas and
NGLs. Those designated as cash flow hedges are expected to be highly effective in offsetting cash
flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be
recognized primarily as a result of locational differences between the hedging derivative and the
hedged item.
Other activities
We also enter into energy commodity derivatives for other than risk management purposes,
including managing certain remaining legacy natural gas contracts and positions from our former
power business and providing services to third parties. These legacy natural gas contracts include
substantially offsetting positions and have an insignificant net impact on earnings.
Volumes
Our energy commodity derivatives are comprised of both contracts to purchase the commodity
(long positions) and contracts to sell the commodity (short positions). Derivative transactions are
categorized into four types:
| • | Central hub risk: Includes physical and financial derivative exposures to Henry Hub for natural gas, West Texas Intermediate for crude oil, and Mont Belvieu for NGLs; |
| • | Basis risk: Includes physical and financial derivative exposures to the difference in value between the central hub and another specific delivery point; |
15
Table of Contents
Notes (Continued)
| • | Index risk: Includes physical derivative exposure at an unknown future price; |
| • | Options: Includes all fixed price options or combination of options (collars) that set a floor and/or ceiling for the transaction price of a commodity. |
Fixed price swaps at locations other than the central hub are classified as both central hub risk
and basis risk instruments to represent their exposure to overall market conditions (central hub
risk) and specific location risk (basis risk).
The following table depicts the notional quantities of the net long (short) positions in our
commodity derivatives portfolio as of March 31, 2011. Natural gas is presented in millions of
British Thermal Units (MMBtu), NGLs are presented in gallons, and oil is presented in barrels. The
volumes for options represent at location zero-cost collars and present one side of the short
position. The net index position for Exploration & Production includes certain positions on behalf
of other segments.
| Unit of | Central Hub | Basis | Index | |||||||||||||||||
| Derivative Notional Volumes | Measure | Risk | Risk | Risk | Options | |||||||||||||||
|
Designated as Hedging Instruments
|
||||||||||||||||||||
|
Exploration & Production
|
Risk Management | MMBtu | (262,335,000 | ) | (262,335,000 | ) | (75,625,000 | ) | ||||||||||||
|
Exploration & Production
|
Risk Management | Barrels | (3,701,250 | ) | ||||||||||||||||
|
Williams Partners
|
Risk Management | MMBtu | 8,250,000 | 7,562,500 | ||||||||||||||||
|
Williams Partners
|
Risk Management | Gallons | (2,280,000 | ) | ||||||||||||||||
|
|
||||||||||||||||||||
|
Not Designated as Hedging Instruments
|
||||||||||||||||||||
|
Exploration & Production
|
Risk Management | MMBtu | (6,542,400 | ) | (17,452,400 | ) | (30,877,696 | ) | ||||||||||||
|
Williams Partners
|
Risk Management | Gallons | (50,000 | ) | ||||||||||||||||
|
Midstream Canada &
Olefins
|
Risk Management | Gallons | (20,000 | ) | ||||||||||||||||
|
Exploration & Production
|
Other | MMBtu | (1,500 | ) | (226,500 | ) | ||||||||||||||
Fair values and gains (losses)
The following table presents the fair value of energy commodity derivatives. Our derivatives
are presented as separate line items in our Consolidated Balance Sheet as current and noncurrent
derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the
contractual timing of expected future net cash flows of individual contracts. The expected future
net cash flows for derivatives classified as current are expected to occur within the next 12
months. The fair value amounts are presented on a gross basis and do not reflect the netting of
asset and liability positions permitted under the terms of our master netting arrangements.
Further, the amounts below do not include cash held on deposit in margin accounts that we have
received or remitted to collateralize certain derivative positions.
| March 31, 2011 | December 31, 2010 | |||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||
| (Millions) | ||||||||||||||||
|
Designated as hedging instruments
|
$ | 233 | $ | 65 | $ | 288 | $ | 22 | ||||||||
|
Not designated as hedging instruments:
|
||||||||||||||||
|
Legacy natural gas contracts from former power
business
|
223 | 224 | 186 | 187 | ||||||||||||
|
All other
|
12 | 10 | 99 | 80 | ||||||||||||
|
|
||||||||||||||||
|
Total derivatives not designated as hedging instruments
|
235 | 234 | 285 | 267 | ||||||||||||
|
|
||||||||||||||||
|
Total derivatives
|
$ | 468 | $ | 299 | $ | 573 | $ | 289 | ||||||||
|
|
||||||||||||||||
16
Table of Contents
Notes (Continued)
The following table presents pre-tax gains and losses for our energy commodity derivatives
designated as cash flow hedges, as recognized in AOCI,
revenues,
or
costs and operating expenses
.
| Three months ended March 31, | ||||||||||
| 2011 | 2010 | Classification | ||||||||
| (Millions) | ||||||||||
|
Net gain (loss) recognized in other comprehensive
income (loss) (effective portion)
|
$ | (23 | ) | $ | 278 | AOCI | ||||
|
|
||||||||||
|
Net gain (loss) reclassified from accumulated other
comprehensive income (loss) into income
(effective portion)
|
$ | 75 | $ | 25 |
Revenues or Costs and
Operating Expenses |
|||||
|
|
||||||||||
|
Gain (loss) recognized in income (ineffective portion)
|
$ | — | $ | 5 |
Revenues or Costs and
Operating Expenses |
|||||
There were no gains or losses recognized in income as a result of excluding amounts from the
assessment of hedge effectiveness or as a result of reclassifications to earnings following the
discontinuance of any cash flow hedges.
The following table presents pre-tax gains and losses for our energy commodity derivatives not
designated as hedging instruments.
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Revenues
|
$ | 2 | $ | 26 | ||||
|
Costs and operating expenses
|
— | — | ||||||
|
|
||||||||
|
Net gain
|
$ | 2 | $ | 26 | ||||
|
|
||||||||
The cash flow impact of our derivative activities is presented in the Consolidated Statement
of Cash Flows as
changes in current and noncurrent derivative assets and liabilities
.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require
us, in certain circumstances, to post additional collateral in support of our net derivative
liability positions. These credit-risk-related provisions require us to post collateral in the form
of cash or letters of credit when our net liability positions exceed an established credit
threshold. The credit thresholds are typically based on our senior unsecured debt ratings from
Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings
decline would lower our credit thresholds, thus requiring us to post additional collateral. We also
have contracts that contain adequate assurance provisions giving the counterparty the right to
request collateral in an amount that corresponds to the outstanding net liability. Additionally,
Exploration & Production has an unsecured credit agreement with certain banks related to hedging
activities. We are not required to provide collateral support for net derivative liability
positions under the credit agreement as long as the value of Exploration & Production’s domestic
natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified
amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money
position on hedges entered into under the credit agreement.
As of March 31, 2011, we did not have any collateral posted to derivative counterparties to
support the aggregate fair value of our net derivative liability position (reflecting master
netting arrangements in place with certain counterparties) of $26 million, which includes a
reduction of significantly less than $1 million to our liability balance for our own nonperformance
risk. At December 31, 2010, we had collateral totaling $8 million posted to
17
Table of Contents
Notes (Continued)
derivative counterparties, all of which was in the form of letters of credit, to support the
aggregate fair value of our net derivative liability position (reflecting master netting
arrangements in place with certain counterparties) of $36 million, which included a reduction of
less than $1 million to our liability balance for our own nonperformance risk. The additional
collateral that we would have been required to post, assuming our credit thresholds were eliminated
and a call for adequate assurance under the credit risk provisions in our derivative contracts was
triggered, was $26 million and $29 million at March 31, 2011 and December 31, 2010, respectively.
Cash flow hedges
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in
AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted
purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction
will not occur by the end of the originally specified time period. As of March 31, 2011, we have
hedged portions of future cash flows associated with anticipated energy commodity purchases and
sales for up to two years. Based on recorded values at March 31, 2011, $99 million of net gains
(net of income tax provision of $60 million) will be reclassified into earnings within the next
year. These recorded values are based on market prices of the commodities as of March 31, 2011. Due
to the volatile nature of commodity prices and changes in the creditworthiness of counterparties,
actual gains or losses realized within the next year will likely differ from these values. These
gains or losses are expected to substantially offset net losses or gains that will be realized in
earnings from previous unfavorable or favorable market movements associated with underlying hedged
transactions.
Guarantees
We are required by our revolving credit agreements to indemnify lenders for any taxes required
to be withheld from payments due to the lenders and for any tax payments made by the lenders. The
maximum potential amount of future payments under these indemnifications is based on the related
borrowings and such future payments cannot currently be determined. These indemnifications
generally continue indefinitely unless limited by the underlying tax regulations and have no
carrying value. We have never been called upon to perform under these indemnifications and have no
current expectation of a future claim.
We have provided a guarantee in the event of nonpayment by our previously owned communications
subsidiary, WilTel, on a certain lease performance obligation that extends through 2042. The
maximum potential exposure is approximately $39 million at March 31, 2011 and December 31, 2010.
Our exposure declines systematically throughout the remaining term of WilTel’s obligation. The
carrying value of the guarantee included in
accrued liabilities
on the Consolidated Balance Sheet
is $35 million at March 31, 2011 and December 31, 2010.
At March 31, 2011, we do not expect these guarantees to have a material impact on our future
liquidity or financial position. However, if we are required to perform on these guarantees in the
future, it may have a material adverse effect on our results of operations.
Concentration of Credit Risk
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their
contractual obligations. Counterparty performance can be influenced by changes in the economy and
regulatory issues, among other factors. Risk of loss is impacted by several factors, including
credit considerations and the regulatory environment in which a counterparty transacts. We attempt
to minimize credit-risk exposure to derivative counterparties and brokers through formal credit
policies, consideration of credit ratings from public ratings agencies, monitoring procedures,
master netting agreements and collateral support under certain circumstances. Collateral support
could include letters of credit, payment under margin agreements, and guarantees of payment by
credit worthy parties. The gross credit exposure from our derivative contracts as of March 31,
2011, is summarized as follows:
18
Table of Contents
Notes (Continued)
| Investment | ||||||||
| Counterparty Type | Grade(a) | Total | ||||||
| (Millions) | ||||||||
|
Gas and electric utilities
|
$ | 2 | $ | 2 | ||||
|
Energy marketers and traders
|
— | 142 | ||||||
|
Financial institutions
|
324 | 324 | ||||||
|
|
||||||||
|
|
$ | 326 | 468 | |||||
|
|
||||||||
|
Credit reserves
|
— | |||||||
|
|
||||||||
|
Gross credit exposure from derivatives
|
$ | 468 | ||||||
|
|
||||||||
We assess our credit exposure on a net basis to reflect master netting agreements in place
with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe
the counterparty under derivative contracts. The net credit exposure from our derivatives as of
March 31, 2011, excluding collateral support discussed below, is summarized as follows:
| Investment | ||||||||
| Counterparty Type | Grade(a) | Total | ||||||
| (Millions) | ||||||||
|
Gas and electric utilities
|
$ | 2 | $ | 2 | ||||
|
Energy marketers and traders
|
— | 1 | ||||||
|
Financial institutions
|
192 | 192 | ||||||
|
|
||||||||
|
|
$ | 194 | 195 | |||||
|
|
||||||||
|
Credit reserves
|
— | |||||||
|
|
||||||||
|
Net credit exposure from derivatives
|
$ | 195 | ||||||
|
|
||||||||
| (a) | We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. |
Our seven largest net counterparty positions represent approximately 96 percent of our net
credit exposure from derivatives and are all with investment grade counterparties. Included within
this group are counterparty positions, representing 83 percent of our net credit exposure from
derivatives, associated with Exploration & Production’s hedging facility. Under certain conditions,
the terms of this credit agreement may require the participating financial institutions to deliver
collateral support to a designated collateral agent (which is another participating financial
institution in the agreement). The level of collateral support required is dependent on whether the
net position of the counterparty financial institution exceeds specified thresholds. The thresholds
may be subject to prescribed reductions based on changes in the credit rating of the counterparty
financial institution.
