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EX-32.2 - OKS CERTIFICATION OF REINERS SECTION 906 - ONEOK Partners LPoksq32015exhibit322.htm
EX-32.1 - OKS CERTIFICATION OF SPENCER SECTION 906 - ONEOK Partners LPoksq32015exhibit321.htm
EX-31.2 - OKS CERTIFICATION OF REINERS SECTION 302 - ONEOK Partners LPoksq32015exhibit312.htm
EX-31.1 - OKS CERTIFICATION OF SPENCER SECTION 302 - ONEOK Partners LPoksq32015exhibit311.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

X Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2015.
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   1-12202


ONEOK PARTNERS, L.P.
(Exact name of registrant as specified in its charter)


Delaware
93-1120873
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
 
100 West Fifth Street, Tulsa, OK
74103
(Address of principal executive offices)
(Zip Code)

Registrant’s telephone number, including area code   (918) 588-7000

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 X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 X  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.
Large accelerated filer X             Accelerated filer __             Non-accelerated filer __             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 X

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 
Class
 
Outstanding at October 26, 2015
Common units
 
212,837,980 units
Class B units
 
72,988,252 units






























This page intentionally left blank.

































2


ONEOK PARTNERS, L.P.
TABLE OF CONTENTS


Page No.
 
 
 
 
 
 
 

As used in this Quarterly Report, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, unless the context indicates otherwise.

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements.  Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.  Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Forward-Looking Statements,” in this Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneokpartners.com) copies of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.  Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request.  Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

3


GLOSSARY

The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:

AFUDC
Allowance for funds used during construction
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2014
ASU
Accounting Standards Update
Bbl
Barrels, 1 barrel is equivalent to 42 United States gallons
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
CFTC
U.S. Commodity Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Act Amendments of 1972, as amended
DOT
United States Department of Transportation
EBITDA
Earnings before interest expense, income taxes, depreciation and amortization
EPA
United States Environmental Protection Agency
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of
ONEOK Partners, L.P.
LIBOR
London Interbank Offered Rate
MBbl/d
Thousand barrels per day
MDth/d
Thousand dekatherms per day
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf/d
Million cubic feet per day
Moody’s
Moody’s Investors Service, Inc.
Natural Gas Policy Act
Natural Gas Policy Act of 1978, as amended
NGL(s)
Natural gas liquid(s)
NGL products
Marketable natural gas liquids purity products, such as ethane, ethane/propane
mix, propane, iso-butane, normal butane and natural gasoline
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
ONE Gas
ONE Gas, Inc.
ONEOK
ONEOK, Inc.
ONEOK Partners GP
ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole
general partner of ONEOK Partners
OPIS
Oil Price Information Service
Partnership Agreement
Third Amended and Restated Agreement of Limited Partnership of ONEOK
Partners, L.P., as amended
Partnership Credit Agreement
The Partnership’s $2.4 billion Amended and Restated Revolving Credit Agreement
dated January 31, 2014, as amended
PHMSA
United States Department of Transportation Pipeline and Hazardous Materials
Safety Administration
POP
Percent of Proceeds
Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
S&P
Standard & Poor’s Ratings Services
SCOOP
South Central Oklahoma Oil Province

4


SEC
Securities and Exchange Commission
West Texas LPG
West Texas LPG Pipeline Limited Partnership and Mesquite Pipeline
WTI
West Texas Intermediate
XBRL
eXtensible Business Reporting Language



5


PART I - FINANCIAL INFORMATION
 
 
 
 
 
 
 
ITEM 1. FINANCIAL STATEMENTS
 
 
 
 
 
 
 
ONEOK Partners, L.P. and Subsidiaries
 

 

 

 
CONSOLIDATED STATEMENTS OF INCOME
 

 

 

 
 
Three Months Ended

Nine Months Ended
 
September 30,

September 30,
(Unaudited)
2015

2014

2015

2014
 
(Thousands of dollars, except per unit amounts)
Revenues
 
 
 
 
 
 
 
Commodity sales
$
1,484,350

 
$
2,754,495

 
$
4,642,320

 
$
8,276,333

Services
414,068

 
364,874

 
1,188,364

 
1,071,074

Total revenues
1,898,418


3,119,369


5,830,684


9,347,407

Cost of sales and fuel
1,360,809


2,583,204


4,307,766


7,807,275

Net margin
537,609


536,165


1,522,918


1,540,132

Operating expenses
 


 


 


 

Operations and maintenance
145,933


152,533


444,185


425,715

Depreciation and amortization
87,517


73,901


259,563


212,083

General taxes
16,158


18,252


62,677


55,898

Total operating expenses
249,608


244,686


766,425


693,696

Gain (loss) on sale of assets
(443
)

1,534


(327
)

1,533

Operating income
287,558


293,013


756,166


847,969

Equity in net earnings (loss) from investments (Note J)
32,244


(52,347
)

93,205


6,747

Allowance for equity funds used during construction
177


1,723


1,718


13,947

Other income
41


79


106


3,003

Other expense
(3,845
)

(2,496
)

(3,941
)

(3,056
)
Interest expense (net of capitalized interest of $8,851, $14,303, $26,008 and $41,446, respectively)
(86,666
)

(70,060
)

(253,867
)

(211,344
)
Income before income taxes
229,509


169,912


593,387


657,266

Income tax (expense) benefit
156


(2,592
)

(5,080
)

(9,967
)
Net income
229,665


167,320


588,307


647,299

Less: Net income attributable to noncontrolling interests
2,704


73


5,982


226

Net income attributable to ONEOK Partners, L.P.
$
226,961


$
167,247


$
582,325


$
647,073

Limited partners’ interest in net income:
 


 


 


 

Net income attributable to ONEOK Partners, L.P.
$
226,961


$
167,247


$
582,325


$
647,073

General partner’s interest in net income
(105,078
)

(87,796
)

(293,868
)

(249,697
)
Limited partners’ interest in net income
$
121,883


$
79,451


$
288,457


$
397,376

Limited partners’ net income per unit, basic and diluted (Note I)
$
0.45


$
0.32


$
1.10


$
1.65

Number of units used in computation (thousands)
272,046


249,091


261,100


240,604

See accompanying Notes to Consolidated Financial Statements.


