ONEOK Partners LP - FORM 10-Q - August 6, 2014

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EX-31.2 - CERTIFICATION OF DEREK S. REINERS SECTION 302 - ONEOK Partners LPoksq22014exhibit312.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 June 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   1-12202


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 July 29, 2014
Common units
 
175,910,629 units
Class B units
 
72,988,252 units





























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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, 2013
ASU
Accounting Standards Update
Bbl
Barrels, 1 barrel is equivalent to 42 United States gallons
Bbl/d
Barrels per day
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Btu
British thermal units, a measure of the amount of heat required to raise the
temperature of one pound of water one degree Fahrenheit
CFTC
Commodities 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
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
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
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
MMBtu/d
Million British thermal units per day
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 $1.7 billion Amended and Restated Revolving Credit
Agreement dated January 31, 2014
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
Securities Act
Securities Act of 1933, as amended
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

Six Months Ended
 
June 30,

June 30,
(Unaudited)
2014

2013

2014

2013
 
(Thousands of dollars, except per unit amounts)
Revenues
 
 
 
 
 
 
 
Commodity sales
$
2,715,109

 
$
2,447,411

 
$
5,521,838

 
$
4,646,205

Services
350,626

 
320,768

 
706,200

 
639,421

Total revenues
3,065,735


2,768,179


6,228,038


5,285,626

Cost of sales and fuel
2,571,402


2,356,226


5,224,071


4,503,074

Net margin
494,333


411,953


1,003,967


782,552

Operating expenses
 


 


 


 

Operations and maintenance
142,664


108,086


273,182


229,375

Depreciation and amortization
71,447


58,226


138,182


112,904

General taxes
17,981


15,890


37,646


32,865

Total operating expenses
232,092


182,202


449,010


375,144

Gain (loss) on sale of assets
(16
)

279


(1
)

320

Operating income
262,225


230,030


554,956


407,728

Equity earnings from investments (Note H)
25,435


26,421


59,094


52,276

Allowance for equity funds used during construction
1,253


5,656


12,224


14,743

Other income
3,189


771


4,522


4,476

Other expense
(1,389
)

(377
)

(2,158
)

(1,858
)
Interest expense (net of capitalized interest of $11,375, $11,359, $27,143 and $23,964, respectively)
(73,008
)

(57,524
)

(141,284
)

(113,396
)
Income before income taxes
217,705


204,977


487,354


363,969

Income taxes
(3,194
)

(2,523
)

(7,375
)

(4,830
)
Net income
214,511


202,454


479,979


359,139

Less: Net income attributable to noncontrolling interests
77


87


153


173

Net income attributable to ONEOK Partners, L.P.
$
214,434


$
202,367


$
479,826


$
358,966

Limited partners’ interest in net income:
 


 


 


 

Net income attributable to ONEOK Partners, L.P.
$
214,434


$
202,367


$
479,826


$
358,966

General partner’s interest in net income
(84,669
)

(66,680
)

(161,901
)

(131,388
)
Limited partners’ interest in net income
$
129,765


$
135,687


$
317,925


$
227,578

Limited partners’ net income per unit, basic and diluted (Note G)
$
0.54


$
0.62


$
1.35


$
1.03

Number of units used in computation (thousands)
240,503


220,116


236,361


219,988

See accompanying Notes to Consolidated Financial Statements.


6

ONEOK Partners, L.P. and Subsidiaries
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(Unaudited)
2014
 
2013
 
2014
 
2013
 
(Thousands of dollars)
Net income
$
214,511

 
$
202,454

 
$
479,979

 
$
359,139

Other comprehensive income (loss)
 

 
 

 
 

 
 

Unrealized gains (losses) on derivatives
(32,515
)
 
55,362

 
(88,970
)
 
42,382

Realized (gains) losses on derivatives recognized in net income
7,834

 
1,330

 
36,842

 
1,069

Total other comprehensive income (loss)
(24,681
)
 
56,692

 
(52,128
)
 
43,451

Comprehensive income
189,830

 
259,146

 
427,851

 
402,590

Less: Comprehensive income attributable to noncontrolling interests
77

 
87

 
153

 
173

Comprehensive income attributable to ONEOK Partners, L.P.
$
189,753

 
$
259,059

 
$
427,698

 
$
402,417

See accompanying Notes to Consolidated Financial Statements.

