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ONEOK INC /NEW/ - Quarter Report: 2019 March (Form 10-Q)

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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 March 31, 2019.
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   001-13643


ONEOK, Inc.
(Exact name of registrant as specified in its charter)


Oklahoma
73-1520922
(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 every Interactive Data File required to be submitted 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 such files).
Yes X  No __
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer X                         Accelerated filer __                         Non-accelerated filer __
Smaller reporting company__                 Emerging growth company__

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.__

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes __ No X

On April 22, 2019, the Company had 412,756,216 shares of common stock outstanding.


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ONEOK, Inc.
TABLE OF CONTENTS
Page No.
 
 
 
 
 
 
 

As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors, divisions, and 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,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would” 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.oneok.com) copies of our Annual Reports, Quarterly Reports, 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, Corporate Governance Guidelines, Director Independence Guidelines, Bylaws and the written charter of our Audit Committee also are available on our website, and we will provide copies of these documents upon request.

In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional channels of distribution to reach public investors. Information contained on our website, posted on our social media accounts, and any corresponding applications, are not incorporated by reference into this report.

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GLOSSARY
The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:
$1.5 Billion Term Loan Agreement
The senior unsecured delayed-draw three-year $1.5 billion term loan agreement dated November 19, 2018
$2.5 Billion Credit Agreement
ONEOK’s $2.5 billion revolving credit agreement, as amended
AFUDC
Allowance for funds used during construction
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2018
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
Bcf/d
Billion cubic feet per day
CFTC
U.S. Commodity Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
DJ
Denver-Julesburg
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
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
MMcf/d
Million cubic feet per day
Moody’s
Moody’s Investors Service, Inc.
NGL(s)
Natural gas liquid(s)
NGL products
Marketable natural gas liquid 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
ONEOK
ONEOK, Inc.
ONEOK Partners
ONEOK Partners, L.P.
OPIS
Oil Price Information Service
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
Roadrunner
Roadrunner Gas Transmission, LLC, a 50 percent-owned joint venture
S&P
S&P Global Ratings
SCOOP
South Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SEC
Securities and Exchange Commission
Series E Preferred Stock
Series E Non-Voting, Perpetual Preferred Stock, par value $0.01 per share
STACK
Sooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in Oklahoma
West Texas LPG
West Texas LPG pipeline and Mesquite pipeline
WTI
West Texas Intermediate
WTLPG
West Texas LPG Pipeline Limited Partnership
XBRL
eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONEOK, Inc. and Subsidiaries
 

 
CONSOLIDATED STATEMENTS OF INCOME
 

 
 
Three Months Ended
 
March 31,
(Unaudited)
2019

2018
 
(Thousands of dollars, except per share amounts)
Revenues (Note L)
 
 
 
Commodity sales
$
2,472,959


$
2,820,004

Services
306,999


282,073

Total revenues
2,779,958


3,102,077

Cost of sales and fuel (exclusive of items shown separately below)
1,956,377


2,368,026

Operations and maintenance
207,251


181,181

Depreciation and amortization
114,158


104,237

General taxes
33,490


29,023

Gain on sale of assets
(60
)

(89
)
Operating income
468,742


419,699

Equity in net earnings from investments (Note I)
43,481


40,187

Allowance for equity funds used during construction
12,441


230

Other income
9,360


738

Other expense
(3,462
)

(3,309
)
Interest expense (net of capitalized interest of $19,192, and $2,038, respectively)
(115,420
)

(115,725
)
Income before income taxes
415,142


341,820

Income taxes
(77,934
)

(75,771
)
Net income
337,208

 
266,049

Less: Net income attributable to noncontrolling interests


1,541

Net income attributable to ONEOK
337,208


264,508

Less: Preferred stock dividends
275

 
275

Net income available to common shareholders
$
336,933

 
$
264,233


 


 

Basic earnings per common share (Note G)
$
0.82

 
$
0.65


 
 
 
Diluted earnings per common share (Note G)
$
0.81

 
$
0.64

Average shares (thousands)
 
 
 
Basic
412,908

 
409,676

Diluted
415,233

 
412,173

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
 
 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
Three Months Ended
 
March 31,
(Unaudited)
2019
 
2018
 
(Thousands of dollars)
Net income
$
337,208

 
$
266,049

Other comprehensive income (loss), net of tax
 

 
 

Unrealized gains (losses) on derivatives, net of tax of $20,593 and $(10,312), respectively
(68,944
)
 
34,524

Realized (gains) losses on derivatives recognized in net income, net of tax of $4,177 and $(3,578), respectively
(12,171
)
 
11,976

Change in retirement and other postretirement benefit plan liability, net of tax of $(699) and $(781), respectively
2,341

 
2,615

Other comprehensive income (loss) on investments in unconsolidated affiliates, net of tax of $750 and $(844), respectively
(2,511
)
 
2,824

Total other comprehensive income (loss), net of tax
(81,285
)
 
51,939

Comprehensive income
255,923

 
317,988

Less: Comprehensive income attributable to noncontrolling interests

 
1,541

Comprehensive income attributable to ONEOK
$
255,923

 
$
316,447

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
 
 

 
CONSOLIDATED BALANCE SHEETS
 
 

 

 
March 31,

December 31,
(Unaudited)
 
2019

2018
Assets
 
(Thousands of dollars)
Current assets
 
 

 
Cash and cash equivalents
 
$
27,814


$
11,975

Accounts receivable, net
 
812,869


818,958

Materials and supplies
 
163,731

 
141,174

Natural gas and natural gas liquids in storage
 
243,223


296,667

Commodity imbalances
 
38,349


29,050

Other current assets
 
56,793


100,808

Total current assets
 
1,342,779


1,398,632

Property, plant and equipment
 
 


 

Property, plant and equipment
 
18,887,742


18,030,963

Accumulated depreciation and amortization
 
3,369,710


3,264,312

Net property, plant and equipment
 
15,518,032


14,766,651

Investments and other assets
 
 


 

Investments in unconsolidated affiliates
 
950,924


969,150

Goodwill and intangible assets
 
964,167


967,142

Other assets
 
158,423


130,096

Total investments and other assets
 
2,073,514


2,066,388

Total assets
 
$
18,934,325


$
18,231,671



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ONEOK, Inc. and Subsidiaries
 
 
 
 
CONSOLIDATED BALANCE SHEETS
 
 
 
 
(Continued)
 
 
 
 
 
 
March 31,
 
December 31,
(Unaudited)
 
2019
 
2018
Liabilities and equity
 
(Thousands of dollars)
Current liabilities
 
 
 
 
Current maturities of long-term debt (Note D)
 
