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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
 (Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2014
or
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to _____________
Commission file number 1-32599
 
WILLIAMS PARTNERS L.P.
(Exact name of registrant as specified in its charter)
DELAWARE
 
20-2485124
(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)
Registrant’s telephone number, including area code: (918) 573-2000
NO CHANGE
 
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ   No ¨
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 þ   No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
 
Accelerated filer ¨
 
Non-accelerated filer ¨
 
Smaller reporting company ¨
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
The registrant had 439,706,147 common units and 26,475,507 Class D units outstanding as of October 29, 2014.
 



Williams Partners L.P.
Index
 
 
Page
 
 
 
Item 1. Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “proposed,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in service date” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
The levels of cash distributions to unitholders;
The closing, expected timing, and benefits of the proposed merger of Access Midstream Partners, L.P. (ACMP) and us (the Proposed Merger);
The expected timing of the drop-down of The Williams Companies, Inc. (Williams) remaining NGL & Petchem Services assets and projects;

1


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;
Seasonality of certain business components;
Natural gas, natural gas liquids, and olefins prices, supply and demand;
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 from operations to enable us to pay current and expected levels of cash distributions, if any, following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;
Availability of supplies, market demand, and volatility of commodity prices;
Inflation, interest rates, fluctuation in foreign exchange rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
The strength and financial resources of our competitors and the effects of competition;
Whether we are able to successfully identify, evaluate and execute investment opportunities;
Our ability to acquire new businesses and assets and successfully integrate those operations and assets into our existing businesses, as well as successfully expand our facilities;
Development of alternative energy sources;
The impact of operational and development hazards and unforeseen interruptions;
Our ability to restart the Geismar plant and recover expected insurance proceeds;
Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation and rate proceedings;
Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
Changes in maintenance and construction costs;


2


Changes in the current geopolitical situation;
Our exposure to the credit risks of our customers and counterparties;
Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings, and the availability and cost of capital;
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;
Additional risks described in our filings with the Securities and Exchange Commission.
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013, and Part II, Item 1A. Risk Factors of this Form 10-Q.

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
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, 2014, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
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
OPPL: Overland Pass Pipeline Company LLC
Government and Regulatory:
EPA: Environmental Protection Agency
FERC: Federal Energy Regulatory Commission
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


4


PART I – FINANCIAL INFORMATION

Williams Partners L.P.
Consolidated Statement of Comprehensive Income
(Unaudited)

 
Three months ended 
 September 30,
 
Nine months ended  
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions, except per-unit amounts)
Revenues:
 
 
 
 
 
 
 
Service revenues
$
766


$
731

 
$
2,292


$
2,150

Product sales
942


887

 
2,725


3,037

Total revenues
1,708


1,618

 
5,017


5,187

Costs and expenses:



 



Product costs
807


710

 
2,300


2,301

Operating and maintenance expenses
267


265

 
766


811

Depreciation and amortization expenses
209


201

 
624


588

Selling, general, and administrative expenses
129


130

 
391


391

Net insurance recoveries – Geismar Incident

 
(50
)
 
(161
)
 
(50
)
Other (income) expense – net
(1
)

21

 
43


26

Total costs and expenses
1,411


1,277

 
3,963


4,067

Operating income
297


341

 
1,054


1,120

Equity earnings (losses)
36


31

 
91


84

Interest incurred
(155
)
 
(119
)

(428
)

(355
)
Interest capitalized
36

 
24


86


68

Other income (expense) – net
13

 
7

 
23

 
19

Income before income taxes
227

 
284

 
826

 
936

Provision (benefit) for income taxes
9

 
(1
)
 
22

 
35

Net income
218


285

 
804


901

Less: Net income attributable to noncontrolling interests
1


1

 
3


2

Net income attributable to controlling interests
$
217


$
284

 
$
801


$
899

Allocation of net income for calculation of earnings per common unit:
 
 
 
 
 
 
 
Net income attributable to controlling interests
$
217

 
$
284

 
$
801

 
$
899

Allocation of net income to general partner
171

 
60

 
518

 
343

Allocation of net income to Class D units
17

 

 
49

 

Allocation of net income to common units
$
29

 
$
224

 
$
234

 
$
556

Basic and diluted earnings per common unit
$
.07

 
$
.52

 
$
.53

 
$
1.34

Weighted average number of common units outstanding (thousands)
439,138

 
428,682

 
438,798

 
414,949

Cash distributions per common unit
$
.9285

 
$
.8775

 
$
2.7495

 
$
2.5875

Other comprehensive income (loss):
 
 
 
 
 
 
 
Net unrealized gain (loss) from derivative instruments
$

 
$
1

 
$

 
$
2

Foreign currency translation adjustments
(53
)
 
17

 
(48
)
 
(28
)
Other comprehensive income (loss)
(53
)
 
18

 
(48
)
 
(26
)
Comprehensive income
$
165

 
$
303

 
$
756

 
$
875

Less: Comprehensive income attributable to noncontrolling interests
1

 
1

 
3

 
2

Comprehensive income attributable to controlling interests
$
164

 
$
302

 
$
753

 
$
873


See accompanying notes.