6


ONEOK Partners, L.P. and Subsidiaries
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
(Unaudited)
2015
 
2014
 
2015
 
2014
 
(Thousands of dollars)
Net income
$
229,665

 
$
167,320

 
$
588,307

 
$
647,299

Other comprehensive income (loss)
 

 
 

 
 

 
 

Unrealized gains (losses) on risk-management assets/liabilities
15,949

 
7,378

 
21,373

 
(81,592
)
Realized (gains) losses recognized in net income
(19,094
)
 
3,003

 
(43,785
)
 
39,845

Total other comprehensive income (loss)
(3,145
)
 
10,381

 
(22,412
)
 
(41,747
)
Comprehensive income
226,520

 
177,701

 
565,895

 
605,552

Less: Comprehensive income attributable to noncontrolling interests
2,704

 
73

 
5,982

 
226

Comprehensive income attributable to ONEOK Partners, L.P.
$
223,816

 
$
177,628

 
$
559,913

 
$
605,326

See accompanying Notes to Consolidated Financial Statements.

7


ONEOK Partners, L.P. and Subsidiaries
 

 
CONSOLIDATED BALANCE SHEETS
 

 

September 30,

December 31,
(Unaudited)
2015

2014
Assets
(Thousands of dollars)
Current assets
 

 
Cash and cash equivalents
$
7,263


$
42,530

Accounts receivable, net
584,309


735,830

Affiliate receivables
4,764


8,553

Natural gas and natural gas liquids in storage
142,308


134,134

Commodity imbalances
30,602


64,788

Materials and supplies
62,604


55,833

Other current assets
53,261


44,385

Total current assets
885,111


1,086,053

Property, plant and equipment
 


 

Property, plant and equipment
14,234,678


13,377,617

Accumulated depreciation and amortization
2,075,061


1,842,084

Net property, plant and equipment
12,159,617


11,535,533

Investments and other assets
 


 

Investments in unconsolidated affiliates
1,137,059


1,132,653

Goodwill and intangible assets
827,852


822,358

Other assets
21,405


23,803

Total investments and other assets
1,986,316


1,978,814

Total assets
$
15,031,044


$
14,600,400

Liabilities and equity
 


 

Current liabilities
 


 

Current maturities of long-term debt (Note F)
$
657,650


$
7,650

Notes payable (Note E)
287,272


1,055,296

Accounts payable
612,939


874,692

Affiliate payables
21,318


36,106

Commodity imbalances
96,192


104,650

Accrued interest
89,498


91,990

Other current liabilities
141,493


165,672

Total current liabilities
1,906,362


2,336,056

Long-term debt, excluding current maturities
6,145,603


6,004,232

Deferred credits and other liabilities
155,607


141,337

Commitments and contingencies (Note L)





Equity (Note G)
 


 

ONEOK Partners, L.P. partners’ equity:
 


 

General partner
237,860


211,914

Common units: 212,837,980 and 180,826,973 units issued and outstanding at
September 30, 2015, and December 31, 2014, respectively
5,252,840


4,456,372

Class B units: 72,988,252 units issued and outstanding at
September 30, 2015, and December 31, 2014
1,281,731


1,374,375

Accumulated other comprehensive loss (Note H)
(114,235
)

(91,823
)
Total ONEOK Partners, L.P. partners’ equity
6,658,196


5,950,838

Noncontrolling interests in consolidated subsidiaries
165,276


167,937

Total equity
6,823,472


6,118,775

Total liabilities and equity
$
15,031,044


$
14,600,400

See accompanying Notes to Consolidated Financial Statements.

8


ONEOK Partners, L.P. and Subsidiaries
 

 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 

 
 
Nine Months Ended
 
September 30,
(Unaudited)
2015

2014
 
(Thousands of dollars)
Operating activities
 

 
Net income
$
588,307


$
647,299

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
259,563


212,083

Allowance for equity funds used during construction
(1,718
)

(13,947
)
Loss (gain) on sale of assets
327


(1,533
)
Deferred income taxes
4,309


4,397

Equity in net earnings from investments
(93,205
)

(6,747
)
Distributions received from unconsolidated affiliates
92,042


84,298

Changes in assets and liabilities:
 


 

Accounts receivable
149,776


159,829

Affiliate receivables
3,789


3,256

Natural gas and natural gas liquids in storage
(8,174
)

(150,059
)
Accounts payable
(182,985
)

(33,945
)
Affiliate payables
(14,788
)

(18,076
)
Commodity imbalances, net
25,728


(36,094
)
Accrued interest
(2,492
)
 
(4,663
)
Risk-management assets and liabilities
(46,267
)
 
3,438

Other assets and liabilities, net
(27,186
)

37,519

Cash provided by operating activities
747,026


887,055

Investing activities
 


 

Capital expenditures (less allowance for equity funds used during construction)
(928,870
)

(1,172,950
)
Cash paid for acquisitions

 
(14,000
)
Contributions to unconsolidated affiliates
(27,540
)

(1,063
)
Distributions received from unconsolidated affiliates in excess of cumulative earnings
25,111


24,925

Proceeds from sale of assets
3,171


2,388

Other
(12,607
)
 

Cash used in investing activities
(940,735
)

(1,160,700
)
Financing activities
 


 

Cash distributions:
 


 

General and limited partners
(897,474
)

(768,094
)
Noncontrolling interests
(8,192
)

(353
)
Borrowing (repayment) of notes payable, net
(768,024
)
 

Issuance of long-term debt, net of discounts
798,896

 

Debt financing costs
(7,676
)
 

Repayment of long-term debt
(5,738
)
 
(5,738
)
Issuance of common units, net of issuance costs
1,025,660


947,472

Contribution from general partner
20,990


19,857

Cash provided by financing activities
158,442


193,144

Change in cash and cash equivalents
(35,267
)

(80,501
)
Cash and cash equivalents at beginning of period
42,530


134,530

Cash and cash equivalents at end of period
$
7,263


$
54,029

See accompanying Notes to Consolidated Financial Statements.