$
307,650

 
$
507,650

Accounts payable
 
1,027,322

 
1,116,337

Commodity imbalances
 
120,145

 
110,197

Accrued interest
 
113,567

 
161,377

Finance lease liability
 
1,809

 
1,765

Other current liabilities
 
119,176

 
211,110

Total current liabilities
 
1,689,669

 
2,108,436

Long-term debt, excluding current maturities (Note D)
 
10,004,341

 
8,873,334

Deferred credits and other liabilities
 
 
 
 
Deferred income taxes
 
270,751

 
219,731

Finance lease liability
 
25,775

 
26,244

Other deferred credits
 
501,783

 
424,383

Total deferred credits and other liabilities
 
798,309

 
670,358

Commitments and contingencies (Note J)
 

 

Equity (Note E)
 
 
 
 
ONEOK shareholders’ equity:
 
 
 
 
Preferred stock, $0.01 par value:
authorized and issued 20,000 shares at March 31, 2019, and December 31, 2018
 

 

Common stock, $0.01 par value:
authorized 1,200,000,000 shares, issued 445,016,234 shares and outstanding
412,752,687 shares at March 31, 2019; issued 445,016,234 shares and outstanding
411,532,606 shares at December 31, 2018
 
4,450

 
4,450

Paid-in capital
 
7,527,847

 
7,615,138

Accumulated other comprehensive loss (Note F)
 
(269,524
)
 
(188,239
)
Retained earnings
 

 

Treasury stock, at cost: 32,263,547 shares at March 31, 2019, and
33,483,628 shares at December 31, 2018
 
(820,767
)
 
(851,806
)
Total equity
 
6,442,006

 
6,579,543

Total liabilities and equity
 
$
18,934,325

 
$
18,231,671

See accompanying Notes to Consolidated Financial Statements.


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ONEOK, Inc. and Subsidiaries
 
 

 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 

 
 
 
Three Months Ended
 
 
March 31,
(Unaudited)
 
2019

2018
 
 
(Thousands of dollars)
Operating activities
 
 

 
Net income
 
$
337,208


$
266,049

Adjustments to reconcile net income to net cash provided by operating activities:
 





Depreciation and amortization
 
114,158


104,237

Equity in net earnings from investments
 
(43,481
)

(40,187
)
Distributions received from unconsolidated affiliates
 
45,936


41,095

Deferred income taxes
 
75,994


74,890

Share-based compensation expense
 
8,607

 
7,203

Pension and postretirement benefit expense, net of contributions
 
(12,250
)
 
(8,393
)
Allowance for equity funds used during construction
 
(12,441
)

(230
)
Gain on sale of assets
 
(60
)

(89
)
Changes in assets and liabilities:
 
 




Accounts receivable
 
6,089


358,733

Natural gas and natural gas liquids in storage
 
53,444


149,825

Accounts payable
 
(62,469
)

(361,008
)
Commodity imbalances, net
 
649


(39,755
)
Accrued interest
 
(47,810
)

(37,784
)
Risk-management assets and liabilities
 
4,362


34,387

Other assets and liabilities, net
 
(114,330
)

(53,652
)
Cash provided by operating activities
 
353,606


495,321

Investing activities
 
 


 

Capital expenditures (less allowance for equity funds used during construction)
 
(889,705
)

(264,467
)
Contributions to unconsolidated affiliates
 
(1,016
)

(147
)
Distributions received from unconsolidated affiliates in excess of cumulative earnings
 
13,527


8,721

Proceeds from sale of assets
 
12,365


241

Cash used in investing activities
 
(864,829
)

(255,652
)
Financing activities
 
 


 

Dividends paid
 
(354,203
)
 
(316,408
)
Distributions to noncontrolling interests
 

 
(1,500
)
Borrowing (repayment) of short-term borrowings, net
 


(614,673
)
Issuance of long-term debt, net of discounts
 
1,442,782



Debt financing costs
 
(11,663
)


Repayment of long-term debt
 
(501,913
)

(501,913
)
Issuance of common stock
 
4,784

 
1,182,117

Other, net
 
(52,725
)
 
(7,011
)
Cash provided by (used in) financing activities
 
527,062


(259,388
)
Change in cash and cash equivalents
 
15,839

 
(19,719
)
Cash and cash equivalents at beginning of period
 
11,975


37,193

Cash and cash equivalents at end of period
 
$
27,814


$
17,474

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
 
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
 
 
 
 
 
 
 
 
 
ONEOK Shareholders’ Equity
(Unaudited)
 
Common
Stock Issued
 
Preferred Stock Issued
 
Common
Stock
 
Preferred Stock
 
Paid-in
Capital
 
 
(Shares)
 
(Thousands of dollars)
January 1, 2019
 
445,016,234

 
20,000

 
$
4,450

 
$

 
$
7,615,138

Cumulative effect adjustment for adoption of ASU 2016-02 (Note A)
 

 

 

 

 

Net income
 

 

 

 

 

Other comprehensive income (loss) (Note F)
 

 

 

 

 

Preferred stock dividends - $13.75 per share (Note E)
 

 

 

 

 

Common stock issued
 

 

 

 

 
(24,779
)
Common stock dividends - $0.86 per share (Note E)
 

 

 

 

 
(17,438
)
Other
 

 

 

 

 
(45,074
)
March 31, 2019
 
445,016,234

 
20,000

 
$
4,450

 
$

 
$
7,527,847


 
 
ONEOK Shareholders’ Equity
(Unaudited)
 
Common
Stock Issued
 
Preferred Stock Issued
 
Common
Stock
 
Preferred Stock
 
Paid-in
Capital
 
 
(Shares)
 
(Thousands of dollars)
January 1, 2018
 
423,166,234

 
20,000

 
$
4,232

 
$

 
$
6,588,878

Cumulative effect adjustment for adoption of ASUs (a)
 

 

 

 

 

Net income
 

 

 

 

 

Other comprehensive income (loss)
 

 

 

 

 

Preferred stock dividends - $13.75 per share
 

 

 

 

 
(275
)
Common stock issued
 
21,850,000

 

 
218

 

 
1,169,247

Common stock dividends - $0.77 per share
 

 

 

 

 
(11,960
)
Distributions to noncontrolling interests
 

 

 

 

 

Contributions from noncontrolling interests
 

 

 

 

 

Other
 

 

 

 

 
(10,717
)
March 31, 2018
 
445,016,234

 
20,000

 
$
4,450

 
$

 
$
7,735,173



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ONEOK, Inc. and Subsidiaries
 
 
 
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
 
 
(Continued)
 
 
 
 
 
 
 
 
 
 
ONEOK Shareholders’ Equity
(Unaudited)
 
Accumulated
Other
Comprehensive
Loss
 
Retained Earnings
 
Treasury
Stock
 
Total
Equity
 
 
(Thousands of dollars)
January 1, 2019
 
$
(188,239
)
 