5


Williams Partners L.P.
Consolidated Balance Sheet
(Unaudited)
 
September 30,
2014
 
December 31,
2013
 
(Dollars in millions)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
110

 
$
110

Trade accounts and notes receivable, net
613

 
568

Inventories
284

 
194

Other current assets
183

 
96

Total current assets
1,190

 
968

Investments
2,374

 
2,187

Property, plant, and equipment, at cost
27,382

 
25,062

Accumulated depreciation
(7,905
)
 
(7,437
)
Property, plant, and equipment – net
19,477

 
17,625

Goodwill
646

 
646

Other intangible assets, net of amortization
1,600

 
1,642

Regulatory assets, deferred charges, and other
527

 
503

Total assets
$
25,814

 
$
23,571

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
$
893

 
$
889

Affiliate
89

 
104

Accrued interest
146

 
115

Asset retirement obligations
34

 
64

Other accrued liabilities
248

 
375

Long-term debt due within one year
750

 

Commercial paper
265

 
225

Total current liabilities
2,425

 
1,772

Long-term debt
11,048

 
9,057

Asset retirement obligations
651

 
497

Deferred income taxes
129

 
117

Regulatory liabilities, deferred income, and other
678

 
561

Contingent liabilities (Note 10)


 

Equity:
 
 
 
Partners’ equity:
 
 
 
Common units (439,706,147 and 438,625,699 units outstanding at September 30, 2014 and December 31, 2013, respectively)
10,834

 
11,596

Class D units (26,475,507 units outstanding at September 30, 2014)
884

 

General partner
(1,502
)
 
(536
)
Accumulated other comprehensive income (loss)
43

 
92

Total partners’ equity
10,259

 
11,152

Noncontrolling interests in consolidated subsidiaries
624

 
415

Total equity
10,883

 
11,567

Total liabilities and equity
$
25,814

 
$
23,571

 
See accompanying notes.

6


Williams Partners L.P.
Consolidated Statement of Changes in Equity
(Unaudited)
 
 
Williams Partners L.P.
 
 
 
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
 
 
Common
Units
 
Class D Units
 
General
Partner
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total Partners’ Equity
 
Noncontrolling
Interests
 
Total
Equity
 
(Millions)
Balance – December 31, 2013
$
11,596

 
$

 
$
(536
)
 
$
92

 
$
11,152

 
$
415

 
$
11,567

Net income
290

 
6

 
505

 

 
801

 
3

 
804

Other comprehensive income (loss)

 

 

 
(48
)
 
(48
)
 

 
(48
)
Cash distributions (Note 3)
(1,190
)
 

 
(509
)
 

 
(1,699
)
 

 
(1,699
)
Distributions to The Williams Companies, Inc.  net

 

 
(11
)
 

 
(11
)
 

 
(11
)
Issuance of common units (Note 8)
55

 

 

 

 
55

 

 
55

Issuance of Class D units in common control transaction (Note 1)

 
961

 
(961
)
 

 

 

 

Beneficial conversion feature of Class D units
117

 
(117
)
 

 

 

 

 

Amortization of beneficial conversion feature of Class D units
(34
)
 
34

 

 

 

 

 

Contributions from general partner

 

 
10

 

 
10

 

 
10

Contributions from noncontrolling interests

 

 

 

 

 
205

 
205

Other

 

 

 
(1
)
 
(1
)
 
1

 

   Net increase (decrease) in equity
(762
)
 
884

 
(966
)
 
(49
)
 
(893
)
 
209

 
(684
)
Balance – September 30, 2014
$
10,834

 
$
884

 
$
(1,502
)
 
$
43

 
$
10,259

 
$
624

 
$
10,883


See accompanying notes.


7


Williams Partners L.P.
Consolidated Statement of Cash Flows
(Unaudited)

 
Nine months ended  
 September 30,
 
2014
 
2013
 
(Millions)
OPERATING ACTIVITIES:
 
 
 
Net income
$
804

 
$
901

Adjustments to reconcile to net cash provided by operations:
 
 
 
Depreciation and amortization
624

 
588

Cash provided (used) by changes in current assets and liabilities:
 
 
 
Accounts and notes receivable
(46
)
 
101

Inventories
(89
)
 
(53
)
Other current assets and deferred charges
(44
)
 
7

Accounts payable
26

 
(40
)
Accrued liabilities
(71
)
 
100

Affiliate accounts receivable and payable – net
(19
)
 
(21
)
Other, including changes in noncurrent assets and liabilities
50

 
108

Net cash provided by operating activities
1,235

 
1,691

FINANCING ACTIVITIES:
 
 
 