9


ONEOK Partners, L.P. and Subsidiaries
 
 
 
 
 
 
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
 
 
 
 
 
 
 
 
 
ONEOK Partners, L.P. Partners’ Equity
(Unaudited)
 

Common
Units
 
Class B
Units
 
General
Partner
 
Common
Units
 
 
(Units)
 
(Thousands of dollars)
January 1, 2015
 
180,826,973

 
72,988,252

 
$
211,914

 
$
4,456,372

Net income
 

 

 
293,868

 
208,119

Other comprehensive income (loss) (Note H)
 

 

 

 

Issuance of common units (Note G)
 
32,011,007

 

 

 
1,023,915

Contribution from general partner (Note G)
 

 

 
20,990

 

Distributions paid (Note G)
 

 

 
(288,912
)
 
(435,580
)
Other
 

 

 

 
14

September 30, 2015
 
212,837,980

 
72,988,252

 
$
237,860

 
$
5,252,840


 
 
ONEOK Partners, L.P. Partners’ Equity
(Unaudited)
 

Common
Units
 
Class B
Units
 
General
Partner
 
Common
Units
 
 
(Units)
 
(Thousands of dollars)
January 1, 2014
 
159,007,854

 
72,988,252

 
$
170,561

 
$
3,459,920

Net income
 

 

 
249,697

 
274,963

Other comprehensive income (loss) (Note H)
 

 

 

 

Issuance of common units (Note G)
 
18,346,627

 

 

 
955,108

Contribution from general partner (Note G)
 

 

 
19,760

 

Distributions paid (Note G)
 

 

 
(235,908
)
 
(369,057
)
September 30, 2014
 
177,354,481

 
72,988,252

 
$
204,110

 
$
4,320,934



10


ONEOK Partners, L.P. and Subsidiaries
 
 
 
 
 
 
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
 
 
 
 
(Continued)
 
 
 
 
 
 
 
 
 
ONEOK Partners, L.P. Partners’ Equity
 
 
 
(Unaudited)
 
Class B
Units
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests in
Consolidated
Subsidiaries
 
Total
Equity
 
 
(Thousands of dollars)
January 1, 2015
 
$
1,374,375

 
$
(91,823
)
 
$
167,937

 
$
6,118,775

Net income
 
80,338

 

 
5,982

 
588,307

Other comprehensive income (loss) (Note H)
 

 
(22,412
)
 

 
(22,412
)
Issuance of common units (Note G)
 

 

 

 
1,023,915

Contribution from general partner (Note G)
 

 

 

 
20,990

Distributions paid (Note G)
 
(172,982
)
 

 
(8,192
)
 
(905,666
)
Other
 

 

 
(451
)
 
(437
)
September 30, 2015
 
$
1,281,731

 
$
(114,235
)
 
$
165,276

 
$
6,823,472



 
ONEOK Partners, L.P. Partners’ Equity
 
 
 
(Unaudited)
 
Class B
Units
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests in
Consolidated
Subsidiaries
 
Total
Equity
 
 
(Thousands of dollars)
January 1, 2014
 
$
1,422,516

 
$
(58,837
)
 
$
4,536

 
$
4,998,696

Net income
 
122,413

 

 
226

 
647,299

Other comprehensive income (loss) (Note H)
 

 
(41,747
)
 

 
(41,747
)
Issuance of common units (Note G)
 

 

 

 
955,108

Contribution from general partner (Note G)
 

 

 

 
19,760

Distributions paid (Note G)
 
(163,129
)
 

 
(353
)
 
(768,447
)
September 30, 2014
 
$
1,381,800

 
$
(100,584
)
 
$
4,409

 
$
5,810,669




See accompanying Notes to Consolidated Financial Statements.


11


ONEOK PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented.  All such adjustments are of a normal recurring nature. The 2014 year-end consolidated balance sheet data was derived from our audited financial statements but does not include all disclosures required by GAAP.  These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

Our significant accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time.  At July 1, 2015, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than its carrying amount. Due to the current commodity price environment, we elected to perform a quantitative assessment, or Step 1 analysis, to test our goodwill for impairment.  The assessment included our current commodity price assumptions, expected contractual terms, anticipated operating costs and volume estimates.  Our goodwill impairment analysis performed as of July 1, 2015, did not result in an impairment charge nor did our analysis reflect any reporting units at risk.  In each reporting unit, the fair value substantially exceeded the carrying value. Subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets. 

Recently Issued Accounting Standards Update - In March 2015, the FASB issued ASU 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, “Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting,” which amended the SEC paragraphs of ASC Subtopic 835-30 to include the language from the SEC Staff Announcement indicating that the SEC would not object to presenting deferred debt issuance costs related to line-of-credit agreements as assets and subsequently amortizing the deferred debt issuance costs ratably over the term of the agreement. This guidance is effective for public companies for fiscal years beginning after December 15, 2015, with early adoption permitted. We elected to adopt this guidance beginning in the second quarter 2015. Retrospective adjustment of prior periods presented was required. Therefore, the December 31, 2014, balance sheet was recast to reclassify $34.1 million of debt issuance costs from other assets to long-term debt. The impact of adopting this guidance was not material.

In April 2014, the FASB issued ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” which alters the definition of a discontinued operation to include only asset disposals that represent a strategic shift with a major effect on an entity’s operations and financial results.  The amendment also requires more extensive disclosures about a discontinued operation’s assets, liabilities, income, expenses and cash flows. This guidance will be effective for interim and annual periods for all assets that are disposed of or classified as being held for sale in fiscal years that begin on or after December 15, 2014. We adopted this guidance beginning in the first quarter 2015, and it could impact us in the future if we dispose of any individually significant components.

In September 2015, the FASB issued ASU 2015-16, “Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments,” which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendment also requires the acquirer to record the income statement effects of changes to provisional amounts in the financial statements in the period in which the adjustments occurred. This guidance is effective for public companies for fiscal years beginning after December 15, 2015, with early adoption permitted. We expect to adopt this guidance in the first quarter 2016, and it could impact us in the future if we complete any acquisitions with subsequent measurement period adjustments.

In April 2015, the FASB issued ASU 2015-05, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement,” which clarifies whether a cloud computing arrangement includes a software license. If it does, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses; if not, the customer should not account for the

12


arrangement as a service contract. This guidance is effective for public companies for fiscal years beginning after December 15, 2015. Early adoption is permitted. We expect to adopt this guidance in the first quarter 2016, and we do not expect it to materially impact us.

In February 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which eliminates the presumption that a general partner should consolidate a limited partnership. It also modifies the evaluation of whether limited partnerships are variable interest entities or voting interest entities and adds requirements that limited partnerships must meet to qualify as voting interest entities. This guidance is effective for public companies for fiscal years beginning after December 15, 2015. We expect to adopt this guidance in the first quarter 2016, and we are evaluating the impact on us.

In August 2014, the FASB issued ASU 2014-15, “Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The standard applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We expect to adopt this guidance beginning in the fourth quarter 2016, and we do not expect it to materially impact us.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which outlines the principles an entity must apply to measure and recognize revenue for entities that enter into contracts to provide goods or services to their customers. The core principle is that an entity should recognize revenue at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services to a customer. The amendment also requires more extensive disaggregated revenue disclosures in interim and annual financial statements. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” that deferred the effective date of ASU 2014-09 by one year. This update is now effective for interim and annual periods that begin after December 15, 2017, with either retrospective application for all periods presented or retrospective application with a cumulative effect adjustment. We expect to adopt this guidance beginning in the first quarter 2018, and we are evaluating the impact on us.