$

 
$
(851,806
)
 
$
6,579,543

Cumulative effect adjustment for adoption of ASU 2016-02 (Note A)
 

 
(67
)
 

 
(67
)
Net income
 

 
337,208

 

 
337,208

Other comprehensive income (loss) (Note F)
 
(81,285
)
 

 

 
(81,285
)
Preferred stock dividends - $13.75 per share (Note E)
 

 
(275
)
 

 
(275
)
Common stock issued
 

 

 
31,039

 
6,260

Common stock dividends - $0.86 per share (Note E)
 

 
(336,866
)
 

 
(354,304
)
Other
 

 

 

 
(45,074
)
March 31, 2019
 
$
(269,524
)
 
$

 
$
(820,767
)
 
$
6,442,006


 
 
ONEOK Shareholders’ Equity
 
 
 
 
(Unaudited)
 
Accumulated
Other
Comprehensive
Loss
 
Retained Earnings
 
Treasury
Stock
 
Noncontrolling
Interests in
Consolidated
Subsidiaries
 
Total
Equity
 
 
(Thousands of dollars)
January 1, 2018
 
$
(188,530
)
 
$

 
$
(876,713
)
 
$
157,485

 
$
5,685,352

Cumulative effect adjustment for adoption of ASUs (a)
 
(38,101
)
 
39,803

 

 
17

 
1,719

Net income
 

 
264,508

 

 
1,541

 
266,049

Other comprehensive income (loss)
 
51,939

 

 

 

 
51,939

Preferred stock dividends - $13.75 per share
 

 

 

 

 
(275
)
Common stock issued
 

 

 
13,228

 

 
1,182,693

Common stock dividends - $0.77 per share
 

 
(304,311
)
 

 

 
(316,271
)
Distributions to noncontrolling interests
 

 

 

 
(1,500
)
 
(1,500
)
Contributions from noncontrolling interests
 

 

 

 
10,263

 
10,263

Other
 

 

 

 

 
(10,717
)
March 31, 2018
 
$
(174,692
)
 
$

 
$
(863,485
)
 
$
167,806

 
$
6,869,252

(a) - Includes cumulative effect for adoption of the following: ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” and ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”

See accompanying Notes to Consolidated Financial Statements.



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ONEOK, INC. 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 statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2018 year-end Consolidated Balance Sheet data was derived from our audited Consolidated Financial Statements but does not include all disclosures required by GAAP. Certain reclassifications have been made in the prior-year Consolidated Financial Statements to conform to the current year presentation. These unaudited Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements in our Annual Report.

Recently Issued Accounting Standards Update - Changes to GAAP are established by the Financial Accounting Standards Board (FASB) in the form of ASUs to the FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs listed below. The following table provides a brief description of recent accounting pronouncements and our analysis of the effects on our financial statements:
Standard
 
Description
 
Date of Adoption
 
Effect on the Financial Statements or Other Significant Matters
Standards that were adopted
 
 
 
 
ASU 2016-02, “Leases (Topic 842)”
 
The standard requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. It also requires qualitative disclosures along with specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.
 
First quarter 2019
 
We adopted this standard on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. We recorded an immaterial cumulative effect for the adoption of the new standard and recorded $17.5 million of right-of-use assets and $17.4 million of lease liabilities related to operating leases that were not previously recorded on our Consolidated Balance Sheets. Our finance lease assets and liabilities of $28.1 million and $28.0 million, respectively, did not change as a result of adopting this standard. See Note K for additional disclosures.
ASU 2018-07, “Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting”
 
The standard aligns the measurement and classification guidance for share-based payments to nonemployees with the guidance for share-based payments to employees, with certain exceptions.
 
First quarter 2019
 
The impact of adopting this standard was not material.
Standards that are not yet adopted
 
 
 
 
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”
 
The standard requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented net of the allowance for credit losses to reflect the net carrying value at the amount expected to be collected on the financial asset; and the initial allowance for credit losses for purchased financial assets, including available-for-sale debt securities, to be added to the purchase price rather than being reported as a credit loss expense.
 
First quarter 2020
 
We do not expect the adoption of this standard to materially impact us.
ASU 2017-04, “Intangibles- Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”
 
The standard simplifies the subsequent measurement of goodwill by eliminating the requirement to calculate the implied fair value of goodwill under step 2. Instead, an entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The standard does not change step zero or step 1 assessments.
 
First quarter 2020
 
We do not expect the adoption of this standard to materially impact us.


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B.
FAIR VALUE MEASUREMENTS

Determining Fair Value - For our fair value measurements, we utilize market prices, third-party pricing services, present value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the transfer of a liability in an orderly transaction at the measurement date. 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 derivative 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 may utilize modeling techniques using NYMEX-settled pricing data and implied forward LIBOR curves. Inputs into our fair value estimates include commodity-exchange prices, data obtained from third-party pricing services, LIBOR and other liquid money-market instrument rates. Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account with daily margin requirements. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

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 the implied forward LIBOR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using counterparty-specific bond yields. 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 materially from our estimates.

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. 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, including quoted prices for similar assets and liabilities in active markets and inputs from third-party pricing services supported with corroborative evidence. These balances are comprised of over-the-counter interest-rate derivatives.
Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed natural gas basis and NGL price curves that incorporate observable and unobservable market data from broker quotes and third-party pricing services. These balances are comprised predominantly of exchange-cleared and over-the-counter derivatives for natural gas basis and NGLs. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at March 31, 2019, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as our derivatives are accounted for as hedges.

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.


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Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:
 
March 31, 2019
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net
 
(Thousands of dollars)
Derivative assets
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
1,468

 
$

 
$
32,840

 
$
34,308

 
$
(27,156
)
 
$
7,152

Physical contracts

 

 
751

 
751

 

 
751

Total derivative assets
$
1,468

 
$

 
$
33,591

 
$
35,059

 
$
(27,156
)
 
$
7,903

Derivative liabilities
 

 
 

 
 

 
 

 
 

 
 

Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
(5,094
)
 
$

 
$
(22,062
)
 
$
(27,156
)
 
$
27,156

 
$

Interest-rate contracts

 
(149,984
)
 

 
(149,984
)
 

 
(149,984
)
Total derivative liabilities
$
(5,094
)
 
$
(149,984
)
 
$
(22,062
)
 
$
(177,140
)
 
$
27,156

 
$
(149,984
)
(a) - 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 March 31, 2019, we held no cash and posted $20.0 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheet.