At March 31, 2011, the designated collateral agent is not required to hold any collateral
support on our behalf under Exploration & Production’s hedging facility. We hold collateral
support, which may include cash or letters of credit, of $8 million related to our other derivative
positions.
Note 11. Contingent Liabilities
Issues Resulting from California Energy Crisis
Our former power business was engaged in power marketing in various geographic areas,
including California. Prices charged for power by us and other traders and generators in California
and other western states in 2000 and 2001 were challenged in various proceedings, including those
before the
Federal Energy Regulatory Commission (FERC). We have entered into settlements with the State of California (State Settlement),
major California utilities (Utilities Settlement), and others that substantially resolved each of
these issues with these parties.
19
Table of Contents
Notes (Continued)
Although the State Settlement and Utilities Settlement resolved a significant portion of the
refund issues among the settling parties, we continue to have potential refund exposure to
nonsettling parties, including various California end users that did not participate in the
Utilities Settlement. We are currently in settlement negotiations with certain California
utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject
to a final “true-up” mechanism, the settlement agreement would also resolve our collection of
accrued interest from counterparties as well as our payment of accrued interest on refund amounts.
Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not
all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to
these matters, amounts accrued are not material to our financial position.
Certain other issues also remain open at the FERC and for other nonsettling parties.
Reporting of Natural Gas-Related Information to Trade Publications
Civil suits based on allegations of manipulating published gas price indices have been brought
against us and others, in each case seeking an unspecified amount of damages. We are currently a
defendant in class action litigation and other litigation originally filed in state court in
Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas
in those states. These cases were transferred to the federal court in Nevada. In 2008, the
court granted summary judgment in the Colorado case in favor of us and most of the other
defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of
the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal, but the appeal cannot
occur until the case against the remaining defendant is concluded.
In the other cases, our joint motions for summary judgment to preclude the plaintiffs’ state
law claims based upon federal preemption have been pending since late 2009. If the motions are
granted, we expect a final judgment in our favor which the plaintiffs could appeal. If the motions
are denied, the current stay of activity would be lifted, class certification would be addressed,
and discovery would be completed as the cases proceed towards trial. Because of the uncertainty
around these current pending unresolved issues, including an insufficient description of the
purported classes and other related matters, we cannot reasonably estimate a range of potential
exposures at this time. However, it is reasonably possible that the ultimate resolution of these
items could result in future charges that may be material to our results of operations.
Environmental Matters
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain
facilities and locations for polychlorinated biphenyl, mercury contamination, and other hazardous
substances. These activities have involved the U.S. Environmental Protection Agency (EPA), various
state environmental authorities and identification as a potentially responsible party at various
Superfund waste disposal sites. At March 31, 2011, we have accrued liabilities of $12 million for
these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities,
primarily related to soil and groundwater contamination. At March 31, 2011, we have accrued
liabilities totaling $7 million for these costs.
In March 2008, the EPA proposed a penalty of $370,000 for alleged violations relating to leak
detection and repair program delays at our Ignacio gas plant in Colorado and for alleged permit
violations at a compressor station. Tentative settlement has been reached in first-quarter 2011.
In September 2007, the EPA requested, and our Transco subsidiary later provided, information
regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the
EPA’s investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued
notices of violation alleging violations of Clean Air Act requirements at these compressor
stations. Transco met with the EPA in May 2008 and submitted our response denying the allegations
in June 2008. The EPA has requested additional information pertaining to these compressor stations,
most recently in February 2011. In August 2010, the EPA requested and our Transco subsidiary
provided, similar information for a compressor station in Maryland.
20
Table of Contents
Notes (Continued)
Former operations, including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate.
These potential obligations include the indemnification of the purchasers of certain of these
assets and businesses for environmental and other liabilities existing at the time the sale was
consummated. Our responsibilities relate to the operations of the
assets and businesses described below.
| • | Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; |
| • | Former petroleum products and natural gas pipelines; |
| • | Discontinued petroleum refining facilities; |
| • | Former exploration and production and mining operations. |
At March 31, 2011, we have accrued environmental liabilities of $31 million related to these
matters.
Actual costs for these matters could be substantially greater than amounts accrued depending
on the actual number of contaminated sites identified, the actual amount and extent of
contamination discovered, the final cleanup standards mandated by the EPA and other governmental
authorities. Any incremental amount cannot be reasonably estimated at this time.
Certain of our subsidiaries have been identified as potentially responsible parties at various
Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are
alleged to have incurred, various other hazardous materials removal or remediation obligations
under environmental laws.
Environmental matters — general
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and
issue updated guidance to existing rules. These new rules and rulemakings include, but are not
limited to, rules for reciprocating internal combustion engine maximum achievable control
technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide
emission limits. We are unable to estimate the costs of asset additions or modifications necessary
to comply with these new regulations due to uncertainty created by the various legal challenges to
these regulations and the need for further specific regulatory guidance.
Other Legal Matters
Gulf Liquids litigation
Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture
between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana.
National American Insurance Company (NAICO) and American Home Assurance Company provided payment
and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases
in Louisiana and Texas against Gulf Liquids and us.
In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims,
the jury returned its actual and punitive damages verdict against us and Gulf Liquids. Based on our
interpretation of the jury verdicts, we recorded a charge based on our estimated exposure for
actual damages of approximately $68 million plus potential interest of approximately $20 million.
In addition, we concluded that it was reasonably possible that any ultimate judgment might have
included additional amounts of approximately $199 million in excess of our accrual, which primarily
represented our estimate of potential punitive damage exposure under Texas law.
From May through October 2007, the court entered seven post-trial orders in the case
(interlocutory orders) which, among other things, overruled the verdict award of tort and punitive
damages as well as any damages against
21
Table of Contents
Notes (Continued)
us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the
court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in
favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby,
Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with certain of
these parties and reduced our liability as of December 31, 2008, by $43 million, including $11
million of interest. On February 17, 2011, the Texas Court of Appeals upheld the dismissals of the
tort and punitive damages claims and reversed and remanded the contract claim and attorney fee
claims for further proceedings. The appellate court ruling is subject to a potential appeal to the
Texas Supreme Court. If the appellate court judgment is upheld, our
remaining liability could be
less than the amount of our accrual for these matters.
Royalty litigation
22
Table of Contents
Notes (Continued)
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action
suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas
royalty payments, failed to account for the proceeds that we received from the sale of natural gas and
extracted products, improperly charged certain expenses, and failed to refund amounts withheld in
excess of ad valorem tax obligations. Plaintiffs sought to certify as a class of royalty interest
owners, recover underpayment of royalties and obtain corrected payments resulting from calculation
errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification,
reserved two claims for court resolution, resolved all other class claims relating to past
calculation of royalty and overriding royalty payments, and established certain rules to govern
future royalty and overriding royalty payments. This settlement resolved all claims relating to
past withholding for ad valorem tax payments and established a procedure for refunds of any such
excess withholding in the future. The first reserved claim is whether we are entitled to deduct in
our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the
treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment
on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals
found in our favor in April 2011. We anticipate knowing later in
2011 whether plaintiffs will
pursue any further appeal on the first reserved claim. The second
reserved claim relates to whether we are required to have
proportionately increased the value of natural gas by transporting that gas on
mainline transmission lines and, if required, whether we did so
and are thus entitled to deduct a proportionate share of
transportation costs in calculating royalty payments. We anticipate trial on the second reserved
claim following resolution of the first reserved claim. We believe our royalty calculations have
been properly determined in accordance with the appropriate contractual
arrangements and Colorado law.
At this time, the plaintiffs have not provided us a sufficient framework to calculate an
estimated range of exposure related to their claims. However, it is reasonably possible that the
ultimate resolution of this item could result in a future charge that
may be material to our results of
operations.
Other producers have been in litigation or discussions with a federal regulatory agency and a
state agency in New Mexico regarding certain deductions, comprised primarily of processing,
treating and transportation costs, used in the calculation of royalties. Although we are not a
party to these matters, we have monitored them to evaluate whether their resolution might have the
potential for unfavorable impact on our results of operations. One of these matters involving
federal litigation was decided on October 5, 2009. The resolution of this specific matter is not
material to us. However, other related issues in these matters that could be material to us remain
outstanding. We received notice from the U.S. Department of Interior Office of Natural Resources
Revenue (ONRR) in the fourth quarter of 2010, intending to clarify the guidelines for calculating
federal royalties on conventional gas production applicable to our federal leases in New Mexico.
The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for
transportation and processing can be deducted from the royalty payment. We believe using these
guidelines would not result in a material difference in determining our historical federal royalty
payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for
leases in other states, but such guidelines are expected in the future. However, the timing of
receipt of the necessary guidelines is uncertain. In addition, these interpretive guidelines on
the applicability of certain deductions in the calculation of federal royalties are extremely
complex and will vary based upon the ONRR’s assessment of the configuration of processing, treating
and transportation operations supporting each federal lease. From January 2004 through December
2010, our deductions used in the calculation of the royalty payments in states other than New
Mexico associated with conventional gas production total approximately $55 million. Based on
correspondence in 2009 with the ONRR’s predecessor, we believe
our calculating assumptions have
been consistent with the requirements. The issuance of similar guidelines in Colorado and other
states could affect our previous royalty payments and the effect could be material to our results
of operations.