B.
ACQUISITIONS

West Texas LPG Acquisition - In November 2014, we completed the acquisition of an 80 percent interest in the West Texas LPG Pipeline Limited Partnership and a 100 percent interest in the Mesquite Pipeline for approximately $800 million from affiliates of Chevron Corporation. We accounted for this acquisition as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition-date fair values. See Note B in the Notes to Consolidated Financial Statements in our Annual Report for additional information on this acquisition.

Our consolidated balance sheet as of September 30, 2015, reflects the final purchase price allocation. Adjustments to the preliminary purchase price allocation reported in Note B in the Notes to the Consolidated Financial Statements in our Annual Report were not material. Therefore, prior period financial statements have not been recast.

C.
FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date.  We use market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive.  This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values.  For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and implied forward LIBOR curves.  Inputs into our fair value estimates include commodity-exchange prices, over-the-counter quotes, historical correlations of pricing data, data obtained from third-party pricing services and LIBOR and other liquid money-market instrument rates.  We validate our valuation inputs with third-party information and settlement prices from other sources, where available. 


13


In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps.  We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.  We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and monitoring the credit default swap markets. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.

The fair value of our forward-starting interest-rate swaps are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest swap settlements.

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets, including NYMEX-settled prices. These balances are comprised predominantly of exchange-traded derivative contracts for natural gas and crude oil.
Level 2 - fair value measurements are based on significant observable pricing inputs, such as NYMEX-settled prices for natural gas and crude oil, and financial models that utilize implied forward LIBOR yield curves for interest-rate swaps.
Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including natural gas basis and NGL price curves that incorporate observable and unobservable market data from broker quotes, third-party pricing services, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. These balances categorized as Level 3 are comprised of derivatives for natural gas and NGLs. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness has not been material.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.
Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:
 
September 30, 2015
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net (b)
 
(Thousands of dollars)
Derivative assets
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
40,799

 
$

 
$
5,756

 
$
46,555

 
$
(29,319
)
 
$
17,236

Physical contracts

 

 
4,866

 
4,866

 

 
4,866

Total derivative assets
$
40,799

 
$

 
$
10,622

 
$
51,421

 
$
(29,319
)
 
$
22,102

Derivative liabilities
 

 
 

 
 

 
 

 
 

 
 

Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
(573
)
 
$

 
$
(5,326
)
 
$
(5,899
)
 
$
5,899

 
$

Interest-rate contracts

 
(13,648
)
 

 
(13,648
)
 

 
(13,648
)
Total derivative liabilities
$
(573
)
 
$
(13,648
)
 
$
(5,326
)
 
$
(19,547
)
 
$
5,899

 
$
(13,648
)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis.  We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At September 30, 2015, we held $23.4 million of cash from various counterparties and no cash collateral posted.
(b) - Included in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.


14


 
December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net (b)
 
(Thousands of dollars)
Derivative assets
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
42,880

 
$

 
$
354

 
$
43,234

 
$
(25,979
)
 
$
17,255

Physical contracts

 

 
9,922

 
9,922

 

 
9,922

Interest-rate contracts

 
2,288

 

 
2,288

 

 
2,288

Total derivative assets
$
42,880

 
$
2,288

 
$
10,276

 
$
55,444

 
$
(25,979
)
 
$
29,465

Derivative liabilities
 

 
 

 
 

 
 

 
 

 
 

Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
(169
)
 
$

 
$
(968
)
 
$
(1,137
)
 
$
1,137

 
$

Physical contracts

 

 
(23
)
 
(23
)
 

 
(23
)
Interest-rate contracts

 
(44,843
)
 

 
(44,843
)
 

 
(44,843
)
Total derivative liabilities
$
(169
)
 
$
(44,843
)
 
$
(991
)
 
$
(46,003
)
 
$
1,137

 
$
(44,866
)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2014, we held $24.8 million of cash from various counterparties and no cash collateral posted.
(b) - Included in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.

The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
Derivative Assets (Liabilities)
2015
 
2014
 
2015
 
2014
 
(Thousands of dollars)
Net assets (liabilities) at beginning of period
$
10,387

 
$
(1,313
)
 
$
9,285

 
$
(782
)
Total realized/unrealized gains (losses):


 


 
 
 
 
Included in earnings (a)
(15
)
 
207

 
95

 
(688
)
Included in other comprehensive income (loss)
(5,076
)
 
402

 
(4,084
)
 
(2,968
)
Purchases, issuances and settlements

 

 

 
3,734

Net assets (liabilities) at end of period
$
5,296

 
$
(704
)
 
$
5,296

 
$
(704
)
(a) - Included in commodity sales revenues in our Consolidated Statements of Income.

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the three and nine months ended September 30, 2015 and 2014, gains or losses included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities still held at the end of each reporting period were not material.

We recognize transfers into and out of the levels in the fair value hierarchy as of the end of each reporting period. During the three and nine months ended September 30, 2015 and 2014, there were no transfers between levels.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. Our notes payable are classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market.

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $6.6 billion and $6.4 billion at September 30, 2015, and December 31, 2014, respectively.  The book value of the aggregate of our senior notes outstanding, including current maturities, was $6.8 billion and $6.0 billion at September 30, 2015, and December 31, 2014, respectively.  The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities.  The estimated fair value of our long-term debt is classified as Level 2.


15


D.
RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold.  We use physical-forward purchases and sales and financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products; to reduce our exposure to interest-rate fluctuations; and to achieve more predictable cash flows.  We follow established policies and procedures to assess risk and approve, monitor and report our risk-management activities.  We have not used these instruments for trading purposes.  We are also subject to the risk of interest-rate fluctuation in the normal course of business.

Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate.  We use the following commodity derivative instruments to mitigate the near-term commodity price risk associated with a portion of the forecasted sales of these commodities:
Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;
Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or NGLs for future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties; and
Swaps - Exchange of one or more payments based on the value of one or more commodities. These instruments transfer the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability.

We may also use other instruments including options or collars to mitigate commodity price risk. Options are contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity at a fixed price within a specified period of time. Options may either be standardized and exchange traded or customized and nonexchange traded. A collar is a combination of a purchased put option and a sold call option, which places a floor and a ceiling price for commodity sales being hedged.

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of receiving commodities in exchange for services associated with our POP contracts. We also are exposed to basis risk between the various production and market locations where we receive and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs and condensate.