 
December 31, 2018
 
Level 1
 
Level 2
 
Level 3
 
Total - Gross
 
Netting (a)
 
Total - Net
 
(Thousands of dollars)
Derivative assets
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
10,812

 
$

 
$
69,165

 
$
79,977

 
$
(32,739
)
 
$
47,238

Physical contracts

 

 
1,142

 
1,142

 

 
1,142

Interest-rate contracts

 
19,005

 

 
19,005

 

 
19,005

Total derivative assets
$
10,812

 
$
19,005

 
$
70,307

 
$
100,124

 
$
(32,739
)
 
$
67,385

Derivative liabilities
 

 
 

 
 

 
 

 
 

 
 

Commodity contracts
 
 
 
 
 
 
 
 
 
 
 
Financial contracts
$
(2,916
)
 
$

 
$
(29,823
)
 
$
(32,739
)
 
$
32,739

 
$

Interest-rate contracts

 
(99,260
)
 

 
(99,260
)
 

 
(99,260
)
Total derivative liabilities
$
(2,916
)
 
$
(99,260
)
 
$
(29,823
)
 
$
(131,999
)
 
$
32,739

 
$
(99,260
)
(a) - 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, 2018, we held no cash and posted $0.8 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheet.

The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:
 
Three Months Ended
 
March 31,
Derivative Assets (Liabilities)
2019
 
2018
 
(Thousands of dollars)
Net assets (liabilities) at beginning of period
$
40,484

 
$
(32,838
)
Total realized/unrealized gains (losses):
 
 
 
Included in earnings (a)

 
(85
)
Included in other comprehensive income (loss) (b)
(28,955
)
 
36,021

Net assets (liabilities) at end of period
$
11,529

 
$
3,098

(a) - Included in commodity sales revenues in our Consolidated Statements of Income.
(b) - Included in unrealized gains (losses) on derivatives in our Consolidated Statements of Comprehensive Income.


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Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the three months ended March 31, 2019 and 2018, there were no transfers in or out of Level 3 of the fair value hierarchy.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings 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 short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market.

The estimated fair value of our consolidated long-term debt, including current maturities, was $11.0 billion and $9.6 billion at March 31, 2019, and December 31, 2018, respectively. The book value of our consolidated long-term debt, including current maturities, was $10.3 billion and $9.4 billion at March 31, 2019, and December 31, 2018, respectively. The estimated fair value of the aggregate long-term debt outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.

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 are also subject to the risk of interest-rate fluctuation in the normal course of business. 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 commodity price and 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.

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 may use the following commodity derivative instruments to reduce 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;
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; and
Options - 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.

We may also use other instruments including collars to mitigate commodity price risk. 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 retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. We also are exposed to basis risk between the various production and market locations where we buy 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 primarily exposed to commodity price risk resulting from the relative values of the various NGL products to each other, the value of NGLs in storage and the relative value of NGLs to natural gas. We are also exposed to location price differential risk as a result of the relative value of NGL purchases at one location and sales at another location, primarily related to our optimization and marketing activities. As part of our hedging strategy, 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 pipelines consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for services

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provided. When the amount consumed in operations 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 this segment 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 may use physical-forward sales or purchases to reduce the impact of natural gas price fluctuations. At March 31, 2019, and December 31, 2018, 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, interest-rate swaps and treasury lock contracts. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. In March 2019, we settled $1.0 billion of our forward-starting interest-rate swaps related to our underwritten public offering of $1.25 billion senior unsecured notes.

At March 31, 2019, and December 31, 2018, we had forward-starting interest-rate swaps with notional amounts totaling $2.0 billion and $3.0 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At March 31, 2019, and December 31, 2018, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of our LIBOR-based interest payments. All of our interest-rate swaps are designated as cash flow hedges.

Accounting Treatment - Our accounting treatment of derivative instruments is consistent with that disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Fair Values of Derivative Instruments - All derivatives held at March 31, 2019, and December 31, 2018, were designated as hedging 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 presented on a gross basis for the periods indicated:
 
 
 
March 31, 2019
 
December 31, 2018
 
Location in our Consolidated Balance Sheets
 
Assets
 
(Liabilities)
 
Assets
 
(Liabilities)
 
 
 
(Thousands of dollars)
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
 
Commodity contracts (a)
 
 
 
 
 
 
 
 
 
Financial contracts
Other current assets
 
$
30,763

 
$
(24,662
)
 
$
78,891

 
$
(31,793
)
 
Other assets
 
3,545

 
(2,494
)
 
1,086

 
(946
)
Physical contracts
Other current assets
 
751

 

 
1,142

 

Interest-rate contracts
Other current assets/other current liabilities
 

 
(4,714
)
 
19,005

 
(15,012
)
 
Other deferred credits
 

 
(145,270
)
 

 
(84,248
)
Total derivatives designated as hedging instruments
 
$
35,059

 
$
(177,140
)
 
$
100,124

 
$
(131,999
)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:
 
 
March 31, 2019
 
December 31, 2018
 
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

 
(41.4
)
 

 
(29.9
)
- Crude oil and NGLs (MMBbl)
Futures, forwards
and swaps
6.5

 
(13.5
)
 
6.5

 
(13.8
)
Basis
 
 

 
 

 
 
 
 
- Natural gas (Bcf)
Futures and swaps

 
(41.4
)
 

 
(29.9
)
Interest-rate contracts (Millions of dollars)
Swaps
$
3,250.0

 
$

 
$
4,250.0

 
$



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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 - 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
Derivatives in Cash Flow Hedging Relationships
March 31,
2019
 
2018
 
(Thousands of dollars)
Commodity contracts
$
(21,625
)
 
$
20,925

Interest-rate contracts
(67,912
)
 
23,911

Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives
$
(89,537
)
 
$
44,836


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
Loss into Net Income
Three Months Ended
March 31,
2019
 
2018
 
 
(Thousands of dollars)
Commodity contracts
Commodity sales revenues/cost of sales and fuel
$
18,852

 
$
(11,611
)
Interest-rate contracts
Interest expense
(2,504
)
 
(3,943
)
Total gain (loss) reclassified from accumulated other comprehensive loss into net income on derivatives
$
16,348

 
$
(15,554
)

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 use internally developed credit ratings for counterparties that do not have a credit rating.

Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account with daily margin requirements. However, we may enter into financial derivative instruments that 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 at March 31, 2019.

The counterparties to our derivative contracts typically consist 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 March 31, 2019, the credit exposure from our derivative assets is with investment-grade companies in the financial services sector.