Proceeds from (payments of) commercial paper – net
39

 
370

Proceeds from long-term debt
2,740

 
1,705

Payments of long-term debt

 
(2,080
)
Proceeds from sales of common units
55

 
1,962

General partner contributions
10

 
50

Distributions to limited partners and general partner
(1,699
)
 
(1,404
)
Contributions from noncontrolling interests
205

 
300

Contributions from The Williams Companies, Inc. – net
45

 
191

Other – net

 
(6
)
Net cash provided by financing activities
1,395

 
1,088

INVESTING ACTIVITIES:
 
 
 
Property, plant and equipment:
 
 
 
Capital expenditures
(2,458
)
 
(2,422
)
Net proceeds from dispositions
28

 
1

Purchase of businesses from affiliates
(56
)
 
25

Purchases of and contributions to equity-method investments
(265
)
 
(344
)
Other – net
121

 
(9
)
Net cash used by investing activities
(2,630
)
 
(2,749
)
 
 
 
 
Increase (decrease) in cash and cash equivalents

 
30

Cash and cash equivalents at beginning of period
110

 
82

Cash and cash equivalents at end of period
$
110

 
$
112

 
See accompanying notes.

8


Williams Partners L.P.
Notes to Consolidated Financial Statements
(Unaudited)

Note 1 – General 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 in Exhibit 99.1 of our Form 8-K dated May 19, 2014. 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 Williams Partners L.P. and its subsidiaries.
We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of September 30, 2014, Williams owns an approximate 64 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC, an operating limited liability company (wholly owned by us).
Description of Business
Our operations are located in North America and are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude production handling and transportation in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), and a 60 percent equity-method investment in Discovery Producer Services LLC.
West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC, and our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming.
NGL & Petchem Services is comprised of our 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta. This segment also includes our NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC.

9



Notes (Continued)

Basis of Presentation
Canada Acquisition
We acquired certain Canadian operations in February 2014 from Williams (Canada Acquisition) for total consideration of $56 million of cash (including a $31 million post-closing adjustment paid in the second quarter), 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units receive quarterly distributions of additional paid-in-kind Class D units. All outstanding Class D units will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Acquisition provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. At September 30, 2014, no additional Class D units have been issued to Williams under this provision. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. These Canadian operations are reported in our NGL & Petchem Services segment. In October 2014, a purchase price adjustment was finalized whereby we will receive $56 million in cash from Williams in the fourth quarter 2014 and Williams will waive $2 million in payments on its IDRs with respect to our November 2014 distribution.

The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition, along with the cash consideration paid for the Canada Acquisition, are reflected within Distributions to The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.

Prior period amounts and disclosures have been recast for this transaction. The effect of recasting our financial statements to account for this transaction increased net income for the three and nine months ended September 30, 2013, by $5 million and $43 million, respectively. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
Certain of our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the statements of income are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet.
Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in the Consolidated Statement of Comprehensive Income.
Accounting standards issued but not yet adopted
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09 establishing Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (ASC 606).  ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. The standard is effective for annual reporting periods beginning after December 15, 2016, and interim periods within the reporting period.  Accordingly, we will adopt this standard in the first quarter of 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is not permitted. We are currently evaluating the impact of this new standard on our consolidated financial statements.

10



Notes (Continued)

Accumulated Other Comprehensive Income (Loss)
AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income in any of the periods presented.
Note 2 – Variable Interest Entities
Consolidated VIEs
As of September 30, 2014, we consolidate the following variable interest entities (VIEs):
Gulfstar One
We own 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. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. We, as construction agent for Gulfstar One, designed, constructed, and installed 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 the fourth quarter of 2014. We have received certain advance payments from the producer customers during the construction process. In certain circumstances, the producer customers will be responsible for Gulfstar One’s unrecovered portion of the firm price of building the facilities if the production handling agreement is terminated. Construction of an expansion project is underway that will provide production handling and gathering 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 for both projects is less than $180 million which we expect will be funded with revenues received from customers and capital contributions from us and the other equity partner on a proportional basis.
Constitution
We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction agent for Constitution, are building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the project in service in late 2015 to 2016 and estimate the total remaining construction costs of the project to be approximately $525 million, which will be funded with capital contributions from us and the other equity partners on a proportional basis.