In our Natural Gas Liquids segment, we are exposed to location price differential risk, primarily as a result of the relative value of NGL purchases at one location and sales at another location. We are also exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines retain natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose us to commodity price risk depending on the regulatory treatment for this activity. To the extent that commodity price risk in our Natural Gas Pipelines segment is not mitigated by fuel cost-recovery mechanisms, we use physical-forward sales or purchases to reduce the impact of price fluctuations related to natural gas. At September 30, 2015, and December 31, 2014, there were no financial derivative instruments with respect to our natural gas pipeline operations.

Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. At December 31, 2014, we had forward-starting interest-rate swaps with notional amounts totaling $900 million that were designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. Upon our debt issuance in March 2015, we settled $500 million of our interest-rate swaps and realized a loss of $55.1 million, which is included in accumulated other comprehensive loss and will be amortized to interest expense over the term of the related debt. At September 30, 2015, our remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates of less than 12 months.


16


Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales transactions that are expected to result in physical delivery.  Commodity price and interest-rate volatility may have a significant impact on the fair value of derivative instruments as of a given date. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
 
 
Recognition and Measurement
Accounting Treatment
 
Balance Sheet
 
Income Statement
Normal purchases and normal sales
-
Fair value not recorded
-
Change in fair value not recognized in earnings
Mark-to-market
-
Recorded at fair value
-
Change in fair value recognized in earnings
Cash flow hedge
-
Recorded at fair value
-
Ineffective portion of the gain or loss on the
derivative instrument is recognized in earnings
 
-
Effective portion of the gain or loss on the
derivative instrument is reported initially
as a component of accumulated other
comprehensive income (loss)
-
Effective portion of the gain or loss on the
derivative instrument is reclassified out of
accumulated other comprehensive income (loss)
into earnings when the forecasted transaction
affects earnings
Fair value hedge
-
Recorded at fair value
-
The gain or loss on the derivative instrument is
recognized in earnings
 
-
Change in fair value of the hedged item is
recorded as an adjustment to book value
-
Change in fair value of the hedged item is
recognized in earnings

To reduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forward purchases and sales, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate. Interest-rate swaps are used from time to time to manage interest-rate risk. Under certain conditions, we designate our derivative instruments as a hedge of exposure to changes in fair values or cash flows. We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives and strategies for undertaking various hedge transactions, and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the forecasted transaction that has been designated as the hedged item in a cash flow hedge relationship. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis.

Cash flows from futures, forwards and swaps that are accounted for as hedges are included in the same category as the cash flows from the related hedged items in our Consolidated Statements of Cash Flows.


17


Fair Values of Derivative Instruments - See Note C for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments for the periods indicated:
 
September 30, 2015
 
December 31, 2014
 
Assets (a)
 
(Liabilities) (a)
 
Assets (a)
 
(Liabilities) (a)
 
(Thousands of dollars)
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Financial contracts
$
45,534

 
$
(5,108
)
 
$
43,234

 
$
(1,137
)
Physical contracts
4,866

 

 
9,922

 

Interest-rate contracts

 
(13,648
)
 
2,288

 
(44,843
)
Total derivatives designated as hedging instruments
50,400

 
(18,756
)
 
55,444

 
(45,980
)
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Financial contracts
1,021

 
(791
)
 

 

Physical contracts

 

 

 
(23
)
Total derivatives not designated as hedging instruments
1,021

 
(791
)
 

 
(23
)
Total derivatives
$
51,421

 
$
(19,547
)
 
$
55,444

 
$
(46,003
)
(a) - Included on a net basis in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:
 
 
September 30, 2015
 
December 31, 2014
 
Contract
Type
Purchased/
Payor
 
Sold/
Receiver
 
Purchased/
Payor
 
Sold/
Receiver
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Cash flow hedges
 
 
 
 
 
 
 
 
Fixed price
 
 
 
 
 
 
 
 
- Natural gas (Bcf)
Futures and swaps

 
(38.7
)
 

 
(41.2
)
- Crude oil and NGLs (MMBbl)
Futures, forwards
and swaps

 
(3.5
)
 

 
(0.5
)
Basis
 
 

 
 

 
 

 
 

- Natural gas (Bcf)
Futures and swaps

 
(38.7
)
 

 
(41.2
)
Interest-rate contracts (Millions of dollars)
Forward-starting
swaps
$
400.0

 
$

 
$
900.0

 
$

Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Fixed price
 
 
 
 
 
 
 
 
- Crude oil and NGLs (MMBbl)
Futures, forwards
and swaps
0.5

 
(0.5
)
 

 


These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and, consequently, do not reflect our actual exposure to market or credit risk.

Cash Flow Hedges - At September 30, 2015, our Consolidated Balance Sheet reflected a net loss of $114.2 million in accumulated other comprehensive loss.  The portion of accumulated other comprehensive loss attributable to our commodity derivative financial instruments is an unrealized gain of $46.2 million, which will be realized within the next 15 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will realize $41.2 million in net gains over the next 12 months and $5.0 million in net gains thereafter.  The amount deferred in accumulated other comprehensive loss attributable to our settled interest-rate swaps is a loss of $145.5 million, which will be recognized over the life of the long-term, fixed-rate debt, including losses of $15.5 million that will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive loss are attributable primarily to forward-starting interest-rate swaps with future settlement dates, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.


18


The following table sets forth the unrealized effect of cash flow hedges recognized in other comprehensive income (loss) for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
Derivatives in Cash Flow
Hedging Relationships
September 30,
 
September 30,
2015
 
2014
 
2015
 
2014
 
(Thousands of dollars)
Commodity contracts
$
36,559

 
$
17,133

 
$
47,650

 
$
(24,743
)
Interest-rate contracts
(20,610
)
 
(9,755
)
 
(26,277
)
 
(56,849
)
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)
$
15,949

 
$
7,378

 
$
21,373

 
$
(81,592
)

The following table sets forth the effect of cash flow hedges in our Consolidated Statements of Income for the periods indicated:
Derivatives in Cash Flow
Hedging Relationships
Location of Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income
(Loss) into Net Income (Effective Portion)
Three Months Ended
 
Nine Months Ended
September 30,
 
September 30,
2015
 
2014
 
2015
 
2014
 
 
(Thousands of dollars)
Commodity contracts
Commodity sales revenues
$
22,770

 
$
(355
)
 
$
54,020

 
$
(31,961
)
Interest-rate contracts
Interest expense
(3,676
)
 
(2,648
)
 
(10,235
)
 
(7,884
)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)
$
19,094

 
$
(3,003
)
 
$
43,785

 
$
(39,845
)

Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2015 and 2014. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and nine months ended September 30, 2015 and 2014.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated, and for those customers, we use internally developed credit ratings.

Some of our financial derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with contingent features related to credit risk that were in a net liability position at September 30, 2015.