7

ONEOK Partners, L.P. and Subsidiaries
 

 
CONSOLIDATED BALANCE SHEETS
 

 

June 30,

December 31,
(Unaudited)
2014

2013
Assets
(Thousands of dollars)
Current assets
 

 
Cash and cash equivalents
$
278,029


$
134,530

Accounts receivable, net
1,077,512


1,103,130

Affiliate receivables
8,340


9,185

Natural gas and natural gas liquids in storage
335,116


188,286

Commodity imbalances
93,070


80,481

Other current assets
92,339


67,491

Total current assets
1,884,406


1,583,103

Property, plant and equipment
 


 

Property, plant and equipment
11,516,931


10,755,048

Accumulated depreciation and amortization
1,774,798


1,652,648

Net property, plant and equipment
9,742,133


9,102,400

Investments and other assets
 


 

Investments in unconsolidated affiliates (Note H)
1,212,408


1,229,838

Goodwill and intangible assets
826,297


832,180

Other assets
83,271


115,087

Total investments and other assets
2,121,976


2,177,105

Total assets
$
13,748,515


$
12,862,608

Liabilities and equity
 


 

Current liabilities
 


 

Current maturities of long-term debt
$
7,650


$
7,650

Notes payable (Note D)
—


—

Accounts payable
1,260,334


1,255,411

Affiliate payables
39,780


47,458

Commodity imbalances
207,456


213,577

Accrued interest
92,214

 
92,711

Other current liabilities
142,935


89,211

Total current liabilities
1,750,369


1,706,018

Long-term debt, excluding current maturities
6,041,618


6,044,867

Deferred credits and other liabilities
129,614


113,027

Commitments and contingencies (Note J)





Equity (Note E)
 


 

ONEOK Partners, L.P. partners’ equity:
 


 

General partner
200,757


170,561

Common units: 175,910,629 and 159,007,854 units issued and outstanding at
June 30, 2014, and December 31, 2013, respectively
4,318,705


3,459,920

Class B units: 72,988,252 units issued and outstanding at
June 30, 2014, and December 31, 2013
1,413,909


1,422,516

Accumulated other comprehensive loss (Note F)
(110,965
)

(58,837
)
Total ONEOK Partners, L.P. partners’ equity
5,822,406


4,994,160

Noncontrolling interests in consolidated subsidiaries
4,508


4,536

Total equity
5,826,914


4,998,696

Total liabilities and equity
$
13,748,515


$
12,862,608

See accompanying Notes to Consolidated Financial Statements.

8

ONEOK Partners, L.P. and Subsidiaries
 

 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 

 
 
Six Months Ended
 
June 30,
(Unaudited)
2014

2013
 
(Thousands of dollars)
Operating activities
 

 
Net income
$
479,979


$
359,139

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
138,182


112,904

Allowance for equity funds used during construction
(12,224
)

(14,743
)
Loss (gain) on sale of assets
1


(320
)
Deferred income taxes
3,402


3,022

Equity earnings from investments
(59,094
)

(52,276
)
Distributions received from unconsolidated affiliates
61,200


51,546

Changes in assets and liabilities:
 


 

Accounts receivable
23,674


57,998

Affiliate receivables
845


2,953

Natural gas and natural gas liquids in storage
(146,830
)

(26,410
)
Accounts payable
68,045


(23,484
)
Affiliate payables
(7,678
)

(35,988
)
Commodity imbalances, net
(18,710
)

(59,621
)
Accrued interest
(497
)
 
(1,986
)
Other assets and liabilities, net
3,783


10,727

Cash provided by operating activities
534,078


383,461

Investing activities
 


 

Capital expenditures (less allowance for equity funds used during construction)
(792,414
)

(924,832
)
Acquisition
(14,000
)
 
—

Contributions to unconsolidated affiliates
(1,063
)

(4,558
)
Distributions received from unconsolidated affiliates
16,449


17,958

Proceeds from sale of assets
319


324

Cash used in investing activities
(790,709
)

(911,108
)
Financing activities
 


 

Cash distributions:
 


 

General and limited partners
(493,049
)

(444,352
)
Noncontrolling interests
(181
)

(294
)
Borrowing of notes payable, net
—

 
429,000

Repayment of long-term debt
(3,825
)
 