Other
In 2003, we entered into an agreement to sublease certain underground storage facilities to
Liberty Gas Storage (Liberty). We have asserted claims against Liberty for prematurely terminating
the sublease and for damage caused to the facilities. In February 2011, Liberty asserted a
counterclaim for costs in excess of $200 million associated with its use of the facilities. Due to
the lack of information currently available, we are unable to evaluate the merits of the
counterclaim and determine the amount of any possible liability.
23
Table of Contents
Notes (Continued)
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets,
we have indemnified certain purchasers against liabilities that they may incur with respect to the
businesses and assets acquired from us. The indemnities provided to the purchasers are customary in
sale transactions and are contingent upon the purchasers incurring liabilities that are not
otherwise recoverable from third parties. The indemnities generally relate to breach of warranties,
tax, historic litigation, personal injury, property damage, environmental matters, right of way and
other representations that we have provided.
At March 31, 2011, we do not expect any of the indemnities provided pursuant to the sales
agreements to have a material impact on our future financial position. However, if a claim for
indemnity is brought against us in the future, it may have a material adverse effect on our results
of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are
incidental to our operations.
Summary
Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent
uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material
adverse impact on the results of operations in the period in which the ruling occurs. Management,
including internal counsel, currently believes that the ultimate resolution of the foregoing
matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery
from customers or other indemnification arrangements, will not have a material adverse effect upon
our future liquidity or financial position.
Note 12. Segment Disclosures
Our reporting segments are Williams Partners, Exploration & Production and Midstream Canada &
Olefins. All remaining business activities are included in Other. (See Note 2.)
Performance Measurement
We currently evaluate performance based upon
segment profit (loss)
from operations, which
includes
segment revenues
from external and internal customers,
segment costs and expenses
,
equity
earnings (losses)
and
income (loss) from investments
. Intersegment sales are generally accounted
for at current market prices as if the sales were to unaffiliated third parties.
The primary types of costs and operating expenses by segment can be generally summarized as
follows:
| • | Williams Partners—commodity purchases (primarily for NGL and crude marketing, shrink and fuel), depreciation and operation and maintenance expenses; |
| • | Exploration & Production—commodity purchases (primarily in support of commodity marketing and risk management activities), depletion, depreciation and amortization, lease and facility operating expenses and operating taxes; |
| • | Midstream Canada & Olefins—commodity purchases (primarily for shrink, feedstock and NGL and olefin marketing activities), depreciation and operation and maintenance expenses. |
24
Table of Contents
Notes (Continued)
The following table reflects the reconciliation of
segment revenues
and
segment profit (loss)
to
revenues
and
operating income (loss)
as reported in the Consolidated Statement of Operations.
| Exploration | Midstream | |||||||||||||||||||||||
| Williams | & | Canada & | ||||||||||||||||||||||
| Partners | Production | Olefins | Other | Eliminations | Total | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
|
Three months ended March 31, 2011
|
||||||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||||||
|
External
|
$ | 1,478 | $ | 779 | $ | 316 | $ | 2 | $ | — | $ | 2,575 | ||||||||||||
|
Internal
|
101 | 210 | — | 4 | (315 | ) | — | |||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total revenues
|
$ | 1,579 | $ | 989 | $ | 316 | $ | 6 | $ | (315 | ) | $ | 2,575 | |||||||||||
|
|
||||||||||||||||||||||||
|
Segment profit (loss)
|
$ | 437 | $ | 51 | $ | 74 | $ | 20 | $ | — | $ | 582 | ||||||||||||
|
Less:
|
||||||||||||||||||||||||
|
Equity earnings (losses)
|
25 | 6 | — | 9 | — | 40 | ||||||||||||||||||
|
Income (loss) from investments
|
— | — | — | 11 | — | 11 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Segment operating income (loss)
|
$ | 412 | $ | 45 | $ | 74 | $ | — | $ | — | 531 | |||||||||||||
|
|
||||||||||||||||||||||||
|
General corporate expenses
|
(51 | ) | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total operating income (loss)
|
$ | 480 | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Three months ended March 31, 2010
|
||||||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||||||
|
External
|
$ | 1,397 | $ | 925 | $ | 267 | $ | 2 | $ | — | $ | 2,591 | ||||||||||||
|
Internal
|
93 | 232 | 5 | 4 | (334 | ) | — | |||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total revenues
|
$ | 1,490 | $ | 1,157 | $ | 272 | $ | 6 | $ | (334 | ) | $ | 2,591 | |||||||||||
|
|
||||||||||||||||||||||||
|
Segment profit (loss)
|
$ | 424 | $ | 153 | $ | 20 | $ | 7 | $ | — | $ | 604 | ||||||||||||
|
Less equity earnings (losses)
|
26 | 5 | — | 9 | — | 40 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Segment operating income (loss)
|
$ | 398 | $ | 148 | $ | 20 | $ | (2 | ) | $ | — | 564 | ||||||||||||
|
|
||||||||||||||||||||||||
|
General corporate expenses
|
(85 | ) | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total operating income (loss)
|
$ | 479 | ||||||||||||||||||||||
|
|
||||||||||||||||||||||||
Total
segment revenues for Exploration & Production include $405 million and $556 million
of gas management revenues for the three months ended March 31, 2011 and 2010, respectively. Gas
management revenues include sales of natural gas in conjunction with marketing services provided to
third parties and intercompany sales of fuel and shrink gas to the midstream businesses in Williams
Partners. These revenues are substantially offset by similar amounts of gas management costs.
25
Table of Contents
Notes (Continued)
The following table reflects
total assets
by reporting segment.
| Total Assets | ||||||||
| March 31, 2011 | December 31, 2010 | |||||||
| (Millions) | ||||||||
|
Williams Partners
|
$ | 13,437 | $ | 13,404 | ||||
|
Exploration & Production
|
9,735 | 9,827 | ||||||
|
Midstream Canada & Olefins
|
1,014 | 922 | ||||||
|
Other
|
3,588 | 3,481 | ||||||
|
Eliminations
|
(2,691 | ) | (2,662 | ) | ||||
|
|
||||||||
|
Total
|
$ | 25,083 | $ | 24,972 | ||||
|
|
||||||||
26
Table of Contents
Item 2
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Results of Operations
Changes in Structure and Dividend Increase
On February 16, 2011, we announced our reorganization plan to divide our business into two
separate, publicly traded corporations. On April 29, 2011, our wholly owned subsidiary, WPX Energy,
Inc. (WPX), filed a registration statement with the SEC with respect to an initial public offering
of its equity securities. This is the first step in our reorganization plan, which calls for a
separation of our exploration and production business through an initial public offering of up to
20 percent of WPX in 2011 and a tax-free spin-off of our remaining interest in WPX to our
shareholders in 2012, after which Williams would continue as a premier natural gas infrastructure
company. We retain the discretion to determine whether and when to complete these transactions. In
conjunction with the initial public offering, we expect WPX to establish a new credit facility and
issue senior unsecured notes. We expect that a substantial portion of the combined net proceeds of
these transactions will be used to repay a portion of our existing debt.
Additionally, in April 2011 our Board of Directors approved a regular quarterly dividend
payable in June 2011 of $0.20 per share, which reflects an increase of 60 percent compared to the
$0.125 per share paid to our shareholders in each of the last four quarters.
Management believes these actions will serve to enhance the growth potential and overall
valuation of our assets.
Overview of Three Months Ended March 31, 2011
Income (loss) from continuing operations attributable to The Williams Companies, Inc.,
for the
three months ended March 31, 2011, changed favorably by $524 million compared to the three months
ended March 31, 2010. This change includes:
| • | The absence of $645 million of pre-tax costs attributable to The Williams Companies, Inc., associated with our 2010 restructuring, including $606 million of early debt retirement costs. | ||
| • | A $124 million tax benefit recorded in first-quarter 2011 associated with federal settlements and an international revised assessment. (See Note 5 of Notes to Consolidated Financial Statements.) | ||
| • | A $54 million improvement in operating income at Midstream Canada & Olefins due to higher olefin and NGL margins primarily from higher per-unit margins. (See Results of Operations — Segments, Midstream Canada & Olefins). | ||
| • | Slightly improved operating income at Williams Partners primarily due to higher fee revenues and improved NGL prices, offset by lower volumes. (See Results of Operations — Segments, Williams Partners). |
Partially offsetting these favorable changes are lower operating results within Exploration &
Production. (See Results of Operations — Segments, Exploration & Production.)
See additional discussion in Results of Operations.
Our
net cash provided by operating activities
for the three months ended March 31, 2011,
increased $194 million compared to the three months ended March 31, 2010, primarily due to net
favorable changes in working capital.
(
See Management’s Discussion and Analysis of Financial
Condition and Liquidity.)
27
Table of Contents
Management’s Discussion and Analysis (Continued)
Recent Events
Beginning with the first quarter of 2011, we changed our segment reporting structure to
present our Canadian midstream and domestic olefins operations as a separate segment, Midstream
Canada & Olefins. These operations were previously reported within Other. Prior periods have been
recast to reflect this revised segment presentation.
In March 2011, Midstream Canada & Olefins announced a long-term agreement under which it will
produce up to 17,000 barrels per day of ethane/ethylene mix for a chemical company in Alberta,
Canada. We plan to expand two primary facilities located in Alberta to support the new agreement.
(See Results of Operations — Segments, Midstream Canada & Olefins.)
During April 2011, we agreed to contribute an additional 24.5 percent interest in Gulfstream
Natural Gas System, L.L.C. (Gulfstream) to WPZ in exchange for aggregate consideration of $297
million of cash and 632,584 limited partner units, and an increase in the capital account of its
general partner units to allow us to maintain our 2 percent general partner interest. WPZ expects
to fund the cash consideration for this transaction through its credit facility. Upon completing
this transaction, which is expected to close during the second quarter of 2011, the Williams
Partners segment will hold a 49 percent interest in Gulfstream, while Other will hold a 1 percent
interest.
Company Outlook
We believe we are well positioned to execute on our 2011 business plan and to capture
attractive growth opportunities. Economic and commodity price indicators for 2011 and beyond
reflect continued improvement in the economic environment. However, given the potential volatility
of these measures, the economy could worsen and/or commodity prices could decline, negatively
impacting future operating results and increasing the risk of nonperformance of counterparties or
impairments of long-lived assets.
We are positioned to drive additional organic growth and aggressively pursue value-adding
growth opportunities. Our structure is designed to lower capital costs, enhance reliable access to
capital markets, and create a greater ability to pursue development projects and acquisitions.