11



Notes (Continued)

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs, which are joint projects in the development and construction phase:

 
September 30,
2014
 
December 31,
2013
 
Classification
 
(Millions)
 
 
Assets (liabilities):
 
 
 
 
 
Cash and cash equivalents
$
68

 
$
84

 
Cash and cash equivalents
Property, plant, and equipment
1,494

 
1,001

 
Property, plant, and equipment, at cost
Accounts payable
(83
)
 
(122
)
 
Accounts payable - trade
Construction retainage

 
(3
)
 
Other accrued liabilities
Current deferred revenue

 
(10
)
 
Other accrued liabilities
Asset retirement obligation
(56
)
 

 
Asset retirement obligations, noncurrent
Noncurrent deferred revenue associated with customer advance payments
(178
)
 
(115
)
 
Regulatory liabilities, deferred income, and other

Nonconsolidated VIEs
We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:
Laurel Mountain
Our 51 percent-owned equity-method investment in 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, we are not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $464 million at September 30, 2014. On October 1, 2014, a restructuring transaction was completed that increased our ownership interest to 69 percent and amended certain commercial contracts.
Caiman II
During April 2014, Caiman II, a previously reported VIE, became able to finance its current activities without additional subordinated financial support due in part to its primary investee, Blue Racer Midstream LLC, securing a revolving credit agreement with a third party. The total equity investment at risk of Caiman II is sufficient to finance its activities. As a result, Caiman II is no longer a VIE and continues to be reported as a 58 percent-owned equity-method investment due to the significant participatory rights of our partners such that we do not control.

12



Notes (Continued)

Note 3 – Allocation of Net Income and Distributions
The allocation of net income between our general partner and limited partners is as follows:
 
Three months ended 
 September 30,
 
Nine months ended  
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Allocation of net income to general partner:
 
 
 
 
 
 
 
Net income
$
218

 
$
285

 
$
804

 
$
901

Net income applicable to pre-partnership operations allocated to general partner

 
(5
)
 
(15
)
 
(43
)
Net costs charged directly to the general partner
1

 
1

 
1

 
1

Net income applicable to noncontrolling interests
(1
)
 
(1
)
 
(3
)
 
(2
)
Income subject to 2% allocation of general partner interest
218

 
280

 
787

 
857

General partner’s share of net income
2
%
 
2
%
 
2
%
 
2
%
General partner’s allocated share of net income before items directly allocable to general partner interest
5

 
6

 
16

 
17

Priority allocations, including incentive distributions, paid to general partner (1)
164

 
121

 
475

 
337

Pre-partnership net income allocated to general partner interest

 
5

 
15

 
43

Net costs charged directly to the general partner
(1
)
 
(1
)
 
(1
)
 
(1
)
Net income allocated to general partner
$
168

 
$
131

 
$
505

 
$
396

 
 
 
 
 
 
 
 
Net income
$
218

 
$
285

 
$
804

 
$
901

Net income allocated to general partner
168

 
131

 
505

 
396

Net income allocated to Class D limited partners (2)
18

 

 
40

 

Net income allocated to noncontrolling interests
1

 
1

 
3

 
2

Net income allocated to common limited partners (2)
$
31

 
$
153

 
$
256

 
$
503

 
(1)
The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted earnings per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period.

(2)
The net income allocated to common and Class D limited partners includes $14 million and $34 million for the three and nine months ended September 30, 2014, respectively, related to the amortization of the beneficial conversion feature associated with the Class D units.

13



Notes (Continued)

We paid or have authorized payment of the following partnership cash distributions during 2013 and 2014 (in millions, except for per unit amounts):






General Partner


Payment Date

Per Unit
Distribution

Common
Units

2%

Incentive
Distribution
Rights

Total Cash
Distribution
2/8/2013

$
0.8275

 
$
329

 
$
9

 
$
104

 
$
442

5/10/2013

0.8475

 
351

 
10

 
112

 
473

8/09/2013

0.8625

 
357

 
11

 
121

 
489

11/12/2013
 
0.8775

 
385

 
11

 
46

 
442

2/13/2014
 
0.8925

 
392

 
11

 
153

 
556

5/9/2014
 
0.9045

 
396

 
12

 
158

 
566

8/8/2014
 
0.9165

 
402

 
12

 
163

 
577

11/7/2014 (1)
 
0.9285

 
408

 
12

 
167

 
587

 
(1)
The Board of Directors of our general partner declared this $0.9285 per common unit cash distribution on October 20, 2014, to be paid on November 7, 2014, to unitholders of record at the close of business on October 31, 2014.
The 2013 and 2014 cash distributions paid to our general partner in the table above have been reduced by $173 million resulting from the temporary waiver of IDRs associated with certain assets acquired in 2012 and 2014 and an additional $90 million in IDRs waived by our general partner related to the third-quarter 2013 distribution, to support our cash distribution metrics.
Class D Units
As previously mentioned (see Note 1 – General and Basis of Presentation), a portion of the total consideration for the Canada Acquisition was funded through the issuance of Class D units to an affiliate of our general partner, which are convertible to common units on a one-for-one basis beginning in the first quarter of 2016. The Class D units were issued at a discount to the market price of our common units, into which they are convertible. The discount represents a beneficial conversion feature and is reflected as an increase in the common unit capital account and a decrease in the Class D capital account on the Consolidated Statement of Changes in Equity. This discount is being amortized through the conversion date in the first quarter of 2016, resulting in an increase to the Class D capital account and a decrease to the common unit capital account.
Distributions
The Class D units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class D units receive quarterly distributions of additional paid-in-kind Class D units no later than the applicable distribution date. With respect to the Class D units, the number of Class D units to be issued in connection with a Class D unit distribution is the quotient of the amount of the per-unit distribution declared for a common unit for the applicable distribution period multiplied by the number of Class D units outstanding as of the record date, divided by the volume-weighted average price of a common unit calculated over the consecutive 30-day trading period prior to the declaration of the quarterly distribution to common units. On May 9, 2014, we issued 456,916 Class D units as the paid-in-kind Class D distribution with respect to the first quarter 2014. On August 8, 2014, we issued 441,070 Class D units as the paid-in-kind Class D distribution with respect to the second quarter 2014. On October 20, 2014, the Board of Directors of our general partner authorized the issuance of 479,907 Class D units as the paid-in-kind Class D distribution with respect to the third quarter, to be issued on November 7, 2014.
Earnings per unit
Basic and diluted earnings per limited partner unit are calculated using the two-class method. At September 30, 2014, Class D units are anti-dilutive and therefore not included in calculating diluted earnings per common unit.

