UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 FORM 10-Q (Mark One)



QUARTERLY REPORT PURSUANT TO SECTION13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended
September30March31, 20134 r


TRANSITION REPORT PURSUANT TO SECTION13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____________ to ____________ _ Commission file number 1-4174



THEWILLIAMSCOMPANIES,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
74172-0172

(Address of principal executive offices)
(Zip Code) Registrants 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 Section13 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 No 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). Yes 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
Acceleratedfiler
Non-acceleratedfiler
Smallerreportingcompany

(Donotcheckifasmallerreportingcompany)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes No Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date.



Class
Shares Outstanding at OctoberApril 28, 20134

Common Stock, $1 par value
68
3,428,418 Shares5,518,456



The Williams Companies, Inc. Index



Page

Part I. Financial Information

Item1. Financial Statements

Consolidated Statement of Income Three
and Nine Months Ended September30, 2013 and 2012
4

Consolidated Statement of Comprehensive Income Three and Nine Months Ended September30
March31, 20134 and 2012
5

Consolidated Balance Sheet September30, 2013 and December31, 2012
3
6

Consolidated Statement of C
hanges in Equity Nine Months Ended September30,omprehensive Income Three Months Ended March31, 2014 and 03 7

Consolidated
Statement of Cash Flows Nine Months Ended SeptBalance Sheet March31, 2014 and December301, 2013 and 2012
8

Consolidated Statement of Changes in Equity Three Months Ended March31, 2014
9

Consolidated Statement of Cash Flows Three Months Ended March31, 2014 and 2013
10

Notes to Consolidated Financial Statements
911

Item2. Managements Discussion and Analysis of Financial Condition and Results of Operations
28

Item3. Quantitative and Qualitative Disclosures About Market Risk
5547

Item4. Controls and Procedures
5648

Part II. Other Information
5648

Item1. Legal Proceedings
56

Item1A. Risk Factors
57
48

Item6. Exhibits
580 eti atr otie nti eoticuefradloigsaeet ihntemaigo eto2Ao h euiisAto 93 saedd n eto2Eo h euiisEcag c f13,a mne.Teefradloigsaeet eaet niiae iaca efrac,mngmnspasadojcie o uueoeain,bsns rset,otoeo euaoypoedns aktcniin,adohrmtes emk hs owr-okn ttmnsi eineo h aehro rtcin rvddudrtePiaeScrte iiainRfr c f19.Alsaeet,ohrta ttmnso itrclfcs nlddi hsrpr htadesatvte,eet rdvlpet htw xet eiv ratcpt ileito a cu nteftr,aefradloigsaeet.Fradloigsaeet a eietfe yvrosfrso od uha niiae,blee,ses ol,my hud otne,etmts xet,frcss ned,mgt ol,ojcie,tres lne,ptnil rjcs ceue,wl,asms udne ulo,i evc aeo te iia xrsin.Teefradloigsaeet r ae nmngmnsblesadasmtosado nomto urnl vial omngmn n nld,aogohr,saeet eadn:

Amounts and nature of future capital expenditures;


Expansion and growth of our business and operations;


Financial condition and liquidity;


Business strategy;


Cash flow from operations or results of operations;


The levels of dividends to stockholders;
1


Seasonality of certain business components;
Natural gas, natural gas liquids, and olefins prices, supply and demand;
1


Natural gas, natural gas liquids, and olefins prices, supply and demand; and


Demand for our services. 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:


Whether we have sufficient cash to enable us to pay current and expected levels of dividends;


Availability of supplies, market demand, and volatility of prices;


Inflation, interest rates, fluctuation in foreign exchange rates,adgnrleooi odtos(nldn uuedsutosadvltlt ntegoa rdtmresadteipc fteeeet norcsoesadsples;

The strength and financial resources of our competitors and the effects of competition;


Whether we are able to successfully identify, evaluate and execute investment opportunities;


Ability to acquire new businesses and assets and successfully nert hs prtosadast nooreitn uiess swl sscesul xadorfclte;

Development of alternative energy sources;


The impact of operational and development hazards and unforeseen interruptions;


Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), 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 and counterparties;


Risks related to strategy and fnnig nldn etitossemn rmordb gemns uuecagsi u rdtrtnsadteaalblt n oto aia;

The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;


Risks associated with weather and natural phenomena, including climate conditions;


Acts of terrorism, including cybersecurity threats and related disruptions; and


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.
2
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, Item1A. Risk Factors in our Annual Report on Form 10-K for the year ended December31, 2012, and Part II, Item1A. Risk Factors of this Form 10-Q.
3
3.
3
DEFINITIONS
The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Form 10-Q.
Measurements : Barrel : One barrel of petroleum products that equals 42 U.S. gallons Bcf : One billion cubic feet of natural gas Bcf/d : One billion cubic feet of natural gas per day British Thermal Unit (Btu) : A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit Dekatherms (Dth) : A unit of energy equal to one million British thermal units Mbbls/d : One thousand barrels per day Mdth/d : One thousand dekatherms per day MMcf/d : One million cubic feet per day Consolidated Entities : Constitution: Constitution Pipeline Company, LLC Gulfstar One: Gulfstar One LLC Northwest Pipeline: Northwest Pipeline LLC Transco: Transcontinental Gas Pipe Line Company, LLC WPZ: Williams Partners L.P. Partially Owned Entities : Entities in which we do not own a 100 percent ownership interest and which we account for as an equity investment, including principally the following: Access GP: Access Midstream Partners GP, L.L.C. Access Midstream Partners: Access GP and ACMP ACMP: Access Midstream Partners, L.P. Aux Sable: Aux Sable Liquid Products LP Bluegrass Pipeline: Bluegrass Pipeline Company LLC Caiman II: Caiman Energy II, LLC Discovery: Discovery Producer Services LLC Gulfstream: Gulfstream Natural Gas System, L.L.C. Laurel Mountain: Laurel Mountain Midstream, LLC Moss Lake: Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC OPPL: Overland Pass Pipeline Company LLC Government and Regulatory: EPA: Environmental Protection Agency FERC: Federal Energy Regulatory Commission
4
Other : B/B Splitter: Butylene/Butane splitter RGP Splitter: Refinery grade propylene splitter IDR: Incentive distribution right NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications NGL margins : NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation
5

PART I FINANCIAL INFORMATION
The Williams Companies, Inc. Consolidated Statement of Income (Unaudited)



Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions, except per-share amounts)

Revenues:

Service revenues
$
736819
$
675
$
2,163
$
2,019
706

Product sales
887930
1,
077
3,037
3,598
104

Total revenues
1,
623749
1,
752
5,200
5,617
810

Costs and expenses:

Product costs
7
1069
7
71
2,301
2,628
90

Operating and maintenance expenses
2
698
26
1
820
766
0

Depreciation and amortization expenses
2
07
196
606
545
14
201


Selling, general, and administrative expenses
1
350
13
7
385
415
2

Net insurance recoveries Geismar Incident
(119
)


Other (income) expensenet
(29
)
14
(24
)
3
17
1
Total costs and expenses
1,
287329
1,3
79
4,088
4,385
84

Operating income (loss)
336
373
1,112
1,232
420
426


Equity earnings (losses)
37
30
93
8
(48
)
1
8
Interest incurred
(15169
)
(14052
)
(454
)
(421
)

Interest capitalized
279
11
75
33
24

Other investing income net
1
04
13
62
75


Other income (expense)net
1
1
(1
(2
)

Income (loss) from continuing operations before income taxes
26047
3277
889
1,006


Provision (benefit) for income taxes
62
77
260
281
51
96


Income (loss) from continuing operations
19
8
200
629
725
6
231


Income (loss) from discontinued operations
(1
)
3
(10
)
138

Net income (loss)
19
76
2
03
619
86
30

Less: Net income attributable to noncontrolling interests
56
48
175
153
69

Net income (loss) attributable to The Williams Companies, Inc.
$
1410
$
1
55
$
444
$
710
61

Amounts attributable to The Williams Companies, Inc.:

Income (loss) from continuing operations
$
1430
$
152
$
454
$
57
62
Income (loss) from discontinued operations
(21
)
3
(10
)
138

Net income (loss)
$
1410
$
1
55
$
444
$
710
61

Basic earnings (loss) per common share:

Icm ls)fo otnigoeain
$
.210
$
.25
$
.66
$
.9
4
Income (loss) from discontinued operations
(.01
)
.22

Net income (loss)
$
.210
$
.25
$
.65
$
1.16
4

Weighted-average shares (thousands)
68
3,274
626,809
682,744
613,888
4,773
682,052


Diluted earnings (loss) per common share:

Income (loss) from continuing operations
$
.20
$
.25
$
.66
$
.9
3
Income (loss) from discontinued operations
(.01
)
.22

Nticm ls) $
.20
$
.25
$
.65
$
1.15
3

Weighted-average shares (thousands)
68
7,306
632,019
687,007
619,765
8,904
687,143


Cash dividends declared per common share
$
.366402
$
.3
125
$
1.0575
$
.8712
3875 See accompanying notes .
46
The Williams Companies, Inc. Consolidated Statement of Comprehensive Income (Unaudited)



Three months ended
September 30,
Nine months ended
September 30,
March 31,

2014
2013


(Millions)
2013
2012
2013
2012

Net income (loss)
$
1976
$
2
03
$
619
$
86
30

Other comprehensive income (loss):

Cash flow hedging activities:

Net unrealized gain (loss) from derivative instru
Foreign currency translation adjustments, net of taxes of $3 and ($9)1 in 20124
1
(9
(44
)
1
25

Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $3 and $5 in 2012
(1
)
(1
(21 )
(1
)
(15
)

Foreign currency translation adjustments
20
30
(31
)
32

Pension and other postretirement benefits:

Prior service credit arising during the year, net of taxes of ($8) and ($8) in 2013 (Note 7)
15
15

Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 and $1 in 20134
(1
)
(1
)

Net actuarial gain (loss) arising during the year, net of taxes of ($7) and ($7) in 2013 and $1 and $2 in 2012 (Note 7)
12
(1
)
12
(4
)

Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($73) and ($186) in 20134 and ($6) and ($17) in 2012
9
2013, respectively
6

10
29
29

Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012
(3
Other comprehensive income (loss)
(39
)
(12

)

Other comprehensive income (loss)
56
19
24
63

Comprehensive income (loss)
253
222
643
926
157
218


Less: Comprehensive income (loss) attributable to noncontrolling interests
56
40
175
157
69

Comprehensive income (loss) attributable to The Williams Companies, Inc.
$
19701
$
1
82
$
468
$
76
49 See accompanying notes.
57
The Williams Companies, Inc. Consolidated Balance Sheet (Unaudited)



March31,
2014
December31,
2013

(Millions, except per-share amounts)
September30,
2013
December31,
2012

ASSETS

Current assets:

Cash and cash equivalents
$
7321,064
$
839681

Accounts and notes receivable, net:

Trade and other
629
600


Accounts and notesIncome tax receivable
590
688
29
74


Deferred income tax asset
1
17
11
41
2
7
Inventories
23022
1
7594

Regulatory assets
32
39

Other current assets and deferred charges
81
66
93
107


Total current assets
2,1,782
1,
924683

Investments
4,
278
3,987
520
4,360


Property, plant and equipment, at cost
2
4,934
22,546
6,484
25,823


Accumulated depreciation and amortization
(7,
467773
)
(7,079613
)

Property, plant and equipment net
1
7,467
15,467
8,711
18,210


Goodwill
646
6496

Other intangible
assets
1,6
5932
1,
70644
Regulatory assets, deferred charges, and other
623619
59
69

Total assets
$
2
6,4558,306
$
2
4,3277,142

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable
$
1,0194 $
9260
Accrued liabilities
7004
628797

Commercial paper
371225

Long-term debt due within one year
751
1
1

Total current liabilities
2,
086549
1,
549983

Long-term debt
1
0,359
10,7
2,099
11,
353

Deferred income taxes
3,
414
2,841
528
3,529


Other noncurrent liabilities
1,
650413
1,
775356

Contingent liabilities (Note 121)
Equity:

Stockholders equity:

Common stock (960 million shares authorized at $1 par value; 7
1820 million shares issued at SeptemberMarch 301, 20134 and 7168 million shares issued at December 31, 2012)3)
720

718
716

Capital in excess of par value
11,5
8245
11,
134599

Retained deficit
(
5,9736,385
)
(
5,6956,248
)

Accumulated other comprehensive income (loss)
(
338223
)
(
362164
)

Treasury stock, at cost (35 million shares of common stock)
(1,041
)
(1,041
)

Total stockholders equity
4,948616
4,
752864

Noncontrolling interests in consolidated subsidiaries
3,998
2,675
4,101
4,057


Total equity
8,
946
7,427
717
8,921


Total liabilities and equity
$
2
6,4558,306
$
2
4,3277,142
See accompanying notes.
68
The Williams Companies, Inc. Consolidated Statement of Changes in Equity (Unaudited)



The Williams Companies, Inc., Stockholders

Common Stock
Capitalin Excess of ParValue
Retained Deficit
Accumulated Other Comprehensive Income (Loss)
Treasury Stock
Total Stockholders Equity
Noncontrolling Interest
Total Equity

(Millions)

Balance December31, 20123
$
7168
$
11,134599
$
(
5,6956,248
)
$
(
362164
)
$
(1,041
)
$
4,752864
$
2,6754,057
$
7,4278,921

Net income (loss)
444
444
175
140
140
56

6196

Other comprehensive income (loss)
24
24
24
(39
)
(39
)
(39
)


Cash dividends common stock
(
722276
)
(
722276
)
(
722276
)

Dividends and distributions to noncontrolling interests
(
344147
)
(
344147
)

Issuance of common stock from debentures conversion
1
1
1

Stock-based compensation and related common stock issuances, net of tax
2
21
38
40
40
23
23


Sales of limited partner units of Williams Partners L.P.
1,819
1,819

Changes in ownership of consolidated subsidiaries, net
409
409
(652
(72
)
(20

)
(
9243
)
135
43

Contributions from noncontrolling interests
327
327
63
63

Deconsolidation of Bluegrass Pipeline (Note 2)
(63
)
(63
)


Other
(23
)
(1
)
(4

)
(24
)

Balance
September30March31, 20134
$
71820
$
11,58245
$
(
5,9736,385
)
$
(
338223
)
$
(1,041
)
$
4,948616
$
3,9984,101
$
8,946717
See accompanying notes.
79
The Williams Companies, Inc. Consolidated Statement of Cash Flows (Unaudited)



NinThree months ended
September 30,March 31,

2014
2013


(Millions)
2013
2012

OPERATING ACTIVITIES:

Net income (loss)
$
619
$
863196
$
230


Adjustments to reconcile to net cash provided (used) by operating activities:

Depreciation and amortization
606
545
214
201


Provision (benefit) for deferred income taxes
301
117

Net (gain) loss on dispositions of assets
1
(5
(96 )
103

Gain on reconsolidation of Wilpro entities (Note 3)
(144
)

Amortization of stock-based awards
28
27
11
9


Cash provided (used) by changes in current assets and liabilities:

Accounts and notes receivable
85
82
16
(72
)


Inventories
(527
)
(1
3 )
19

Other current assets and deferred charges
22
11
28

Accounts payable
(4716
)
(165
)
6

Accrued liabilities
91
14
67
(25
)


Other, including changes in noncurrent assets and liabilities
60
(41
)
59
45


Net cash provided (used) by operating activities
1,702
1,289
446
495


FINANCING ACTIVITIES:

Proceeds from (payments of) commercial paper net
370(225
)


Proceeds from long-term debt
1,
705
2,109
496
770


Payments of long-term debt
(
2,081895
)
(1,313
)

Proceeds from issuance of common stock
14
9357

Proceeds from sale of limited partner units of consolidated partnership
1,819
1,559
617

Dividends paid
(
722276
)
(
538231
)

Dividends and distributions paid to noncontrolling interests
(
344147
)
(246105
)

Distributions paid to noncontrolling interests on sale of Wilpro assets (Note 3)
(38
)

Contributions from noncontrolling interests
6327
42

Othernet
64
2611

Net cash provided (used) by financing activities
1,094
2,498
929
176


INVESTING ACTIVITIES:

Capital expenditures
*
(2,542
(1)
(793

)
(
1,652
713
)
Purchases of and contributions to equity -method investments
(
350228
)
(28293
)

Purchases of businesses
(2,049
)

Proceeds from dispositions of investments
79

Cash of Wilpro entities upon reconsolidation (Note 3)
121

Othernet
(1129
(2

)
103

Net cash provided (used) by investing activities
(
2,903992
)
(3,6808
)


Increase (decrease) in cash and cash equivalents
383
(1037 )
107

Cash and cash equivalents at beginning of period
681
839
889

Cash and cash equivalents at end of period
$
7321,064
$
996702

_________

* (1)Icesst rpry ln,adeupet $
(
2,685840
)
$
(
1,784732
)

Changes in related accounts payable and accrued liabilities
14347
1
329

Capital expenditures
$
(2,542793
)
$
(
1,652713
)
See accompanying notes.
810
The Williams Companies, Inc. Notes to Consolidated Financial Statements (Unaudited)

Note 1 General, Description of Business, and Basis of Presentation 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 for the year ended December31, 20123, in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements. 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. Unless the context clearly indicates otherwise, references in this report to we, our, us, or similar language refer to The Williams Companies, Inc. and its subsidiaries. Description of Business Our operations are located principally in the United States and are organized into the Williams Partners, Williams NGL& Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other. Williams Partners consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ), and includes gas pipeline and domestic midstream businesses. The gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent consolidated interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity). WPZs midstream operations are composed of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and natural gas liquid (NGL) fractionation and transportation assets. WPZs midstream assets also include an NGL fractionator and storage facilities near Conway, Kansas as well as an NGL light-feed olefins cracker in Geismar, Louisiana, along with associated ethane and propane pipelines, and a refinery grade splitter in Louisiana. Williams NGL& Petchem Services consists primarily of a Canadi, an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta, and a 50 percent consolidated interest in Bluegrass Pipeline Company LLC (Bluegrass Pipeline). Williams NGL& Petchem Services consists primarily of a 50 percent equity investment in Bluegrass Pipeline Company LLC (Bluegrass Pipeline) and certain domestic olefins pipeline assets and Canadian facilities under development. Access Midstream Partners consists of our equity investment in Access Midstream Partners, L.P. (ACMP). As of September30March31, 20134 , this investment includes an indirect 50 percent interest in Access Midstream Partners, GP, L.L.C. (Access GP), including incentive distribution rights, and a 23 percent limited partner interest in ACMP. ACMP is a publicly-traded master limited partnership that provides gathering, treating, and compression services to producers under long-term, fee-based contracts. Access GP is the general partner of ACMP. Other includes other business activities that are not operating segments, as well as corporate operations. Basis of Presentation
As disclosed in our 2012 Annual Report on Form 10-K, we contributed our 83.3 percent undivided interest in the olefins-production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region to WPZ in November 2012. As a result, prior period segment disclosures have been recast for this transaction.
9