We continue to operate with a focus on Economic Value Added (EVA
®
)
1
and
invest in our businesses in a way that meets customer needs and enhances our competitive position
by:
| • | Continuing to invest in and grow our gathering and processing, interstate natural gas pipeline systems, and natural gas drilling; | ||
| • | Retaining the flexibility to adjust somewhat our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. |
Potential risks and/or obstacles that could impact the execution of our plan include:
| • | Lower than anticipated energy commodity prices and margins; | ||
| • | Lower than expected levels of cash flow from operations; | ||
| • | Availability of capital; | ||
| • | Counterparty credit and performance risk; | ||
| • | Decreased drilling success at Exploration & Production; | ||
| • | Decreased volumes from third parties served by our midstream businesses; |
| 1 | Economic Value Added ® (EVA ® ) is a registered trademark of Stern Stewart & Co. This tool considers both financial earnings and a cost of capital in measuring performance. We look for opportunities to improve EVA ® because we believe there is a strong correlation between EVA ® improvement and creation of shareholder value. |
28
Table of Contents
Management’s Discussion and Analysis (Continued)
| • | General economic, financial markets, or industry downturn; | ||
| • | Changes in the political and regulatory environments; | ||
| • | Physical damages to facilities, especially damage to offshore facilities by named windstorms. |
We continue to address these risks through utilization of commodity hedging strategies,
disciplined investment strategies, and maintaining at least $1 billion in consolidated liquidity
from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize
master netting agreements and collateral requirements with our counterparties to reduce credit risk
and liquidity requirements.
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 of this Form 10-Q and our 2010 Annual
Report on Form 10-K.
Critical Accounting Estimate
Impairments of Long-Lived Assets
We evaluate our long-lived assets for impairment when we believe events or changes in
circumstances indicate that we may not be able to recover the carrying value. Our computations
utilize judgments and assumptions that include the estimated fair value of the asset, undiscounted
future cash flows, discounted future cash flows, and the current and future economic environment in
which the asset is operated.
As a result of significant declines in forward natural gas prices during the third quarter of
2010, we assessed Exploration & Production’s natural gas producing properties and acquired unproved
reserve costs for impairment using estimates of future cash flows. Significant judgments and
assumptions in these assessments include estimates of natural gas reserves quantities, estimates of
future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials,
drilling plans, expected capital costs, and our estimate of an applicable discount rate
commensurate with risk of the underlying cash flow estimates. The assessment performed at September
30, 2010, identified certain properties with a carrying value in excess of their calculated fair
values which resulted in an impairment charge.
In addition to those long-lived assets described above for which impairment charges were
recorded, certain others were reviewed for which no impairment was required. These reviews included
Exploration & Production’s other domestic producing properties and acquired unproved reserve costs,
and utilized inputs generally consistent with those described above. Judgments and assumptions are
inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate
judgments and assumptions could result in the recognition of different levels of impairment charges
in the consolidated financial statements. For Exploration & Production’s other producing assets
reviewed, but for which impairment charges were not recorded, we estimate that approximately 9
percent could be at risk for impairment if forward prices across all future periods decline by
approximately 8 percent, on average, as compared to the forward prices at December 31, 2010. A
substantial portion of the remaining carrying value of these other assets (primarily related to
Exploration & Production’s assets in the Piceance basin) could be at risk for impairment if forward
prices across all future periods decline by at least 30 percent, on average, as compared to the
prices at December 31, 2010. At March 31, 2011, forward natural gas prices remained above those
used in our year-end analysis. As a result, we have not re-evaluated these assets for impairment.
29
Table of Contents
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 months ended March 31, 2011, compared to the three months ended March 31, 2010. The
results of operations by segment are discussed in further detail following this consolidated
overview discussion.
| Three months ended | ||||||||||||||||
| March 31, | ||||||||||||||||
| 2011 | 2010 | $ Change* | % Change* | |||||||||||||
| (Millions) | ||||||||||||||||
|
Revenues
|
$ | 2,575 | $ | 2,591 | -16 | -1 | % | |||||||||
|
Costs and expenses:
|
||||||||||||||||
|
Costs and operating expenses
|
1,908 | 1,917 | +9 | 0 | % | |||||||||||
|
Selling, general and administrative expenses
|
137 | 111 | -26 | -23 | % | |||||||||||
|
Other (income) expense — net
|
(1 | ) | (1 | ) | — | 0 | % | |||||||||
|
General corporate expenses
|
51 | 85 | +34 | +40 | % | |||||||||||
|
|
||||||||||||||||
|
Total costs and expenses
|
2,095 | 2,112 | ||||||||||||||
|
Operating income (loss)
|
480 | 479 | ||||||||||||||
|
Interest accrued — net
|
(149 | ) | (147 | ) | -2 | -1 | % | |||||||||
|
Investing income — net
|
51 | 39 | +12 | +31 | % | |||||||||||
|
Early debt retirement costs
|
— | (606 | ) | +606 | +100 | % | ||||||||||
|
Other income (expense) — net
|
4 | (7 | ) | +11 | NM | |||||||||||
|
|
||||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
386 | (242 | ) | |||||||||||||
|
Provision (benefit) for income taxes
|
(6 | ) | (94 | ) | -88 | -94 | % | |||||||||
|
|
||||||||||||||||
|
Income (loss) from continuing operations
|
392 | (148 | ) | |||||||||||||
|
Income (loss) from discontinued operations
|
(8 | ) | 2 | -10 | NM | |||||||||||
|
|
||||||||||||||||
|
Net income (loss)
|
384 | (146 | ) | |||||||||||||
|
Less: Net income attributable to noncontrolling interests
|
63 | 47 | -16 | -34 | % | |||||||||||
|
|
||||||||||||||||
|
Net income (loss) attributable to The Williams Companies, Inc.
|
$ | 321 | $ | (193 | ) | |||||||||||
|
|
||||||||||||||||
| * | + = 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 March 31, 2011 vs. three months ended March 31, 2010
The decrease in
revenues
is primarily due to lower gas management revenues at Exploration &
Production, reflecting a decrease in average natural gas sales prices and a decrease in natural gas
sales volumes. In addition, NGL production revenues at Williams Partners decreased due to a
decrease in NGL volumes, partially offset by an increase in average NGL per-unit sales prices.
These decreases are partially offset by higher marketing revenues at Williams Partners due to
higher average NGL and crude prices and higher NGL volumes, partially offset by lower crude
volumes.
In addition, NGL and olefins production revenues at Midstream Canada
& Olefins increased due to higher per-unit margins.
The decrease in
costs and operating expenses
is primarily due to decreased average natural gas
prices and purchase volumes associated with gas management activities at Exploration & Production
and decreased costs associated with the production of NGLs at Williams Partners reflecting lower
average natural gas prices and lower NGL volumes. These decreases are partially offset by
increased marketing purchases at Williams Partners due to higher average NGL and crude prices and
higher NGL volumes, partially offset by lower crude volumes. In addition, gathering, processing
and transportation expenses at Exploration & Production increased and operating costs increased at
Williams Partners, primarily due to higher depreciation, an unfavorable change in system gains and
losses, and higher maintenance costs.
30
Table of Contents
Management’s Discussion and Analysis (Continued)
The increase in
selling, general and administrative expenses
is primarily due to
$13 million
increase at Exploration & Production primarily due to higher bad
debt expense, higher wages, salary and benefits costs as a result of
an increase in the number of employees and $11 million increase at Williams Partners including higher
employee-related expenses from gas pipeline operations.
General corporate expenses
in 2010 includes $39 million of transaction costs associated with
our strategic restructuring transaction.
The favorable change in
investing income — net
is primarily due to $11 million gain in 2011
related to the 2010 sale of our interest in Accroven SRL at Other (see Management’s Discussion and
Analysis — Other).
Early debt retirement costs
in 2010 reflect costs related to corporate debt retirements
associated with our first quarter 2010 strategic restructuring transaction, including premiums of
$574 million.
Provision (benefit) for income taxes
changed unfavorably primarily due to pre-tax income in
2011 compared to pre-tax loss in 2010, partially offset by approximately $124 million tax benefit
from federal settlements and an international revised assessment. 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.
The unfavorable change in
net income attributable to noncontrolling interests
reflects our
decreased percentage of ownership of WPZ, which was 75 percent at March 31, 2011 compared to 84
percent at March 31, 2010, and slightly lower results, primarily at WPZ, due to increased interest
on debt in 2011 compared to 2010 and decreased capitalized interest due to project completions.
31
Table of Contents
Management’s Discussion and Analysis (Continued)
Results of Operations
—
Segments
Williams Partners
Our Williams Partners segment includes WPZ, our consolidated master limited partnership, which
includes two interstate natural gas pipelines, as well as investments in natural gas
pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico
and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern
United States. WPZ also includes natural gas gathering and processing and treating facilities and
oil gathering and transportation facilities located primarily in the Rocky Mountain and Gulf Coast
regions of the United States. As of March 31, 2011, we own approximately 75 percent of the
interests in WPZ, including the interests of the general partner, which is wholly owned by us, and
incentive distribution rights.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate
natural gas transmission and midstream infrastructures where our assets can be fully utilized and
drive low per-unit costs. We focus on consistently attracting new business by providing highly
reliable service to our customers and utilizing our low cost-of-capital to invest in growing
markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the western United States,
and areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related storage activities are subject to
regulation by the FERC and as such, our rates and charges for the transportation of natural gas in
interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and
accounting, among other things, are subject to regulation. The rates are established through the
FERC’s ratemaking process. Changes in commodity prices and volumes transported have little
near-term impact on revenues because the majority of cost of service is recovered through firm
capacity reservation charges in transportation rates.
Overview of Three Months Ended March 31, 2011
Significant events during 2011 include the following:
Perdido Norte
Both oil and gas production began to flow on a sustained basis during the fourth quarter of
2010 through our Perdido Norte expansion, located in the western deepwater of the Gulf of Mexico.
The project includes a 200 MMcf/d expansion of our onshore Markham gas processing facility and a
total of 179 miles of deepwater oil and gas lines that expand the scale of our existing
infrastructure. While production volumes are currently significantly lower than expected, producers
continue to work through technical issues and we anticipate volumes to increase significantly
during 2011.
Overland Pass Pipeline
We became operator of Overland Pass Pipeline Company LLC (OPPL) effective April 1, 2011. We
own a 50 percent interest in OPPL which includes a 760-mile NGL pipeline from Opal, Wyoming, to the
Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the
Piceance and Denver-Julesburg basins in Colorado, respectively. Our equity NGL volumes from our two
Wyoming plants and our Willow Creek plant in Colorado are dedicated for transport on OPPL under a
long-term shipping agreement. Work is under way to determine optimal expansions to serve producers
in the OPPL corridor.
32
Table of Contents
Management’s Discussion and Analysis (Continued)
Marcellus Shale Gathering Asset Transition and Expansion
We assumed the operational activities for a gathering business in Pennsylvania’s Marcellus
Shale which we acquired at the end of 2010. This business includes 75
miles of gathering pipelines and two compressor stations. We expect gathered volumes to increase
under our long-term dedicated gathering agreement for the seller’s production. Additionally,
engineering and construction activities continue on our Springville gathering pipeline which will
connect the gathering system into the Transco pipeline.