14



Notes (Continued)

Note 4 – Other Income and Expenses
The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income:
 
Three months ended 
 September 30,
 
Nine months ended  
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Northeast G&P
 
 
 
 
 
 
 
Impairment of certain equipment held for sale (see Note 9)
$

 
$

 
$
17

 
$

Net gain related to partial acreage dedication release
(12
)
 

 
(12
)
 

Accrued loss associated with a producer claim

 
9

 

 
9

Atlantic-Gulf
 
 
 
 
 
 
 
Amortization of regulatory assets associated with asset retirement obligations
8

 
8

 
25

 
15

Write-off of the Eminence abandonment regulatory asset not recoverable through rates

 
9

 

 
15

Insurance recoveries associated with the Eminence abandonment

 
(3
)
 

 
(15
)
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our 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:
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;
Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.
During the nine month period ended September 30, 2014, we received $175 million, and during the three and nine month periods ended September 30, 2013, we received $50 million of insurance recoveries related to the Geismar Incident. These amounts are reported within our NGL & Petchem Services segment and reflected in Net insurance recoveries – Geismar Incident in the Consolidated Statement of Comprehensive Income. Also included in Net insurance recoveries – Geismar Incident are $14 million of related covered insurable expenses incurred in excess of our retentions (deductibles) during the nine month period ended September 30, 2014.
The three and nine month periods ended September 30, 2013, include $4 million and $10 million, respectively, of costs under our insurance deductibles reported in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income.

15



Notes (Continued)

Note 5 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:
 
Three months ended 
 September 30,
 
Nine months ended  
 September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Current:
 
 
 
 
 
 
 
State
$
2

 
$
1

 
$
4

 
$
3

Foreign

 
(2
)
 
1

 
(6
)
 
2

 
(1
)
 
5

 
(3
)
Deferred:
 
 
 
 
 
 
 
State
5

 

 
5

 
14

Foreign
2

 

 
12

 
24

 
7

 

 
17

 
38

Total provision (benefit)
$
9

 
$
(1
)
 
$
22

 
$
35

The effective income tax rates for the total provision for the three and nine months ended September 30, 2014 and 2013, are less than the federal statutory rate due to income not subject to U.S. federal tax, partially offset by taxes on foreign operations and the effect of Texas franchise tax. The 2013 state deferred provision includes $14 million related to the impact of a second-quarter Texas franchise tax law change.
Note 6 – Inventories
 
September 30,
2014
 
December 31,
2013
 
(Millions)
Natural gas liquids, olefins, and natural gas in underground storage
$
202

 
$
111

Materials, supplies, and other
82

 
83

 
$
284

 
$
194

Note 7 – Debt and Banking Arrangements
Long-Term Debt
Issuances
On June 27, 2014, we completed a public offering of $750 million of 3.9 percent senior unsecured notes due 2025 and $500 million of 4.9 percent senior unsecured notes due 2045. We used a portion of the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
On March 4, 2014, we 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. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
Commercial Paper Program
At September 30, 2014, $265 million of Commercial paper was outstanding at a weighted average interest rate of 0.26 percent under our $2 billion commercial paper program.

16



Notes (Continued)

Credit Facility
Letter of credit capacity under our $2.5 billion credit facility is $1.3 billion. At September 30, 2014, no letters of credit have been issued and no loans were outstanding under our credit facility. We issued letters of credit totaling $1 million as of September 30, 2014, under a certain bilateral bank agreement.
Note 8 – Partners’ Capital
In August 2014, we issued 1,080,448 common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of $55 million were used for general partnership purposes. We incurred commission fees of $554 thousand associated with these transactions.
Note 9 – Fair Value Measurements and Guarantee
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
 
 
 
 
 
Fair Value Measurements Using
 
 Carrying 
Amount
 
Fair
Value
 
Quoted
Prices In
Active
 Markets for 
Identical
Assets
(Level 1)
 