11

Notes (Continued)
Also as disclosed in our 2012 Annual Report on Form 10-K, we have revised the overall presentation of our Consolidated Statement of Income, Basis of Presentation In February 2014, we contributed certain Canadian operations to WPZ (Canada Dropdown) for total consideration of $25 million of cash from WPZ (subject to certain cludosing the separate padjustments), 25,577,521 WPZ Class D limited-partner units, and an increasentation of service revenues , product sales , product costs , and depreciation and amortization expenses . All prior periods presented have been recast, along with corresponding information presented in the Notes to Consolidated Financial Statements, to reflect this change. Consolidated master limited partnership During the first quarter of 2013, WPZ completed equity issuances of 15,937,500 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement transaction. In the third qu in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All Class D units outstanding will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Dropdown provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. These operations were previously reported within the Williams NGL & Petchem Services segment, but are now reported within Williams Partner of 2013, WPZ completed equity issuances of 24,725,000 common units representings. Prior period segment disclosures have been recast for this transaction. Consolidated master limited partner interests.ship Following these transactions discussed above, as of March 31, 2014, we own approximately 646 percent of the interests in WPZ, including the interests of the general partner, which are wholly owned by us, and incentive distribution rights as of September30, 2013 . The previously described equity issuances by WPZ had the combined net impact of increasing our noncontrolling interests in consolidated subsidiaries by $1.169 billion , capital in excess of par value by $408 million and deferred income taxes by $242 million in the Consolidated Balance Sheet . WPZ is self-funding and maintains separate lines of bank credit and cash management accounts. WPZ and also initiated itshas a commercial paper program in the first quarter of 2013. (See Note 98 Debt and Banking Arrangements .) 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. Discontinued operations The discontinued operations presented in the accompanying consolidated financial statements and notes primarily reflect gains in 2012 associated with certain of our former Venezuela operations. (See Note 3 Discontinued Operations .) Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations. Note 2 Variable Interest Entities Consolidated VIEs We consolidate variable interest entities (VIEs) of which we are the primary beneficiary. The primary beneficiary of a VIE is the entity that has both (1)the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2)the obligation to absorb losses or the right to receive benefits that could be significant to the VIE. As of September30Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations. Note 2 Variable Interest Entities Consolidated VIEs As of March31, 20134 , we consolidate the following VIEs: Gulfstar
During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar) in exchange for a 49 percent ownership interest in Gulfstar. This contribution was based on 49 percent of WPZs estimated cumulative net investment to date. The $187 million was then distributed to WPZ. Following this transaction, WPZ owns a 51 percent interest in Gulfstar
variable interest entities (VIEs): Gulfstar One
WPZ owns a 51 percent interest in Gulfstar One LLC (Gulfstar One)
, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar Ones economic performance. WPZ, as construction agent for Gulfstar, is One, designinged, constructinged, and is installing a proprietary floating-production system, Gulfstar FPS , and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. The project is expected to be in service in mid-the third quarter of 2014. WPZ has received certain advance payments from the producer customers and is committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $40250 million , which we expect will be funded with capital contributions from WPZ and the other equity partner, proportional to ownership interest. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar.by us and our partner. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar One.
In December 2013, WPZ committed an additional amount to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in the first quarter of 2016. The current estimate of the total remaining construction costs of the Gunflint project is less than $134 million . The other equity partner has an option to participate in the funding of the expansion project on a proportional basis. Constitution WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the

1
02
Notes (Continued)
Constitution
During the second quarter of 2013, a third party contributed $4 million to Constitution in exchange for a 10 percent ownership interest in Constitution. This contribution was based on 10 percent of Constitutions contributed capital to date. The $4 million was then distributed to WPZ. Following this transaction, WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the
activities that most significantly impact Constitutions economic performance. WPZ, as construction agent for Constitution, is building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. WPZ plans to place the project in service in March 2015late 2015 to 2016 and estimates the total remaining construction costs of the project to be less than $62500 million , which will be funded with capital contributions from WPZ and the other equity partners, proportional to ownership interest. Bluegrass Pipeline
We own a 50 percent interest in Bluegrass Pipeline, a subsidiary that, due to insufficient equity to finance activities during its development stage, is a VIE. We are the primary beneficiary because we have the power to direct the activities of the project that most significantly impact its economic performance until the first developmental stage milestone is met; we have the power to direct whether the project moves forward. We and our partner plan to construct an NGL pipeline connecting processing facilities in the Marcellus and Utica shale-gas areas in the northeastern United States to growing petrochemical and export markets in the gulf coast area of the United States. Pre-construction activities are under way and the project is planned to be in service in late 2015. This development stage entity is currently operating under a preliminary activities budget that governs the spending levels through February28, 2014. Prior to that time, certain elections by either partner could change the relative ownership of the entity, impact the continued development of the project, and/or revise the determination of the primary beneficiary. The remaining amount that has been projected for spending under the preliminary activities budget is less than $140 million , and will be funded by us and our partner, proportional to ownership interest. Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions. Our Board of Directors has approved our continued investment in this project.
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:.



September30March31,
201
34
December
31,
20123 (1)
Classification

(Millions)

Assets (liabilities):

Cash and cash equivalents
$
5836
$
8122
Cash and cash equivalents

Construction in progress
897
556
Accounts receivable
10
Accounts and notes receivable, net

Property, plant and equipment
1,209
1,111

Property, plant and equipment, at cost

Accounts payable
(1
353
)
(12845
)
Accounts payable

Construction retainage
(24
)
(3

)
Accrued liabilities

DCurrent deferred revenue associated with customer advance payments
(1
1
)
(109Accrued liabilities

Asset retirement obligation
(30

)
Other noncurrent liabilities
11
Notes (Continued)
Nonconsolidated VIEs We have also identified certain interests in VIEs where we are not the primary beneficiary. These include: Laurel Mountain
WPZs 51 percent -owned equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, WPZ is not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $492 million at September30, 2013 . Caiman II
WPZs 47.5 percent -owned equity-method investment in Caiman Energy II, LLC (Caiman II) has been determined to be a VIE because it has insufficient equity to finance activities during the construction stage of the Blue Racer Midstream joint project, which is an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. WPZ is not the primary beneficiary because it does not have the power to direct the activities of Caiman II that most significantly impact its economic performance. Our maximum exposure to loss is limited to the $380 million of total contributions that we have committed to make. At September30, 2013 , the carrying value of our investment in Caiman II was $257 million , which substantially reflects our contributions to date. Moss Lake
Our equity-method investment in Moss Lake Fractionation LLC (Moss Lake) is a VIE because it has insufficient equity to finance activities during its development stage. We currently own 50 percent of this joint project which plans to construct a new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a pipeline connecting these facilities to the Bluegrass Pipeline. We are not the primary beneficiary because we do not have the power to direct the majority of the activities of Moss Lake that most significantly impact its economic performance at this stage. The carrying value of our investment in Moss Lake at September30, 2013 , was $2 million , which represents our contributions to date. The amount we project for spending in order to fund our proportional share of the preliminary activities budget through February 28, 2014, is $52 million . Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions. Note 3 Discontinued Operations Income (loss) from discontinued operations for the three and nine months ended September30, 2013 , includes a $3 million and $15 million , respectively, pre-tax charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. Income (loss) from discontinued operations for the nine months ended September30, 2012 , includes a $144 million gain on reconsolidation related to our majority ownership in entities (the Wilpro entities) that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009. We deconsolidated the Wilpro entities in 2009.In 2012, the El Furrial and PIGAP II assets were sold as part of a settlement related to the 2009 expropriation of these assets.Upon closing, the lenders that had provided financing for these operations were repaid in full, and the Wilpro entities received $98 million in cash and the right to receive quarterly cash installments of $15 million (receivable) plus interest through the first quarter of 2016.Following the settlement and repayment in full of the lenders, we reestablished control and, therefore, reconsolidated the Wilpro entities and recognized the gain on reconsolidation. This gain reflected our share of the cash, including cash received in the settlement, and the estimated fair value of the receivable held by the Wilpro entities at the time of reconsolidation. See Note 11 Fair Value Measurements for a further discussion of this receivable.
12
Notes (Continued)
Note 4 Asset Sales and Other Accruals
On June13, 2013, an explosion and fire occurred at WPZs Geismar olefins plant located south of Baton Rouge, Louisiana, in an industrial complex, that resulted in the tragic deaths of two employees and injuries of additional employees and contractors. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects.
We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:

Noncurrent deferred revenue associated with customer advance payments
(130
)
(115
)
Other noncurrent liabilities

Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption;


General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;(1) Amounts presented for December 31, 2013, include balances related to Bluegrass Pipeline. See discussion of the subsequent deconsolidation of Bluegrass Pipeline below.
Nonconsolidated VIEs We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include: Laurel Mountain
WPZs 51 percent -owned equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, WPZ is not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $482 million at March31, 2014 . Caiman II
In the first quarter of 2014, WPZ contributed $119 million to Caiman Energy II, LLC (Caiman II) in exchange for an increased ownership of Caiman II. Following these contributions, WPZ owns a 58 percent interest in Caiman II, which is reported as an equity-method investment. Caiman II is considered to be a VIE because it has insufficient equity to finance the construction stage activities of its 50 percent interest in Blue Racer Midstream LLC, which is expanding the gathering and processing and associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. WPZ is not the primary beneficiary because it does not have the power to direct the activities of Caiman II that most significantly impact its economic performance. Our maximum exposure to loss is limited to the $500 million of total contributions that we have committed to make inclusive of contributions made to date. At March31, 2014 , the carrying value of our investment in Caiman II was $415 million , which substantially reflects our contributions to that date.
13
Notes (Continued)
Bluegrass Pipeline The Bluegrass Pipeline is a proposed NGL pipeline that would connect processing facilities in the Marcellus and Utica shale-gas areas in the northeastern United States to growing petrochemical and export markets in the Gulf Coast area of the United States. Bluegrass Pipeline is considered to be a VIE because it has insufficient equity to finance activities during its development stage. As of March 31, 2014, we own a 50 percent equity-method investment interest in Bluegrass Pipeline. From its inception until the first quarter of 2014, we were the primary beneficiary of this entity because we had the power to direct whether the project moved forward and thus we previously consolidated the Bluegrass Pipeline. On February 16, 2014, we and our partner executed an amendment to the governing documents that removed our power to direct whether the project moved forward. As a result, we were no longer the primary beneficiary as of that date and we deconsolidated the Bluegrass Pipeline and began reporting our 50 percent interest as an equity-method investment. There was no gain or loss recognized upon deconsolidation.
Completion of this project is subject to execution of customer contracts sufficient to support the project. Although discussions with potential customers continue, we have not received sufficient executed customer commitments to date to support the continued development of the project. Considering this and other factors, our management decided in April to discontinue further funding of the project at this time. Given these developments, the capitalized project development costs at the Bluegrass Pipeline entity were written off as of March 31, 2014, and as a result, we have recognized $67 million in related equity losses in the first quarter of 2014. The carrying value of our investment in Bluegrass Pipeline is $1 million at March31, 2014 .
Moss Lake Our 50 percent -owned equity-method investments in Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake) are considered to be VIEs because they have insufficient equity to finance activities during their development stage. Moss Lake may construct a proposed new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a proposed pipeline connecting these facilities to the Bluegrass Pipeline. Additionally, Moss Lake may construct a proposed new liquefied petroleum gas (LPG) terminal. We are not the primary beneficiary of this entity because we do not have the power to direct the majority of the activities of Moss Lake that most significantly impact its economic performance at this stage. In the first quarter of 2014, we have recognized $4 million in equity losses related to Moss Lake, primarily associated with the underlying write-off of capitalized project development costs at Moss Lake. The carrying value of our investment in Moss Lake is $2 million at March 31, 2014. Note 3 Other Income and Expenses On June13, 2013, an explosion and fire occurred at WPZs Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects. We have substantial insurance coverage for repair and replacement costs, lost production, and additional expenses related to the incident as follows:



Workers compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence. We have expensed $4 million and $10 million during the three and nine months ended September 30, 2013, respectively, of costs under our insurance deductibles in operating and maintenance expenses in the Consolidated Statement of Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through September 30, 2013, we have recognizedProperty damage and business interruption coverage with a combined per-occurrence limit of $500 million of insurance recoveries related to this incident as a gain to other (income) expense net within costs and expenses in our Consolidated Statement of Income. Included in selling, general, and administrative expenses are charges of $6 million and $14 million during the three and nine months ended September 30, 2012, respectively, related to our engagement of a consulting firm to assist in better aligning resources to support our business strategy following the spin-off of WPX Energy, Inc. (WPX). During the second quarter of 2012, we incurred acquisition transaction costs of $16 million related to the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC. These costs are also included in selling, general, and administrative expenses . Other (income) expense net within costs and expenses, in addition to the insurance recoveries mentioned above, includes:and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption;


Charges of $9 million and $15 million for the three and nine months ended September 30, 2013, respectively, related to the portion of the Eminence abandonment regulatory asset that will not be recovered through rates, pursuant to Transcos General liability coverage with per-occurrence and aggreement in principle associated with its general rate case filing (See Note 12 Contingent Liabilities .). We also recognized incomegate annual limits of $3610 million and $15 million for the three and nine months ended September 30, 2013, respectively, related to insurance recoveries associated with this eventretentions (deductibles) of $2 million per occurrence;

Charges of $2 million during the nine months ended September30, 2013 and $2 million and $17 million during the three and nine months ended September30, 2012, respectively, related to project development costs associated with natural gas pipeline expansion projects;


A $9 million accrued loss in the three and nine months ended September 30, 2013 for a contingent liability associated with a pending producer claim against us;


Charges of $8 million and $15 million during the three and nine months ended September30, 2013 and $2 million and $5 million during the three and nine months ended September30, 2012 related to the amortization of regulatory assets associated with asset retirement obligations
Workers compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.
1
34
Notes (Continued)
Other investing income net includes $11 million and $37 million of interest income for the three and nine months ended September30, 2013, respectively, associated with a receivable related to the sale of certain former Venezuela assets (see Note 3 Discontinued Operations During the first quarter of 2014, we received $125 million of insurance recoveries related to the Geismar Incident and incurred $6 million of related covered insurable expenses in excess of our retentions (deductibles). Thisese amount reflects a current year increase in yield associated with a revision in our estimate of the cash flows expected to be received as a result of continued timely payment by the counterparty. In the nine months ended September30, 2012 , other investing income net includes $63 millions are reflected as a net gain in Net insurance recoveries Geismar Incident within Costs and expenses in our Consolidated Statement of iIncome, including $10 million of interest, related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan as . Selling, general, and administrative expensets infor the first quarter of 2012 (see Note 3 Discontinued Operations ), we also received payment for all outstanding balances due from this sale, including interest. Income had previously been recognized upon receipt of payments, as future collections were not reasonably assured.
Also included in other investing income net for
4 includes $19 million of project development costs related to the Bluegrass Pipeline. Other investing income net includes $13 million of interest income for each of the ninthree month periods ended September 30, 2013, is a $26 million gain resulting from Access Midstream Partners equity issuance in April 2013. This equity issuancMarch31, 2013 and 2014 associated with a receivable resulated into the dilution of our ownership interest from approximately 24 percent to 23 percent , which is accounted for as though we sold a portion of our investmentsale of certain former Venezuela assets. Note 54 Provision (Benefit) for Income Taxes The pProvision (benefit) for income taxes from continuing operationsicue:


Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)
(Millions)

Current:

Federal
$
25137
$
58
$
(47
(11
)
$
112

State
10
3
18
5
2


Foreign
2
6
3
30
2

27
7
144
(
417
)
160

Deferred:

Federal
21
6
233
123
(96
)
82


State
9
(3
(1
)
41
(9
)
13

Foreign
54
27
7
8

(935
3)
301
121
103

Total provision (benefit)
$
6251
$
77
$
260
$
281
96
The effective income tax rate for the total provision for the three months ended
September30March31, 20134, is less than the federal statutory rate primarily due to a tax benefit related to the completion of the Canada Dropdown and the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes and taxes on foreign operations. The effective income tax rate for the total provision for the ninthree months ended September30March 31, 2013, is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes. The 2013 deferred provision includes $10 million related to the impact of a second-quarter Texas franchise tax law change, net of federal benefit. The effective income tax rate for the total provision for the three months ended September30, 2012, is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests. The effective income tax rate for the total provision for the nine months ended September30, 2012, is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations. During the first quarter of 2013, we finalized a settlement with the Internal Revenue Service (IRS) on tax matters related to the IRSs examination of our 2009 and 2010 consolidated corporate income tax returns.We recorded a taxAs a result of closing the Canada Dropdown, $90 million of previously deferred tax liability has been reclassified as a current income tax liability in the first quarter of 2014. During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.
1
45
Notes (Continued)
provision of approximately $2 million related to these matters during the third quarter of 2012.With respect to the examined years, we made cash payments of $ 12 million to the IRS in February of 2013. With the spin-off of WPX on December31, 2011, WPX entered into a tax sharing agreement with us under which we are generally liable for all U.S. federal, state, local and foreign income taxes attributable to WPX with respect to taxable periods ending on or before the distribution date. We are also principally responsible for managing any income tax audits by the various tax jurisdictions for pre-spin-off periods. In 2012, we prepared pro forma tax returns for each tax period in which WPX or any of its subsidiaries were combined or consolidated with us. In the first quarter of 2013, we reimbursed WPX a net $2 million for the additional losses shown on the pro forma tax returns, offset with additional tax resulting from the 2009 to 2010 IRS settlement. On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce or improve tangible property and proposed regulations providing guidance on the dispositions of such property. The implementation date for these regulations is January1, 2014. Changes for tax treatment elected by us or required by the regulations will generally be effective prospectively; however, implementation of many of the regulations provisions will require a calculation of the cumulative effect of the changes on prior years, and it is expected that such amount will have to be included in the determination of our taxable income in 2014, or possibly over a four-year period beginning in 2014. The IRS is expected to issue additional procedural guidance regarding 2014 tax return filing requirements and how the requirements may be implemented for the gas transmission and distribution industry. Since the changes will affect the timing for deducting expenditures for tax purposes, the impact of implementation will be reflected in the amount of income taxes payable or receivable, cash flows from operations and deferred taxes beginning in 2014, with no net tax provision effect. Pending the issuance of additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations.
During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.
On October 30, 2013, WPZ announced its intent to pursue an agreement to acquire certain of our Canadian operations. As a result, we no longer consider the undistributed earnings from these foreign operations to be permanently reinvested and thus expect to recognize approximately $200 million of deferred income tax expense in the fourth quarter of 2013. Of this amount, we estimate approximately $140 million will be characterized as a current income tax liability upon consummation of the proposed transaction.
Note 65 anns(os e omnSaefo otnigOeain



Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(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
$
1430
$
152
$
454
$
57
62
Basic weighted-average shares
68
3,274
626,809
682,744
613,888
4,773
682,052


Effect of dilutive securities:

Nonvested restricted stock units
1,901
2,490
1,975
2,096
2,72
10

Stock options
2,
113
2,535
2,169
2,695
017
2,187


Convertible debentures
18
18
5
119
461
4

Diluted weighted-average shares
68
7,306
632,019
687,007
619,765
8,904
687,143


Earnings (loss) per common share from continuing operations:

Basic
$
.210
$
.25
$
.66
$
.9
4
Diluted
$
.20
$
.2
5
$
.66
$
.93
15
Notes (Continued)
Note 7
3
Note 6
Employee Benefit Plans
Net periodic benefit cost
(credit) sa olw:


Pension Benefits

Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Components of net periodic benefit cost:

Sriecs
$
11
$
10
$
33
$
29
11

Interest cost
1
26
1
4
38
42
3

Expected return on plan assets
(19
)
(15
)
(16
)
(45
)
(48
)

Amortization of prior service cost
1
1

Amortization of net actuarial loss
9
15
13
45
40

Net actuarial loss from settlements
2
4

Net periodic benefit cost
$
16
$
24
$
23
$
72
$
67



Other Postretirement Benefits

Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Components of net periodic benefit cost (credit):
Service cost
$
1
$
1
$
2
$
2

Interest cost
2
4
8
10
3

Expected return on plan assets
(3
)
(32
)
(7
)
(7
)

Amortization of prior service credit
(35
)
(2
)
(7
)
(5
)

Amortization of net actuarial loss
1
2
4
6

AmortizReclassification tof euaoylaiiy 1
1

Net periodic benefit cost (credit)
$
(14
)
$
2
$
1
$
6
16
Notes (Continued)

Amortization of prior service credit and net actuarial loss included in net periodic benefit cost
(credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recorded to net regulatory assets/liabilities instead of other comprehensive income (loss). Amounts recognized in net regulatory assets/laiiisicue



Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Amortization of prior service credit
$
(13
)
$
(21
)
$
(4
)
$
(4
)

Amortization of net actuarial loss
1
2
4
16
Notes (Continued)
During the third quarter of 2013, our other postretirement benefit plan was amended, which resulted in a remeasurement of the plans funded status. The overall impact of the remeasurement was to reduce our liability reflecting the plans funded status by $121 million , with $59 million of the decrease directly attributable to the plan amendment and $62 million due to other actuarial gains through the remeasurement date. The decrease in our liability reflecting the plans funded status is offset by increases to accumulated other comprehensive income (loss) and net regulatory liabilities . During the nine months ended September30
During the three months ended March31, 20134 , we contributed $9216 million to our pension plans and $62 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $247 million to our pension plans and approximately $6 million to our other postretirement benefit plans in the remainder of 20134. Note 87 netre



Sept March31,
2014
Dec
ember301, 2013
December31, 2012

(Millions)

Natural gas liquids, olefins, and natural gas in underground storage
$
1481
$
97111

Materials, supplies, and other
8
21
783

$
23022
$
1
7594
Note
98 Debt and Banking Arrangements Credit Facilities On July31Long-Term Debt Issuances On March 4, 20134, we amended our $900 million and WPZs $2.4 billion credit facilities to increase the aggregate commitments to $1.5 billion and $2.5 billion, respectively and extend the maturity dates for both credit facilities to July31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended WPZ credit facility to the extent not otherwise utilized by the other co-borrowers. Both credit facilities may also, under certain conditions, be increased up to an additional $500 million. As a result of the modifications, the previously deferred fees and costs related to these facilities are being amortized over the term of the new arrangements. At September30, 2013 , lWPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. WPZ used a portion of the net proceeds to repay amounts outstanding under its commercial paper program and expects to utilize the remainder to fund capital expenditures and for general partnership purposes. Credit Facilities Letter of credit capacity under our $1.5 billion and WPZs $2.5 billion credit facilities is $700 million and $1.3 billion , respectively. At September30March31, 20134 , no letters of credit have been issued and no loans are outstanding on these credit facilities. We have issued letters of credit totaling $175 million as of September30, 2013 , under certain bilateral bank agreements. Commercial Paper Program In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. At September30, 2013 , WPZ has $371 million in commercial paper outstanding at a weighted average interest rate of 0.41 percent .
nd WPZ issued letters of credit totaling $9 million as of March31, 2014 , under certain bilateral bank agreements.
1
Notes (Continued)
Note
10 Stockholders Equity9 Accumulated Other Comprehensive Income The following table presents the changes in aAcuuae te opeesv noe(os ycmoet e ficm ae:


Cash Flow Hedges
Foreign Currency Translation
Pensionand Other Post Retirement Benefits
Total

(Millions)

Balance at December31, 201
2
3
$ (1
)
$
16928
$
(530291
)
$
(
362164
)

Other comprehensive income (loss) before reclassifications
1
(31
(44
)
27
(3
(44
)

Amounts reclassified from accumulated other comprehensive income (loss)
(15
5

Other comprehensive income (loss)
(44
)
5
(39

)
28
27

Other comprehensive income (lossChanges in ownership of consolidated subsidiaries, net
(20
)
(
3120
)
55
24

Balance at
September30March 31, 20134
$
(1
)
$
13864
$
(475286
)
$
(
338223
) Reclassifications out of
aAccumulated other comprehensive income (loss) are presented in the following table by component for the ninthree months ended September30March31, 20134



Component
Reclassifications
Classification

(Millions)

Cash flow hedges:

Energy commodity contracts
$
(1
)
Product sales

Total cash flow hedges
(1
)


Pension and other postretirement benefits:

Amortization of prior service cost (credit) included in net periodic benefit cost
$
(2
)
Note 76 mlyeBnftPas
Amortization of actuarial (gain) loss included in net periodic benefit cost
479
Note
76 mlyeBnftPas
Total pension and other postretirement benefits

45
, before income taxes
7



Reclassifications before income tax
44

Income tax benefit
(172
)
Provision (benefit) for income taxes

Reclassifications during the period
$
275
18
Notes (Continued)
Note 110 Fair Value Measurements
and Guarantees h olwn al rsns ylvlwti h arvleheacy eti forfnnilast n iblte.Tecryn auso ahadcs qiaet,acut eevbe omrilppr n conspybeapoiaefi au eas ftesottr aueo hs ntuet.Teeoe hs sesadlaiiisaentpeetdi h olwn al.


Fi au esrmnsUig
Carrying Amount
Fair Value
Quoted PricesIn Active Marketsfor Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)

(Millions)

Assets (liabilities) at
SeptemberMarch 301, 20134:
Measured on a recurring basis:

ARO Trust investments
$
3145
$
3145
$
31
45
$ $

Energy derivatives assets not designated as hedging instruments
63
63
1
5
3

Energy derivatives liabilities not designated as hedging instruments
(32
)
(3
)
(1
2
)
(2
)

Additional disclosures:

Notes receivable and other
8275
1
4830
12
76
1
4022

Long-term debt, including current portion (
a1)
(1
0,3582,849
)
(1
1,0263,790
)
(1
1,0263,790
)

Guarantee
(321
)
(298
)
(298
)

Assets (liabilities) at December 31, 20123:
Measured on a recurring basis:

ARO Trust investments
$
1833
$
1833
$
1833
$
$

Energy derivatives assets not designated as hedging instruments
53
53
53

Energy derivatives liabilities not designated as hedging instruments
(13
)
(3

)
(1
)
(12
)

Additional disclosures:

Notes receivable and other
9577
1
3840
21
86
1
2833

Long-term debt
, including current portion (a)
(10,734
(1)
(11,353

)
(1
2,3881,971
)
(1
2,3881,971
)

Guarantee
(332
)
(3129
)
(3129
)



(a1) Excludes capital leases Fair Value Methods We use the following methods and assumptions in estimating the fair value of our financial instruments: Assets and liabilities measured at fair value on a recurring basis ARO Trust investments : Transco deposits a portion of its collected rates, pursuant to its 2008 rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in rRegulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. Energy derivatives : Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring
19
Notes (Continued)
Energy derivatives : Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. 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 do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in oOther current assets and deferred charges and rRegulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in aAccrued liabilities and oOther noncurrent liabilities in the Consolidated Balance Sheet. 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 transfers between Level 1 and Level 2 occurred during the ninthree months ended September30March31, 20134 or 20123 . Additional fair value disclosures Notes receivable and other: Notes receivable and other includes a receivable related to the sale of certain former Venezuela assets (see Note 3 Discontinued Operations ). The disclosed fair value of this receivable is determined by an income approach. We calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty, future probabilities of default, our likelihood of using arbitration if the counterparty does not perform, and discount rates. We determined the fair value of the receivable to be $10587 million at September30March31, 20134 . The carrying value of this receivable is $382 million at September30March31, 20134 . The current and noncurrent portions are reported in aAccounts and notes receivable, net and rRegulatory assets, deferred charges, and other , respectively, in the Consolidated Balance Sheet. Notes receivable and other also includes a receivable from our former affiliate, WPX Energy, Inc (WPX) (see Note 121 Contingent Liabilities ) and other notes receivable. The disclosed fair value of these receivables is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in aAccounts and notes receivable , net and the noncurrent portion is reported in rRegulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Long-term debt : The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. Guarantee : The guarantee represented in the 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 that extends through 2042. To estimate the disclosed fair value of the guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTels current owner and the term of the underlying obligation. The default rate is published by Moodys Investors Service. This guarantee is reported in aAccrued liabilities in the Consolidated Balance Sheet. Guarantees We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain 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. Regarding our previously described guarantee of Wiltels lease performance, the maximum potential exposure is approximately $35 million at March31, 2014 and December31, 2013 . Our exposure declines systematically throughout the remaining term of WilTels obligation.20
Notes (Continued)
Regarding our previously described guarantee of Wiltels lease performance, the maximum potential exposure is approximately $36 million at September30, 2013 and December31, 2012 . Our exposure declines systematically throughout the remaining term of WilTels obligation. We have provided guarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily a natural gas purchase contract extending through 2023. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $7659 million at September30March31, 20134 . Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant. Note 121 Contingent Liabilities Indemnification of WPX Matters We have agreed to indemnify our former affiliate, WPX and its subsidiaries, related to the following matters. In connection with this indemnification, we have accrued asset and liability balances associated with these matters, and as a result, have an indirect exposure to future developments in these matters. Issues resulting from California energy crisis WPXs former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by WPX 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). WPX has 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. Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, WPX continuesd to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. WPX and certain California utilities have agreed in principle toOn April 24, 2014, the FERC approved a settlement among the California utilities, WPX, and us which resolves WPXs collection of accrued interest from counterparties as well as WPXs payment of accrued interest on refund amounts. As currently contemplated by the parties, tThe settlement, which is subject to FERC and California regulatory approval, wouldill resolve most of WPXs legal issues arising from the 2000-2001 California Energy Crisis. We currently have a net receivable from WPX related to these matters. Reporting of natural gas-related information to trade publications Direct and indirect purchasers of natural gas in various states filed class actions against WPX and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. In 2011, the Nevada district court granted WPXs joint motions for summary judgment to preclude the plaintiffs state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs class certification motion as moot. The plaintiffs appealed the courts ruling and on April10, 2013, the Ninth Circuit Court of Appeals reversed the district court and remanded the cases to the district court to permit the plaintiffs to pursue their state antitrust claims for natural gas sales that were not subject to FERC jurisdiction under the Natural Gas Act. On August 26, 2013, WPX and the other defendants filed their petition for a writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around the remaining 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 and our related indemnification obligation could result in future charges that may be material to our results of operations. Other Legal Matters Geismar Incident As a result of the previously discussed Geismar Incident, there were two fatalities, and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. WPZ is cooperating with the Chemical Safety Board and the U.S. Environmental Protection Agency (EPA) regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Acts Risk
21
Notes (Continued)
Other Legal Matters Geismar Incident As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. WPZ is cooperating with the Occupational Safety and Health Administration, the Chemical Safety Board, and the U.S. Environmental Protection Agency (EPA) to conduct investigations to determine the cause of the incidenManagement Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPAs preliminary determinations about the facilitys documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations. On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued citations in connection with its investigation of the June 13, 2013 incident, which included a Notice of Penalty for $99,000 . Although we and OSHA continue settlement negotiations, we are contesting the citations. On June 25, 2013, OSHA commenced a second inspection pursuant to its Refinery and Chemical National Emphasis Program (NEP). OSHA has not issued any citation to WPZ in connection with this NEP inspection. There is a six month statute of limitations for violation of the Occupational Safety and Health Act of 1970 or regulations promulgated under such act. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries. Due to the ongoing investigation into the cause of the incident, and the limited information available associated with the filed lawsuits, which do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time. Gulf Liquids litigation
Gulf Liquids, one of our subsidiaries, 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 us. The court also denied the plaintiffs claims for attorneys fees. On January28, 2008, the court issued its judgment awarding certain damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby and 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 accrued liability as of December31, 2008, by $43 million , including $11 million of interest. On February17, 2011, the Texas Court of Appeals upheld the dismissals of the tort and punitive damages claims. As a result, we reduced our accrued liability as of December31, 2011 by $33 million , including $14 million of interest. The Texas Court of Appeals also reversed and remanded the remaining claims for further proceedings. None of the parties filed a petition for review in the Texas Supreme Court. On May8, 2012, the Texas Court of Appeals issued its mandate remanding the original breach of contract claims involving Gulsby and attorney fee claims (the remaining claims) to trial court. Trial is set for October 14, 2014Gulsby-Bay and Bay. On February17, 2011, the Texas Court of Appeals upheld the dismissals of the tort and punitive damages claims and reversed and remanded the remaining claims for further proceedings. None of the parties filed a petition for review in the Texas Supreme Court. On May8, 2012, the Texas Court of Appeals issued its mandate remanding the original breach of contract claims involving Gulsby and attorney fee claims to trial court. Trial is set for October 14, 2014. In 2006, we accrued a charge, and related interest, for our estimate of probable loss associated with the initial adverse verdict. From 2008 through 2011, the amount accrued was reduced based on subsequent judgments and settlement payments. As of March 31, 2014, we have a remaining accrued liability of $13 million associated with the litigation. Alaska refinery contamination litigation In January 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA have made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the James West claim. We and FHRA subsequently filed motions for summary judgment on the others claims. On November 5, 2013, the court ruled that the applicable statute of limitations bars all
22
Notes (Continued)
seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the James West claim. Our claims against FHRA and their claims against us remain outstanding. We and FHRA filed motions for summary judgment on thFHRAs claims against us and dismissed those claims with prejudice. FHRA has asked the court to reconsider and clarify its ruling, and we anticipate others claims, but the motions are unlikely to resolve alat FHRA will appeal the courtstanding claims decision. We currently estimate that our reasonably possible loss exposure in this matter could range from an insignificant amount up to $32 million , although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount. Independent of the litigation matter described in the preceding paragraphs, the Alaska Department of Environmental Conservation (ADEC) indicated that it views FHRA and us as responsible parties. During the first quarter of 2013 and again on December 23, 2013, ADEC informed FHRA and us that itADEC intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinerys boundaries to be performed in 2014. In addition, ADEC will seek from each of FHRA and us an adequate financial performance guarantee for the benefit of ADEC. As such, we will likely be required to contribute some amount, whether to reimburse the State, to reimburse FHRA, or to comply with an ADEC orderOn March 6, 2014, the State of Alaska filed suit against FHRA and us in state court in Fairbanks seeking injunctive relief and damages in connection with the sulfolane contamination. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs between the namedamong the potentially responsible parties, we are unable to estimate a range of liability at this time. 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 Libertys continued failure to substantiate its counterclaim, we are unable to evaluate its merits and determine the amount of any possible liability.exposure at this time. Transco 2012 rate case On August31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in ourits prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC that wouldproposing to resolve all issues in this proceeding without the need for a hearing after reaching an agreement in principle with the participants. The stipulation and agreement is subject to review and approval by the FERC. We have provided a reserve for rate refunds which we believe is adequate(Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective March 1, 2014. As of March 31, 2014, Accounts Payable includes $118 million for anyrate refunds that may be requiredwere subsequently paid on April 18, 2014. Environmental Matters We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. 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. As of September30March31, 20134 , we have accrued liabilities totaling $456 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities. The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules.More recent 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, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors.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.
23
Notes (Continued)
internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors.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. Continuing operations Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances.These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites.At September30March31, 20134 , we have accrued liabilities of $113 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 September30March31, 20134 , we have accrued liabilities totaling $7 million for these costs. 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 remediation activities at the direction of federal and state environmental authorities and h nenfcto fteprhsr fcrano hs sesadbsnse o niomna n te iblte xsiga h ietesl a osmae.Orrsosblte eaet h prtoso h sesadbsnse ecie eo.

Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;


Former petroleum products and natural gas pipelines;


Former petroleum refining facilities;


Former exploration and production and mining operations;


Former electricity and natural gas marketing and trading operations. At September30March31, 20134 , we have accrued environmental liabilities of $276 million related to these matters. 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 September30March31, 20134 , other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future 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 We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties

24
Notes (Continued)
Summary We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. Note 132 Segment Disclosures Our reportable segments are Williams Partners, Williams NGL& Petchem Services, and Access Midstream Partners. All remaining business activities are included in Other. (See Note 1 General, Description of Business, and Basis of Presentation .) Performance Measurement We currently evaluate segment operating performance based upon sSegment profit (loss) from operations, which includes sSegment revenues from external and internal customers, segment costs and expenses, eEquity earnings (losses) and iIncome (loss) from investments . General corporate expenses represent sSelling, general, and administrative expenses that are not allocated to our segments. Intersegment revenues are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
2
Notes (Continued)
The following table reflects the reconciliation of sSegment revenues and sSegment profit (loss) to Total revenues and oOperating income (loss) as reported in the Consolidated Statement of Income and tToa sesb eotbesget



Williams Partners
Williams NGL&Petchem Services
Access Midstream Partners
Other
Eliminations
Total

(Millions)

Three months ended
SeptemberMarch 301, 20134

Segment revenues:

Service revenues

External
$
7
631
$
$
$
56
$
$
736819

Internal
23
(
23
)

Total service revenues
7
31
7
(2
63
59
(3

)
736819

Product sales

External
855
32
887
930
930


Internal
27
(27
)

Total product sales
855
59
(27
)
887
930
930


Total revenues
$
1,
586693
$
59
$
$
759
$
(293
)
$
1,623749

Segment profit (loss)
$
405503
$
(2100
)
$
6
$
3
$
412

Less
:

E
equity earnings (losses)
3123
(77
)

6
37

Income (loss) from investments
(1
(48
)
(1
)

Segment operating income (loss)
$
374480
$
(123
)
$
$
3
376460

General corporate expenses
(40
)

Operating income (loss)
$
336420


Three months ended
SeptemberMarch 301, 20123

Segment revenues:

Service revenues

External
$
668702
$
2
$
$
54
$
$
675706

Internal
23
(
23
)

Total service revenues
668
702 7
(23
)
675706

Product sales

External
1,
1049
28
1,077
1,104

Internal
32
(32
)

Total product sales
1,
1049
60
(32
)
1,077
1,104

Total revenues
$
1,717806
$
62
$
$
7
$
(34
)
$
1,752810

Segment profit (loss)
$
4
294
$
16(2
)

$
$
1(5
)

$
44687

Less:

Equity earnings (losses)
30
30
18
18

Income (loss) from investments
(1
)
(1
)


Segment operating income (loss)
$
399477
$
16(2
)

$
$
1(5
)

4
1670

General corporate expenses
(434
)

Operating income (loss)
$
373426

March31, 2014



26
Notes (Continued)



Williams Partners
Williams NGL&Petchem Services
Access Midstream Partners
Other
Eliminations
Total

(Millions)

Nine months ended September 30, 2013

Segment revenues:

Service revenues

External
Total assets
$
2
,1474,791
$
378
$
2,136
$
13,459
$
(458
)
$
2
,1638,306

Internal
8
(8
)
December31, 2013

Total
service revenues
2,147
3
21
(8
)
2,163

Product sales

External
2,922
115
3,037

Internal
103
(103
)

Total product sales
2,922
218
(103
)
3,037

Total revenue
assets $
5,06923,571
$
221486
$
2,161
$
21,359
$
(111435
)
$
5,200

Segment profit (loss)
$
1,264
$
56
$
35
$
$
1,355

Less:

Equity earnings (losses)
84
9
93

Income (loss) from investments
(3
)
27,142
26
23Notes (Continued)
Note 13 Subsequent Event
On April 23, 2014, an explosion and fire occurred at WPZs natural gas processing facility near Opal, Wyoming. There were no reported injuries or damage to property outside the facility. The facility was immediately shut down and natural gas gathering from surrounding producing areas was temporarily suspended as a result of the incident.
The facility is primarily comprised of five turbo-expander (TXP) cryogenic gas-processing units. Although we have not yet made a full assessment of all plant equipment, the initial visual assessment of damage indicates that the impact was largely limited to the TXP-3 unit. We are inspecting the damaged equipment in cooperation with regulatory authorities and developing preliminary plans to bring the other four units back into service. The capacity of the four undamaged plants is sufficient to handle all of the natural gas currently available to the facility.
We have insurance coverage, subject to retentions (deductibles), for property damage and business interruption that we expect to significantly mitigate the financial effects of the incident.
27
Item2 Managements Discussion and Analysis of Financial Condition and Results of Operations General We are an energy infrastructure company focused on connecting North Americas significant hydrocarbon resource plays to growing markets for natural gas, natural gas liquids, and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners, Williams NGL& Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other. Williams Partners Williams Partners 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, processing, and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain, Gulf Coast, and Marcellus Shale regions of the United States. WPZ also owns a 5/6 interest in an olefin production facility, along with a refinery grade propylene splitter and pipelines in the Gulf region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta. We produce olefins and NGLs. As of March 31, 2014, we own approximately 66 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 Gulf Coast Region, 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 FERCs ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on transmission revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates. Williams NGL& Petchem Services Williams NGL & Petchem Services includes certain other domestic olefins pipeline assets, certain Canadian growth projects under development, including a propane dehydrogenation facility and a liquids extraction plant, as well as the proposed Bluegrass Pipeline joint project (see Note 2 Variable Interest Entities of Notes to Consolidated Financial Statements for more information regarding current period developments). As discussed in Note 1 General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements, the currently operating Canadian assets contributed to Williams Partners in the first quarter of 2014 and are now presented in the Williams Partners segment. As a result, this segment is currently comprised primarily of projects under development and thus has no operating revenues to date. Access Midstream Partners Access Midstream Partners includes our equity method investment in ACMP. As of March 31, 2014, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access GP, including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and
28
Managements Discussion and Analysis (Continued)
acquires natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas. Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form10-Q and our 2013 Annual Report on Form10K, filed February26, 2014. Dividends In March 2014, we paid a regular quarterly dividend of $0.4025 per share, which was 19 percent higher than the same period last year and 6 percent higher than the prior quarter.Also, consistent with our expectation of receiving increasing cash distributions from our interests in WPZ and ACMP, we expect to increase our dividend on a quarterly basis. We expect a 20 percent annual dividend increase in both 2014 and 2015. Overview of Three Months Ended March31, 2014 Income (loss) from continuing operations attributable to The Williams Companies, Inc. , for the three months ended March31, 2014, changed unfavorably by $22 million compared to the three months ended March31, 2013, primarily due to equity losses from the proposed Bluegrass Pipeline project, primarily reflecting a write-off of development costs that were previously capitalized and other associated costs that were incurred during the first quarter. The three months ended March 31, 2014 also reflects increased service revenues partially offset by lower NGL margins. See additional discussion in Results of Operations. Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth. Williams Partners
Canada Dropdown On February 28, 2014, we contributed certain of our Canadian operations to WPZ, including an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta, and the Boreal pipeline. These businesses were previously reported within our Williams NGL & Petchem Services segment, but are now reported within Williams Partners. Prior period segment disclosures have been recast for this transaction. WPZ funded the transaction with $25 million of cash (subject to certain closing adjustments), the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All Class D units outstanding will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Dropdown provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.
Opal Incident
On April 23, 2014, an explosion and fire occurred at our natural gas processing facility near Opal, Wyoming. There were no reported injuries or damage to property outside the facility. The facility was immediately shut down and natural gas gathering from surrounding producing areas was temporarily suspended as a result of the incident. The facility is primarily comprised of five turbo-expander (TXP) cryogenic gas-processing units. Although we have not yet made a full assessment of all plant equipment, the initial visual assessment of damage indicates that the impact was largely limited to the TXP-3 unit. We are inspecting the damaged equipment in cooperation with regulatory authorities and developing preliminary plans to bring the other four units back into service. The capacity of the four undamaged plants is sufficient to handle all of the natural gas currently available to the facility.
29
Managements Discussion and Analysis (Continued)
We have insurance coverage, subject to retentions (deductibles), for property damage and business interruption that we expect to significantly mitigate the financial effects of the incident. Geismar Incident On June13, 2013, an explosion and fire occurred at WPZs Geismar olefins plant. The fire was extinguished on the day of the incident. The Geismar Incident rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects. We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:


Segment operating income (loss)
$
1,180
$
59
$
$
1,239

General corporate expenses
(127
)
Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a 60-day waiting period per occurrence for business interruption;

Operating income (loss)
$
1,112

General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

Nine months ended September 30, 2012

Segment revenues:Workers compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence. During the first quarter of 2014, we received $125 million of insurance recoveries related to the Geismar Incident and incurred $6 million of related covered insurable expenses in excess of our retentions (deductibles). These amounts are reflected as a net gain in Net insurance recoveries- Geismar Incident within Costs and expenses in our Consolidated Statement of Income . Following the repair and an expansion of the plant, the Geismar plant is expected to begin start-up in the latter-half of June 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate cash recoveries from insurers of approximately $430 million related to business interruption and approximately $70 million related to the repair of the plant. Of these amounts, we received $50 million of insurance proceeds during 2013 and $125 million in the first quarter of 2014. We are impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles, policy limits, and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different. New Transco rates effective On August31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March1, 2013, subject to refund and the outcome of a hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective March 1, 2014. We accrued $118 million for rate refunds as of March31, 2014, which were subsequently paid on April 18, 2014. Caiman II As a result of $119 million of contributions made in the first quarter of 2014, our ownership in the Caiman II joint project increased to 58 percent at March 31, 2014. These contributions are used to fund Caiman IIs 50 percent investment in Blue Racer Midstream LLC, which is expanding gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale.
30
Managements Discussion and Analysis (Continued)
Volatile commodity prices NGL margins were approximately 26 percent lower in the first three months of 2014 compared to the same period of 2013 driven by lower volumes, as well as higher natural gas prices, partially offset by favorable non-ethane prices. Volumes declined primarily due to a customer contract in the West that expired in September 2013, as well as higher inventory levels. Due to unfavorable ethane economics, we continued our reduced recoveries of ethane in our domestic plants in the first quarter of 2014, consistent with the same period in 2013. 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. The following graph illustrates the effects of this price volatility, notably the decline in equity ethane sales driven by reduced recoveries, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.


Service revenues

External
$
2,005
$
2
$
$
12
$
$
2,019

Internal
8
(8
)
Williams NGL& Petchem Services Bluegrass Pipeline and Moss Lake We own a 50 percent interest in the proposed Bluegrass Pipeline, which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast. Completion of this project is subject to execution of customer contracts sufficient to support the project. Although discussions with potential customers continue, we have not received sufficient executed customer
31
Managements Discussion and Analysis (Continued)
commitments to date to support the continued development of the project. Considering this and other factors, our management decided in April to discontinue further funding of the project at this time. Given these developments, the capitalized project development costs at the Bluegrass Pipeline entity were written off as of March 31, 2014, and as a result, we have recognized $67 million in related equity losses in the first quarter of 2014.
We also own 50 percent interests in Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake). Moss Lake may construct a proposed new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a proposed pipeline connecting these facilities to the Bluegrass Pipeline. Additionally, Moss Lake may construct a proposed new liquefied petroleum gas (LPG) terminal. In the first quarter of 2014, we have recognized $4 million in equity losses related to Moss Lake, primarily associated with the underlying write off of capitalized project development costs at Moss Lake. Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to safety, environmental stewardship, operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our shareholders.
Fee-based businesses are a significant component of our portfolio. As we continue to transition to an overall business mix that is increasingly fee-based, the influence of commodity price fluctuations on our operating results and cash flows is expected to become somewhat less significant.
As previously noted, the financial impact of the Geismar Incident is expected to be significantly mitigated by our insurance policies. We expect the timing of recognizing recoveries under our business interruption policy will favorably impact our operating results in 2014.
Our business plan for 2014 reflects both significant capital investment and continued dividend growth. Our planned consolidated capital investments for 2014 total approximately $4.1 billion. We also expect approximately 20 percent growth in total 2014 dividends, which we expect to fund primarily with distributions received from WPZ and ACMP. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions.
Potential risks and obstacles that could impact the execution of our plan include:


Total service revenues
2,005
2
20
(8
)
2,019

Product salesGeneral economic, financial markets, or industry downturn;

External
3,497
101
3,598

Internal
98
(98
)
Unexpected significant increases in capital expenditures or delays in capital project execution;

Total product sales
3,497
199
(98
)
3,598

Total revenues
$
5,502
$
201
$
$
20
$
(106
)
$
5,617
Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident;

Segment profit (loss)
$
1,371
$
72
$
$
61
$
1,504

L
ess:imited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

Equity earnings (losses)
87
1
88

Income (loss) from investments
(2
)
53
51
Lower than expected distributions, including IDRs, from WPZ. WPZs liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth;

Segment operating income (loss)
$
1,284
$
74
$
$
7
1,365

General corporate expenses
(133
)
Counterparty credit and performance risk;

Operating income (loss)
$
1,232

September30, 2013Decreased volumes from third parties served by our midstream business;

Total assets
$
21,633
$
1,543
$
2,162
$
1,839
$
(722
)
$
26,455

December31, 2012

Total assets
$
19,709
$
1,134
$
2,187
$
1,782
$
(485
)
$
24,327
27
Item2 Managements Discussion and Analysis of Financial Condition and Results of Operations General We are an energy infrastructure company focused on connecting North Americas significant hydrocarbon resource plays to growing markets for natural gas, natural gas liquids (NGLs), and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners, Williams NGL& Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other. Williams Partners Williams Partners includes Williams Partners L.P. (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, processing, and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain, Gulf Coast, and Marcellus Shale regions of the United States. WPZ also owns a 5/6 interest in an olefin production facility, along with a refinery grade propylene splitter and pipelines in the Gulf region. As of September 30, 2013, we own approximately 64 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 Federal Energy Regulatory Commission (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 FERCs 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. Williams NGL& Petchem Services Williams NGL& Petchem Services includes our oil sands offgas processing plant near Fort McMurray, Alberta and our NGL/olefin fractionation facility and butylene/butane (B/B) splitter facility at Redwater, Alberta. We produce NGLs and propylene. Our NGL products include propane, normal butane, isobutane/butylene (butylene), and condensate. Williams NGL & Petchem Services also includes Bluegrass Pipeline Company LLC (Bluegrass Pipeline), a new joint project, which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast. Access Midstream Partners Access Midstream Partners includes our equity method investment in Access Midstream Partners L.P. (ACMP), acquired in December 2012. As of September 30, 2013, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access Midstream Partners GP L.L.C. (Access GP), including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and acquires
28
Lower than anticipated energy commodity prices and margins;
32

Managements Discussion and Analysis (Continued)
natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas. Unless indicated otherwise, the following discussion and analysis of our results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form10-Q and our 2012 Annual Report on Form 10-K, filed February27, 2013. Proposed Dropdown On October 30, 2013, WPZ announced its intent to pursue an agreement to acquire certain of our Canadian operations, including our oil sands offgas processing plant near Fort McMurray, an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, and the Boreal pipeline. WPZ expects to fund the transaction through the issuance of a new class of limited-partner units to us. These units will receive quarterly distributions of additional paid-in-kind units, all of which will be convertible to common units at a future date. The transaction is subject to execution of an agreement, review and recommendation by the Conflicts Committee of the general partner of WPZ, and approval of both our and WPZs Board of Directors. Dividends In September 2013, we paid a regular quarterly dividend of $0.36625 per share, which was 17.2 percent higher than the same period last year and 3.9 percent higher than the prior quarter.Also, consistent with our expectation of receiving increasing cash distributions from our interests in WPZ and ACMP, we expect to increase our dividend on a quarterly basis. We expect a 20 percent annual dividend increase in 2013, 2014, and 2015. Overview of Nine Months Ended September30, 2013 Income (loss) from continuing operations attributable to The Williams Companies, Inc. , for the nine months ended September30, 2013, changed unfavorably by $118 million compared to the nine months ended September30, 2012. This change primarily reflects:


A $104 million unfavorable change in segment operating income at Williams Partners primarily due to lower NGL margins driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, and higher natural gas prices, along with higher operating costs associated with ongoing growth. Partially offsetting these unfavorable changes was an increase in fee revenues (see Results of Operations Segments, Williams Partners) Changes in the political and regulatory environments;

The absence of $63 million of income recognized in 2012 related to the 2010 sale of our interest in Accroven SRL. This is partially offset by $37 million of interest income recorded in 2013 associated with a receivable related to the sale of certain former Venezuela assets and a gain of $26 million resulting from Access Midstream Partners equity issuance in April 2013 (see Note 4 Asset Sales and Other Accruals of Notes to Consolidated Financial Statements). See additional discussion in Results of Operations. Williams Partners Geismar Incident On June13, 2013, an explosion and fire occurred at WPZs Geismar olefins plant located south of Baton Rouge, Louisiana, in an industrial complex, which resulted in the tragic deaths of two employees and injuries of additional employees and contractors. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects. We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:
29
Managements Discussion and Analysis (Continued)
Physical damages to facilities, including damage to offshore facilities by named windstorms;


Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductiblReduced availability of insurance coverage. We continue to address these risks through disciplined investment strategies, sufficient liquidity from cash and cash equivalents and available capacity under our revolving credit facilities.
In 2014, we anticipate an overall improvement in operating results compared to 2013 primarily due to an increase in our fee based, olefins, and Canadian midstream businesses, partially offset by lower NGL margins and higher operating expenses associated with the growth of our business.
The following factors, among others, could impact our businesses in 2014.
Williams Partners
Commodity price changes
NGL and olefin price changes have historically correlated somewhat with changes in the price of crude oil, although NGL, olefin, crude, and natural gas prices are highly volatile, and difficult to predict. Commodity margins are highly dependent upon regional supply/demand balanc
es) of $10 million per occurrence for property damage and a 60-day waiting period per occurrence for business interruption;natural gas as they relate to NGL margins, while olefins are impacted by continued demand within the global economy. NGL prices will benefit from exports to satisfy global demand. NGL products are currently the preferred feedstock for ethylene and propylene production, and are expected to remain advantaged over crude-based feedstocks into the foreseeable future. We continue to benefit from our strategic feedstock cost advantage in propylene production from Canadian oil sands offgas.
We anticipate the following trends in overall commodity prices in 2014 as compared to 2013:



General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;Natural gas prices are expected to be higher in part due to the additional demand to replace the gas volumes withdrawn during the colder than normal weather over the past winter season.