Volatile commodity prices
Average per-unit NGL margins in the first quarter of 2011 are significantly higher than the
same period in 2010, benefiting from significantly lower natural gas prices driven by abundant
natural gas supplies, while a strong demand for NGLs has resulted in slightly higher NGL prices.
NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel,
and third-party transportation and fractionation. Per-unit NGL margins are calculated based on
sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we
own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing
agreements, where we have the obligation to replace the lost heating value with natural gas, and
“percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no
obligation to replace the lost heating value.
33
Table of Contents
Management’s Discussion and Analysis (Continued)
Outlook for the Remainder of 2011
The following factors could impact our business in 2011.
Commodity price changes
| • | We expect our average per-unit NGL margins in 2011 to be higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude and natural gas prices are highly volatile, difficult to predict and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets. | ||
| • | As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of approximately 14 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink gas requirements for the remainder of 2011. The combined impact of these energy commodity derivatives will provide a margin on the hedged volumes of $171 million. |
Gathering, processing, and NGL sales volumes
| • | The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. | ||
| • | We anticipate growth in our onshore businesses’ gas gathering and processing volumes as our infrastructure grows to support drilling activities in the Piceance and Appalachian basins. However, we anticipate no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. Due to the high proportion of fee-based processing agreements in the Piceance basin, we anticipate only a slight increase in NGL equity sales volumes. | ||
| • | In our Gulf Coast businesses, we expect higher gas gathering, processing and crude transportation volumes as our Perdido Norte pipelines move into a full year of operation and other in-process drilling is completed. Recent increases in permitting, subsequent to the 2010 drilling moratorium, give us reason to expect gradual increased drilling activities in the Gulf of Mexico. While we expect an overall increase in processed gas volumes in 2011, NGL equity volumes are expected to be lower as a major contract changed from “keep-whole” to “percent-of-liquids” processing. |
Expansion projects
We expect to spend $1,420 million to $1,700 million in 2011 on capital projects and additional
investments in partially owned equity investments, of which $1,276
million to $1,556 million remains to
be spent. The ongoing major expansion projects include:
85 North
An expansion of our existing natural gas transmission system from Alabama to various
delivery points as far north as North Carolina. The cost of the project is estimated to be $227
million. Phase I service was placed into service in July 2010 and increased capacity by 90
Mdt/d. Phase II was placed in service in May 2011, increasing capacity by 219 Mdt/d.
Mobile Bay South II
Additional compression facilities and modifications to existing facilities in Alabama
allowing natural gas
34
Table of Contents
Management’s Discussion and Analysis (Continued)
transportation service to various southbound delivery points. In July 2010 we received
approval from the U.S. Federal Energy Regulatory Commission. Construction began in October 2010
and is estimated to cost $35 million. This project was placed in service in May 2011, increasing
capacity by 380 Mdt/d.
Mid-South
Additional compressor facilities and expansion of our existing natural gas transmission
system from Alabama to markets as far north as North Carolina. The cost of the project is
estimated to be $217 million. The project is expected to be phased into service in September
2012 and June 2013, with an increase in capacity of 225 Mdt/d.
Mid-Atlantic Connector
An expansion to our existing natural gas transmission system from North Carolina to markets
as far downstream as Maryland. The cost of the project is estimated to be $55 million and will
increase capacity by 142 Mdt/d. We plan to place the project into service in November 2012.
Marcellus Shale
Additional gathering assets, including compression and dehydration, in the Appalachian
basin. In conjunction with a long-term agreement with a significant producer, we plan to
construct and operate a 33-mile, 24-inch diameter natural gas gathering pipeline in the
Marcellus Shale region which will connect our recently acquired gathering assets in
Pennsylvania’s Marcellus Shale into the Transco pipeline. Engineering and construction
activities on the Springville pipeline and compressor station have begun and that project is
expected to be completed in the latter part of 2011. Other compression and dehydration projects
to increase capacity to approximately 500 to 550 MMcf/d are nearing completion and are expected to be
in service by the end of the second quarter of 2011.
Laurel Mountain
Capital to be invested within our Laurel Mountain Midstream, LLC (Laurel Mountain) equity
investment, also in the Marcellus Shale region, to enable the rapid expansion of our gathering
system including the initial stages of projects that are planned to provide approximately 1.5
Bcf/d of gathering capacity and 1,400 miles of gathering lines, including 400 new miles of
6-inch to 24-inch diameter pipeline. The initial phase of our Shamrock compressor station went
in service during the first quarter of 2011, providing 30 MMcf/d of additional capacity, with
another 150 MMcf/d expected to be available by the end of the fourth quarter of 2011. This
compressor station is expandable to 350 MMcf/d, and will likely be the largest central delivery
point out of the Laurel Mountain system.
We have several other proposed projects to meet customer demands in addition to the various
in-progress expansion projects previously discussed. Subject to regulatory approvals, construction
of some of these projects could begin in the remainder of 2011.
Period-Over-Period Operating Results
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Segment revenues
|
$ | 1,579 | $ | 1,490 | ||||
|
|
||||||||
|
Segment profit
|
$ | 437 | $ | 424 | ||||
|
|
||||||||
35
Table of Contents
Management’s Discussion and Analysis (Continued)
Three months ended March 31, 2011 vs. three months ended March 31, 2010
The increase in
segment revenues
includes:
| • | A $102 million increase in marketing revenues primarily due to higher average NGL and crude prices and higher NGL volumes, partially offset by lower crude volumes. These changes are offset by similar changes in marketing purchases. | ||
| • | A $12 million increase in fee revenues primarily due to higher gathering and processing fee revenue in the Piceance basin as a result of the agreement with Exploration & Production executed in November 2010 and new gathering fee revenues from our recently acquired gathering assets in the Marcellus Shale. These increases are partially offset by a decline in gathering and transportation fees in the Four Corners area and in the deepwater of the eastern Gulf of Mexico due primarily to natural field declines. | ||
| • | A $9 million increase in natural gas transportation revenue associated with gas pipeline expansion projects placed into service in 2010. | ||
| • | A $32 million decrease in revenues associated with the production of our equity NGLs reflecting a decrease of $40 million associated with a 13 percent decrease in NGL volumes, partially offset by an increase of $8 million associated with a slight increase in average NGL per-unit sales prices. The decrease in NGL volumes was primarily due to a change in a major contract from “keep-whole” to “percent-of-liquids” processing. |
Segment
costs and expenses
increased $75 million, including:
| • | A $90 million increase in marketing purchases primarily due to higher average NGL and crude prices and higher NGL volumes, partially offset by lower crude volumes. These changes are offset by similar changes in marketing revenues. | ||
| • | A $29 million increase in operating costs including $10 million higher maintenance expenses, $10 million higher depreciation primarily due to our new Perdido Norte pipelines and a $6 million unfavorable change related to system losses in the current period compared with system gains in the same period in 2010. | ||
| • | A $46 million decrease in costs associated with the production of our NGLs reflecting a decrease of $34 million associated with a 25 percent decrease in average natural gas prices and a $12 million decrease from lower NGL volumes. |
The increase in Williams Partners’
segment profit
includes:
| • | A $14 million increase in NGL margins reflecting a $46 million decrease in NGL production costs, substantially offset by $32 million in lower revenues, as discussed above. | ||
| • | A $12 million increase in fee revenues as previously discussed. | ||
| • | A $12 million increase in margins related to the marketing of NGLs and crude primarily due to more favorable changes in pricing while product was in transit in 2011 as compared to 2010. | ||
| • | A $10 million reversal of project feasibility costs from expense to capital, associated with a natural gas pipeline expansion project, upon determining that the related project was probable of development. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates. | ||
| • | A $29 million increase in operating costs as previously discussed. |
Exploration & Production
Our
Exploration & Production segment is engaged in
the exploitation and development of long-life unconventional properties. We are focused on
profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance
Basin of the Rocky Mountain region, and on developing and growing our position in the Bakken Shale
oil play in North Dakota and our Marcellus Shale natural gas position in Pennsylvania. Our other
areas of domestic operations include the Powder River basin in Wyoming and the San Juan basin in
the southwestern United States. In addition, we own a 69 percent controlling ownership interest in
Apco Oil and Gas International Inc. (Apco), which holds oil and gas concessions in Argentina and
Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.”
In addition to our exploration and development activities, we engage in natural gas sales
and marketing. Our sales and marketing activities to date include the sale of our natural gas and
oil production, in addition to third party purchases and sales of natural gas, including sales to
Williams Partners for use in its midstream business. Our sales and marketing activities include the
management of various natural gas related contracts such as transportation, storage and related
hedges. We also sell natural gas purchased from working interest owners in operated wells and other
area third party producers. We primarily engage in these activities to enhance the value received
from the sale of our natural gas and oil production. Revenues
associated with the sale of our domestic production are recorded in
domestic production revenues. The revenues and expenses related to
other marketing activities are reported on a gross basis as part of
gas management revenues and costs and expenses.
36
Table of Contents
Management’s Discussion and Analysis (Continued)
As
previously disclosed, WPX filed its initial registration statement
with the Securities and Exchange Commission on April 29, 2011. The
operating results reported by WPX will differ from those
of Exploration & Production due to differences associated with
reporting WPX on a stand-alone basis.
Overview of Three Months Ended March 31, 2011
Highlights of the comparative periods, primarily
related to our production activities, include:
| For the three months ended March 31, | ||||||||||||
| 2011 | 2010 | % Change | ||||||||||
|
Average daily domestic production (MMcfe)
|
1,155 | 1,091 | +6 | % | ||||||||
|
Average daily total production (MMcfe)
|
1,210 | 1,145 | +6 | % | ||||||||
|
Domestic production realized average price ($/Mcfe)(1)
|
$ | 5.34 | $ | 5.77 | -7 | % | ||||||
|
Capital expenditures and acquisitions ($ millions)
|
$ | 272 | $ | 271 | — | |||||||
|
Domestic production revenues ($ millions)
|
$ | 554 | $ | 566 | -2 | % | ||||||
|
Segment revenues ($ millions)
|
$ | 989 | $ | 1,157 | -15 | % | ||||||
|
Segment profit ($ millions)
|
$ | 51 | $ | 153 | -67 | % | ||||||
| (1) | Realized average prices include market prices, net of fuel and shrink and hedge gains and losses. The realized hedge gain per Mcfe was $0.73 and $0.29 for the first three months of 2011 and 2010, respectively. |
During the first quarter, we initiated a formal process to pursue the divestiture of our
holdings in the Arkoma basin. Due to this decision, we have reported our
Arkoma results of operations as discontinued operations. Our daily production is approximately 10 MMcfd, or less than one
percent of our domestic and international production.