(3,825
)
Issuance of common units, net of issuance costs
878,765


15,942

Contribution from general partner
18,420


332

Cash provided by (used in) financing activities
400,130


(3,197
)
Change in cash and cash equivalents
143,499


(530,844
)
Cash and cash equivalents at beginning of period
134,530


537,074

Cash and cash equivalents at end of period
$
278,029


$
6,230

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, 2014
 
159,007,854

 
72,988,252

 
$
170,561

 
$
3,459,920

Net income
 
—

 
—

 
161,901

 
218,874

Other comprehensive income (loss) (Note F)
 
—

 
—

 
—

 
—

Issuance of common units (Note E)
 
16,902,775

 
—

 
—

 
875,276

Contribution from general partner (Note E)
 
—

 
—

 
18,321

 
—

Distributions paid (Note E)
 
—

 
—

 
(150,026
)
 
(235,365
)
June 30, 2014
 
175,910,629

 
72,988,252

 
$
200,757

 
$
4,318,705

See accompanying Notes to Consolidated Financial Statements.

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, 2014
 
$
1,422,516

 
$
(58,837
)
 
$
4,536

 
$
4,998,696

Net income
 
99,051

 
—

 
153

 
479,979

Other comprehensive income (loss) (Note F)
 
—

 
(52,128
)
 
—

 
(52,128
)
Issuance of common units (Note E)
 
—

 
—

 
—

 
875,276

Contribution from general partner (Note E)
 
—

 
—

 
—

 
18,321

Distributions paid (Note E)
 
(107,658
)
 
—

 
(181
)
 
(493,230
)
June 30, 2014
 
$
1,413,909

 
$
(110,965
)
 
$
4,508

 
$
5,826,914



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 2013 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.

Recently Issued Accounting Standards Update - 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 amendments also require 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 will adopt this guidance beginning in the first quarter 2015, and we are evaluating the impact on 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 amendments also require more extensive disaggregated revenue disclosures in interim and annual financial statements. This update will be effective for interim and annual periods that begin on or after December 15, 2016, with either retrospective application for all periods presented or retrospective application with a cumulative effect adjustment. We will adopt this guidance beginning in the first quarter 2017, and we are evaluating the impact on us.

B.
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 groups 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, historical correlations of NGL product prices to crude oil prices and implied forward LIBOR curves.  Inputs into our fair value estimates include commodity-exchange prices, over-the-counter quotes, historical correlations of pricing data and LIBOR and other liquid money-market instrument rates.  We also utilize internally developed basis curves that incorporate observable and unobservable market data.  We validate our valuation inputs with third-party information and settlement prices from other sources, where available. 

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.


12

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-rate 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 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 internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, 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 is not material.

Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:
 
June 30, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net (b)
 
(Thousands of dollars)
Derivatives assets
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
945

 
$
—

 
$
506

 
$
1,451

 
$
(1,451
)
 
$
—

Physical contracts
—

 
—

 
1,526

 
1,526

 
(933
)
 
593

Interest-rate contracts
—

 
26,649

 
—

 
26,649

 
—

 
26,649

Total derivative assets
$
945

 
$
26,649

 
$
2,032

 
$
29,626

 
$
(2,384
)
 
$
27,242

Derivatives liabilities
 

 
 

 
 

 
 

 
 

 
 

Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
(3,814
)
 
$
(2,865
)
 
$
(1,120
)
 
$
(7,799
)
 
$
4,934

 
$
(2,865
)
Physical contracts
—

 
—

 
(2,225
)
 
(2,225
)
 
933

 
(1,292
)
Interest-rate contracts
—

 
(19,240
)
 
—

 
(19,240
)
 
—

 
(19,240
)
Total derivative liabilities
$
(3,814
)
 
$
(22,105
)
 
$
(3,345
)
 
$
(29,264
)
 
$
5,867

 
$
(23,397
)
(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 June 30, 2014, we held no cash collateral and posted $3.5 million of cash collateral with various counterparties.
(b) - Included in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.