The counterparties to our derivative contracts consist primarily of major energy companies, financial institutions and commercial and industrial end users. This concentration of counterparties may affect our overall exposure to credit risk, either positively or negatively, in that the counterparties may be affected similarly by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

At September 30, 2015, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial services sector.

E.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

Partnership Credit Agreement - At September 30, 2015, we had $287.3 million of commercial paper outstanding, $14.0 million in letters of credit issued and no borrowings under our Partnership Credit Agreement.


19


Our Partnership Credit Agreement, which is scheduled to expire in January 2019, is a $2.4 billion revolving credit facility and includes a $100 million sublimit for the issuance of standby letters of credit and a $150 million swingline sublimit. Our Partnership Credit Agreement is available for general partnership purposes. During the first quarter 2015, we increased the size of our Partnership Credit Agreement to $2.4 billion from $1.7 billion by exercising our option to increase the capacity of the facility through increased commitments from existing lenders and a commitment from one new lender. During the first quarter 2015, we also increased the size of our commercial paper program to $2.4 billion from $1.7 billion. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement.

Our Partnership Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Under the terms of the Partnership Credit Agreement, based on our current credit ratings, borrowings, if any, will accrue at LIBOR plus 117.5 basis points, and the annual facility fee is 20 basis points. Our Partnership Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership. Borrowings under our Partnership Credit Agreement are nonrecourse to ONEOK.

Our Partnership Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1.  If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter in which the acquisition was completed and the two following quarters.  As a result of the West Texas LPG acquisition we completed in the fourth quarter 2014, the allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to 1 through the second quarter 2015. If we were to breach certain covenants in our Partnership Credit Agreement, amounts outstanding under our Partnership Credit Agreement, if any, may become due and payable immediately.  At September 30, 2015, our ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Neither we nor ONEOK guarantees the debt or other similar commitments of unaffiliated parties. ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners, and ONEOK Partners does not guarantee the debt or other similar commitments of ONEOK.

F.
LONG-TERM DEBT

In March 2015, we completed an underwritten public offering of $800 million of senior notes, consisting of $300 million, 3.8 percent senior notes due 2020, and $500 million, 4.9 percent senior notes due 2025. The net proceeds, after deducting underwriting discounts, commissions and other expenses, were approximately $792.3 million. We used the proceeds to repay amounts outstanding under our commercial paper program and for general partnership purposes.

These notes are governed by an indenture, dated September 25, 2006, between us and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and to sell and lease back our property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of our outstanding senior notes to declare those notes immediately due and payable in full.

We may redeem our 3.8 percent senior notes due 2020 and our 4.9 percent senior notes due 2025 from the March 2015 offering at par, plus accrued and unpaid interest to the redemption date, starting one month and three months, respectively, before their maturity dates. Prior to these dates, we may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. Our senior notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and structurally subordinate to any of the existing and future debt and other liabilities of any nonguarantor subsidiaries.

Our $650 million, 3.25 percent senior notes mature on February 1, 2016. The carrying amount of these notes is reflected in current portion of long-term debt in our Consolidated Balance Sheet as of September 30, 2015.


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G.
EQUITY

ONEOK - ONEOK and its affiliates owned all of the Class B units, 41.3 million common units and the entire 2 percent general partner interest in us, which together constituted a 41.2 percent ownership interest in us at September 30, 2015.

Equity Issuances - In August 2015, we completed a private placement of approximately 21.5 million common units at a price of $30.17 per unit with ONEOK. Additionally, we completed a concurrent sale of approximately 3.3 million common units at a price of $30.17 per unit to funds managed by Kayne Anderson Capital Advisors in a registered direct offering, which were issued through our existing “at-the-market” equity program. The combined offerings generated net cash proceeds of approximately $749 million. In conjunction with these issuances, ONEOK Partners GP contributed approximately $15.3 million in order to maintain its 2 percent general partner interest in us. We used the proceeds for general partnership purposes, including capital expenditures and repayment of commercial paper borrowings. No other units were sold through the “at-the-market” program during the three months ended September 30, 2015.

We have an “at-the-market” equity program for the offer and sale from time to time of our common units, up to an aggregate amount of $650 million. The program allows us to offer and sell our common units at prices we deem appropriate through a sales agent. Sales of common units are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program. At September 30, 2015, we had approximately $138 million of registered common units available for issuance through our “at-the-market” equity program.

During the nine months ended September 30, 2015, we sold approximately 10.5 million common units through our “at-the-market” equity program, including the units sold to funds managed by Kayne Anderson Capital Advisors in the registered direct offering discussed above. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $381.6 million, which were used for general partnership purposes, including repayment of commercial paper borrowings.

In May 2014, we completed an underwritten public offering of approximately 13.9 million common units at a public offering price of $52.94 per common unit, generating net proceeds of approximately $714.5 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $15.0 million in order to maintain its 2 percent general partner interest in us. We used the proceeds for general partnership purposes, including capital expenditures and repayment of commercial paper borrowings.

During the three months ended September 30, 2014, we sold approximately 1.4 million common units through our “at-the-market” equity program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $81.3 million, which were used for general partnership purposes.

During the nine months ended September 30, 2014, we sold approximately 4.4 million common units through our “at-the-market” equity program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $245.4 million, which were used for general partnership purposes.

Partnership Agreement - Available cash, as defined in our Partnership Agreement, generally will be distributed to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. Our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. Under the incentive distribution provisions, as set forth in our Partnership Agreement, our general partner receives:
15 percent of amounts distributed in excess of $0.3025 per unit;
25 percent of amounts distributed in excess of $0.3575 per unit; and
50 percent of amounts distributed in excess of $0.4675 per unit.

Cash Distributions - In October 2015, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the third quarter 2015, which will be paid on November 13, 2015, to unitholders of record at the close of business on November 2, 2015.