Outlook for the remainder of 2011
We believe that our portfolio of reserves provides an opportunity to continue to grow in our
strategic areas, including the Piceance basin, the Marcellus Shale and the Bakken Shale positions. We
are focused on developing a more balanced portfolio that may include a larger portion of oil and
NGLs reserves and production than we have historically maintained.
Currently we expect
2011 capital expenditures between $1.3 billion and $1.6 billion. We expect to maintain three to five
drilling rigs in our newly acquired Williston basin properties with related capital
expenditures expected to be between $200 million and
$300 million. Additionally, we expect
capital expenditures between $200 million and $300 million in our
Appalachian basin. The remaining amount of capital expenditures will
primarily be for development drilling in the Piceance basin.
We also expect annual average daily total production to increase approximately 9 percent
over 2010.
37
Table of Contents
Management’s Discussion and Analysis (Continued)
Risks to achieving our expectations include unfavorable energy commodity price movements which
are impacted by numerous factors, including weather conditions, domestic natural gas, oil and NGL
production levels and demand. A significant decline in natural gas, oil and NGL prices would impact
these expectations for 2011, although the impact would be partially mitigated by our hedging
program, which hedges a significant portion of our expected production. In addition, changes in
laws and regulations may impact our development drilling program.
Commodity Price Risk Strategy
To
manage the commodity price risk and volatility of owning producing
natural gas and oil properties,
we enter into derivative contracts for a portion of our future production. For the remainder of
2011, we have the following contracts for our daily domestic production, shown at weighted average
volumes (natural gas in billions of Btu - BBtu) and basin-level weighted average prices:
| Remainder of 2011 Natural Gas | ||||
|
Weighted
Average Price ($/MMBtu) |
||||
| Volume | Floor-Ceiling for | |||
| (BBtu/d) | Collars | |||
|
Collar agreements — Rockies
|
45 | $5.30 - $7.10 | ||
|
Collar agreements — San Juan
|
90 | $5.27 - $7.06 | ||
|
Collar agreements — Mid-Continent
|
80 | $5.10 - $7.00 | ||
|
Collar agreements — Southern California
|
30 | $5.83 - $7.56 | ||
|
Collar
agreements — Appalachia
|
30 | $6.50 - $8.14 | ||
|
Fixed price at basin swaps
|
375 | $5.19 | ||
| Remainder of 2011 Crude Oil | ||||||||
|
Volume
(Bbls/d) |
Weighted
Average Price ($/Bbl) |
|||||||
|
WTI Crude Oil fixed-price
|
3,917 | $ | 96.01 | |||||
The following is a summary of our agreements and contracts for daily domestic production shown
at weighted average volumes and basin-level weighted average prices for the three months ended
March 31, 2011 and 2010:
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Weighted
Average Price ($/MMBtu) |
Weighted
Average Price ($/MMBtu) |
|||||||
| Volume | Floor-Ceiling for | Volume | Floor-Ceiling for | |||||
| Natural Gas | (BBtu/d) | Collars | (BBtu/d) | Collars | ||||
|
Collars — Rockies
|
45 | $5.30 - $7.10 | 100 | $6.53 - $8.94 | ||||
|
Collars — San Juan
|
90 | $5.27 - $7.06 | 240 | $5.72 - $7.77 | ||||
|
Collars — Mid-Continent
|
80 | $5.10 - $7.00 | 105 | $5.37 - $7.41 | ||||
|
Collars — Southern California
|
30 | $5.83 - $7.56 | 45 | $4.80 - $6.43 | ||||
|
Collars
— Appalachia and other
|
30 | $6.50 - $8.14 | 20 | $5.54 - $6.81 | ||||
|
NYMEX and basis fixed-price
|
344 | $5.24 | 120 | $4.42 | ||||
|
|
||||||||
|
Crude Oil
|
Volume
(Bbls/d) |
Weighted
Average Price ($/Bbl) |
Volume
(Bbls/d) |
Weighted
Average Price ($/Bbl) |
||||
|
|
||||||||
|
WTI Crude Oil fixed -price
|
1,475 | $94.84 | — | — | ||||
38
Table of Contents
Management’s Discussion and Analysis (Continued)
Additionally, we utilize contracted pipeline capacity to move our production from the Rockies
to other locations when pricing differentials are favorable to Rockies pricing. We hold a long-term
obligation to deliver on a firm basis 200,000 MMbtu per day of gas at
monthly pricing to a buyer at the White River
Hub (Greasewood-Meeker, CO), which is the major market hub exiting the Piceance basin. Our
interests in the Piceance basin hold sufficient reserves to meet this
obligation which expires in 2014.
Period-Over-Period Operating Results
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Segment revenues:
|
||||||||
|
Domestic production revenues
|
$ | 554 | $ | 566 | ||||
|
Gas management revenues
|
405 | 556 | ||||||
|
Hedge
ineffectiveness and mark-to-market gains and losses
|
3 | 9 | ||||||
|
Other revenues
|
27 | 26 | ||||||
|
|
||||||||
|
Total segment revenues
|
$ | 989 | $ | 1,157 | ||||
|
|
||||||||
|
Segment profit
|
$ | 51 | $ | 153 | ||||
|
|
||||||||
Three months ended March 31, 2011 vs. Three months ended March 31, 2010
The
decrease in total
segment revenues
is primarily due to the following:
| • | The $12 million decrease in domestic production revenues reflects a decrease of $45 million associated with a 7 percent decrease in realized average prices including the effect of hedges, partially offset by an increase of $33 million associated with a 6 percent increase in production volumes sold. Excluding the impact of hedges, production revenues would have decreased $59 million from 2010. Production revenues in 2011 and 2010 include approximately $65 million and $46 million, respectively, related to natural gas liquids and approximately $34 million and $11 million, respectively, related to oil and condensate. The increase in NGL revenues is primarily due to higher volumes in our Piceance basin primarily processed by Williams Partners’ Willow Creek facility. The increase in crude and condensate is primarily related to our Bakken production which was acquired in the fourth quarter of 2010; | ||
| • | The $151 million decrease in gas management revenues is primarily due to a decrease in physical natural gas revenue as a result of a 20 percent decrease in average prices on physical natural gas sales and a 9 percent decrease in natural gas sales volumes. This is primarily related to gas sales associated with our transportation and storage contracts and is significantly offset by a similar decrease in segment costs and expenses ; |
Total
segment costs and expenses
decreased $65 million, primarily due to the following:
| • | $141 million decrease in gas management expenses, primarily due to an 18 percent decrease in average prices on physical natural gas purchases and a 9 percent decrease in natural gas purchase volumes. This decrease is primarily related to the gas purchases associated with our previously discussed transportation and storage contracts and is partially offset by a similar decrease in segment revenues . Gas management expenses in 2011 and 2010 include $10 million and $13 million, respectively, related to charges for unutilized pipeline capacity; |
| Partially offsetting the decreased costs are increases, primarily due to the following: |
| • | $23 million higher gathering, processing, and transportation expenses partially as a result of higher rates charged on gathering and processing associated with certain gathering and processing assets in the Piceance basin that were transferred to WPZ in the fourth quarter of 2010 and higher volumes processed at Williams Partners’ Willow Creek plant. Transportation costs are also higher as a result of the increase in production volumes; |
39
Table of Contents
Management’s Discussion and Analysis (Continued)
| • | $17 million higher exploration expense primarily due to higher amortization and write-off of base acquisition costs. The increase reflects amortization of leasehold acquisition costs associated with the 2010 acquisitions of leaseholds and $7 million related to leases in the Barnett Shale that are likely to expire in 2011 without further development; | ||
| • | $14 million higher lease and other operating expenses primarily due to increased workover, water management and maintenance activity; | ||
| • | $14 million higher selling, general and administrative expense (SG&A) due primarily to higher bad debt expense, higher wages, salary and benefits costs as a result of an increase in the number of employees; | ||
| • | $9 million higher depreciation, depletion and amortization expenses primarily due to higher production volumes. |
The $102 million decrease in s
egment profit
is primarily due to the previously discussed
increases in
segment costs and expenses.
Midstream Canada & Olefins
Our Midstream Canada & Olefins segment includes our oil sands off-gas processing plant near
Fort McMurray, Alberta, our NGL/olefin fractionation facility and butylene/butane splitter (B/B
splitter) facility at Redwater, Alberta, our NGL light-feed olefins cracker in Geismar, Louisiana
along with associated ethane and propane pipelines, and our refinery grade splitter in Louisiana.
The products we produce are: NGLs, ethylene, propylene, and other olefin by-products.
Our NGL products include: propane, normal butane, isobutane/butylene (butylene), and condensate.
Prior to the operation of the B/B splitter, we also produced and sold butylene/butane mix product
(B/B mix) which is now separated and sold as butylene and normal butane.
Overview of Three Months Ended March 31, 2011
Segment profit
for the three months ended March 31, 2011 improved compared to the prior year
primarily due to higher production margins on Geismar ethylene, Canadian propane and propylene and
products produced from Canadian B/B mix product.
Significant events for 2011
We signed a long-term agreement to initially produce 10,000 barrels per day (bbls/d) of
ethane/ethylene mix for a third-party customer. We expect that we will ultimately increase our
production of ethane/ethylene mix to 17,000 bbls/d and we expect to complete our expansions
necessary to produce the initial barrels in the first quarter of 2013.
Outlook for the Remainder of 2011
The following factors could impact our business in 2011.
Commodity price changes
We believe average per-unit margins for 2011 will be at or above our 2010 levels. Margins are
highly dependent upon continued demand within the global economy. NGL products are currently the
preferred feedstock for ethylene and propylene production which has been shifting away from the
more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas
supplies, we expect to benefit from these dynamics in the broader global petrochemical markets
because of our NGL-based olefins production.