13

 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net (b)
 
(Thousands of dollars)
Derivatives assets
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts


 


 


 


 


 


Financial contracts
$
—

 
$
3,657

 
$
2,812

 
$
6,469

 
$
(1,746
)
 
$
4,723

Physical contracts
—

 
—

 
2,023

 
2,023

 
(946
)
 
1,077

Interest-rate contracts
—

 
54,503

 
—

 
54,503

 
—

 
54,503

Total derivative assets
$
—

 
$
58,160

 
$
4,835

 
$
62,995

 
$
(2,692
)
 
$
60,303

Derivatives liabilities
 

 
 

 
 

 
 

 
 

 
 

Commodity contracts


 


 


 


 


 


Financial contracts
$
—

 
$
(2,953
)
 
$
(2,154
)
 
$
(5,107
)
 
$
1,746

 
$
(3,361
)
Physical contracts
—

 
—

 
(3,463
)
 
(3,463
)
 
946

 
(2,517
)
Total derivative liabilities
$
—

 
$
(2,953
)
 
$
(5,617
)
 
$
(8,570
)
 
$
2,692

 
$
(5,878
)
(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, 2013, we had no cash collateral held or 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
 
Six Months Ended
 
June 30,
 
June 30,
Derivative Assets (Liabilities)
2014
 
2013
 
2014
 
2013
 
(Thousands of dollars)
Net assets (liabilities) at beginning of period
$
1,972

 
$
(4,855
)
 
$
(782
)
 
$
(2,423
)
Total realized/unrealized gains (losses):


 


 
 
 
 
Included in earnings (a)
33

 
—

 
(895
)
 
—

Included in other comprehensive income (loss)
(3,318
)
 
12,537

 
(3,370
)
 
10,105

Purchases, issuances and settlements
—

 
—

 
3,734

 
—

Net assets (liabilities) at end of period
$
(1,313
)
 
$
7,682

 
$
(1,313
)
 
$
7,682

(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 six months ended June 30, 2014 and 2013, 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 the 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 six months ended June 30, 2014 and 2013, 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 $6.8 billion and $6.5 billion at June 30, 2014, and December 31, 2013, respectively.  The book value of the aggregate of our senior notes outstanding, including current maturities, was $6.0 billion and $6.1 billion at June 30, 2014, and December 31, 2013, 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.


14

C.
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 sales and financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products.  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 - We are exposed 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 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 typically are nontransferable and only can 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.

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 are also 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 minimize the impact of price fluctuations related to natural gas, NGLs and condensate.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are 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 to reduce the impact of price fluctuations related to NGLs. At June 30, 2014, and December 31, 2013, there were no financial derivative instruments used in our natural gas liquids operations.

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 as fuel 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 June 30, 2014, and December 31, 2013, there were no financial derivative instruments used in 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 June 30, 2014, we had forward-starting interest-rate swaps with notional amounts totaling $900 million that have been 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, of which $400 million have settlement dates greater than 12 months.

Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery.  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.


15

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

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, 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.

Fair Values of Derivative Instruments - See Note B for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments:
 
June 30, 2014
 
December 31, 2013
 
Assets (a)
 
(Liabilities) (a)
 
Assets (a)
 
(Liabilities) (a)
 
(Thousands of dollars)
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Financial contracts
$
1,451

 
$
(7,799
)
 
$
6,469

 
$
(5,107
)
Physical contracts
1,462

 
(2,225
)
 
1,064

 
(3,463
)
Interest-rate contracts
26,649

 
(19,240
)
 
54,503

 
—

Total derivatives designated as hedging instruments
$
29,562

 
$
(29,264
)
 
$
62,036

 
$
(8,570
)
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Physical contracts
64

 
—

 
959

 
—

Total derivatives not designated as hedging instruments
64

 
—

 
959

 
—

Total derivatives
$
29,626

 
$
(29,264
)
 
$
62,995

 
$
(8,570
)
(a) - Included on a net basis in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.


16

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments designated as hedging instruments for the periods indicated:
 
 
June 30, 2014
 
December 31, 2013
 
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
—

 
(38.8
)
 
—

 
(48.1
)
- Crude oil and NGLs (MMbbl)
Futures, forwards
and swaps
0.1

 
(3.0
)
 
—

 
(4.0
)
Basis
 
 

 
 

 
 

 
 

- Natural gas (Bcf)
Futures and swaps
—

 
(38.8
)
 
—

 
(48.1
)
Interest-rate contracts (Millions of dollars)
Forward-starting
swaps
$
900.0

 
$
—

 
$
400.0

 
$
—


These notional quantities 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 June 30, 2014, our Consolidated Balance Sheet reflected a net unrealized loss of $111.0 million in accumulated other comprehensive income (loss).  The portion of accumulated other comprehensive income (loss) attributable to our commodity derivative instruments is a loss of $11.9 million, which will be realized within the next 18 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will recognize $13.6 million in losses over the next 12 months and $1.7 million in gains thereafter.  The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $104.6 million, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $10.5 million will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive income (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.