Workers compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence. We have been focused on conducting the causal investigations with the Occupational Safety and Health Administration and the Chemical Safety Board. We have expensed $4 million and $10 million during the three and nine months ended September 30, 2013, respectively, of costs under our insurance deductibles in operating and maintenance expenses in the Consolidated Statement of Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through September 30, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to other (income) expense - net within costs and expenses in our Consolidated Statement of Income. Following the repair and plant expansion, the Geismar plant is expected to be in operation by April 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate $343 million of total cash recoveries from insurers related to business interruption losses. Our current damage assessment and repair plan reaffirmed the previously estimated cost of $102 million to repair the plant. We will be impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different. Marcellus Shale In the second quarter of 2013, we completed an expansion to our natural gas gathering system, processing facilities, and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility, which added 200 MMcf/d of processing capacity. In the first half of 2014, we expect to add fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43thousand barrels per day (Mbbls/d), complete our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity, and finalize the construction of our first deethanizer with a capacity of 40 Mbbls/d and the associated 50-mile ethane line to Houston, Pennsylvania. Overland Pass Pipeline Through our equity investment in Overland Pass Pipeline Company LLC (OPPL), we completed the construction of a pipeline expansion in the second quarter of 2013, which increased the pipelines capacity to 255 Mbbls/d. In addition, a new connection was completed in April 2013 to bring new volumes to OPPL from the Bakken Shale in the Williston basin. Mid-South The Mid-South expansion project involves an expansion of Transcos mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011, we received approval from the FERC for the project. We placed the first phase of the project into service in the third quarter of 2012, which increased capacity by 95thousand dekatherms per day (Mdth/d). The second phase was placed into service in the second quarter of 2013, which increased capacity by an additional 130 Mdth/d.
30
Managements Discussion and Analysis (Continued)
Three Rivers Midstream In April 2013, we announced an agreement to launch a new midstream joint project to provide gas gathering and gas processing services for production located in northwest Pennsylvania. The project will invest in both wet-gas handling infrastructure and dry-gas infrastructure serving the Marcellus and Utica Shale wells in the area. We will initially own substantially all of the new project, Three Rivers Midstream, and operate the assets. Our partner has the right to invest capital and increase its ownership to a maximum of 50 percent by July 2015. The current estimate of the total cost of the project is expected to be approximately $150 million. This does not include the cost of the gathering system, which will be determined in the future based upon the producers needs. Subsequent capital investment is expected as the business and scale increases. Three Rivers Midstream has signed a long-term fee-based dedicated gathering and processing agreement for our partners production in the area, including approximately 275,000 dedicated acres. Three Rivers Midstream plans to construct a 200million cubic feet per day (MMcf/d) cryogenic gas processing plant and related facilities at a location to be determined. The initial plant is expected to be placed into service in mid-2015. The system is expected to be connected to two major proposed developments in Pennsylvania our partners proposed ethylene cracker (feasibility study is in progress) in Beaver County and our joint project to develop the Bluegrass Pipeline system that would deliver Marcellus and Utica liquids to the Gulf Coast and export markets. Gulfstar Effective April1, 2013, WPZ sold a 49 percent interest in Gulfstar One LLC (Gulfstar) to a third party for $187 million, representing t
Ethane prices are expected to be somewhat higheir proportionate share of estimated capital expenditures to date for the construction of Gulfstar FPS , which is a proprietary floating production system and has been under construction since late 2011. It is supported by multiple agreements with two major producers to provide production handling, export pipeline, oil and gas gathering and gas processing services for the Tubular Bells field development located in the eastern deepwater Gulf of Mexico. The Gulfstar FPS will tie into our wholly owned oil and gas gathering and gas processing systems in the eastern Gulf of Mexico. Gulfstar FPS is expected to have an initial capacity of 60 Mbbls/d, up to 200 MMcf/d of natural gas and the capability to provide seawater injection services. We expect Gulfstar FPS to be capable of serving as a central host facility for other deepwater prospects in the area. The project is expected to be in service in mid-2014. Mid-Atlantic Connector The Mid-Atlantic Connector Project involves an expansion of Transcos mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In July 2011, we received approval from the FERC for the project. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d. Volume impacts in 2013 Due to unfavorable ethane economics, we reduced our recoveries of ethane in our plants during most of the first nine months of 2013, which resulted in 29 percent lower NGL production volumes and 46 percent lower NGL equity sales volumes in the first nine months of 2013 compared to the same period of 2012. As a result of the Geismar Incident, ethylene sales volumes have decreased 96 percent and 41 percent for the three and nine months ended 2013, respectively, compared to the same period of 2012. Volatile commodity prices NGL margins were approximately 42 percent lower in the first nine months of 2013 compared to the same period of 2012 driven by reduced ethane recoveries, as previously mentioned, coupled with lower NGL prices and higher natural gas prices. However, our average per-unit composite NGL margin in the first nine months of 2013 has increased slightly compared to the same period of 2012 as the relative mix of NGL products produced has shifted to a greater proportion of higher-margin non-ethane products.
31
Managements Discussion and Analysis (Continued)
NGL margins are defined as NGL revenues less any applicable British thermal unit (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
due to a modest increase in demand as well as slightly higher natural gas prices.

Propane prices are expected to be higher from an increase in exports and higher natural gas prices.

Williams NGL& Petchem Services Canadian PDH Facility During the first quarter of 2013, we announced plans to build Canadas first propane dehydrogenation (PDH) facility located in Alberta. The new PDH facility will produce approximately 1.1 billion pounds annually, significantly increasing Williams production of polymer-grade propylene currently at 180million pounds. The expected start-up date for the PDH facility is the second quarter of 2017. Bluegrass Pipeline and Moss Lake In the second quarter of 2013, we finalized the formation of a joint project to develop the Bluegrass Pipeline. We own a 50 percent consolidated interest in Bluegrass Pipeline, which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast. The pipeline would deliver mixed NGLs from these producing areas to proposed new fractionation and storage facilities, which would have connectivity to petrochemical facilities and product pipelines along the coasts of Louisiana and Texas. We are working to develop customer support for the pipeline, including the recently announced open season for capacity on Bluegrass Pipeline. The first phase of the project is expected to have a mixed NGLs take-away capacity of 200 Mbbls/d and is planned to be in service in late 2015. The second phase of the project is expected to increase capacity to 400 Mbbls/d.
32
Managements Discussion and Analysis (Continued)
Through our 50 percent equity investment in Moss Lake Fractionation LLC, the project would also include constructing a new large-scale fractionation plant and expanding NGL storage facilities in Louisiana. In October 2013, we announced a related joint project, Moss Lake LPG Terminal, which explores the development of a new liquefied petroleum gas export terminal and related facilities on the Gulf Coast to provide customers access to international markets. Company Outlook Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our shareholders. Fee-based businesses are a significant component of our portfolio. As we continue to transition to an overall business mix that is increasingly fee-based, the influence of commodity price fluctuations on our operating results and cash flows is expected to become somewhat less significant. As previously noted, we expect the financial impact of the Geismar Incident will be significantly mitigated by our insurance policies. However, the timing of recognizing recoveries under our business interruption policy, as well as the effect of the 60-day waiting period, will likely cause a significant negative impact to our 2013 results. In light of all of the above, our business plan for 2013 continues to reflect both significant capital investment and dividend growth. Our planned consolidated capital investments for 2013 total approximately $4.4 billion which we expect to fund primarily through cash on hand, cash flow from operations, and debt and equity issuances by WPZ. We also expect 20 percent growth in total 2013 dividends, which we expect to fund primarily with distributions received from WPZ. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. Potential risks and obstacles that could impact the execution of our plan include:

Propylene prices are expected to be comparable to 2013 prices.

General economic, financial markets, or industry downturn;

Ethylene prices are expected to be slightly lower as compared to 2013 prices. The overall ethylene crack spread is also expected to be slightly lower due to the anticipated lower sales price and a projected higher ethane price.
Gathering, processing, and NGL sales volumes The growth of natural gas production supporting our gathering and processing volumes is impacted by producer drilling activities, which are influenced by commodity prices including natural gas, ethane and propane prices. In addition, the natural decline in production rates in producing areas impact the amount of gas available for gathering and processing. Due in part to the higher natural gas prices in the early part of 2014, we anticipate that overall drilling economics will improve slightly, which will benefit us in the long-term.

Availability of capital;

In Williams Partners northeast region, we anticipate significant growth compared to the prior year in our natural gas gathering and processing volumes as our infrastructure grows to support drilling activities in the region.
33
Managements Discussion and Analysis (Continued)

Lower than expected levels of cash flow from operations;

In Williams Partners Transco and Northwest Pipeline businesses, we anticipate higher natural gas transportation revenues compared to 2013, as a result of expansion projects placed into service in 2013 and anticipated to be placed in service in 2014.

Counterparty credit and performance risk;

In Williams Partners Gulf Coast region, we expect higher production handling volumes compared to 2013, following the scheduled completion of Gulfstar FPS in third quarter 2014.

Decreased volumes from third parties served by our midstream business;

In Williams Partners western region, we anticipate an unfavorable impact in equity NGL volumes in 2014 compared to 2013, primarily due to a customer contract that expired in September 2013.

Unexpected significant increases in capital expenditures or delays in capital project execution;

In 2014, Williams Partners domestic businesses anticipate a continuation of periods when it will not be economical to recover ethane.

Lower than anticipated energy commodity prices and margins;

In Williams Partners Canadian midstream business, we anticipate new ethane volumes in 2014 associated with the fourth quarter 2013 completion of the Canadian ethane recovery project, which is expected to benefit from a contractual minimum ethane sales price.
Olefin production volumes

Changes in the political and regulatory environments;

Williams Partners Gulf olefins business anticipates higher ethylene volumes in 2014 compared to 2013 substantially due to the repair and expansion of the Geismar plant expected to begin start-up in the latter-half of June 2014.

Physical damages to facilities, especially damage to offshore facilities by named windstorms. We continue to address these risks through disciplined investment strategies, commodity hedging strategies, and maintaining at least $1billion in consolidated liquidity from cash and cash equivalents and available capacity under our revolving credit facilities. The following factors, among others, could impact our businesses in 2013.
33
Managements Discussion and Analysis (Continued)
Williams Partners Commodity price changes We expect ethane prices to remain at current levels, which will result in continued ethane rejection across most of our systems. We further expect that the combination of lower NGL prices and higher natural gas prices will result in overall total NGL margins being lower than the previous year. NGL price changes have historically correlated somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, and difficult to predict. NGL margins are highly dependent upon regional supply/demand balances of natural gas. NGL prices will benefit from exports to satisfy global demand. NGL products are currently the preferred feedstock for ethylene and propylene production, and are expected to remain advantaged over crude-based feedstocks into the foreseeable future. Gathering, processing, and NGL sales volumes

Williams Partners Canadian olefins business expects higher propylene volumes in 2014 than 2013. Volumes in 2013 were negatively impacted by both a planned maintenance turnaround and downtime associated with the tie-in of the Canadian ethane recovery project.
Other

The growth of natural gas production supporting our gathering and processing volumes is impacted by producer drilling activities, which are influenced by commodity prices including natural gas, ethane and propane prices. In addition, the natural decline rates in producing areas impact the amount of gas available for gathering and processing.

Williams Partners Gulf olefins business received insurance recoveries of $50 million and $125 million in 2013 and the first quarter of 2014, respectively, related to the Geismar Incident and expects to receive additional insurance recoveries related to the Geismar Incident that will favorably impact our operating results in 2014.

In Williams Partners onshore businesses, we anticipate significant growth compared to the prior year in our natural gas gathering volumes as our infrastructure grows to support drilling activities in the Marcellus Shale region. Based on less favorable producer economics in the western region, we expect a decrease in production and thus a lower supply of natural gas available to gather and process in 2013.

Williams Partners expects higher operating expenses in 2014 compared to 2013, including depreciation expense related to its growing operations in its northeast region and expansion projects in its gas pipeline and Gulf olefins businesses.

We anticipate equity NGL volumes in 2013 to be lower than 2012 primarily due to periods when we expect it will not be economical to recover ethane. In addition, our equity NGL volumes were also impacted by a change in a customers contract from percent-of-liquids to fee-based processing, with a portion of the fee representing a share of the associated NGL margins.


In
Williams Partners businesses in the Gulf Coast, we expect lower production handling and crude transportation volumes compared to 2012, as production flowing through our Devils Tower facility declines.


We anticipate higher general and administrative, operating, and depreciation expense related to our growing operations in the Marcellus Shale area. Eminence Storage Field leak On December28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers. In September
expects higher equity earnings compared to 2013 following the scheduled completion of Discoverys Keathley Canyon Connector lateral in the fourth quarter of 2014.
Access Midstream Partners
In the third-quarter of 2013, Access Midstream Partners increased its cash distribution by five cents per unit. Following the step-up in distributions in
20113, we filed an application with the FERC seeking authorizaannual distributions to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the total abandonment costs, which will be capital in nature, will beunitholders are expected to grow by approximately 15 percent in 2014 and 2015. We forecast that we will receive cash distributions of approximately $1403 million, which is expected to be spent through the first half of 2014. As of September 30, 2013, we have incurred approximately $92 million of these abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent co from our investment in Access Midstream Partners for 2014.
Considering the expected distribution growth from Access Midstream Partners, including the benefit we receive from our 50 percent indirect intere
sts incurred in the abandonment of these caverns. Consistent with the terms of the pending rate case, for the three and nine months ended September 30, 2013, we expensed $9 million and $15 million, respectively, related to the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income for the three and nine months ended September 30, 2013, of $3 million and $15 million, respectively, related to insurance recoveries associated with this event Access GP and its incentive distribution rights, we expect to recognize growing equity earnings from our investment. Our earnings recognized, however, will be reduced by the noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners.
3
Managements Discussion and Analysis (Continued)
Filing of rate cases On August31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, Transco filed with the FERC a stipulation and agreement that would resolve all issues in this proceeding without the need for a hearing. The stipulation and agreement is subject to review and approval by the FERC. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required. During the first quarter of 2012, Northwest Pipeline LLC (Northwest Pipeline) filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than the formerly applicable rates, became effective January1, 2013. Williams NGL& Petchem Services Commodity margin and volume changes While per-unit margins are volatile and highly dependent upon continued demand within the global economy, we believe that our gross commodity margins will be comparable to 2012 levels. Volumes for the year are expected to be somewhat higher than 2012 levels. Canadian oil sands offgas continues to hold a distinct feedstock advantage over traditional crackers. We expect to benefit in the broader global petrochemical markets because of our strategic advantage in NGL and olefins production from oil sands. Access Midstream Partners Access Midstream Partners expects its annual distributions to unitholders will grow by approximately 15 percent in 2013 and 2014. We forecast that we will receive distributions of $92 million from our investment in Access Midstream Partners for 2013. Considering the expected distribution growth from Access Midstream Partners, including the benefit we receive from our 50 percent indirect interest in Access GP and its incentive distribution rights, we expect to recognize growing equity earnings from our investment. Our earnings recognized, however, will be reduced by the noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners. Expansion Projects We expect to invest total capital in 20134 mn u uiessget sflos



Low
High

(Millions)

Segment:

Williams Partners
$
3,135000
$
3,
465500

Williams NGL & Petchem Services
62400
73500 Our ongoing major expansion projects include the following:
Williams Partners Atlantic Sunrise The Atlantic Sunrise Expansion Project involves an expansion of Transcos existing natural gas transmission system along with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along Transcos mainline as far south as Station 85 in Alabama. We plan to file an application with the FERC in the second quarter of 2015 for approval of the project. We plan to place the project into service during the second half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.
Leidy Southeast In September 2013, we filed an application with the FERC for Transcos Leidy Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transcos Leidy Line in Pennsylvania to delivery points along its mainline as far south as Station 85 in Alabama. We plan to place the project into service during the fourth quarter of 2015, assuming timely receipt of all necessary regulatory approvals, and expect it to increase capacity by 525Mdth/d.
Mobile Bay South III In April 2014, we received approval from the FERC to construct and operate an expansion of Transcos Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line.We plan to place the project into service during the second quarter of 2015 and it is expected to increase capacity on the line by 225 Mdth/d.
Constitution Pipeline In June 2013, we filed an application with the FERC for authorization to construct and operate the jointly owned Constitution pipeline. We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 124-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We plan to place the project into service in late 2015 to 2016, assuming timely receipt of all necessary regulatory approvals, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers.
Northeast Connector In April 2013, we filed an application with the FERC to expand Transcos existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We plan to place the project into service during the fourth quarter of 2014, assuming timely receipt of all necessary regulatory approvals, and expect it to increase capacity by 100 Mdth/d.
35
Managements Discussion and Analysis (Continued)
Williams Partners Leidy Southeast In September 2013, we filed an application with the FERC for Transcos Leidy Line Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transcos Leidy Line in Pennsylvania to delivery points along its main system from Station 85 in Alabama. We plan to place the project into service in December 2015, and expect to increase capacity by an additional 525 Mdth/d. Mobile Bay South III In July 2013, we filed an application with the FERC for an expansion of Transcos Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line.We plan to place the project into service in April 2015 and it is expected to increase capacity on the line by 225 Mdth/d. Constitution Pipeline In June 2013, we filed an application with the FERC for authorization to construct and operate the new jointly-owned Constitution Pipeline. As of May 2013, we currently own 41 percent of Constitution Pipeline with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas PipelineRockaway Delivery Lateral In January 2013, we filed an application with the FERC for Transco to construct a three-mile offshore lateral to a distribution systems in New York. We plan to place the project into service in March 2015, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers. Northeast Connector In Aprilduring the fourth quarter of 20134, we filed an application with the FERC to expand Transcos existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We plan to place the project into service during the second half of 2014, and expect to increase capacity by 100 Mdth/d. Rockaway Delivery Lateral In January 2013, we filed an application with the FERC for Transco to construct a three-mile offshore lateral to a distribution system in New York. We plan to place the project into service during the second half of 2014, with an expected capacity ofassuming timely receipt of all necessary regulatory approvals, and the capacity of the lateral is expected to be 647 Mdth/d.
Virginia Southside In DecNovember 20123, we filed an application withreceived approval from the FERC to expand Transcos existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. We plan to place the project into service in September 2015, and expect to increase capacity by 270 Mdth/d. Northeast Supply Link In November 2012, we received approval from the FERC to expand Transcos existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. We plan to place the project into service in Novemberduring the third quarter of 20135, and expect it to increase capacity by an additional 250 Mdth/d.
36
Managements Discussion and Analysis (Continued)
270Mdth/d.
Marcellus Shale Expansions


Expansion of our gathering infrastructure including compression and gathering pipelines in the Susquehanna Supply Hub in northeastern Pennsylvania as production in the Marcellus increases. The Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 billion cubic feet per day (Bcf/d) by 2015, including capacity contributions from the Constitution Pipeline.

As previously discussed, we completed construction at our Fort BeeIn the first quarter of 2014, we completed a 30 Mbbls/d expansion of the Moundsviller fracilitytionator in the Marcellus Shale, which added 200 MMcf/d of processing capacity in the second quarter of 2013. W. In addition, we have several significant projects under construction with targeted construction completion in the first half of 2014. We are completing a 43 Mbbls/d expansion of the Moundsville fractionator,n installation of 40 Mbbls/d of deethanization capacity, a 50-mile ethane pipeline, condensate stabilization, and the first 200 MMcf/d of processing at Oak Grove. These projects are expected to provide the base facilities required to meet current contractual obligations.