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D.
DEBT

The following table sets forth our consolidated debt for the periods indicated:
 
 
March 31,
2019
 
December 31,
2018
 
 
(Thousands of dollars)
Commercial paper outstanding
 
$

 
$

Senior unsecured obligations:
 
 
 
 
$500,000 at 8.625% due March 2019
 

 
500,000

$300,000 at 3.8% due March 2020
 
300,000

 
300,000

$1,500,000 term loan, variable rate, due November 2021
 
750,000

 
550,000

$700,000 at 4.25% due February 2022
 
547,397

 
547,397

$900,000 at 3.375% due October 2022
 
900,000

 
900,000

$425,000 at 5.0% due September 2023
 
425,000

 
425,000

$500,000 at 7.5% due September 2023
 
500,000

 
500,000

$500,000 at 4.9% due March 2025
 
500,000

 
500,000

$500,000 at 4.0% due July 2027
 
500,000

 
500,000

$800,000 at 4.55% due July 2028
 
800,000

 
800,000

$100,000 at 6.875% due September 2028
 
100,000

 
100,000

$700,000 at 4.35% due March 2029
 
700,000

 

$400,000 at 6.0% due June 2035
 
400,000

 
400,000

$600,000 at 6.65% due October 2036
 
600,000

 
600,000

$600,000 at 6.85% due October 2037
 
600,000

 
600,000

$650,000 at 6.125% due February 2041
 
650,000

 
650,000

$400,000 at 6.2% due September 2043
 
400,000

 
400,000

$700,000 at 4.95% due July 2047
 
700,000

 
700,000

$1,000,000 at 5.2% due July 2048
 
1,000,000

 
450,000

Guardian Pipeline
 
 
 
 
Weighted average 7.85% due December 2022
 
27,045

 
28,957

Total debt
 
10,399,442

 
9,451,354

Unamortized portion of terminated swaps
 
16,320

 
16,750

Unamortized debt issuance costs and discounts
 
(103,771
)
 
(87,120
)
Current maturities of long-term debt
 
(307,650
)
 
(507,650
)
Long-term debt
 
$
10,004,341

 
$
8,873,334


$2.5 Billion Credit Agreement - In June 2018, we extended the term of our $2.5 Billion Credit Agreement by one year to June 2023. Our $2.5 Billion Credit Agreement is a revolving credit facility and 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 $2.5 Billion Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.5 to 1 at March 31, 2019, and 5.0 to 1 thereafter. Once the covenant decreases to 5.0 to 1, if we consummate one or more acquisitions in which the aggregate purchase 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 is completed and the two following quarters. At March 31, 2019, we had no borrowings outstanding, our ratio of indebtedness to adjusted EBITDA was 3.6 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.

Debt Issuances - In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $700 million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued interest, were $1.23 billion. The proceeds were used for general corporate purposes, which included repayment of existing indebtedness and funding capital expenditures.

In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which is available to be drawn until May 2019. Our $1.5 Billion Term Loan Agreement matures in November 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. As of March 31, 2019, we had borrowings totaling $750 million

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outstanding under our $1.5 Billion Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.

Debt Repayments - We repaid our $500 million, 8.625% senior notes due March 2019 with a combination of cash on hand and short-term borrowings.

For additional discussion of our $2.5 Billion Credit Agreement and our $1.5 Billion Term Loan Agreement, see Note F of the Notes to Consolidated Financial Statements in our Annual Report.

E.
EQUITY

Noncontrolling Interests - In July 2018, we acquired the remaining 20% interest that we did not own in WTLPG for $195 million with cash on hand. We are now the sole owner of the West Texas LPG pipeline system.

Equity Issuances - In July 2017, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate amount of $1 billion. The program allows us to offer and sell our common stock at prices we deem appropriate through a sales agent. Sales of our common stock may be 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 stock under the program. No shares have been sold through our “at-the-market” equity program since December 2017.

In January 2018, we completed an underwritten public offering of 21.9 million shares of our common stock, generating net proceeds of $1.2 billion. We used the net proceeds from this offering to fund capital expenditures and for general corporate purposes, which included repaying a portion of our outstanding indebtedness.

Dividends - Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of outstanding preferred stock. Dividends paid on our common stock in February 2019 were $0.86 per share. A dividend of $0.865 per share was declared for shareholders of record at the close of business on April 29, 2019, payable May 15, 2019.

The Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2019. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable May 15, 2019.

F.
ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive loss for the period indicated:
 
 
Unrealized Gains
(Losses) on Risk-
Management
Assets/Liabilities (a)
 
Retirement and Other
Postretirement
Benefit Plan
Obligations (a) (b)
 
Unrealized Gains
(Losses) on Risk-
Management
Assets/Liabilities of
Unconsolidated
Affiliates (a)
 
Accumulated
Other
Comprehensive
Loss (a)
 
 
(Thousands of dollars)
January 1, 2019
 
$
(64,660
)
 
$
(121,785
)
 
$
(1,794
)
 
$
(188,239
)
Other comprehensive income (loss) before reclassifications
 
(68,944
)
 
(104
)
 
(2,453
)
 
(71,501
)
Amounts reclassified from accumulated other comprehensive loss
 
(12,171
)
 
2,445

 
(58
)
 
(9,784
)
Other comprehensive income (loss)
 
(81,115
)
 
2,341

 
(2,511
)
 
(81,285
)
March 31, 2019
 
$
(145,775
)
 
$
(119,444
)
 
$
(4,305
)
 
$
(269,524
)
(a) - All amounts are presented net of tax.
(b) - Includes amounts related to supplemental executive retirement plan.


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The following table sets forth information about the balance of accumulated other comprehensive loss at March 31, 2019, representing unrealized gains (losses) related to risk-management assets and liabilities:
 
 
Risk-
Management
Assets/Liabilities (a)
 
 
(Thousands of dollars)
Commodity derivative instruments expected to be realized within the next 21 months (b)
 
$
6,422

Settled interest-rate swaps to be recognized over the life of the long-term, fixed-rate debt (c)
 
(36,709
)
Interest-rate swaps with future settlement dates expected to be amortized over the life of long-term debt
 
(115,488
)
Accumulated other comprehensive loss at March 31, 2019
 
$
(145,775
)
(a) - All amounts are presented net of tax.
(b) - Based on March 31, 2019, commodity prices, we will realize $5.6 million in net gains, net of tax, over the next 12 months and $0.8 million in net gains, net of tax, thereafter.
(c) - Losses of $13.6 million, net of tax, will be reclassified into earnings during the next 12 months as the hedged items affect earnings.

The remaining amounts in accumulated other comprehensive loss relate primarily to our retirement and other postretirement benefit plan obligations, which are expected to be amortized over the average remaining service period of employees participating in these plans.