 Significant 
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(Millions)
Assets (liabilities) at September 30, 2014:
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
ARO Trust investments
$
42

 
$
42

 
$
42

 
$

 
$

Energy derivatives assets designated as hedging instruments
1

 
1

 

 
1

 

Energy derivatives assets not designated as hedging instruments
2

 
2

 

 

 
2

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

 
(1
)
 
(2
)
Additional disclosures:
 
 
 
 
 
 
 
 
 
Notes receivable and other
5

 
5

 
1

 
4

 

Long-term debt, including current portion
(11,798
)
 
(12,576
)
 

 
(12,576
)
 

Assets (liabilities) at December 31, 2013:
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
ARO Trust investments
$
33

 
$
33

 
$
33

 
$

 
$

Energy derivatives assets not designated as hedging instruments
3

 
3

 

 

 
3

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

 
(1
)
 
(2
)
Additional disclosures:
 
 
 
 
 
 
 
 
 
Notes receivable and other
7

 
7

 
1

 
6

 

Long-term debt
(9,057
)
 
(9,581
)
 

 
(9,581
)
 



17



Notes (Continued)

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 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 Regulatory 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 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 Other current assets and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other 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 nine months ended September 30, 2014 or 2013.
Additional fair value disclosures
Notes receivable and other: The disclosed fair value of our notes receivable 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 Trade accounts and notes receivable, net and the noncurrent portion is reported in Regulatory 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.
Assets and liabilities measured at fair value on a nonrecurring basis
In second quarter 2014, we designated certain equipment within our Northeast G&P segment as held for sale. The estimated fair value (less cost to sell) of the equipment at September 30, 2014, is $44 million and is reported in Other current assets in the Consolidated Balance Sheet. The estimated fair value was determined by a market approach based on our analysis of information related to sales of similar pre-owned equipment in the principal market. This analysis resulted in a second quarter impairment charge of $17 million, recorded in Other (income) expense – net within Costs and expenses. This nonrecurring fair value measurement fell within Level 3 of the fair value hierarchy.
Guarantee
We are required by our revolving credit agreement 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.

18



Notes (Continued)

Note 10 – Contingent Liabilities
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 U.S. Environmental Protection Agency (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 September 30, 2014, we have accrued liabilities totaling $17 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.
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 September 30, 2014, we have accrued liabilities of $11 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 September 30, 2014, we have accrued liabilities totaling $6 million for these costs.
Geismar Incident
As a result of the previously discussed Geismar Incident, there were two fatalities, and numerous individuals (including affiliate employees and contractors) reported injuries, which varied from minor to serious. We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters.  On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act, to which we responded on August 13, 2014. We and the EPA continue to discuss 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. We settled the citations with OSHA on September 12, 2014, for a penalty of $36,000. The settlement was judicially approved on September 23, 2014. On June 25, 2013, OSHA commenced a second inspection pursuant to its Refinery and Chemical National Emphasis Program (NEP). OSHA did not issue a citation to us in connection with this NEP inspection and 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

19



Notes (Continued)

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, customer claims, 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 generally do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.
Transco 2012 Rate Case
On August 31, 2012, Transco submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its 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 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 paid $118 million of rate refunds on April 18, 2014.
Other
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities 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. We disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.
Note 11 – Segment Disclosures
Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General and Basis of Presentation.)
Performance Measurement
We currently evaluate segment operating performance based on Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses, Equity earnings (losses), and Income (loss) from investments. General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business and are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

20



Notes (Continued)

The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income as reported in the Consolidated Statement of Comprehensive Income.


Northeast
G&P

Atlantic-
Gulf

West

NGL &
Petchem
Services

Eliminations 

Total

(Millions)
Three months ended September 30, 2014


Segment revenues:











Service revenues











External
$
114

 
$
363

 
$
257

 
$
32

 
$

 
$
766

Internal

 
1

 

 

 
(1
)
 

Total service revenues
114

 
364

 
257

 
32

 
(1
)
 
766

Product sales
 
 
 
 
 
 
 
 
 
 
 
External
68

 
118

 
22

 
734

 

 
942

Internal

 
108

 
133

 
62

 
(303
)
 

Total product sales
68

 
226

 
155

 
796

 
(303
)
 
942

Total revenues
$
182

 
$
590

 
$
412

 
$
828

 
$
(304
)
 
$
1,708

Segment profit (loss)
$
35

 
$
162

 
$
175

 
$
1

 
 
 
$
373

Less equity earnings (losses)
4

 
25

 

 
7

 
 
 
36

Segment operating income (loss)
$
31

 
$
137

 
$
175

 
$
(6
)
 
 
 
337

General corporate expenses
 
 
 
 
 
 
 
 
 
 
(40
)
Operating income
 
 
 
 
 
 
 
 
 
 
$
297













Three months ended September 30, 2013




Segment revenues:











Service revenues











External
$
93

 
$
345

 
$
266

 
$
27

 
$

 
$
731

Internal

 
1

 