The following table sets forth the effect of cash flow hedges recognized in other comprehensive income (loss) for the periods indicated:
 
Three Months Ended
 
Six Months Ended
Derivatives in Cash Flow
Hedging Relationships
June 30,
 
June 30,
2014
 
2013
 
2014
 
2013
 
(Thousands of dollars)
Commodity contracts
$
(6,114
)
 
$
33,145

 
$
(41,876
)
 
$
13,377

Interest-rate contracts
(26,401
)
 
22,217

 
(47,094
)
 
29,005

Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)
$
(32,515
)
 
$
55,362

 
$
(88,970
)
 
$
42,382


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
 
Six Months Ended
June 30,
 
June 30,
2014
 
2013
 
2014
 
2013
 
 
(Thousands of dollars)
Commodity contracts
Commodity sales revenues
$
(5,187
)
 
$
1,245

 
$
(31,606
)
 
$
3,811

Interest-rate contracts
Interest expense
(2,647
)
 
(2,575
)
 
(5,236
)
 
(4,880
)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)
$
(7,834
)
 
$
(1,330
)
 
$
(36,842
)
 
$
(1,069
)

Ineffectiveness related to our cash flow hedges was not material for the three and six months ended June 30, 2014 and 2013. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment,

17

which would affect earnings.  There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and six months ended June 30, 2014 and 2013.

Credit Risk - Prior to March 31, 2014, all of our commodity derivative financial contracts were with our affiliate ONEOK Energy Services Company, a subsidiary of ONEOK. ONEOK Energy Services Company entered into similar commodity derivative financial contracts with third parties at our direction and on our behalf. On March 31, 2014, ONEOK completed the accelerated wind down of ONEOK Energy Services Company. In the first quarter 2014, outstanding commodity derivative positions with third parties entered into by ONEOK Energy Services Company on our behalf were transferred to us. Beginning in the second quarter 2014, we enter into all commodity derivative financial contracts directly with unaffiliated third parties.

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 June 30, 2014.

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.

D.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

Partnership Credit Agreement - The amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion. At June 30, 2014, we had no commercial paper outstanding, $14.0 million in letters of credit issued and no borrowings under our Partnership Credit Agreement.

Our Partnership Credit Agreement, which was amended and restated effective on January 31, 2014, and expires in January 2019, is a $1.7 billion revolving credit facility and includes a $100 million sublimit for the issuance of standby letters of credit, a $150 million swingline sublimit and an option to request an increase in the size of the facility to an aggregate of $2.4 billion by either commitments from new lenders or increased commitments from existing lenders. Our Partnership Credit Agreement is available for general partnership purposes. During the second quarter 2014, we increased the size of our commercial paper program to $1.7 billion from $1.2 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. 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, and ONEOK does not guarantee our debt, commercial paper or other similar commitments.

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 a pipeline acquisition we completed in the first quarter 2014, the allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to 1 through the third quarter 2014. Upon breach of certain covenants by us in our Partnership Credit Agreement, amounts outstanding under our Partnership Credit

18

Agreement, if any, may become due and payable immediately.  At June 30, 2014, our ratio of indebtedness to adjusted EBITDA was 3.4 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

E.
EQUITY

ONEOK - ONEOK and its affiliates own all of the Class B units, 19.8 million common units and the entire 2 percent general partner interest in us, which together constituted a 38.5 percent ownership interest in us at June 30, 2014.

Equity Issuances - 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 to repay commercial paper, fund our capital expenditures and for general partnership purposes.

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 $300 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.

During the six months ended June 30, 2014, we sold approximately 3.0 million common units through this program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $164.1 million, which were used for general partnership purposes. During the three months ended March 31, 2013, we sold 300,000 common units through this program that resulted in net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, of approximately $16.3 million and used the proceeds for general partnership purposes. There were no common units sold through this program in the second quarter 2013.