Expansions to the Laurel Mountain
Midstream, LLC (Laurel Mountain) gathering system infrastructure to increase the capacity to 700 667MMcf/d by the end of 2015 through capital to be invested withincontributions to hseut netet


Construction of the Blue Racer Midstream joint project, an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and Northwest Pennsylvania through capital to be invested within our Caiman Energy II equity investment. Gulfstar FPS Deepwater Project We willExpansion plans included the addition of Natrium II, a second 200 MMcf/d processing plant at Natrium, which was completed in April 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I is expected to come online in the fourth quarter of 2014.
Gulfstar One We
designed, constructed, and are installing our Gulfstar FPS, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services, as previously discussed.Construc.Installation is under way and the project is expected to be in service in mid-2014. Parachute Due to a reduction in drilling in the Piceance basin during 2012 and early 2013, we delayed the in-service date of our 350 MMcf/d cryogenic natural gas processing plant in Parachute that was planned for service in 2014.We are currently plannthe third quarter 2014. In December 2013, Gulfstar One agreed to host the Gunflint development, which will result ing an in-service date in mid-2016.We will continue to monitor the situation to determine whether an earlier in-service date is warranted. Geismar As a result of the Geismar Incident, the expansion of our Geismar olefexpansion of the Gulfstar One system to provide production handling capacity of 20 Mbbls/d and 40 MMcf/d for Gunflint. The Gunflinst production facilityject is expected to be completed whein the Geismar plant returns to operation, which is expected to occur in April2014. The expansion is expected to increase the facilitys ethylene production capacity by 600million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our share of the Geismar production facility from the current 83.3 percent. Keathley Canyon Connector Our equity investee which we operate, Discovery Producer Services LLC (Discovery), plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discoverys existing 30-inch offshorfirst quarter of 2016, dependent on the producers development activities.
Parachute Due to a reduction in drilling in the Piceance basin during 2012 and early 2013, we delayed the in-service date of our 350 MMcf/d cryogenic natural gas processing plant in Parachute that was planned for service in 2014.We are currently planning an in-servic
e ndatural gas transmission system. The gas will be processed at Discoverys Larose Plant and the NGLs will be fractionated at Discoverys Paradis Fractionator. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. The pipeline is expected to bee in mid-2016.We will continue to monitor the situation to determine whether a different in -service in the fourth quarter of 2014.
37
date is warranted.
36

Managements Discussion and Analysis (Continued)
Williams NGL& Petchem Services Canadian PDH FGeismar As a result of the Geismar Incident, the expansion of our Geismar olefins production facility Ais previously discussexpected to be completed, we hen the Geismare planning to build a propane dehydrogenation (PDH) facility in Alberta that will significantly increase production of polymer-grade propylene. Start-up for the PDH facility is expected to occur in the second quarter of 2017. Ethane Recovery Project The ethane recovery project, which is an expansion of our Canadian facilities, will allow us to recover ethane/et returns to operation. We expect the plant to begin start-up in the latter-half of June2014. The expansion is expected to increase the facilitys ethylene production capacity by 600million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our ownership of the Geismar production facility from the current 83.3 percent.
Keathley Canyon Connector Discovery is constructing a 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico that it will own and operate. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector lateral will originate from a third-party floating production facility in the southeast portion of the Kea
thylene mix from our operations that process offgas from the Alberta oil sands. We plan to modify our oil sands offgas extraction plant near Fort McMurray, Alberta, and construct a deethanizer at our Redwater fractionation facility. Our deethanizer is expected to initially process approximately 10 Mbbls/d of ethane/ethylene mix. We have signed a long-term contract to provide the ethane/ethylene mix to a third-party customer. Wey Canyon area and will connect to Discoverys existing 30-inch offshore natural gas transmission system. The gas will be processed at Discoverys Larose Plant and the NGLs will be fractionated at Discoverys Paradis Fractionator. The lateral pipeline is estimated to have the capacity to flow more than 400MMcf/d and will accommodate the tie-in of other deepwater prospects. The pipeline is expected to be in service in the fourth quarter of 2014.
Redwater Expansion
As part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canadas oil sands near Fort McMurray, Alberta, we plan to increase the capacity of the Redwater facilities where NGL/olefins mixtures will be fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. This project is expected to be placed into service during the third quarter of 2015.
Williams NGL& Petchem Services Canadian PDH Facility We are planning to build a PDH facility in Alberta that will significantly increase production of polymer-grade propylene. Start-up for the PDH facility is expected to occur in the second quarter of 2017. The new PDH facility is
expected to complete the expansions and begin producing ethane/ethylene mix during the fourth quarter of 2013.produce approximately 1.1 billion pounds annually, significantly increasing Williams production of polymer-grade propylene currently at 180 million pounds annually.
NGL Infrastructure Expansion We executedAs part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canadas oil sands near Fort McMurray, Alberta. To support the new agreement, we plan to build a new liquids extraction plant, and an extension of the Boreal Pipeline, and increase the capacity of the Redwater facilities. The extension of the Boreal Pipeline will enable transportation of the NGL/olefins mixture from the new extraction plant to our expanded Redwater facility. The NGL/olefins recovered are initially expected to be approximately 12 Mbbls/d by mid-2015. The NGL/olefins mixture will be fractionated at our Redwater facilities into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. To mitigate the ethane price risk associated with this dealo mitigate the associated ethane price risk, we have a long-term supply agreement with a third-party customer.
Gulf Coast Expansion In November 2012, we acquired 10 liquids pipelines in the Gulf Coast region.The acquired pipelines will be combined with an organic build-out of several projects to expand our petrochemical services in that region.The projects include the construction and commissioning of pipeline systems capable of transporting various products in the Gulf Coast region. The projects are expected to be placed into service beginning in late 2014 through early 2015. Bluegrass Pipeline As previously discussed, in the second quarter we finalized the formation of a joint project to develop the Bluegrass Pipeline. Pre-construction activities are under way and the first phase of the project is planned to be in service in late 2015.
38
2015.
37

Managements Discussion and Analysis (Continued)
Results of Operations Consolidated Overview The following table and discussion is a summary of our consolidated results of operations for the three
and nine months ended September30March31, 20134, compared to the three and nine months ended September30March31, 20123.Terslso prtosb emn r icse nfrhrdti olwn hscnoiae vriwdsuso.


Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
$Change*
%Change*
2013
2012
$Change*
%Change*

(Millions)
(Millions)

Revenues:

Service revenues
$
736819
$
675
+61
+9%
$
2,163
$
2,019
+144
+7
706
+113
+16
%
Product sales
887930
1,
077
-190
-18%
3,037
3,598
-561
104
-174

-16%

Total revenues
1,
623749
1,
752
-129
-7%
5,200
5,617
-417
-7%
810

Costs and expenses:

Product costs
7
1069
7
7190
+
61
+8%
2,301
2,628
+327
+12
21
+3
%
Operating and maintenance expenses
2
698
26
10
-
8
-3%
820
766
-54
-7
38
-15
%
Depreciation and amortization expenses
2
07
196
14
201

-1
13
-6%
606
545
-61
-11%

Selling, general, and administrative expenses
1
350
13
72
+7
+5%
385
415
+30
+7
-18
-14
%
Other (income) expense neNet insurance recoveries Geismar Incident
(
2119 )
14
+43
+119
NM
(24
)

Other (income) expense net
17

31
+55-16
NM

Total costs and expenses
1,
287329
1,3
79
4,088
4,385
84

Operating income (loss)
336
373
1,112
1,232
420
426


Equity earnings (losses)
37
30
+7
+23%
93
88
+5
+6%
(48
)
18
-66
NM


Interest expense
(1
240
)
(1298
)
+5
+4%
(379
)
(388
)
+9
+2
-12
-9
%
Other investing income net
1
04
13
+
7
NM
62
75
-13
-17
1
+8
%
Other income (expense) net
1
+1
NM
1
(1
(2
)
+23
NM

Income (loss) from continuing operations before income taxes
26047
3277
889
1,006


Provision (benefit) for income taxes
62
77
+15
+19%
260
281
+21
51
96
+45

+
47

Income (loss) from continuing operations
19
8
200
629
725
6
231


Income (loss) from discontinued operations
(
)
3
-4
+1
NM
(10
)
138
-148
NM

Net income (loss)
19
76
2
03
619
86
30

Less: Net income attributable to noncontrolling interests
56
48
-8
-17%
175
153
-22
-14
69
+13
+19
%
Net income (loss) attributable to The Williams Companies, Inc.
$
1410
$
1
55
$
444
$
710
61






*
+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. Three months ended
September30March31, 20134 vs. three months ended September30, 2012
The increase in service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in the 2012 acquisitions of Caiman Eastern Midstream, LLC (Caiman Acquisition) and certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). This growth includes
March31, 2013 Service revenues in our Williams Partners segment increased due primarily to an increase in natural gas transportation fee revenues related to projects placed in service in 2013 and new rates effective in March 2013 for Transco, as well as higher fees associated with higher gathering volumes fromdriven by new well connections resulting from infrastructure additions, increased gathering rates associated with customer contract modifications, and contributions from the processing and fractionation facilities placed in service in the latter half ofand increased gathering rates in our businesses in the Northeast area. Service revenues at Other also increased related to new Canadian construction management services performed for third parties.
3
98
Managements Discussion and Analysis (Continued)
2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are lower fee revenues in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes, as well as decreased gathering and processing fee revenues driven by lower volumes in the Piceance and Four Corners areas. The decrease in product sales is primarily due to lower olefin production revenues resulting from the loss of production as a result of the Geismar Incident. In addiProduct sales decreased primarily due to lower olefin sales related to the lack of production as a result of the Geismar Incident and a decrease in volumes at our RGP splitter primarily due to an outage in a third-party storage facility which caused us to reduce production,. NGL production revenues also decreased due to lower volumes primarily driven by reduced ethane recovereflecting lower non-ethane sales volumes partially offset by higher non-ethane per-unit sales prices and a change in a certain customer contract from percent-of-liquids to fee-based processing, as well as decreases in average ethane per-unit sales prices. Marketing revenues also decreased primarily due to lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices. The decrease in phigher ethane sales volumes in Canada. Marketing sales revenues increased primarily due to higher NGL per-unit sales prices and higher ethane volumes, partially offset by lower volumes of non-ethane NGLs and other products. The changes in marketing revenues are substantially offset by similar changes in marketing purchases, reflected above as Product costs . Product costs isdecreased primarily due to decreasedlower olefin feedstock purchases as a result of the Geismar Incident. In addition, marketing purchases decreased resulting from lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices. The increase in operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions including increased pipeline maintenance and repair costs, as well as a scheduled third-quarter shutdown to conduct maintenance at Williams NGL & Petchem Services. These increases are partially offset by a decrease in compressor and pipeline maintenance expenses resulting from the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012 and lower operating costs in our Four Corners area rerelated to the lack of production as a result of the Geismar Incident and a decrease in volumes at our RGP splitter, as previously discussed, partially offset by an increase in marketing purchases. The changes in marketing purchases are more than offset by similar changes in marketing revenues. Operating and maintenance expenses increased related to costs incurred associated with new Canadian construction management services performed for third parties. Depreciation and amortization expenses increased primarily due to depreciation on infrastructure additions in the Northeast area and the Canadian ethane recovery project platced into the consolidation of certain operations. The increase in depreciation and amortizservice in fourth quarter 2013. Selling, general, and administrationve expenses reflects increased depreciation expense in 2013 associated with the businesses acquired in 2012 and depreciationprimarily due to $19 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent onf subsequent infrastructure additions, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives. Thch costs. The 50 percent noncontrolling interest share of these costs are presented in Net income attributable to noncontrolling interests . The favorable change in Net insurance recoveries Geismar Incident is due to receipt of $125 million of insurance drecrease in selling, general, and administrative expenses (SG&A) includes the absence of reorganization related costs inoveries partially offset by $6 million of related covered insurable expenses in excess of our retentions (deductibles) incurred in the first quarter of 20124. (sSee Note 4 Asset Sales and Other Accrual3 Other Income and Expenses of Notes to Consolidated Financial Statements).) The unfavorable changes in oOther (income) expense net within oOperating income (loss)is primarily include $50 million of income associated with insurance recoveries related to the Geismar Incident and $3 million of insurance recoveries related to the abandonment of certain Eminence storage assets. Partially offsetting these changes is a $9 million expense recognized in third-quarter 2013 related to the portion of certain of the Eminence abandonment regulatory asset that will not bdue to the absence of a $6 million favorable contingency settlement recognized in first-quarter 2013 and costs incurred in first quarter 2014 associated with fire damage at a compressor station in the Susquehanna Supply Hub. Operating income rdecovered in rates andreased primarily due to a $9122 million accrued loss for a contingent liability associated with a pending producer claim against us. The unfavorable change in operating income (loss) generally reflects lower olefin production margins, lower NGL production margins and a decrease in marketing margins, partially offset by increased fee revenues and the favorable changes in other (income) expense net as described above. The favorable change in equity earnings (losses) is primarily due to higher equity earnings at Access Midstream Partners due to the absence of this investment in 2012 and higher equity earnings from Laurel Mountain and Aux Sable Liquidecrease in olefin margins, including $111 million lower product margins at our Geismar plant, and decreases in NGL margins driven primarily by lower NGL volumes, as well as higher depreciation and amortization expense in 2014. These decreases were substantially offset by $125 million of income associated with insurance recoveries related to the Geismar Incident and a $61 million increase in service revenues at Williams Partners. Equity earnings (losses) changed unfavorably primarily due to $77 million of equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized Pproducts LP (Aux Sable) driven by their higher operating results . These higher earnings are partially offset by lower equity earnings from Discovery driven by lower NGL margins resulting from decreased ethane recoveriject development costs, (see Note 2 Variable Interest Entities of Notes to Consolidated Financial Statements.) Higher equity earnings from Access Midstream Partners partially offset these losses. Interest expense deincreased due to a $17 million increase in iInterest capitalized related to construction projects primarily at Williams Pincurred primarily due to new debt issuances in the fourth quarter of 2013 and first quartners, partially offset by an increase in interest incurred primarily due to an increase in borrowings. The favorable change in other investing income net is primarily due to $8 million higher interest income record of 2014 (see Note 8 Debt and Banking Arrangements of Notes to Consolidated Financial Statements). Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 4 Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared into the third quarter of 2013 associated with a receivable related to the sale of certain former Venezuela assets (See Note 4 Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.)
40
federal statutory rate for both periods. The favorable change in Net income attributable to noncontrolling interests primarily reflects our partners 50 percent share of project development costs expensed by Bluegrass Pipeline during the portion of the first quarter of 2014 that we consolidated Bluegrass Pipeline.
39

Managements Discussion and Analysis (Continued)
Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income in 2013. See Note5 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
See Note 3 Discontinued Operations of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations. The unfavorable change in net income attributable to noncontrolling interests primarily reflects the noncontrolling interests share of WPZ income from Geismar in 2013, following the dropdown in November 2012, as well as our slightly decreased percentage of limited partner ownership of WPZ, partially offset by higher income allocated to the general partner associated with incentive distribution rights. Nine months ended September30, 2013 vs. nine months ended September30, 2012
The increase in service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in 2012, including higher volumes from new well connections resulting from infrastructure additions, a full nine month of operations from these businesses, increased gathering rates associated with customer contract modifications, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are decreased gathering and processing fee revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin, and severe winter weather conditions in the first quarter of 2013 which prevented producers from delivering gas. In addition, fee revenues decreased in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes. The decrease in product sales is primarily due to a decrease in NGL production revenues due to lower volumes primarily driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices. Marketing revenues also decreased resulting from lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices. Also impacting the decrease are lower crude oil volumes related to natural declines in Bass Lite and Blind Faith production area and lower olefin production revenues primarily due to lower volumes from the loss of production as a result of the Geismar Incident, partially offset by higher per-unit sales prices. The decrease in product costs is primarily due to lower marketing purchases resulting from lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices. In addition, olefin feedstock purchases decreased reflecting lower sales volumes and lower average per-unit feedstock costs. Costs associated with the production of NGLs also decreased primarily resulting from lower volumes, driven by lower ethane recoveries, partially offset by an increase in average natural gas prices. The increase in operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions including higher pipeline maintenance and repair costs, a scheduled third-quarter 2013 shutdown to conduct maintenance at Williams NGL & Petchem Services and $10 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by lower compressor and pipeline maintenance and repair expenses resulting from the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012 and lower operating costs in our Four Corners area related to the consolidation of certain operations. The increase in depreciation and amortization expenses reflects a full nine months of depreciation expense in 2013 related to the Caiman and Laser Acquisitions and depreciation on subsequent infrastructure additions, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives. The decrease in SG&A is primarily due to the absence of acquisition and transition costs incurred in 2012 and the absence of reorganization related costs in 2012 (see Note 4 Asset Sales and Other Accruals of Notes to Consolidated Financial Statements).
41
Managements Discussion and Analysis (Continued)
The favorable change in other (income) expense net within operating income primarily includes $50 million of income associated with insurance recoveries related to the Geismar Incident, $15 million of insurance recoveries related to the abandonment of certain Eminence storage assets, and $17 million lower project development costs. Partially offsetting these changes is a $15 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates, a $9 million accrued loss for a contingent liability associated with a pending producer claim against us recognized in the third quarter of 2013, and the absence of a $6 million gain on the sale of equipment in the second quarter of 2012. The unfavorable change in operating income (loss) generally reflects lower NGL production margins, higher operating costs, and lower olefin production margins, partially offset by increased fee revenues, and the favorable changes in other (income) expense net as described above. The favorable changes in equity earnings (losses) are primarily due to higher equity earnings from Laurel Mountain driven by higher operating results and higher equity earnings from Access Midstream Partners due to the absence of this investment in 2012, partially offset by lower equity earnings from Discovery due to lower NGL margins driven by decreased ethane recoveries and lower equity earnings at Aux Sable driven by lower NGL margins. Interest expense decreased due to an increase in interest capitalized related to construction projects primarily at Williams Partners, partially offset by an increase in interest incurred primarily due to an increase in borrowings. The unfavorable change in other investing income net is primarily due to the absence of $63 million of income recognized in 2012, including $10 million of interest income, related to the 2010 sale of our interest in Accroven SRL. This is partially offset by $32 million of higher interest income recorded in 2013 associated with a receivable related to the sale of certain former Venezuela assets, as compared to 2012, and a gain of $26 million resulting from Access Midstream Partners equity issuance in April 2013. (See Note 4 Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.) Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income in 2013. See Note 5 Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Income (loss) from discontinued operations in 2013 primarily includes a $15 million charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. Income (loss) from discontinued operations in 2012 primarily includes a $144 million gain on reconsolidation following the sale of certain of our former Venezuela operations. (See Note 3 Discontinued Operations of Notes to Consolidated Financial Statements.) The unfavorable change in net income attributable to noncontrolling interests primarily reflects the noncontrolling interests share of WPZ income from Geismar in 2013, following the dropdown in November 2012, and our slightly decreased percentage of limited partner ownership of WPZ, partially offset by higher income allocated to the general partner associated with incentive distribution rights. It also reflects our partners share of increased interest income related to a receivable from the sale of certain former Venezuela assets. (See Note 4 Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.)
42
Managements Discussion and Analysis (Continued)
Period-Over-Period Operating Results - Segments Williams Partners



Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Segment revenues
$
1,
586693
$
1,
717
$
5,069
$
5,502
806

Segment
profit
405
429
1,264
1,371
Three month
costs eanded September30, 2013 vs. three months ended September30, 2012 The decrease in segment revenues includes: expenses
(1,213
)
(1,330
)


Equity earnings (losses)
23
18

A $114 million decrease in olefin sales primarily due to the loss of production as a result of the Geismar Incident.Segment profit
$
503
$
494
Three months ended March31, 2014 vs. three months ended March31, 2013 The decrease in segment revenues includes:



A $
56190 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $43 million due to lower volumes and a $13 million decrease associated with 5 percent lower average realized non-ethane per-unit sales prices and 32 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 68 percent lower primarily driven by reduced ethane recoveries, as previously mentioned. The decrease in both ethane and non-ethane volumes is also olefin sales primarily associated with a $161 million decrease in volumes due to the lack of production in 2014 as a result of the Geismar Incident and a $25 million decrease in volumes at our RGP splitter primarily due to an outage in a third-party storage facility which caused us to reduce to a change in a certain customers contract from percent-of-liquids to fee-based processingproduction (substantially offset in Product costs ).