 

 
(1
)
 

Total service revenues
93

 
346

 
266

 
27

 
(1
)
 
731

Product sales
 
 
 
 
 
 
 
 
 
 
 
External
47

 
203

 
10

 
627

 

 
887

Internal

 
14

 
202

 
70

 
(286
)
 

Total product sales
47

 
217

 
212

 
697

 
(286
)
 
887

Total revenues
$
140

 
$
563

 
$
478

 
$
724

 
$
(287
)
 
$
1,618

Segment profit (loss)
$
(1
)
 
$
137

 
$
207

 
$
68

 
 
 
$
411

Less:
 
 
 
 
 
 
 
 
 
 
 
Equity earnings (losses)
2

 
17

 

 
12

 
 
 
31

Income (loss) from investments

 

 

 
(1
)
 
 
 
(1
)
Segment operating income (loss)
$
(3
)
 
$
120

 
$
207

 
$
57

 
 
 
381

General corporate expenses
 
 
 
 
 
 
 
 
 
 
(40
)
Operating income
 
 
 
 
 
 
 
 
 
 
$
341

 
 
 
 
 
 
 
 
 
 
 
 
Nine months ended September 30, 2014
Segment revenues:











Service revenues











External
$
320

 
$
1,104

 
$
774

 
$
94

 
$

 
$
2,292

Internal

 
3

 

 

 
(3
)
 

Total service revenues
320

 
1,107

 
774

 
94

 
(3
)
 
2,292

Product sales
 
 
 
 
 
 
 
 
 
 
 
External
165

 
382

 
61

 
2,117

 

 
2,725

Internal

 
274

 
371

 
205

 
(850
)
 

Total product sales
165

 
656

 
432

 
2,322

 
(850
)
 
2,725

Total revenues
$
485

 
$
1,763

 
$
1,206

 
$
2,416

 
$
(853
)
 
$
5,017

Segment profit (loss)
$
56

 
$
495

 
$
492

 
$
226

 
 
 
$
1,269

Less equity earnings (losses)
15

 
56

 

 
20

 
 
 
91

Segment operating income (loss)
$
41

 
$
439

 
$
492

 
$
206

 
 
 
1,178

General corporate expenses
 
 
 
 
 
 
 
 
 
 
(124
)
Operating income
 
 
 
 
 
 
 
 
 
 
$
1,054

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

21



Notes (Continued)


Northeast
G&P

Atlantic-
Gulf

West

NGL &
Petchem
Services

Eliminations 

Total

(Millions)
Nine months ended September 30, 2013
 
 
 
 
Segment revenues:
 
 
 
 
 
 
 
 
 
 
 
Service revenues
 
 
 
 
 
 
 
 
 
 
 
External
$
234

 
$
1,048

 
$
784

 
$
84

 
$

 
$
2,150

Internal

 
9

 

 

 
(9
)
 

Total service revenues
234

 
1,057

 
784

 
84

 
(9
)
 
2,150

Product sales
 
 
 
 
 
 
 
 
 
 
 
External
102

 
628

 
47

 
2,260

 

 
3,037

Internal

 
69

 
555

 
231

 
(855
)
 

Total product sales
102

 
697

 
602

 
2,491

 
(855
)
 
3,037

Total revenues
$
336

 
$
1,754

 
$
1,386

 
$
2,575

 
$
(864
)
 
$
5,187

Segment profit (loss)
$
2

 
$
448

 
$
555

 
$
327

 
 
 
$
1,332

Less:
 
 
 
 
 
 
 
 
 
 
 
Equity earnings (losses)
6

 
53

 

 
25

 
 
 
84

Income (loss) from investments

 

 

 
(3
)
 
 
 
(3
)
Segment operating income (loss)
$
(4
)
 
$
395

 
$
555

 
$
305

 
 
 
1,251

General corporate expenses
 
 
 
 
 
 
 
 
 
 
(131
)
Operating income
 
 
 
 
 
 
 
 
 
 
$
1,120

The following table reflects Total assets by reportable segment.  
 
Total Assets
 
September 30, 
 2014
 
December 31, 
 2013
 
(Millions)
Northeast G&P
$
7,204

 
$
6,229

Atlantic-Gulf
10,742

 
10,007

West
4,688

 
4,767

NGL & Petchem Services
3,552

 
3,035

Other corporate assets
540

 
147

Eliminations (1)
(912
)
 