As a result of these transactions, ONEOK’s aggregate ownership interest in us decreased to 38.5 percent at June 30, 2014, from 41.2 percent at December 31, 2013.

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 July 2014, our general partner declared a cash distribution of $0.76 per unit ($3.04 per unit on an annualized basis) for the second quarter 2014, an increase of 1.5 cents from the previous quarter, which will be paid on August 14, 2014, to unitholders of record at the close of business on August 4, 2014.

The following table shows our distributions paid in the periods indicated:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(Thousands, except per unit amounts)
Distribution per unit
$
0.745

 
$
0.715

 
$
1.475

 
$
1.425

 
 
 
 
 
 
 
 
General partner distributions
$
5,011

 
$
4,469

 
$
9,860

 
$
8,887

Incentive distributions
71,911

 
61,576

 
140,166

 
122,013

Distributions to general partner
76,922

 
66,045

 
150,026

 
130,900

Limited partner distributions to ONEOK
69,125

 
66,344

 
136,862

 
132,224

Limited partner distributions to other unitholders
104,506

 
91,039

 
206,161

 
181,228

Total distributions paid
$
250,553

 
$
223,428

 
$
493,049

 
$
444,352



19

The following table shows our distributions declared for the periods indicated and paid within 45 days of the end of the period:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(Thousands, except per unit amounts)
Distribution per unit
$
0.760

 
$
0.720

 
$
1.505

 
$
1.435

 
 
 
 
 
 
 
 
General partner distributions
$
5,501

 
$
4,512

 
$
10,512

 
$
8,981

Incentive distributions
80,381

 
62,633

 
152,292

 
124,209

Distributions to general partner
85,882

 
67,145

 
162,804

 
133,190

Limited partner distributions to ONEOK
70,519

 
66,807

 
139,646

 
133,151

Limited partner distributions to other unitholders
118,644

 
91,676

 
223,150

 
182,715

Total distributions declared
$
275,045

 
$
225,628

 
$
525,600

 
$
449,056


F.
ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive income (loss) for the period indicated:
 
 
Accumulated
Other
Comprehensive
Loss (a)
 
 
(Thousands of dollars)
January 1, 2014
 
$
(58,837
)
Other comprehensive income (loss) before reclassifications
 
(88,970
)
Amounts reclassified from accumulated other comprehensive income (loss)
 
36,842

Net current-period other comprehensive income (loss) attributable to ONEOK Partners
 
(52,128
)
June 30, 2014
 
$
(110,965
)
(a) All amounts are attributable to unrealized gains (losses) in risk-management assets/liabilities.

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
June 30,
 
Six Months Ended
June 30,
Affected Line Item in the
Consolidated Statements of Income
 
2014
 
2013
 
2014
 
2013
 
 
(Thousands of dollars)
 
Unrealized (gains) losses on risk-management assets/liabilities
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
5,187

 
$
(1,245
)
 
$
31,606

 
$
(3,811
)
Commodity sales revenues
Interest-rate contracts
 
2,647

 
2,575

 
5,236

 
4,880

Interest expense
Total reclassifications for the period attributable to ONEOK Partners
 
$
7,834

 
$
1,330

 
$
36,842

 
$
1,069

Net income attributable to ONEOK Partners

G.
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 waived conditionally its right to increased quarterly distributions, until it gives 90 days notice of the withdrawal of the waiver, each Class B unit and common unit currently 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

20

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 or distributions in excess of earnings.  For additional information regarding our general partner’s incentive distribution rights, see “Partnership Agreement” in Note I of the Notes to Consolidated Financial Statements in our Annual Report.

H.
UNCONSOLIDATED AFFILIATES

Equity Earnings from Investments - The following table sets forth our equity earnings (losses) from investments for the periods indicated:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(Thousands of dollars)
Northern Border Pipeline
$
15,877

 
$
15,279

 
$
39,286

 
$
31,669

Overland Pass Pipeline Company
4,121

 
5,528

 
8,852

 
8,427

Fort Union Gas Gathering
4,280

 
3,080

 
8,409

 
6,949

Bighorn Gas Gathering
(873
)
 
626

 
(1,273
)
 