The following table sets forth the effect of reclassifications from accumulated other comprehensive loss in our Consolidated Statements of Income for the periods indicated:
Details about Accumulated Other
Comprehensive Loss
Components
 
Three Months Ended
 
Affected Line Item in the
Consolidated
Statements of Income
 
March 31,
 
 
2019
 
2018
 
 
 
(Thousands of dollars)
 
 
Risk-management assets/liabilities
 
 
 
 
 
 
Commodity contracts
 
$
18,852

 
$
(11,611
)
 
Commodity sales revenues/cost of sales and fuel
Interest-rate contracts
 
(2,504
)
 
(3,943
)
 
Interest expense
 
 
16,348

 
(15,554
)
 
Income before income taxes
 
 
(4,177
)
 
3,578

 
Income taxes
 
 
$
12,171

 
$
(11,976
)
 
Net income
 
 
 
 
 
 
 
Retirement and other postretirement benefit plan obligations (a)
 
 
 
 
 
 
Amortization of net loss
 
$
(3,232
)
 
$
(4,592
)
 
Other income (expense)
Amortization of unrecognized prior service credit
 
57

 
415

 
Other income (expense)
 
 
(3,175
)
 
(4,177
)
 
Income before income taxes
 
 
730

 
961

 
Income taxes
 
 
$
(2,445
)
 
$
(3,216
)
 
Net income
 
 
 
 
 
 
 
Risk-management assets/liabilities of unconsolidated affiliates
 
 
 
 
 
 
Interest-rate contracts
 
$
75

 
$
47

 
Equity in net earnings from investments
 
 
(17
)
 
(11
)
 
Income taxes
 
 
$
58

 
$
36

 
Net income
 
 
 
 
 
 
 
Total reclassifications for the period
 
$
9,784

 
$
(15,156
)
 
Net income
(a) - These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note H for additional detail of our net periodic benefit cost.


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G.
EARNINGS PER SHARE

The following tables set forth the computation of basic and diluted EPS for the periods indicated:
 
Three Months Ended March 31, 2019
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS
 
 
 
 
 
Net income available for common stock
$
336,933

 
412,908

 
$
0.82

Diluted EPS
 
 
 

 
 

Effect of dilutive securities

 
2,325

 
 

Net income available for common stock and
common stock equivalents
$
336,933

 
415,233

 
$
0.81


 
Three Months Ended March 31, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS
 
 
 
 
 
Net income attributable to ONEOK available for common stock
$
264,233

 
409,676

 
$
0.65

Diluted EPS
 
 
 
 
 

Effect of dilutive securities

 
2,497

 
 

Net income attributable to ONEOK available for common stock and
common stock equivalents
$
264,233

 
412,173

 
$
0.64


H.
EMPLOYEE BENEFIT PLANS

The following table sets forth the components of net periodic benefit cost (income) for our retirement and other postretirement benefit plans for the periods indicated:
 
Retirement Benefits
 
Other Postretirement Benefits
 
Three Months Ended
 
Three Months Ended
 
March 31,
 
March 31,
 
2019
 
2018
 
2019
 
2018
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
 
 
 
 
 
Service cost
$
1,954

 
$
1,832

 
$
117

 
$
211

Interest cost
5,126

 
4,408

 
509

 
527

Expected return on plan assets
(5,892
)
 
(5,969
)
 
(570
)
 
(672
)
Amortization of prior service credit

 

 
(57
)
 
(415
)
Amortization of net loss
3,158

 
4,258

 
74

 
334

Net periodic benefit cost (income)
$
4,346

 
$
4,529

 
$
73

 
$
(15
)


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I.
UNCONSOLIDATED AFFILIATES

Equity in Net Earnings from Investments - The following table sets forth our equity in net earnings (loss) from investments for the periods indicated:
 
Three Months Ended
 
March 31,
 
2019
 
2018
 
(Thousands of dollars)
Northern Border Pipeline
$
20,802

 
$
17,137

Overland Pass Pipeline Company
17,394

 
16,387

Roadrunner Gas Transmission
6,338

 
4,958

Other
(1,053
)
 
1,705

Equity in net earnings from investments
$
43,481

 
$
40,187


Unconsolidated Affiliates Financial Information - The following table sets forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:
 
Three Months Ended
 
March 31,
 
2019
 
2018
 
(Thousands of dollars)
Income Statement
 
 
 
Revenues
$
167,046

 
$
158,908

Operating expenses
$
69,800

 
$
68,401

Net income
$
90,897

 
$
84,480

 
 
 
 
Distributions paid to us
$
59,463

 
$
49,816


We incurred expenses in transactions with unconsolidated affiliates of $41.8 million and $37.5 million for the three months ended March 31, 2019 and 2018, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline. Accounts payable to our equity-method investees at March 31, 2019, and December 31, 2018, were $14.1 million and $14.7 million, respectively.

We have an operating agreement with Roadrunner that provides for reimbursement or payment to us for management services and certain operating costs. Reimbursements and payments from Roadrunner included in operating income in our Consolidated Statements of Income for the three months ended March 31, 2019 and 2018, were not material.

J.
COMMITMENTS AND CONTINGENCIES

Environmental Matters and Pipeline Safety - The operation of pipelines, plants and other facilities for the gathering, processing, transportation and storage of natural gas, NGLs, condensate and other products is subject to numerous and complex laws and regulations pertaining to health, safety and the environment. As an owner and/or operator of these facilities, we must comply with laws and regulations that relate to facility/pipeline safety and integrity as well as air and water quality, hazardous and solid waste management and disposal, cultural resource protection and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with these laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation or construction. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

Legal Proceedings - Gas Index Pricing Litigation - As previously reported, in March 2017, the United States District Court for the District of Nevada (the Nevada District Court) granted summary judgment to ONEOK Energy Services Company, L.P. (OESC) in Sinclair Oil Corporation v. ONEOK Energy Services Company, L.P. (filed in the United States District Court for the District of Wyoming (the Wyoming District Court) in September 2005, transferred to MDL-1566 in the Nevada District Court). In September 2017, the Nevada District Court entered a final judgment in favor of OESC in Sinclair, which was appealed by Sinclair Oil Corporation to the Ninth Circuit Court of Appeals. In August 2018, the Ninth Circuit Court of Appeals reversed

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the Nevada District Court’s granting of summary judgment and remanded the case back to the Nevada District Court. In February 2019, Sinclair was further remanded back to the Wyoming District Court. We expect that future charges, if any, from the ultimate resolution of the Sinclair case will not be material to our results of operations, financial position or cash flows.

Other Legal Proceedings - We are a party to various other litigation matters and claims that have arisen in the normal course of our operations. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from 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.
LEASES

Adoption of ASC Topic 842: Leases - We adopted Topic 842 using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative-effect adjustment to retained earnings as of January 1, 2019. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.

Practical Expedients and Policies Elected - We applied the short-term policy election, which allows us to exclude from recognition leases with an initial term of 12 months or less. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things, allows us to carry forward the historical lease classification; and the land easement expedient, which allows us to apply the guidance prospectively at adoption for land easements on existing agreements.