A $329 million decrease in marketing revenues primarily associated with lowerrevenues from our equity NGLs prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices. The changes in marketing revenues are substantially offset by similar changes in marketing purchasesmarily reflecting a decrease of $56 million due to lower volumes, partially offset by a $27 million increase associated with 16 percent higher average non-ethane per-unit sales prices. Equity non-ethane sales volumes are 31 percent lower primarily due to a customer contract that expired in September 2013 and higher inventory levels, partially offset by 44 percent higher equity ethane sales volumes primarily driven by new volumes from the Canadian ethane recovery project placed into service in the fourth quarter of 2013.

A $6
31 million increase in feservice revenues primarily due to $4631 million higher fee revenuesnatural gas transportation revenues from expansion projects placed into service in 2013, as well as new rates effective in March 2013 for Transco. In addition, fee revenues increased $27 million resulting from higher gathering volumes driven by new well connections related to infrastructure additions and increased gathering rates associated with customer contract modifications in the Northeast region primarily in the Susquehanna Supply Hub and higher gathering volumes and contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in the Ohio Valley Midstream business. Natural gas transportation revenues also increased $26 million from expansion project. Fee revenues also increased $9 million due to contributions from our Ohio Valley Midstream business resulting from the processing and fractionation facilities placed into service in 2012 and 2013, as well as new rates effective in first-quarter 2013. Partially offsetting these increases is a $7 million decrease in gathering and processing revenues resulting from lower production in the Piceance basin and Four Corners areas. In addi3. These increases are partially offset by $10 million lower production handling, lower gathering, and lower crude oil transportation, fee revenues decreased $8 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumin the Gulf Coast region due to a decrease in production area volumes and producers' operational issue.

A $1044 million increase in other product sales primarily due to higher system management gas sales from our gas pipeline businesses (offset in segment costs and expenmarketing revenues primarily associated with higher NGL prices and higher ethane volumes, partially offset by lower non-ethane volumes and other products. The changes in marketing revenues are substantially offset by similar changes in marketing purchases).
The decrease in segment costs and expenses
of $106 million nlds


A $
38119 million decrease in olefin feedstock purchases primarily due to the loss of production as a result of the Geismar Incidentfavorable change in Net insurance recoveries Geismar Incident attributable to the receipt of $125 million of insurance recoveries during the first quarter of 2014, partially offset by $6 million of related covered insurable expenses in excess of our retentions (deductibles).

A $
3368 million decrease in marketingolefin feedstock purchases primarily due to lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas pricesassociated with a $49 million decrease in volumes due to the lack of production in 2014 as a result of the Geismar Incident and a $23 million decrease in volumes at our RGP splitter primarily due to the third-party storage facility outage, as discussed above (more than offset in marketing revenuesProduct sales ).
4
30
Managements Discussion and Analysis (Continued)


A $737 million deincrease in costs associated with our equity NGLs reflecting a $21 million decrease related to lower volumes, partially offset by an increase of $14 million associated with 30 percent higher average natural gas pricmarketing purchases primarily due to higher NGL prices and higher ethane volumes, partially offset by lower non-ethane volumes and other products (more than offset in marketing revenues).

A $
7 9million deincrease in operating costs primarily due to lower compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses associated with the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012 as well as lower operating costs in the Four Corners area related to the consolidation of certain operations. These decreases are partially offset by higher operating and maintenance expenses and depreciation and amortization expenses associated with the Ohio Valley Midstream and Susquehanna Supply Hub businesses due to growth in these operationcosts associated with the production of our equity NGLs reflecting a $30 million increase related to higher average natural gas prices, partially offset by a decrease of $21 million associated with lower volumes


A
n $368 million favorable change in other (income) expense net primarily attributable to the recognition of $50 million of income associated with insurance recoveries during the third quarter of 2013 related to the Geismar Incident and $3 million of insurance recoveries relincrease in operating costs primarily due to a $12 million increase in Depreciation and amortization expenses associated towith the abandonment of certain Eminence storage assets. The favorable changes are partially offset by $9 million of expense related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates as well as a $9 million accrued loss for a contingent liability associated with a pending producer claim against us recognized in third-quarter 2013Ohio Valley Midstream and Susquehanna Supply Hub businesses due to growth in these operations and the ethane recovery project placed into service in fourth-quarter 2013 associated with our Canadian operations.

A $1
06 million increasunfavorable change in oOther product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues)(income) expensenet primarily due to the absence of a $6 million favorable contingency settlement recognized in first-quarter 2013 and costs incurred in first-quarter 2014 associated with fire damage at a compressor station in the Susquehanna Supply Hub. The deinces nsgetpoi nlds


A $76119 million decrease in olefin product margins, including $59 million lower ethylene product margins primarily due to 96 percent lower volumes sold related to the loss of production as a result of the Geismar Incidentfavorable change in Net insurance recoveries Geismar Incident as previously discussed.

A $
4961 million deincrease in NGL margins driven primarily by lower NGL volumes, lower average NGL prices, and higher natural gas pricesservice revenues as previously discussed.

A $67 million deinces nmreigmris


A $
63122 million indecrease in fee revenues as previously discussedolefin margins, including $111 million lower olefin margins at our Geismar plant and $10 million lower olefin margins associated with our Canadian operations driven by lower volumes and higher natural gas prices.

A $3
68 million favorable change in other (income) expense net as previously discusseddecrease in NGL margins driven primarily by lower NGL volumes and higher natural gas prices, partially offset by higher average NGL prices and lower natural gas volumes.

A $
716 million decrease in operating costs as previously discussed. Nine months ended September30, 2013 vs. nine months ended September30, 2012
The decrease in segment revenues includes:
unfavorable change in Other (income) expensenet as previously discussed.


A
$277 million decrease in revenues from our equity NGLs reflecting a decrease of $180 million due to lower volumes and a $97 million decrease associated with 13 percent lower average realized non-ethane per-unit sales prices and 49 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 78 percent lower driven by reduced ethane recoveries, as previously mentioned, and equity non-ethane volumes are 5 percent lower primarily due to a change in a customers contract from percent-of-liquids to fee-based processing and periods of severe winter weather conditions in the first quarter of 2013 that affected our western onshore operations that prevented producers from delivering gas.n $8 million increase in operating costs as previously discussed. Williams NGL& Petchem Services


A $222 million decrease in marketing revenues primarily associated with lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices. The changes in marketing revenues are more than offset by similar changes in marketing purchases.
44
Managements Discussion and Analysis (Continued)


A $132 million decrease in olefin sales due to $169 million lower volumes, partially offset by $37 million associated with higher per-unit sales prices. Olefins production volumes are lower primarily due to the loss of production as a result of the Geismar Incident, partially offset by the absence of 7 days of unplanned turbine maintenance in April 2012, and changes in inventory management. Ethylene prices averaged 21 percent higher, partially offset by 34 percent lower butadiene prices.


A $142 million increase in fee revenues primarily includes $126 million higher fee revenues resulting from higher gathering volumes driven by new well connections related to infrastructure additions, a full nine months of operations, and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in the Ohio Valley Midstream business. Natural gas transportation revenues also increased $71 million from expansion projects placed into service in 2012 and 2013, as well as new rates effective in first-quarter 2013. Partially offsetting these increases is a $39 million decrease in gathering and processing revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin, and severe winter weather conditions in the first quarter of 2013, which prevented producers from delivering gas in our western onshore operations. In addition, fee revenues decreased $25 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.


A $54 million increase in other product sales primarily due to higher system management gas sales from our gas pipeline businesses (offset in segment costs and expenses). The decrease in segment costs and expenses of $329 million includes:


A $246million decrease in marketing purchases primarily due to lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices (substantially offset in marketing revenues).


A $118 million decrease in olefin feedstock purchases due to $90 million of lower volumes, primarily due to the loss of production as a result of the Geismar Incident, and $28 million lower feedstock costs, reflecting 25 percent lower average per-unit ethylene feedstock costs.


A $23million decrease in costs associated with our equity NGLs reflecting a $69 million decrease due to lower natural gas volumes, partially offset by a $46 million increase related to a 37 percent increase in average natural gas prices.


A $54 million increase in operating costs including higher operating and maintenance expenses and depreciation and amortization expenses primarily associated with the businesses acquired in the Laser and Caiman Acquisitions in February and April 2012, respectively, and the subsequent growth in these operations. The increase in operating costs also includes $10 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by the absence of acquisition and transition costs of $22 million incurred in 2012. Additionally, compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses decreased primarily due to the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012. Operating costs in the Four Corners area also decreased related to the consolidation of certain operations.


A $49 million increase in other product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues ).


A $47 million favorable change in other (income) expense net primarily attributable to the recognition of $50 million of income associated with insurance recoveries during the third quarter of 2013 related to the Geismar Incident and $17 million lower project development costs. The favorable changes are partially offset by a $9 million accrued loss for a contingent liability associated with a pending producer claim against us recognized in third-quarter 2013 and the absence of a $6 million gain on the sale of equipment in the second quarter of 2012.
45
Managements Discussion and Analysis (Continued)
The decrease in segment profit includes:


A $254 million decrease in NGL margins driven primarily by lower NGL volumes and prices and higher natural gas prices.


A $54 million increase in operating costs as previously discussed.


A $14 million decrease in olefin product margins including $67 million lower ethylene volumes offset by $41 million higher ethylene prices and $25 million lower ethane costs.


A $3 million decrease in equity earnings primarily due to $17 million and $4 million lower equity earnings from Discovery and Aux Sable, respectively, both driven by lower NGL margins. The decreases are partially offset by $17 million higher equity earnings from Laurel Mountain driven primarily by 66 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in the second quarter of 2013, and lower leased compression expenses.


A $142 million increase in fee revenues as previously discussed.


A $47 million favorable change in other (income) expense net as previously discussed.


A $24 million increase in marketing margins. Williams NGL& Petchem Services



Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Segment
revcosts and expenuse
$
59(23
)

$
62(2
)

Equity earnings (losses)
(77
)

Segment profit (loss)

$
221(100
)

$
201

Segment profit (loss)
(2
)

16
56
72
Three months ended September30March31, 20134 vs. three months ended September30March31, 20123 Segment revcosts and expenuses deincreased slightly$21 million primarily due to lower sales volumes resulting from a scheduled third-quarter 2013 shutdown to conduct maintenance and to effect the ethane recovery project tie-in, substantially offset by higher average per-unit sales prices. Propylene product sales revenue decreased slightly due to 36 percent lower sales volumes substantially offset by 42 percent higher average per-unit sales prices. NGL product sales revenues remained consistent due to 6 percent lower sales volumes offset by 7 percent higher average per-unit sales prices. Segment costs and expenses increased $15 million primarily due to $14 million higher operating and maintenance expenses resulting from scheduled third-quarter 2013 shutdown. Segment profit (loss) decreased primarily due to $14 million higher operating and maintenance expenses resulting from scheduled third-quarter 2013 shutdown. Nine months ended September30, 2013 vs. nine months ended September30, 2012 Segment revenues increased primarily due to $19 million higher NGL$19 million of project development costs expensed during the first quarter of 2014 related to the Bluegrass Pipeline. The unfavorable change in Equity earnings (losses) is due to equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized produject sales revenues primarily due to 21 percent higher sales volumes partially offset by 6 percent lower average per-unit sales prices. The higher sales volumes resulted from the absence of the impact of filling the Boreal pipeline which occurred in June 2012 and improved production volumes in 2013, partially offset by reduced volumes due to the scheduled third-quarter 2013 shutdown. Segment costs and expenses increased $36 million primarily due to $20 million higher operating and maintenance costs primarily resulting from the scheduled third-development costs. The unfavorable change in Segment profit (loss) is due to equity losses from Bluegrass Pipeline and Moss Lake as well as costs incurred during the first quarter of 2013 shutdown and $13 million higher NGL feedstock costs primarily due to 21 percent higher sales volumes. Additionally, depreciation and amortization expenses increased
46
4 related to the development of the Bluegrass Pipeline.
41

Managements Discussion and Analysis (Continued)
$11million primarily due to certain assets that were decommissioned in the third quarter of 2013 in preparation of the completion of the ethane recovery system, in addition to the depreciation related to the Boreal Pipeline, which was placed into service in June 2012. These increases were partially offset by an $8 million decrease in other expenses, primarily related to the impact of foreign currency exchange. Segment profit decreased primarily due to $20 million higher operating and maintenance expenses resulting primarily from the scheduled third-quarter 2013 shutdown and $11 million higher depreciation and amortization expenses as previously discussed. These increased expenses were partially offset by $6 million higher NGL product margins primarily due to 21 percent higher sales volumes partially offset by 12 percent lower average per-unit margins combined with an $8 million decrease in other expenses. Acs isra ates


Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Segment profit
$
6
$
$
35
$
Three months ended SeptemberMarch 301, 20134 vs. three months ended September30March31, 20123 Segment profit in the third quarter of 2013 includes $22 million of equity earnings recognized from Access Midstream Partners, offset by $16 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners. During the third-quarter 2013, we receivedcludes equity earnings recognized from ACMP of $21 million and $17 million in 2014 and 2013, respectively. Offsetting the equity earnings a regular quarterly distribution charges of $2215 million from Access Midstream Partners. Nine months ended September 30, 2013 vs. nine months ended September30, 2012 Segment profit in 2013 includes $57 million of equity earnings recognized from Access Midstream Partners, offset by $48 millionand $17 million in 2014 and 2013, respectively, of noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream PCMP. We received regular quartners. In addition, segment profit in 2013 includes a noncash gainly distributions from ACMP of $2631 million resulting from Access Midstream Partners equity issuance in April 2013. This equity issuance resulted in the dilution of our ownership from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment. Inand $20 million during the first quarter of 2014 and 2013, we rrespecetived regular quarterly distributions of $64 million from Access Midstream Partnersly.Ohr


Three months ended
September 30,
Nine months ended
September 30
March 31,
2014
2013
2012
2013
2012

(Millions)

Segment revenues
$
759
$
7
$
21
$
20

Segment profit (loss)
3
1
61
(5
) Three months ended March 31, 2014 vs. three months ended March 31, 2013 Segment revenues increased due to new Canadian construction management services performed for third parties (substantially offset in segment costs and expenses ) . Segment costs and expenses increased by $44 million primarily due to new Canadian construction management services performed for third parties. The favorable change in segment profit (loss) reflects the absence of $6 million of project development costs incurred during the first quarter of 2013.

4
72
Managements Discussion and Analysis (Continued)
Nine months ended September 30, 2013 vs. nine months ended September30, 2012 The unfavorable change in segment profit is primarily due to the absence of the gain of $53 million recognized in 2012 related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012, we received payment for all outstanding balances due from this sale. (See Note 4 Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.) The unfavorable change also reflects $6 million of project development costs incurred in the first quarter of 2013.
48
Managements Discussion and Analysis (Continued)
Managements Discussion and Analysis of Financial Condition and Liquidity Outlook We seek to manage our businesses with a focus on applying conservative financial policy andin order to maintaining investment-grade credit metrics. Our plan for 20134 elcsorogigtasto oa vrl uiesmxta sicesnl e-ae.Atog u ahfosaeipce yfutain neeg omdt rcs htipc ssmwa iiae ycrano u ahfo tem htaentdrcl matdb hr-emcmoiypiemvmns nldn:

Firm demand and capacity reservation transportation revenues under long-term contracts;


Fee-based revenues from certain gathering and processing services. 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, dividends and distributions, debt service payments, and tax payments
, including a $90 million tax payment as a result of WPZs acquisition of certain of our Canadian operations, while maintaining a sufficient level of liquidity. In particular, we note the following for 2013:

We expect capital and investment expenditures to total between $4.13.76 billion and $4.644 billion in 20134. Of this total, maintenance capital expenditures, which are generally considered nondiscretionary and include expenditures to meet legal and regulatory requirements, to maintain and/or extend the operating capacity and useful lives of our assets, and to complete certain well connections, are expected to total between $34560 million and $4405 million. Expansion capital expenditures, which are generally more discretionary as compared to maintenance capital expenditures, are used to fund projects in order to grow our business and are expected to total between $3.7554 billion and $4.195 billion. See Company Outlook Expansion Projects, Williams Partners and Williams NGL& Petchem Servicesfrdsusosdsrbn h eea aueo hs xedtrs nadto,w eantefeiiiyt dutorpandlvl fcptladivsmn xedtrsi epnet hne neooi odtoso uiesopruiis


We expect to pay total annual cash dividends of approximately $1.4475 per common share in 20134, an increase of 202 percent over 20123 ees


We expect to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions and tax payments primarily through cash flow from operations, cash and cash equivalents on hand, issuances of
Williams and WPZ debt and/or equity securities, and utilization of our crevolverdit facility and WPZs crevolverdit facility and/or commercial paper program. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.11 billion and $2.15 billion in 2013.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 2014. Our internal and external sources of consolidated liquidity include:


We expect to maintain consolidated liquidity (which includes liquidity at WPZ) of at least $1 billion from cash and cash equivalents and unused revolver capacity. 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 2013. Our internal and external sources of consolidated liquidity include cash generated from our operations, cash and cash equivalents on hand, cash proceeds from WPZs offerings of common units, our revolver and WPZs revolver and/or commercial paper program. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of debt and/or equity 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 expected to be self-funding through its cash flows from operations, use of its revolver and/or commercial paper program, and its access to capital markets. WPZ makes cash distributions to us in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.
49
Managements Discussion and Analysis (Continued)
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
Cash generated from our operations, including cash distributions from WPZ and our equity-method investments based on our level of ownership and incentive distribution rights;


Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditionsCash and cash equivalents on hand;

Sustained reductions in energy commodity prices and margins from the range of current expectationCash proceeds from WPZs issuances of debt and/or equity securities


Significant physical damage to facilities, especially damage to WPZs offshore facilities by named windstorms;Use of WPZs commercial paper program and/or credit facility. Additional sources of liquidity available to us at the parent level include our credit facility, proceeds from the issuance of debt and/or equity securities, and proceeds from asset sales. WPZ is expected to be self-funding through its cash flows from operations, use of its commercial paper program and/or credit facility, and its access to capital markets.
43
Managements Discussion and Analysis (Continued)
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include those previously discussed in Company Outlook. As of March31, 2014 , we had a working capital deficit (current liabilities, in excess of current assets) of $371 million . However, we note the following about our available liquidity.