Allocation of capital to projects
We expect to spend $350 million to $450 million in 2011 on capital projects, of which $288
million to $388 million remains to be spent. The major expansion projects include:
| • | The Ethane Recovery project which is an expansion in our Canadian facilities that will allow us to produce ethane/ethylene mix from our operations that process off-gas from the Alberta oil sands. We will modify |
40
Table of Contents
Management’s Discussion and Analysis (Continued)
| our oil sands off-gas extraction plant near Fort McMurray, Alberta, and construct a de-ethanizer at our Redwater fractionation facility. Our de-ethanizer will enable us to initially produce approximately 10,000 bbls/d of ethane/ethylene mix. We have signed a long-term contract to provide the ethane/ethylene mix to a third-party customer. We have begun pre-construction activities and expect to complete the expansions and begin producing ethane/ethylene mix in the first quarter of 2013. | |||
| • | The Boreal Pipeline project which is a 12-inch diameter pipeline in Canada that will transport recovered NGLs and olefins from our extraction plant in Fort McMurray to our Redwater fractionation facility. The pipeline will have sufficient capacity to transport additional recovered liquids in excess of those from our current agreements. Construction has begun and we anticipate an in-service date in 2012. |
Period-Over-Period Operating Results
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Segment revenues
|
$ | 316 | $ | 272 | ||||
|
|
||||||||
|
Segment profit
|
$ | 74 | $ | 20 | ||||
|
|
||||||||
Three months ended March 31, 2011 vs. three months ended March 31, 2010
Segment revenues
increased primarily due to:
| • | $14 million higher Canadian NGL revenues produced from the B/B mix product. Through mid-2010, we sold B/B mix product, but in August 2010, the new B/B splitter began producing and selling both butylene and butane. The separated butylene and butane products receive higher values in the marketplace than the B/B mix sold previously. The 2010 B/B mix volumes were significantly reduced by operational issues at a third-party facility that provides feedstock to our Canadian facility. | ||
| • | $14 million higher propane production revenues primarily due to higher Canadian propane production revenues resulting primarily from 73 percent higher volumes on 6 percent higher per-unit prices. The higher Canadian volumes were primarily due to the absence of the 2010 third-party operational issues noted above slightly offset by decreases in 2011 volumes from operational issues at our Fort McMurray facility. | ||
| • | $6 million higher propylene production revenues primarily due to $11 million increased Canadian propylene production revenues resulting from 75 percent higher volumes and 11 percent higher average per-unit sales prices. The increase in volumes is primarily due to the issues noted above. | ||
| • | $7 million higher ethylene production sales revenues primarily due to 4 percent higher volumes and 3 percent higher average per-unit sales prices. |
Segment costs and expenses
decreased $10 million primarily as a result of $9 million lower
ethylene feedstock costs from lower average per-unit feedstock costs and the absence of a $5
million 2010 unfavorable inventory adjustment, partially offset by 4 percent higher ethylene sales
volumes.
Segment profit
increased primarily due to:
| • | $16 million higher Geismar ethylene production margins primarily due to higher per-unit margins, the absence of a $5 million 2010 inventory adjustment, and 4 percent higher sales volumes. | ||
| • | $12 million higher Canadian NGL margins from the B/B mix production products. | ||
| • | $11 million higher Canadian propane margins due to 73 percent higher volumes and 27 percent higher per-unit margins. | ||
| • | $11 million higher Canadian propylene margins resulting from 75 percent higher volumes and 25 percent higher per-unit margins. |
41
Table of Contents
Management’s Discussion and Analysis (Continued)
Other
Other includes other business activities that are not operating segments, primarily a 25.5
percent interest in Gulfstream, as well as corporate operations.
Period-Over-Period Operating Results
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Segment revenues
|
$ | 6 | $ | 6 | ||||
|
|
||||||||
|
Segment profit
|
$ | 20 | $ | 7 | ||||
|
|
||||||||
The increase in segment profit is primarily due to the receipt of $11 million in the first
quarter of 2011 on the 2010 sale of our interest in Accroven SRL. This receipt reflects the first
quarterly payment, which was originally due from Petróleos de Venezuela S.A. in October 2010.
Payments are recognized as income upon receipt, until such point
future collections are reasonably assured.
42
Table of Contents
Management’s Discussion and Analysis (Continued)
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
For 2011, we expect operating cash flows to be stronger than 2010 levels. Lower-than-expected
energy commodity prices would be somewhat mitigated by certain of our cash flow streams that are
substantially insulated from short-term changes in commodity prices as follows:
| • | Firm demand and capacity reservation transportation revenues under long-term contracts from our gas pipelines; | ||
| • | Hedged natural gas sales at Exploration & Production related to a significant portion of its production; | ||
| • | Fee-based revenues from certain gathering and processing services in our midstream businesses. |
We believe we have, or have access to, the financial resources and liquidity necessary to meet
our requirements for working capital, capital and investment expenditures, and tax and debt
payments while maintaining a sufficient level of liquidity. In addition to the previously discussed
transactions related to our reorganization plan, we note the following assumptions for the year:
| • | We expect to maintain consolidated liquidity (which includes liquidity at WPZ) of at least $1 billion from cash and cash equivalents and unused revolving credit facilities; | ||
| • | We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolving credit facilities, and proceeds from debt issuances and sales of equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.75 billion and $3.45 billion in 2011; | ||
| • | We expect WPZ to fund its $458 million of current year debt maturities with new debt issuances; | ||
| • | We expect capital and investment expenditures to total between $3.275 billion and $3.975 billion in 2011. Of this total, a significant portion of Williams Partners’ expected expenditures of $1.56 billion to $1.885 billion (excluding the announced acquisition of the additional 24.5 percent interest in Gulfstream) are considered nondiscretionary to meet legal, regulatory, and/or contractual requirements or to fund committed growth projects. Exploration & Production’s expected expenditures of $1.3 billion to $1.6 billion are considered primarily discretionary. Midstream Canada & Olefins’ expected expenditures of $350 million to $450 million are considered primarily nondiscretionary. See Results of Operations — Segments, Williams Partners, Exploration & Production and Midstream Canada & Olefins for discussions describing the general nature of these expenditures. |
Potential risks associated with our planned levels of liquidity and the planned capital and
investment expenditures discussed above include:
| • | Sustained reductions in energy commodity prices from the range of current expectations; | ||
| • | Lower than expected distributions, including incentive distribution rights, from WPZ. WPZ’s liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth; | ||
| • | Lower than expected levels of cash flow from operations from Exploration & Production and our other businesses. |
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we
expect to have sufficient liquidity to manage our businesses in 2011. Our internal and external
sources of consolidated liquidity include cash generated from our operations, cash and cash
equivalents on hand, and our credit facilities. Additional sources of liquidity, if needed, include
bank financings, proceeds from the issuance of long-term debt and equity
43
Table of Contents
Management’s Discussion and Analysis (Continued)
securities, and proceeds from asset sales. These sources are available to us at the parent
level and are expected to be available to certain of our subsidiaries, particularly equity and debt
issuances from WPZ. WPZ is self-funding through its cash flows from operations, use
of its credit facility, and its access to capital markets. Cash held by WPZ is available to us
through distributions in accordance with the partnership agreement, which considers our level of
ownership and incentive distribution rights. Our ability to raise funds in the capital markets will
be impacted by our financial condition, interest rates, market conditions, and industry conditions.
| March 31, 2011 | ||||||||||||||
| Expiration | WPZ | WMB | Total | |||||||||||
| Available Liquidity | (Millions) | |||||||||||||
|
Cash and cash equivalents
|
$ | 232 | $ | 691 | (1) | $ | 923 | |||||||
|
Available capacity under our $900 million unsecured
revolving and letter of credit facility (2)
|
May 1, 2012 | 900 | 900 | |||||||||||
|
Capacity available to Williams Partners L.P. under its
$1.75 billion senior unsecured credit facility (2)
|
February 17, 2013 | 1,750 | 1,750 | |||||||||||
|
|
||||||||||||||
|
|
$ | 1,982 | $ | 1,591 | $ | 3,573 | ||||||||
|
|
||||||||||||||
| (1) | Cash and cash equivalents includes $8 million of funds received from third parties as collateral. The obligation for these amounts is reported as accrued liabilities on the Consolidated Balance Sheet. Also included is $531 million of cash and cash equivalents that is held by and expected to be utilized by certain subsidiary and international operations. The remainder of our cash and cash equivalents is primarily held in government-backed instruments. | |
| (2) | At March 31, 2011, we are in compliance with the financial covenants associated with these credit facilities. |
In addition to the credit facilities listed above, we have issued letters of credit totaling
$74 million as of March 31, 2011 under certain bilateral bank agreements.
WPZ filed a shelf registration statement as a well-known, seasoned issuer in October 2009 that
allows it to issue an unlimited amount of registered debt and limited partnership unit securities.
At the parent-company level, we filed a shelf registration statement as a well-known, seasoned
issuer in May 2009 that allows us to issue an unlimited amount of registered debt and equity
securities.
Exploration & Production has an unsecured credit agreement with certain banks that, so long as
certain conditions are met, serves to reduce our use of cash and other credit facilities for margin
requirements related to our hedging activities as well as lower transaction fees. The agreement
extends through December 2015.
44
Table of Contents
Management’s Discussion and Analysis (Continued)
Credit Ratings
Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ.
The current ratings are as follows:
| WMB | WPZ | |||
|
Standard and Poor’s (1)
|
||||
|
Corporate Credit Rating
|
BBB- | BBB- | ||
|
Senior Unsecured Debt Rating
|
BB+ | BBB- | ||
|
Outlook
|
Positive | Positive | ||
|
Moody’s Investors Service (2)
|
||||
|
Senior Unsecured Debt Rating
|
Baa3 | Baa3 | ||
|
Outlook
|
Stable |
Under review for
possible upgrade |
||
|
Fitch Ratings (3)
|
||||
|
Senior Unsecured Debt Rating
|
BBB- | BBB- | ||
|
Outlook
|
Stable | Stable |
| (1) | A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category. | |
| (2) | A rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1,” “2,” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates the lower end of the category. | |
| (3) | A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category. |
Credit rating agencies perform independent analyses when assigning credit ratings. No
assurance can be given that the credit rating agencies will continue to assign us investment grade
ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade
of our credit rating might increase our future cost of borrowing and would require us to post
additional collateral with third parties, negatively impacting our available liquidity. As of March
31, 2011, we estimate that a downgrade to a rating below investment grade for WMB or WPZ would
require us to post up to $506 million or $67 million, respectively, in additional collateral with
third parties.
Sources (Uses) of Cash
| Three months ended March 31, | ||||||||
| 2011 | 2010 | |||||||
| (Millions) | ||||||||
|
Net cash provided (used) by:
|
||||||||
|
Operating activities
|
$ | 811 | $ | 617 | ||||
|
Financing activities
|
(104 | ) | (405 | ) | ||||
|
Investing activities
|
(579 | ) | (435 | ) | ||||
|
|
||||||||
|
Increase (decrease) in cash and cash equivalents
|
$ | 128 | $ | (223 | ) | |||
|
|
||||||||
45
Table of Contents
Management’s Discussion and Analysis (Continued)
Operating activities
Our
net cash provided by operating activities
for the three months ended March 31, 2011
increased $194 million from the same period in 2010 primarily due to net favorable changes in
working capital.