21


The following table shows our distributions paid during the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(Thousands, except per unit amounts)
Distribution per unit
$
0.79

 
$
0.76

 
$
2.37

 
$
2.235

 
 
 
 
 
 
 
 
General partner distributions
$
6,081

 
$
5,501

 
$
17,950

 
$
15,361

Incentive distributions
91,794

 
80,381

 
270,962

 
220,547

Distributions to general partner
97,875

 
85,882

 
288,912

 
235,908

Limited partner distributions to ONEOK
73,302

 
70,519

 
219,907

 
207,381

Limited partner distributions to other unitholders
132,862

 
118,644

 
388,655

 
324,805

Total distributions paid
$
304,039

 
$
275,045

 
$
897,474

 
$
768,094


Distributions are declared and paid within 45 days of the completion of each quarter. The following table shows our distributions declared for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(Thousands, except per unit amounts)
Distribution per unit
$
0.79

 
$
0.775

 
$
2.37

 
$
2.280

 
 
 
 
 
 
 
 
General partner distributions
$
6,660

 
$
5,683

 
$
18,696

 
$
16,195

Incentive distributions
100,538

 
84,452

 
282,221

 
236,744

Distributions to general partner
107,198

 
90,135

 
300,917

 
252,939

Limited partner distributions to ONEOK
90,323

 
71,911

 
236,927

 
211,557

Limited partner distributions to other unitholders
135,480

 
122,105

 
396,925

 
345,255

Total distributions declared
$
333,001

 
$
284,151

 
$
934,769

 
$
809,751


Noncontrolling Interest - In November 2014, we completed the acquisition of an 80 percent interest in the West Texas LPG Pipeline Limited Partnership (WTLPG). We consolidate WTLPG as we control the system. We have recorded noncontrolling interests in consolidated subsidiaries on our consolidated financial statements to recognize the portion of WTLPG that we do not own. Prior to November 2014, our noncontrolling interests in consolidated subsidiaries were not material.

H.
ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive loss for the period indicated:
 
 
Accumulated
Other
Comprehensive
Loss (a)
 
 
(Thousands of dollars)
January 1, 2015
 
$
(91,823
)
Other comprehensive loss before reclassifications
 
21,373

Amounts reclassified from accumulated other comprehensive loss
 
(43,785
)
Net current-period other comprehensive loss attributable to ONEOK Partners
 
(22,412
)
September 30, 2015
 
$
(114,235
)
(a) - All amounts are attributable to unrealized losses in risk-management assets/liabilities.


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The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Consolidated Statements of Income for the periods indicated:
Details about Accumulated Other
Comprehensive Income (Loss)
Components
 
Three Months Ended
 
Nine Months Ended
 
Affected Line Item in the
Consolidated Statements of
Income
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
 
(Thousands of dollars)
 
 
Unrealized (gains) losses on risk-management assets/liabilities
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(22,770
)
 
$
355

 
$
(54,020
)
 
$
31,961

 
Commodity sales revenues
Interest-rate contracts
 
3,676

 
2,648

 
10,235

 
7,884

 
Interest expense
Total reclassifications for the period attributable to ONEOK Partners
 
$
(19,094
)
 
$
3,003

 
$
(43,785
)
 
$
39,845

 
Net income attributable to ONEOK Partners

I.
LIMITED PARTNERS’ NET INCOME PER UNIT

Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units. Because ONEOK has conditionally waived its right to increased quarterly distributions, until it gives 90 days notice of the withdrawal of the waiver, currently each Class B and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences.

ONEOK Partners GP owns the entire 2 percent general partnership interest in us, which entitles it to incentive distribution rights that provide for an increasing proportion of cash distributions from the Partnership as the distributions made to limited partners increase above specified levels. For purposes of our calculation of limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is allocated to the general partner as follows: (i) an amount based upon the 2 percent general partner interest in net income attributable to ONEOK Partners, L.P.; and (ii) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared for the period.

The terms of our Partnership Agreement limit the general partner’s incentive distribution to the amount of available cash calculated for the period. As such, incentive distribution rights are not allocated on undistributed earnings. For additional information regarding our general partner’s incentive distribution rights, see “Partnership Agreement” in Note G.

J.
UNCONSOLIDATED AFFILIATES

Equity in Net Earnings from Investments - The following table sets forth our equity in net earnings from investments for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(Thousands of dollars)
Share of investee earnings
 
 
 
 
 
 
 
Northern Border Pipeline
$
16,156

 
$
14,371

 
$
51,131

 
$
53,657

Overland Pass Pipeline Company
10,538

 
3,856

 
27,048

 
12,708

Other (a)
5,550

 
(17,153
)
 
15,026

 
(6,197
)
Total share of investee earnings
32,244

 
1,074

 
93,205

 
60,168

Impairment of investment in Bighorn Gas Gathering

 
(53,421
)
 

 
(53,421
)
Equity in net earnings (loss) from investments
$
32,244

 
$
(52,347
)
 
$
93,205

 
$
6,747

(a) - Includes proportionate share of investee impairment of long-lived assets charge on Bighorn Gas Gathering of $23.0 million for the three and nine months ended September 30, 2014.


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Unconsolidated Affiliates Financial Information - The following table sets forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(Thousands of dollars)
Income Statement
 
 
 
 
 
 
 
Operating revenues
$
135,474

 
$
126,218

 
$
390,793

 
$
403,006

Operating expenses (a)
$
64,786

 
$
123,620

 
$
178,324

 
$
247,169

Net income (loss) (a)
$
67,121

 
$
(5,119
)
 
$
196,123

 
$
134,432

 
 
 
 
 
 
 
 
Distributions paid to us
$
36,370

 
$
31,574

 
$
117,153

 
$
109,223

(a) - Includes long-lived asset impairment charge on Bighorn Gas Gathering for the three and nine months ended September 30, 2014.

We incurred expenses in transactions with unconsolidated affiliates of $28.4 million and $15.0 million for the three months ended September 30, 2015 and 2014, respectively, and $74.2 million and $43.5 million for the nine months ended September 30, 2015 and 2014, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline Company. Accounts payable to our equity method investees at September 30, 2015, and December 31, 2014, were $9.4 million and $20.5 million, respectively.

Roadrunner Gas Transmission - In March 2015, we entered into a 50-50 joint venture named Roadrunner Gas Transmission (Roadrunner) with a subsidiary of Fermaca Infrastructure B.V. (Fermaca), a Mexico City-based natural gas infrastructure company, to construct a pipeline to transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. During the nine months ended September 30, 2015, we contributed approximately $30 million to Roadrunner.

Powder River Basin Equity Method Investments - Crude oil and natural gas producers have primarily focused their development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the coal-bed methane areas in the Powder River Basin. The reduced coal-bed methane development activities and natural production declines in the dry natural gas formations of the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the dry natural gas formations of the Powder River Basin still exists, future drilling and development in this area will be affected by commodity prices and producers’ alternative prospects.

The current commodity price environment has caused natural gas producers to reduce drilling for natural gas, which we expect will slow volume growth or reduce volumes of natural gas delivered to systems owned by our Powder River Basin equity method investments. A continued decline in volumes gathered in the coal-bed methane area of the Powder River Basin may reduce our ability to recover the carrying value of our equity investments in this area and could result in noncash charges to earnings. The net book value of our equity method investments in this dry natural gas area is $214.2 million, which includes $130.5 million of equity method goodwill.