Unexpected significant increases in capital expenditures or delays in capital project execution;

March31, 2014

Lower than expected distributions, including incentive distribution rights, from WPZ. WPZs liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth.



September30, 2013

Available Liquidity
WPZ
WMB
Total

(Millions)

Cash and cash equivalents
$
535
$
64529
$
668
(1)
$
732
1,064

Capacity available under our $1.5 billion
crevolverdit facility (expires July 31, 2018) (21) 1,500
1,500

Capacity available to WPZ under its $2.5 billion
revolverfive-year credit facility (expires July 31, 2018) less amounts outstanding under theits $2 billion commercial paper program (3) (42)
2,
129500
2,
129500

$
2,1933,035
$
2,168029
$
4,3615,064





(1)
Includes $342 million of cash and cash equivalents held primarily by certain international entities, that we intend to utilize to fund growth in our Canadian midstream operations and therefore, is not considered available for general corporate purposes. The remainder of our cash and cash equivalents is primarily held in government-backed instrumentsWe have not borrowed on our credit facility during 2014. At March31, 2014 , we are in compliance with the financial covenants associated with this credit facility. The credit facility capacity, under certain circumstances, may be increased up to an additional $500 million.

(2)
At September30, 2013 , we are in compliance with the financial covenants associated with this revolver. On July31, 2013, we amended our $900 million revolver to increase the aggregate commitments to $1.5 billion and extend the maturity date to JulyWPZ has not borrowed on its credit facility during 2014 and has no Commercial paper outstanding at March 31, 20184. The amended revolver, under certain circumstances, may be increased up to an additionalhighest amount outstanding under the commercial paper program during 2014 was $5900 million.


(3)
At September30
At March31, 20134 , WPZ is in compliance with the financial covenants associated with the WPZ revolvercredit facility and commercial paper program. The WPZ crevolverdit facility is only available to WPZ, Transco, and Northwest Pipeline as co-borrowers. On July31, 2013, WPZ amended its $2.4 billion revolver to increase the aggregate commitments to $2.5 billion and ex and under certain circumstances, the capacity may be increased up to an additional $500 million. In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZs credit facility inclusive of any outstanding amounts under WPZs commercial paper program.
In addition to the credit facilities and WPZs commercial paper program lis
tend the maturity date to July31, 2018. The amended revolver, under certain circumstances, may be increased up to an additional $500 million.


(4)
In managing our available liquidity, we do not expect a maximum
above, we have issued letters of credit totaling $15 million and WPZ has issued letters of credit totaling $9 million as of March31, 2014 , under certain bilateral bank agreements. Debt Offering On March 4, 2014, WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. WPZ used a portion of the net proceeds to repay amounts outstanding amount under WPZits commercial paper program in excess of the capacity available under WPZs revolver.
In addition to the revolvers listed above, we have issued letters of credit totaling $17 million as of September30, 2013 , under certain bilateral bank agreements.
50
and expects to utilize the remainder to fund capital expenditures and for general partnership purposes. Distributions from Equity-Method Investees Our equity-method investees organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Shelf Registration In April 2013, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $600 million. These sales will be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. Such sales will be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for its own accounts as principals. As of March31, 2014 , no common units have been issued under this registration.
44

Managements Discussion and Analysis (Continued)
Commercial Paper In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. At September30, 2013 , WPZ had $ 371 million in commercial paper outstanding. Shelf Registration In April 2013, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $600 million. These sales will be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. Such sales will be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals. As of September30, 2013 , no common units have been issued under this registration. Equity Offerings In August 2013, WPZ completed an equity issuance of 21,500,000 common units representing limited partner interests. Subsequently, the underwriters exercised their option to purchase 3,225,000 common units. The net proceeds of approximately $1.2 billion to WPZ were used to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes. In March 2013, WPZ completed an equity issuance of 14,250,000 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement. Subsequently, the underwriters exercised their option to purchase 1,687,500 common units. The net proceeds of approximately $760 million to WPZ, including $143 million received from us on the private placement sale, were used to repay amounts outstanding under the WPZ revolver. WPZ Incentive Distribution Rights Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZs partnership agreement. We have agreed to temporarily waive our incentive distributions through 2013 related to the common units issued by WPZ to us and the seller in connection with the Caiman AcquisitionWPZ Incentive Distribution Rights Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZs partnership agreement. In connection with the contribution of certain Gulf olefins assets to WPZ in November 2012, we also agreed to waive $16 million per quarter of incentive distributions until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational. Cash distributions to us from WPZ through the November 2013 distribution have been reduced by a total of $131 million associated with these waived incentive distributions. In May 2013, we agreed to waive additional incentive distributions of up to $200 million total through the subsequent four quarters to further support WPZs cash distribution metrics as its large platform of growth projects moves toward completion. The November 2013 cash distribution to us from WPZ will be reduced by $90 million in association with these waived incentive distributions.
51
Managements Discussion and Analysis (Continued)

Insurance Renewal Our onshore property damage and business interruption insurance coverage renewed on May 1st, with a combined per-occurrence limit between $500 million and $750 million, subject to retentions (deductibles) of $40 million per occurrence for property damage and a waiting period of 120 days per occurrence for business interruption.

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:



Rating Agency
Outlook
Senior Unsecured Debt Rating
Corporate CreditRating



Williams:

Standard & Poors
Stable
BBB-
BBB

Moodys Investors Service
Stable
Baa3
N/A

Fitch Ratings
Stable
BBB-
N/A

Williams Partners:

Standard & Poors
Stable
BBB
BBB

Moodys Investors Service
Stable
Baa2
N/A

Fitch Ratings
PositivStable
BBB
-
N/A

With respect to Standard and Poors, 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 and Poors 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 and Poors may modify its ratings with a + or a - sign to show the obligors relative standing within a major rating category. With respect to Moodys, 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 a ranking at the lower end of the category.
With respect to Fitch, 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 obligors 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
theirits 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 September30March31, 20134 , we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $71 million or $23381million, respectively, in additional collateral with third parties.
452
Managements Discussion and Analysis (Continued)
Sources (Uses) of Cash



NinThree months ended
SeptemberMarch 301,
2014
2013
2012

(Millions)

Net cash provided (used) by:

Operating activities
$
1,702446
$
1,289495

Financing activities
1,094
2,498
929
176


Investing activities
(
2,903992
)
(3,6808
)

Increase (decrease) in cash and cash equivalents
$
(107
)
383
$
107
(137
)
Operating activities The factors that determine operating activities are largely the same as those that affect nNet income (loss) , with the exception of non-cash expenses such as dDepreciation and amortization, p and Provision (benefit) for deferred income taxes, and gain on reconsolidation of Wilpro entities. The increase in net cash provided by operating activities is primarily due to proceeds from insurance recoveries on the Eminence Storage Field leak and Geismar Incident, $64 million of distributions from our investment in Access Midstream Partners acquired in December 2012, and . Our Net cash provided by operating activities was also impacted by e aoal hne noeaigwrigcptl iacn ciiisSgiiattascin nld:

$
370225 million net proceeds received in 2013 fromayments in 2014 on WPZs commercial paper issuances;

$1.
705 billion in 2013 and $960 million in 2012 received496 billion net received in 2014 from WPZs prevolver borrowiously mentioned debt offerings;

$7
4570 million net proceeds received from WPZs August 2012 public offering of $750 million of senior unsecured notes due 2022received in 2013 from WPZs credit facility borrowings;

$
3895 million net proceeds received from Transcos July 2012 issuance of $400 million of senior unsecured notes due 2042paid in 2013 on WPZs credit facility borrowings;

$2.080 billion in 2013 and $960 million in 2012 paid on WPZs revolver borrow$617 million received in 2013 from WPZs equity offerig;

$
325276 million paid to retire Transcos 8.875 percent notes that matured in July 2012in 2014 and $231 million in 2013 paid for quarterly dividends on common stock;

$
88147 million net proceeds received from our 2012 equity offeringin 2014 and $105 million in 2013 paid for dividends and distributions to noncontrolling interests;

$
1.819 billion in 2013 and $1.559 bi63 million received in 2014 from contributions from noncontrolliong in 2012 received from WPZs equity offerings;terests. Investing activities Significant transactions include:


$722Capital expenditures of $793 million in 20134 and $538713 million in 2012 paid for quarterly dividends on common stock3;

$344 million in 2013 and $284 million in 2012 paid for dividends and distributions to noncontrolling interests;Purchases of and contributions to our equity-method investments of $228 million in 2014 and $93 million in 2013. Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments We have various other guarantees and commitments which are disclosed in Note 2 Variable Interest Entities , Note 10 Fair Value Measurements and Guarantees , and Note 11 Contingent Liabilities 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
Item3 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 2014. Foreign Currency Risk Our foreign operations, whose functional currency is the local currency, are located primarily in Canada. Net assets of our foreign operations were approximately $1.14 billion and $1.12 billion at March31, 2014 and December31, 2013, respectively. These investments have the potential to impact our financial position due to fluctuations in these local currencies arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar would have changed total stockholders equity by approximately $117 million at March31, 2014 .
47
Item4 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 Rules13a - 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 also is 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. Changes in Internal Controls Over Financial Reporting There have been no changes during the first quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting. PART II. OTHER INFORMATION Item1. Legal Proceedings Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
In September 2007, the EPA requested, and Transco later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPAs investigation of Transcos compliance with the Clean Air Act. On March28, 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 a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland. Since 2011 we have not received any additional requests for information related to these facilities.
48
In November 2013 we became aware of deficiencies with the air permit for the Ft. Beeler gas processing facility located in West Virginia. We notified the EPA and the West Virginia Department of Environmental Protection and are working to bring the Ft. Beeler facility into full compliance. At March 31, 2014, we have accrued liabilities of $100,000 for potential penalties arising out of the deficiencies. Other The additional information called for by this item is provided in Note 11 Contingent Liabilities of the Notes to Consolidated Financial Statements included under Part I, Item1. Financial Statements of this report, which information is incorporated by reference into this item.
49
Item6.Exhibits



$327 million received in contributions from noncontrolling interests in 2013.
53
Managements Discussion and Analysis (Continued)
Investing activities Significant transactions include:


Capital expenditures of $2.542 billion in 2013 and $1.652 billion in 2012;


Purchases of and contributions to our equity method investments of $350 million in 2013 and $282 million in 2012;


$1.72 billion paid, net of purchase price adjustments, for WPZs Caiman Acquisition in 2012;


$325 million paid, net of cash acquired in the transaction, for WPZs Laser Acquisition in 2012;


$121 million received from the reconsolidation of the Wilpro entities in 2012. (See Note 3 Discontinued Operations of our Notes to Consolidated Financial Statements.) This cash is only considered available for use in our international operations. Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments We have various other guarantees and commitments which are disclosed in Note 11 Fair Value Measurements and Note 12 Contingent Liabilities 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.
54
Item3 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 nine months of 2013. Foreign Currency Risk Our foreign operations, whose functional currency is the local currency, are located primarily in Canada. Net assets of our foreign operations were approximately $1.046 billion and $899 million at September30, 2013 and December31, 2012, respectively. These investments have the potential to impact our financial position due to fluctuations in these local currencies arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar would have changed total stockholders equity by approximately $209 million at September30, 2013 .
55
Item4 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. Third-Quarter 2013 Changes in Internal Controls There have been no changes during the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.
PART II. OTHER INFORMATION Item1. Legal Proceedings Environmental Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings. In September 2007, the EPA requested, and Transco later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPAs investigation of Transcos compliance with the Clean Air Act. On March28, 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 a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland. The New Mexico Environment Departments Air Quality Bureau (NMED) issued a Notice of Violation to Williams Four Corners LLC (Four Corners) on October23, 2012, as revised on February7, 2013, for the El Cedro Gas Treating
56
Plant related to the plants use of a standby generator and the timing of periodic testing. Settlement negotiations with the NMED to resolve the alleged violations are ongoing, with the NMED offering on April5, 2013, to settle for $162,711. On January18, 2013, the NMED issued a Notice of Violation to Four Corners relating to permitting issues for condensate storage tanks at the La Jara Compressor Station. Four Corners has been in discussions with the NMED about such permitting issues since early 2011. The NMED withdrew the Notice of Violation on September 9, 2013. On February12, 2013, the NMED issued a Notice of Violation to Four Corners related to the alleged modification of turbine units and a separator tank and alleged failure to conduct performance tests on certain facilities at the La Jara Compressor Station. Four Corners has been in discussions with the NMED since 2012 regarding the separator tank and other permitting issues. Settlement negotiations to resolve the issues are ongoing, with the NMED offering on June10, 2013, to settle for $1,336,564. Other The additional information called for by this item is provided in Note 12 Contingent Liabilities of the Notes to Consolidated Financial Statements included under Part I, Item1. Financial Statements of this report, which information is incorporated by reference into this item. Item1A. Risk Factors Part I, Item1A. Risk Factors in our Annual Report on Form 10-K for the year ended December31, 2012 , 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: The time required to return WPZs Geismar olefins plant to operation following the explosion and fire at the facility on June13, 2013 and the extent and timing of costs and insurance recoveries related to the incident could be materially different than we anticipate and could cause our financial results and levels of dividends to be materially different than we project. Our projections of financial results and expected levels of dividends are based on numerous assumptions and estimates, including but not limited to the time required to return WPZs Geismar, Louisiana olefins plant to operation and complete the expansion project at the facility following the explosion and fire at the plant on June13, 2013 and the extent and timing of costs and insurance recoveries related to the incident. Our financial results and levels of dividends could be materially different than we project if our assumptions and estimates related to the incident are materially different than actual outcomes.
57
Item6. Exhibits



Exhibit No.
Description


Exhibit3.1
Amended and Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to tThe CompanyWilliams Companies, Inc.s Ccurrent Rreport on Form8-K (File No. 001-04174) and incorporated herein by reference).


Exhibit 3.2
Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to tThe CompanyWilliams Companies Inc.s Ccurrent Rreport on Form8-K (File No. 001-04174) and incorporated herein by reference).


Exhibit10.1
First Amended & Restated CrediSettlement Agreement, dated as of July 31February 25, 20134, by and among The Williams Companies, Inc., as Borrower, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31Corvex Management LP, Keith Meister, Soroban Master Fund LP, Soroban Capital Partners LLC, Eric W. Mandelblatt, and The Williams Companies, Inc. (filed on February 25, 20134, as Exhibit 1099.1 to tThe Companys quarterly report on Form 10-QWilliams Companies Inc.s current report on Form 8-K (File No. 001-04174) n noprtdhri yrfrne.
*Exhibit 10.2
Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast G&P, regarding Relocation from Pennsylvania Benefits.

Exhibit 10.2
First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).


*Exhibit 12
Computation of Ratio of Earnings to Fixed Charges.


*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.


*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.


**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.


*xii11IS XBRL Instance Document.


*Exhibit101.SCH
XBRL Taxonomy Extension Schema.


*Exhibit101.CAL
XBRL Taxonomy Extension Calculation Linkbase.


*xii 0.E
XBRL Taxonomy Extension Definition Linkbase.


*Exhibit 101.LAB
XBRL Taxonomy Extension Label Linkbase.


*Exhibit 101.PRE
XBRL Taxonomy Extension Presentation Linkbase.



*Filed herewith. **Furnished herewith. Management contract or compensatory plan or arrangement.
5
80
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.



T HE W ILLIAMS C OMPANIES , I NC .

(Registrant)


/s/ TE .TIMRAS
Ted T. Timmermans

Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer) October3May1, 20134
EXHIBIT INDEX



Exhibit No.
Description


Exhibit3.1
Amended and Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to tThe CompanyWilliams Companies, Inc.s Ccurrent Rreport on Form8-K (File No. 001-04174) n noprtdhri yrfrne.

Exhibit 3.2
Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to tThe CompanyWilliams Companies, Inc.s Ccurrent Rreport on Form8-K (File No. 001-04174) and incorporated herein by reference).


Exhibit10.1
First Amended & Restated CrediSettlement Agreement, dated as of July 31February 25, 20134, by and among The Williams Companies, Inc., as Borrower, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31Corvex Management LP, Keith Meister, Soroban Master Fund LP, Soroban Capital Partners LLC, Eric W. Mandelblatt, and The Williams Companies, Inc. (filed on February 25, 20134, as Exhibit 1099.1 to tThe Company's quarterly report on Form 10-QWilliams Companies, Inc.s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).)

*Exhibit 10.2
Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast G&P, regarding Relocation from Pennsylvania Benefits.

Exhibit 10.2
First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).


*xii 2 Computation of Ratio of Earnings to Fixed Charges.


*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.


*xii 12 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.


**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.


*Exhibit101.INS
XBRL Instance Document.


*Exhibit101.SCH
XBRL Taxonomy Extension Schema.


*Exhibit101.CAL
XBRL Taxonomy Extension Calculation Linkbase.


*Exhibit 101.DEF
XBRL Taxonomy Extension Definition Linkbase.


*Exhibit 101.LAB
XBRL Taxonomy Extension Label Linkbase.


*Exhibit 101.PRE
XBRL Taxonomy Extension Presentation Linkbase.



*Filed herewith. **Furnished herewith. Management contract or compensatory plan or arrangement.