1,338

Other
2,030

 
1,908

 
3,820

 
3,893

Equity earnings from investments
$
25,435

 
$
26,421

 
$
59,094

 
$
52,276


Unconsolidated Affiliates Financial Information - The following table sets forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(Thousands of dollars)
Income Statement
 
 
 
 
 
 
 
Operating revenues
$
121,509

 
$
132,152

 
$
276,788

 
$
259,953

Operating expenses
$
51,870

 
$
61,124

 
$
123,549

 
$
125,395

Net income
$
60,878

 
$
65,746

 
$
139,551

 
$
123,950

 
 
 
 
 
 
 
 
Distributions paid to us
$
42,579

 
$
39,311

 
$
77,649

 
$
69,504


We incurred expenses in transactions with unconsolidated affiliates of $14.3 million and $12.6 million for the three months ended June 30, 2014 and 2013, respectively, and $28.4 million and $20.4 million for the six months ended June 30, 2014 and 2013, respectively, primarily related to Overland Pass Pipeline Company, which are included in cost of sales and fuel in our Consolidated Statements of Income. Accounts payable to our equity method investees at June 30, 2014, and December 31, 2013, were not material.

Low natural gas prices and the relatively higher crude oil and NGL prices, compared with natural gas on a heating-value basis, have caused producers primarily to focus 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 will be affected by commodity prices and producers’ alternative prospects.

Due to recent reductions in producer activity and declines in natural gas volumes gathered in the dry natural gas area of the Powder River Basin on the Bighorn Gas Gathering system, in which we own a 49 percent equity interest, we tested our investment for impairment at December 31, 2013. The estimated fair value exceeded the carrying value; however, a decline of 10 percent or more in the fair value of our investment in Bighorn Gas Gathering would result in a noncash impairment charge. We were not able to reasonably estimate a range of potential future impairment charges, as many of the assumptions that would be used in our estimate of fair value are dependent upon events beyond our control. The carrying amount of our investment at

21

June 30, 2014, was $85.7 million, which includes $53.4 million in equity method goodwill.

I.
RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers.  Prior to March 31, 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 and for the six months ended June 30, 2013, 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 accelerated wind down of ONEOK Energy Services Company, a subsidiary of ONEOK. For the first quarter 2014 and the three and six months ended June 30, 2013, we had transactions with ONEOK Energy Services Company, which are reflected as affiliate transactions.

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 Company and Midwestern Gas Transmission Company 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 and ONEOK Services Company 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 and the three and six months ended June 30, 2013, 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
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(Thousands of dollars)
Revenues
$
—

 
$
91,340

 
$
53,526

 
$
173,974

Expenses
 

 
 

 
 

 
 

Cost of sales and fuel
$
—

 
$
8,742

 
$
10,835

 
$
18,293

Administrative and general expenses
78,705

 
61,861

 
155,951

 
134,357

Total expenses
$
78,705

 
$
70,603

 
$
166,786

 
$
152,650

 
ONEOK Partners GP made additional general partner contributions to us of approximately $18.3 million and $0.3 million during the six months ended June 30, 2014 and 2013, respectively, to maintain its 2 percent general partner interest in connection with the issuances of common units.  See Note E for additional information about our equity issuances and cash distributions paid to ONEOK for its general partner and limited partner interests.


22

J.
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, wetland 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, emission 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 that 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 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 proposed regulatory actions on our facilities and operations is unknown. We continue to monitor these proposed regulations 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 six months ended June 30, 2014 and 2013.

The EPA’s “Tailoring Rule” regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology (BACT), conduct air-quality and conduct 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. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown. In addition, on June 23, 2014, the Supreme Court of the United States, in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit greenhouse gas (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. However, the 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. We are in the process of evaluating the effects the decision may have on our existing operations, and the opportunities it creates for design decisions for new project applications.

The EPA’s rule on air-quality standards, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE NESHAP), initially included a compliance date in 2013, and has since become effective. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

In July 2011, the EPA issued a proposed rule that would change the air emission 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

23

fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. 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.