Financing activities
Significant transactions include:
| • | $3.491 billion received by WPZ in February 2010 from the issuance of $3.5 billion of senior unsecured notes related to our restructuring; | ||
| • | $3 billion of senior unsecured notes retired in February 2010 and $574 million paid in associated premiums utilizing proceeds from the $3.5 billion debt issuance; | ||
| • | $250 million received from revolver borrowings on WPZ’s $1.75 billion unsecured credit facility in February 2010 to repay a term loan. |
Investing activities
Significant transactions include:
| • | Capital expenditures totaled $526 million and $428 million for 2011 and 2010, respectively. |
Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Notes 10 and 11 of
Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible
fulfillment of them will prevent us from meeting our liquidity needs.
46
Table of Contents
Item 3
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not
materially changed during the first three months of 2011.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of natural gas, NGL and
crude, as well as other market factors, such as market volatility and energy commodity price
correlations. We are exposed to these risks in connection with our owned energy-related assets, our
long-term energy-related contracts and our proprietary trading activities. We manage the risks
associated with these market fluctuations using various derivatives and nonderivative
energy-related contracts. The fair value of derivative contracts is subject to many factors,
including changes in energy commodity market prices, the liquidity and volatility of the markets in
which the contracts are transacted, and changes in interest rates. (See Note 10 of Notes to
Consolidated Financial Statements.)
We measure the risk in our portfolios using a value-at-risk methodology to estimate the
potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk
requires a number of key assumptions and is not necessarily representative of actual losses in fair
value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method
to simulate hypothetical movements in future market prices and assumes that, as a result of changes
in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the
portfolios will not exceed the value at risk. The simulation method uses historical correlations
and market forward prices and volatilities. In applying the value-at-risk methodology, we do not
consider that the simulated hypothetical movements affect the positions or would cause any
potential liquidity issues, nor do we consider that changing the portfolios in response to market
conditions could affect market prices and could take longer than a one-day holding period to
execute. While a one-day holding period has historically been the industry standard, a longer
holding period could more accurately represent the true market risk given market liquidity and our
own credit and liquidity constraints.
We segregate our derivative contracts into trading and nontrading contracts, as defined in the
following paragraphs. We calculate value at risk separately for these two categories. Contracts
designated as normal purchases or sales and nonderivative energy contracts have been excluded from
our estimation of value at risk.
Trading
Our trading portfolio consists of derivative contracts entered into for purposes other than
economically hedging our commodity price-risk exposure. The fair value of our trading derivatives
was a net asset of $5 million at March 31, 2011. The value at risk for contracts held for trading
purposes was less than $1 million at March 31, 2011 and December 31, 2010.
Nontrading
Our nontrading portfolio consists of derivative contracts that hedge or could potentially
hedge the price risk exposure from the following activities:
| Segment | Commodity Price Risk Exposure | |
|
Williams Partners
|
• Natural gas purchases | |
|
|
• NGL sales | |
|
|
||
|
Exploration & Production
|
• Natural gas purchases and sales | |
|
|
• Crude oil sales | |
|
|
||
|
Midstream Canada & Olefins
|
• NGL purchases |
47
Table of Contents
The fair value of our nontrading derivatives was a net asset of $164 million at March 31, 2011.
The value at risk for derivative contracts held for nontrading purposes was $30 million at
March 31, 2011, and $24 million at December 31, 2010.
Certain of the derivative contracts held for nontrading purposes are accounted for as cash
flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges had a net asset
value of $168 million as of March 31, 2011. Though these contracts are included in our
value-at-risk calculation, any changes in the fair value of the effective portion of these hedge
contracts would generally not be reflected in earnings until the associated hedged item affects
earnings.
48
Table of Contents
Item 4
Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not
expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of
the Securities Exchange Act) (Disclosure Controls) or our internal controls over financial
reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter
how well conceived and operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control system must reflect the
fact that there are resource constraints, and the benefits of controls must be considered relative
to their costs. Because of the inherent limitations in all control systems, no evaluation of
controls can provide absolute assurance that all control issues and instances of fraud, if any,
within the company have been detected. These inherent limitations include the realities that
judgments in decision-making can be faulty and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the individual acts of some persons, by
collusion of two or more people, or by management override of the control. The design of any system
of controls is also based in part upon certain assumptions about the likelihood of future events,
and there can be no assurance that any design will succeed in achieving its stated goals under all
potential future conditions. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected. We monitor our
Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this
regard is that the Disclosure Controls and Internal Controls will be modified as systems change and
conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was
performed as of the end of the period covered by this report. This evaluation was performed under
the supervision and with the participation of our management, including our Chief Executive Officer
and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance
level.
First-Quarter 2011 Changes in Internal Controls
In the first quarter, we completed the implementation of a new risk management and evaluation
system. Internal controls related to tracking and recording physical and financial derivative
transactions, designating and evaluating hedges, determining fair values of these transactions, and
reporting, including the related disclosures, were affected by this implementation.
Other than described above, there have been no changes during the first quarter of 2011 that
have materially affected, or are reasonably likely to materially affect, our Internal Controls.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The information called for by this item is provided in Note 11 of Notes to Consolidated
Financial Statements included under Part I, Item 1. Financial Statements of this report, which
information is incorporated by reference into this item.
49
Table of Contents
Item 1A. Risk Factors
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December
31, 2010, includes certain risk factors that could materially affect our business, financial
condition or future results. Those Risk Factors have not materially changed, except as set forth
below:
If our plan to separate our exploration and production business is delayed or not completed, our
stock price may decline and our growth potential may not be enhanced.
On April 29, 2011, our wholly owned subsidiary, WPX Energy, Inc. (WPX), filed a registration
statement with the SEC with respect to an initial public offering of its equity securities. This
is the first step in our previously announced reorganization plan to divide our businesses into two
separate, publicly traded corporations. The reorganization plan calls for a separation of our
exploration and production business through an initial public offering of up to 20 percent of WPX
in 2011 and a tax-free spin-off of our remaining interest in WPX to our shareholders in 2012. The
completion and timing of these transactions is dependent on a number of factors including, but not
limited to, the macroeconomic environment, credit markets, equity markets, energy prices, the
receipt of a tax opinion from counsel and/or Internal Revenue Service rulings, final approvals from
our Board of Directors and other customary matters. We may not complete the transactions at all or
complete the transactions on the timeline or on the terms that we announced. If the transactions
are not completed or delayed, our stock price may decline and our growth potential may not be
enhanced.
Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the
FERC or competition in our markets may not allow us to recover such costs in the rates we charge
for our services.
We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by
regulatory authorities to test or undertake modifications to our systems that could result in a
material adverse impact on our business, financial condition and results of operations if the costs
of testing, maintaining or repairing our facilities exceed current expectations and the FERC or
competition in our markets do not allow us to recover such costs in the rates we charge for our
service. For example, in response to a recent third-party pipeline rupture, the U.S. Department of
Transportation Pipeline and Hazardous Materials Safety Administration issued an Advisory Bulletin
which, among other things, advises pipeline operators that if they are relying on design,
construction, inspection, testing, or other data to determine the pressures at which their
pipelines should operate, the records of that data must be traceable, verifiable and complete.
Locating such records and, in the absence of any such records, verifying maximum pressures through
physical testing or modifying or replacing facilities to meet the demands of such pressures, could
significantly increase our costs.
50
Table of Contents
Item 6. Exhibits
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Exhibit 3.1
|
— | Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to the Company’s Current Report on Form 8-K) and incorporated herein by reference. | ||
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Exhibit 3.2
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— | Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to the Company’s Current Report on Form 8-K) and incorporated herein by reference. | ||
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Exhibit 12
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— | Computation of Ratio of Earnings to Fixed Charges.(1) | ||
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Exhibit 31.1
|
— | Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) | ||
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|
Exhibit 31.2
|
— | Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) | ||
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|
Exhibit 32
|
— | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(2) | ||
|
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Exhibit 101.INS
|
— | XBRL Instance Document.(2) | ||
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|
Exhibit 101.SCH
|
— | XBRL Taxonomy Extension Schema.(2) | ||
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|
Exhibit 101.CAL
|
— | XBRL Taxonomy Extension Calculation Linkbase.(2) | ||
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Exhibit 101.DEF
|
— | XBRL Taxonomy Extension Definition Linkbase.(2) | ||
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Exhibit 101.LAB
|
— | XBRL Taxonomy Extension Label Linkbase.(2) | ||
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|
Exhibit 101.PRE
|
— | XBRL Taxonomy Extension Presentation Linkbase.(2) |
| (1) | Filed herewith. | |
| (2) | Furnished herewith. |
51
Table of Contents
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
THE WILLIAMS COMPANIES, INC.
(Registrant) |
||||
| /s/ Ted T. Timmermans | ||||
| Ted T. Timmermans | ||||
| Controller (Duly Authorized Officer and Principal Accounting Officer) | ||||
May 5, 2011
Table of Contents
EXHIBIT INDEX
|
Exhibit 3.1
|
— | Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to the Company’s Current Report on Form 8-K) and incorporated herein by reference. | ||
|
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|
Exhibit 3.2
|
— | Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to the Company’s Current Report on Form 8-K) and incorporated herein by reference. | ||
|
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|
Exhibit 12
|
— | Computation of Ratio of Earnings to Fixed Charges.(1) | ||
|
|
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|
Exhibit 31.1
|
— | Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) | ||
|
|
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|
Exhibit 31.2
|
— | Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1) | ||
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|
Exhibit 32
|
— | Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(2) | ||
|
|
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|
Exhibit 101.INS
|
— | XBRL Instance Document.(2) | ||
|
|
||||
|
Exhibit 101.SCH
|
— | XBRL Taxonomy Extension Schema.(2) | ||
|
|
||||
|
Exhibit 101.CAL
|
— | XBRL Taxonomy Extension Calculation Linkbase.(2) | ||
|
|
||||
|
Exhibit 101.DEF
|
— | XBRL Taxonomy Extension Definition Linkbase.(2) | ||
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|
Exhibit 101.LAB
|
— | XBRL Taxonomy Extension Label Linkbase.(2) | ||
|
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|
Exhibit 101.PRE
|
— | XBRL Taxonomy Extension Presentation Linkbase.(2) |
| (1) | Filed herewith. | |
| (2) | Furnished herewith. |
TABLE OF CONTENTS
Note 1. GeneralprintNote 2. Basis Of PresentationprintNote 3. Discontinued OperationsprintNote 4. Asset Sales and Other AccrualsprintNote 5. Provision (benefit) For Income TaxesprintNote 6. Earnings (loss) Per Common Share From Continuing OperationsprintNote 7. Employee Benefit PlansprintNote 8. InventoriesprintNote 9. Fair Value MeasurementsprintNote 10. Financial Instruments, Derivatives, Guarantees, and Concentration Of Credit RiskprintNote 11. Contingent LiabilitiesprintNote 12. Segment DisclosuresprintPart II. Other InformationprintItem 1. Legal ProceedingsprintItem 1A. Risk FactorsprintItem 6. Exhibitsprint