Adoption - Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Consolidated Balance Sheet of $17.5 million and $17.4 million, respectively, as of January 1, 2019. The difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases did not change. Adoption of Topic 842 did not materially impact our Consolidated Financial Statements.

Leases - We lease certain buildings, warehouses, office space, land and equipment, including pipeline equipment, rail cars and information technology equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in a lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include any residual value guarantees or material restrictive covenants.

Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own an office building and a parking garage and lease excess space in these facilities to affiliates and others. Our consolidated lease income is not material.

For the three months ended March 31, 2019, cash paid for amounts included in the measurement of our lease liabilities was not material.


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The following table sets forth information about our lease assets and liabilities included in our Consolidated Balance Sheet for the period indicated:
Leases
Location in our Consolidated Balance Sheet
 
March 31, 2019
 
 
 
(Thousands of dollars)
Assets
 
 
 
Operating lease assets
Other assets
 
$
16,374

Finance lease assets
Property, plant and equipment
 
28,286

Finance lease assets
Accumulated depreciation
 
(471
)
Total leased assets
 
 
$
44,189

 
 
 
 
Liabilities
 
 
 
Current
 
 
 
Operating
Other current liabilities
 
$
4,497

Finance
Finance lease liability
 
1,809

Noncurrent
 
 
 
Operating
Other deferred credits
 
12,281

Finance
Finance lease liability
 
25,775

Total lease liabilities
 
 
$
44,362


The following table sets forth information about our leases for the periods indicated:
 
Location in our Consolidated Statement of Income
Three Months Ended March 31, 2019
At March 31, 2019
 
Lease cost
Weighted-Average Remaining Lease Term
 
Weighted-Average Discount Rate (a)
 
 
(Thousands of dollars)
(Years)
 
 
Operating leases
Operations and maintenance
$
1,730

9.3
 
4.58%
Finance lease
 


9.6
 
10.00%
Amortization of lease assets
Depreciation and amortization
283

 
 
 
Interest on lease liabilities
Interest expense
697

 
 
 
Total lease cost
 
$
2,710

 
 
 
(a) - Our weighted-average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our lease liabilities as of March 31, 2019:
 
 
Finance
Lease
 
Operating
Leases
 
 
(Millions of dollars)
Remainder of 2019
 
$
3.4

 
$
5.1

2020
 
4.5

 
1.8

2021
 
4.5

 
1.7

2022
 
4.5

 
1.6

2023
 
4.5

 
1.6

2024 and beyond
 
21.6

 
9.2

Total lease payments
 
43.0

 
21.0

Less: Interest
 
15.4

 
4.2

Present value of lease liabilities
 
$
27.6

 
$
16.8


Our future lease payments presented under the previous accounting standard as of December 31, 2018, are not materially different than those presented above.


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L.
REVENUES

Accounting Policies - Our revenue recognition policy is described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Contract Assets and Contract Liabilities - The following tables set forth the balances in contract assets and contract liabilities for the periods indicated:
Contract Assets
 
(Millions of dollars)
Balance at January 1, 2019 (a)
 
$
6.2

Amounts invoiced in excess of revenue recognized
 
(0.7
)
Balance at March 31, 2019 (b)
 
$
5.5

(a) - Contract assets of $1.7 million and $4.5 million are included in other current assets and other assets, respectively, in our Consolidated Balance Sheets.
(b) - Contract assets of $1.3 million and $4.2 million are included in other current assets and other assets, respectively, in our Consolidated Balance Sheets.
Contract Liabilities
 
(Millions of dollars)
Balance at January 1, 2019 (a)
 
$
31.7

Revenue recognized included in beginning balance

(13.2
)
Net additions
 
13.0

Balance at March 31, 2019 (b)
 
$
31.5

(a) - Contract liabilities of $15.6 million and $16.1 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheets.
(b) - Contract liabilities of $10.6 million and $20.9 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheets.

Receivables from Customers and Revenue Disaggregation - Substantially all of the balances in accounts receivable on our Consolidated Balance Sheets at March 31, 2019, and December 31, 2018, relate to customer receivables. Revenues sources are disaggregated in Note M.

Practical Expedients - We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) variable consideration on contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

Transaction Price Allocated to Unsatisfied Performance Obligations - The following table presents aggregate value allocated to unsatisfied performance obligations as of March 31, 2019, and the amounts we expect to recognize in revenue in future periods, related primarily to firm transportation and storage contracts with remaining contract terms ranging from one month to 25 years:
Expected Period of Recognition in Revenue
 
(Millions of dollars)
Remainder of 2019
 
$
258.0

2020
 
296.0

2021
 
264.0

2022
 
202.3

2023 and beyond
 
907.9

Total estimated transaction price allocated to unsatisfied performance obligations
 
$
1,928.2


The table above excludes variable consideration allocated entirely to wholly unsatisfied performance obligations, wholly unsatisfied promises to transfer distinct goods or services that are part of a single performance obligation and consideration we determine to be fully constrained. The amounts we determined to be fully constrained relate to future sales obligations under long-term sales contracts where the transaction price is not known and minimum volume agreements, which we consider to be fully constrained until invoiced.

M.
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;

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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.

Other and eliminations consist of corporate costs, the operating and leasing activities of our headquarters building and related parking facility and eliminations necessary to reconcile our reportable segments to our Consolidated Financial Statements.

Accounting Policies - The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:
Three Months Ended
March 31, 2019
Natural Gas
Gathering and
Processing
 
Natural Gas
Liquids (a)
 
Natural Gas
Pipelines (b)
 
Total Segments
 
(Thousands of dollars)
NGL and condensate sales
$
332,332

 
$
2,158,103

 
$

 
$
2,490,435

Residue natural gas sales
319,036

 

 
970

 
320,006

Gathering, processing and exchange services revenue
39,742

 
98,534

 

 
138,276

Transportation and storage revenue

 
52,322

 
103,470

 
155,792

Other
3,551

 
2,541

 
11,960

 
18,052

Total revenues (c)
694,661

 
2,311,500

 
116,400

 
3,122,561

 
 
 
 
 
 
 
 
Cost of sales and fuel (exclusive of depreciation and operating costs)
(450,913
)
 
(1,846,673
)
 
(1,755
)
 
(2,299,341
)
Operating costs
(94,247
)
 
(110,438
)
 
(36,268
)
 
(240,953
)
Equity in net earnings (loss) from investments
(1,202
)
 
17,544

 
27,139

 
43,481

Noncash compensation expense and other
3,945

 
5,706

 
1,132

 
10,783

Segment adjusted EBITDA
$
152,244

 
$
377,639

 
$
106,648

 
$
636,531

 
 
 
 
 
 
 
 
Depreciation and amortization
$
(52,681
)
 
$
(46,401
)
 
$
(14,156
)
 
$
(113,238
)
Total assets
$
6,208,883

 
$
10,220,412

 
$
2,138,759

 
$
18,568,054

Capital expenditures
$
215,148

 
$
639,338

 
$
28,688

 
$
883,174

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $323.1 million, of which $270.0 million related to sales within the segment, and cost of sales and fuel of $118.5 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $70.1 million and cost of sales and fuel of $5.6 million.
(c) - Intersegment revenues for the Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments totaled $335.8 million, $3.5 million and $3.9 million, respectively.