K.
RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Prior to April 1, 2014, our Natural Gas Gathering and Processing segment sold natural gas to ONEOK and its subsidiaries, and our Natural Gas Pipelines segment provided transportation and storage services to ONEOK and its subsidiaries. Additionally, our Natural Gas Gathering and Processing segment and Natural Gas Liquids segment purchased a portion of the natural gas used in their operations from ONEOK and its subsidiaries.

On January 31, 2014, ONEOK completed the separation of its former natural gas distribution business into ONE Gas. ONE Gas was an affiliate prior to this separation. Commodity sales and services revenues in the Consolidated Statements of Income for the one month ended January 31, 2014, for transactions with ONE Gas prior to the separation are reflected as affiliate transactions. Transactions with ONE Gas that occurred after the separation are reflected as unaffiliated, third-party transactions.

On March 31, 2014, ONEOK completed the wind down of ONEOK Energy Services Company, a subsidiary of ONEOK. For the first quarter 2014, we had transactions with ONEOK Energy Services Company, which are reflected as affiliate transactions.


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Under the Services Agreement with ONEOK and ONEOK Partners GP (the Services Agreement), our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides to us similar services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP operates Guardian Pipeline, Viking Gas Transmission and Midwestern Gas Transmission according to each pipeline’s operating agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK to fulfill its operating obligations.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, legal and administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are incurred specifically on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. Beginning in the second quarter 2014, ONEOK allocates substantially all of its general overhead costs to us as a result of ONEOK’s separation of its natural gas distribution business and the wind down of its energy services business in the first quarter 2014. For the first quarter 2014, it is not practicable to determine what these general overhead costs would have been on a stand-alone basis. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

The following table sets forth the transactions with related parties for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
(Thousands of dollars)
Revenues
$

 
$

 
$

 
$
53,526

Expenses
 

 
 

 
 

 
 

Cost of sales and fuel
$

 
$

 
$

 
$
10,835

Operating expenses
89,342

 
84,221

 
265,611

 
240,172

Total expenses
$
89,342

 
$
84,221

 
$
265,611

 
$
251,007


ONEOK Partners GP made additional general partner contributions to us of approximately $21.0 million and $19.8 million during the nine months ended September 30, 2015 and 2014, respectively, to maintain its 2 percent general partner interest in connection with the issuances of common units.  See Note G for additional information about cash distributions paid to ONEOK for its general partner and limited partner interests.

L.
COMMITMENTS AND CONTINGENCIES

Environmental Matters - We are subject to multiple historical preservation, wildlife preservation and environmental laws and/or regulations that affect many aspects of our present and future operations.  Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands preservation, hazardous materials transportation, and pipeline and facility construction.  These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals.  Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations.  For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows.  In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities.  We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us.

In June 2013, the Executive Office of the President of the United States (the President) issued the President’s Climate Action Plan, which includes, among other things, plans for further regulatory actions to reduce carbon emissions from various sources. On March 28, 2014, the President released the Climate Action Plan - Strategy to Reduce Methane Emissions (Methane Strategy) that lists a number of actions the federal agencies will undertake to continue to reduce above-ground methane emissions from several industries, including the oil and natural gas sectors. The proposed measures outlined in the Methane Strategy include, without limitation, the following: collaboration with the states to encourage emission reductions; standards to

25


minimize natural gas venting and flaring on public lands; policy recommendations for reducing emissions from energy infrastructure to increase the performance of the nation’s energy transmission, storage and distribution systems; and continued efforts by PHMSA to require pipeline operators to take steps to eliminate leaks and prevent accidental methane releases and evaluate the progress of states in replacing cast-iron pipelines. The impact of any such regulatory actions on our facilities and operations is unknown. We continue to monitor these developments and the impact they may have on our businesses. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a significant impact on our business, financial position, results of operations and cash flows.

Our expenditures for environmental assessment, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters have had no material effects on earnings or cash flows during the three and nine months ended September 30, 2015 and 2014.

In April 2014, the EPA and the United States Army Corps of Engineers proposed a joint rule-making to redefine the definition of “Waters of the United States” under the Clean Water Act. The final rule was published on June 29, 2015, and became effective on August 28, 2015. The final rule is not expected to result in material impacts on our projects, facilities and operations.

The EPA’s “Triggering and Tailoring Rules” regulate GHG emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology (BACT), conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. At current emission threshold levels, this rule has had a minimal impact on our existing facilities. In addition, on June 23, 2014, the Supreme Court of the United States (Supreme Court), in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit GHG emissions alone cannot subject a facility to the permitting requirements for major stationary source provisions of the Clean Air Act. The decision invalidated the EPA’s current Triggering and Tailoring Rule for GHG Prevention of Significant Deterioration (PSD) and Title V requirements as applied to facilities considered major sources only for GHGs (referred to as Step 2 sources). However, the Supreme Court also ruled that to the extent a source pursues a capital project (new construction or expansion of existing facility), which otherwise subjects the source to major source PSD permitting for conventional criteria pollutants, the permitting authorities may impose BACT analysis and emission limits for GHGs from those sources.

In April 2015, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), on remand from the Supreme Court, issued its further Order following the Supreme Court’s decision in Utility Air Regulatory Group v. EPA. The D.C. Circuit’s Order included the following: (1) it formally vacated EPA regulations implementing the Tailoring Rule to the extent that they require a stationary source to obtain a PSD or Title V permit based solely on the source’s GHG emissions; and (2) ordered the EPA to consider whether any further revisions to its regulations are appropriate in light of the Supreme Court’s decision. On April 30, 2015, the EPA issued a direct final rule to allow for the rescission of Clean Air Act PSD permits issued by the EPA or delegated state and local permitting authorities under Step 2 of the GHG Tailoring Rule. The direct final rule was to become effective unless adverse comments were received by the EPA. On August 19, 2015, the EPA published the direct final rule in the Federal Register to confirm that no adverse comments were received and that the rule was now in effect. We do not expect the direct final rule to have a material impact on our existing operations or design decisions for new project applications.

In July 2011, the EPA issued a proposed rule that would change the air emissions New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification.

In September 2015, the EPA published several proposed rule-makings in the Federal Register that affect the oil and gas industry. The rule-makings included, but were not limited to, proposed amendments to the NSPS rule. The proposed amendments to the NSPS rule included, in part, the proposed direct regulation of methane emissions for the first time as an individual air pollutant from oil and gas sources, as part of the President’s Methane Strategy. Comments on the proposed rule-makings remain ongoing.

In October