The rule was most recently amended in September 2013, and a further proposed rulemaking was published in July 2014. The EPA has indicated that further amendments may be issued in 2014. Based on the amendments, our understanding of pending stakeholder responses to the NSPS rule and the proposed rulemaking, we do not anticipate a material impact to our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping at affected facilities in the crude oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

Pipeline Safety - We are subject to PHMSA regulations, including asset integrity-management regulations.  The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to the following:
•
an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;
•
a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions;
•
a verification of records for pipelines in Class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and
•
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. The CFTC has issued final regulations for most of the provisions of the Dodd-Frank Act, and we have implemented measures to comply with the regulations that are applicable to our businesses. We continue to participate in financial markets for hedging certain risks inherent in our business, including commodity-price and interest-rate risks. Although the impact to date has not been material, we continue to monitor proposed regulations and the impact the regulations may have on our business and our risk-management strategies in the future.

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations.  While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material.  Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

K.
SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments, as follows:
•
our Natural Gas Gathering and Processing segment gathers, treats and processes natural gas;
•
our Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products; and
•
our Natural Gas Pipelines segment operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.

Accounting Policies - We evaluate performance based principally on each segment’s operating income and equity earnings. The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report. Affiliate and intersegment sales are recorded on the same basis as sales to unaffiliated customers.  Net margin is comprised of total revenues less cost of sales and fuel.  Cost of sales and fuel includes commodity purchases, fuel, storage and transportation costs.

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As a result of ONEOK’s separation of its natural gas distribution business into a stand-alone publicly traded company called ONE Gas on January 31, 2014, transactions with ONE Gas subsequent to the separation are reflected as sales to unaffiliated customers.

Customers - The primary customers of our Natural Gas Gathering and Processing segment are major and independent crude oil and natural gas production companies.  Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies, major and independent crude oil and natural gas production companies, propane distributors, ethanol producers and petrochemical, refining and NGL marketing companies. Natural Gas Pipelines segment customers include natural gas distribution, electric-generation, natural gas marketing, industrial and major and independent crude oil and natural gas production companies.

For the three and six months ended June 30, 2014 and 2013, we had no single customer from which we received 10 percent or more of our consolidated revenues.  

Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:
Three Months Ended
Natural Gas
Gathering and
Processing
 
Natural Gas
Liquids (a)
 
Natural Gas
Pipelines (b)
 
Other and
Eliminations
 
Total
June 30, 2014
 
 


 
(Thousands of dollars)
Sales to unaffiliated customers
$
374,112


$
2,612,336


$
79,287


$
—


$
3,065,735

Intersegment revenues
349,253


52,974


2,698


(404,925
)

—

Total revenues
$
723,365


$
2,665,310


$
81,985


$
(404,925
)

$
3,065,735

Net margin
$
154,970


$
266,145


$
75,471


$
(2,253
)

$
494,333

Operating costs
59,386


76,081


27,287


(2,109
)

160,645

Depreciation and amortization
29,443


31,109


10,895


—


71,447

Gain (loss) on sale of assets
(28
)

11


—


1


(16
)
Operating income
$
66,113

 
$
158,966

 
$
37,289

 
$
(143
)
 
$
262,225

Equity earnings from investments
$
5,099


$
4,459


$
15,877


$
—


$
25,435

Capital expenditures
$
168,208


$
210,676


$
8,710


$
1,819


$
389,413

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $153.3 million, of which $135.3 million related to sales within the segment, net margin of $84.4 million and operating income of $34.5 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.3 million, net margin of $59.5 million and operating income of $26.1 million.


25

Three Months Ended
Natural Gas
Gathering and
Processing
 
Natural Gas
Liquids (a)
 
Natural Gas
Pipelines (b)
 
Other and
Eliminations
 
Total
June 30, 2013
 
 
 
 
 
(Thousands of dollars)
Sales to unaffiliated customers
$
166,709

 
$
2,461,119

 
$
49,011

 
$
—

 
$
2,676,839

Sales to affiliated customers
66,578

 
—

 
24,762

 
—

 
91,340

Intersegment revenues
248,972

 
29,996

 
1,269

 
(280,237
)
 
—

Total revenues
$
482,259

 
$
2,491,115

 
$
75,042

 
$
(280,237
)
 
$
2,768,179

Net margin
$
125,269

 
$
219,225

 
$
67,695

 
$
(236
)
 
$
411,953

Operating costs
44,975

 
54,264

 
24,985

 
(248
)
 
123,976

Depreciation and amortization
25,106

 
22,302

 
10,818

 
—

 
58,226

Gain (loss) on sale of assets
285

 
(6
)