(614
)
Total
$
25,814

 
$
23,571

 
(1)
Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.
Note 12 – Subsequent Event
On October 26, 2014, we announced that we have entered into a merger agreement with Access Midstream Partners, L.P. (ACMP). Williams controls the general partners of both us and ACMP. The merged partnership will be named Williams Partners L.P. Under the terms of the agreement, each of our publicly held common units will be exchanged for 0.86672 ACMP common units. Prior to completing the merger, each publicly held ACMP common unit will receive an additional 0.06152 ACMP common unit. Upon consummation of these transactions, Williams expects to receive ACMP common units representing a net effective exchange ratio of 0.82080 ACMP common units for each WPZ common unit it holds. Our Class D units will convert to common units in conjunction with the merger. Following the merger, Williams is expected to own approximately 60 percent of the merged partnership, including the general partner interest and IDRs. The approval and adoption of the merger agreement and the merger requires approval by a majority of our outstanding common units. Williams’ subsidiary, Williams Gas Pipeline Company LLC, which owns a sufficient number of our common units to approve the merger on behalf of all of our unitholders, has executed a support agreement in which it has irrevocably agreed to consent to the merger. The merger is expected to close in early 2015, subject to customary closing conditions, including effectiveness of a registration statement on Form S-4 related to the issuance of new ACMP common units to our common unitholders.


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Item 2
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins through our gas pipeline and midstream businesses.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure 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. These services include natural gas gathering, processing and treating, NGL fractionation and transportation, crude oil production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.
Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, which are comprised of the following businesses as of September 30, 2014:
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity-method investment in Laurel Mountain and a 58 percent equity-method investment in Caiman II.
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity).
West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline.
NGL & Petchem Services is comprised of our 83.3 percent interest in an olefins production facility in Geismar, Louisiana, along with an RGP Splitter and various petrochemical and feedstock pipelines in the Gulf Coast 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. This segment also includes an NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.
As of September 30, 2014, Williams holds an approximate 66 percent interest in us, comprised of an approximate 64 percent limited partner interest and all of our 2 percent general partner interest and IDRs.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8-K dated May 19, 2014.

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Management’s Discussion and Analysis (Continued)

Proposed Merger
As discussed in more detail in Note 12 – Subsequent Event of the Notes to Consolidated Financial Statements, we announced on October 26, 2014, that we have entered into a merger agreement with Access Midstream Partners, L.P. (ACMP). Williams controls the general partners of both us and ACMP. The merger is expected to close in early 2015, subject to customary closing conditions, including effectiveness of a registration statement on Form S-4 related to the issuance of new ACMP common units to WPZ common unitholders. All subsequent references to forecast amounts within this Management’s Discussion and Analysis do not reflect the proposed merger.
Distributions
In October 2014, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.9285 per common unit, an increase of approximately 1 percent over the prior quarter and 6 percent over the same period in the prior year. We expect to increase limited partner per-unit cash distributions by approximately 6 percent, at the midpoint of our guidance range, in 2014.
Overview of Nine Months Ended September 30, 2014
Our results for the first nine months of 2014, as compared to the same period of the prior year, were unfavorable primarily due to lower NGL margins driven by lower volumes and lower olefin margins associated with the absence of volumes from our Geismar plant partially offset by related insurance recoveries. Interest expense related to higher debt levels also contributed to our lower results, partially offset by higher fee-based revenues. 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.
Canada Acquisition
On February 28, 2014, we acquired certain of Williams’ Canadian operations for total consideration valued at approximately $1.2 billion. The operations included an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B Splitter facility at Redwater, Alberta. We funded the transaction with $56 million of cash including $31 million that was paid in the second quarter, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units 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 Acquisition provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. At September 30, 2014, no additional Class D units have been issued to Williams under this provision. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. In October 2014, a purchase price adjustment was finalized whereby we will receive $56 million in cash from Williams in the fourth quarter 2014 and Williams will waive $2 million in payments on its IDRs with respect to our November 2014 distribution.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our 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. This facility is part of our NGL & Petchem Services segment.

24



Management’s Discussion and Analysis (Continued)

We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:
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;
General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;
Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.
During the first nine months of 2014, we received $175 million of insurance recoveries related to the Geismar Incident and incurred $14 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 Comprehensive Income.
Following the repair and an expansion of the plant, we expect the Geismar plant to return to operation in the fourth quarter of 2014. We expect our total loss to exceed our $500 million policy limit, which would result in a total claim of approximately $433 million related to business interruption and approximately $67 million related to the repair of the plant. Through September 2014, we have received a total of $225 million from insurers. We received $50 million of our most recent claim of $200 million as the insurers are evaluating our claim and have raised questions around key assumptions involving our business interruption claim. We continue to work with insurers in support of all claims, as submitted, and are vigorously pursuing collection of the remaining $275 million insurance limits. We, in consultation with independent experts, presented further support for our insurance claim to insurers in September 2014 and have agreed with insurers to non-binding mediation, which is scheduled to begin in late November, in an effort to advance the resolution of the claim.
Further, 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.
Northeast G&P
Caiman II
As a result of contributions made in the first quarter of 2014, our ownership in the Caiman II joint project increased to 58 percent at September 30, 2014. These contributions are used to fund Caiman II’s 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.
Atlantic-Gulf
New Transco rates effective
On August 31, 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 March 1, 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 paid $118 million of rate refunds on April 18, 2014.

25