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Three Months Ended
March 31, 2019
 
Total
Segments
 
Other and
Eliminations
 
Total
 
 
(Thousands of dollars)
Reconciliations of total segments to consolidated
 
 
 
 
 
 
NGL and condensate sales
 
$
2,490,435

 
$
(338,351
)
 
$
2,152,084

Residue natural gas sales
 
320,006

 

 
320,006

Gathering, processing and exchange services revenue
 
138,276

 

 
138,276

Transportation and storage revenue
 
155,792

 
(2,521
)
 
153,271

Other
 
18,052

 
(1,731
)
 
16,321

Total revenues (a)
 
$
3,122,561

 
$
(342,603
)
 
$
2,779,958

 
 
 
 
 
 
 
Cost of sales and fuel (exclusive of depreciation and operating costs)
 
$
(2,299,341
)
 
$
342,964

 
$
(1,956,377
)
Operating costs
 
$
(240,953
)
 
$
212

 
$
(240,741
)
Depreciation and amortization
 
$
(113,238
)
 
$
(920
)
 
$
(114,158
)
Equity in net earnings from investments
 
$
43,481

 
$

 
$
43,481

Total assets
 
$
18,568,054

 
$
366,271

 
$
18,934,325

Capital expenditures
 
$
883,174

 
$
6,531

 
$
889,705

(a) - Noncustomer revenue for the three months ended March 31, 2019, totaled $22.3 million related primarily to gains reclassified from accumulated other comprehensive loss from commodity derivative contracts.

Three Months Ended
March 31, 2018
Natural Gas
Gathering and
Processing
 
Natural Gas
Liquids (a)
 
Natural Gas
Pipelines (b)
 
Total Segments
 
(Thousands of dollars)
NGL and condensate sales
$
413,157

 
$
2,552,770

 
$

 
$
2,965,927

Residue natural gas sales
254,997

 

 
4,919

 
259,916

Gathering, processing and exchange services revenue
38,429

 
83,258

 

 
121,687

Transportation and storage revenue

 
53,478

 
98,338

 
151,816

Other
1,408

 
2,963

 
6,654

 
11,025

Total revenues (c)
707,991

 
2,692,469

 
109,911

 
3,510,371

 
 
 
 
 
 
 
 
Cost of sales and fuel (exclusive of depreciation and operating costs)
(492,622
)
 
(2,281,072
)
 
(5,454
)
 
(2,779,148
)
Operating costs
(88,359
)
 
(88,592
)
 
(33,190
)
 
(210,141
)
Equity in net earnings from investments
1,668

 
16,424

 
22,095

 
40,187

Other
1,873

 
2,850

 
263

 
4,986

Segment adjusted EBITDA
$
130,551

 
$
342,079

 
$
93,625

 
$
566,255

 
 
 
 
 
 
 
 
Depreciation and amortization
$
(47,748
)
 
$
(42,427
)
 
$
(13,269
)
 
$
(103,444
)
Total assets
$
5,462,305

 
$
8,370,364

 
$
2,060,700

 
$
15,893,369

Capital expenditures
$
111,729

 
$
124,921

 
$
19,898

 
$
256,548

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $300.0 million, of which $253.4 million related to sales within the segment, and cost of sales and fuel of $122.8 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.0 million and cost of sales and fuel of $9.1 million.
(c) - Intersegment revenues for the Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments totaled $397.8 million, $9.0 million and $2.1 million, respectively.


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Three Months Ended
March 31, 2018
 
Total
Segments
 
Other and
Eliminations
 
Total
 
 
(Thousands of dollars)
Reconciliations of total segments to consolidated
 
 
 
 
 
 
NGL and condensate sales
 
$
2,965,927

 
$
(408,910
)
 
$
2,557,017

Residue natural gas sales
 
259,916

 
2,250

 
262,166

Gathering, processing and exchange services revenue
 
121,687

 
(21
)
 
121,666

Transportation and storage revenue
 
151,816

 
(2,094
)
 
149,722

Other
 
11,025

 
481

 
11,506

Total revenues (a)
 
$
3,510,371

 
$
(408,294
)
 
$
3,102,077

 
 
 
 
 
 
 
Cost of sales and fuel (exclusive of depreciation and operating costs)
 
$
(2,779,148
)
 
$
411,122

 
$
(2,368,026
)
Operating costs
 
$
(210,141
)
 
$
(63
)
 
$
(210,204
)
Depreciation and amortization
 
$
(103,444
)
 
$
(793
)
 
$
(104,237
)
Equity in net earnings from investments
 
$
40,187

 
$

 
$
40,187

Total assets
 
$
15,893,369

 
$
538,978

 
$
16,432,347

Capital expenditures
 
$
256,548

 
$
7,919

 
$
264,467

(a) - Noncustomer revenue for the three months ended March 31, 2018, totaled $(9.0) million related primarily to losses reclassified from accumulated other comprehensive loss from commodity derivative contracts.

 
Three Months Ended
 
March 31,
 
2019
 
2018
 
(Thousands of dollars)
Reconciliation of net income to total segment adjusted EBITDA
 
 
 
Net income
$
337,208

 
$
266,049

Add:
 
 
 
Interest expense, net of capitalized interest
115,420

 
115,725

Depreciation and amortization
114,158

 
104,237

Income taxes
77,934

 
75,771

Noncash compensation expense
5,540

 
9,226

Other corporate costs and noncash items
(13,729
)
 
(4,753
)
Total segment adjusted EBITDA
$
636,531

 
$
566,255


N.
SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

ONEOK and ONEOK Partners are issuers of certain public debt securities. We, ONEOK Partners and the Intermediate Partnership guarantee the indebtedness of ONEOK and ONEOK Partners. The Intermediate Partnership holds all of ONEOK Partners’ partnership interests and equity in its subsidiaries, as well as a 50 percent interest in Northern Border Pipeline. In lieu of providing separate financial statements for each subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuers in separate columns in this single set of condensed consolidating financial statements.

For purposes of the following footnote:
we are referred to as “Parent Issuer and Guarantor”
ONEOK Partners is referred to as “Subsidiary Issuer and Guarantor”
the Intermediate Partnership is referred to as “Guarantor Subsidiary” and
the “Non-Guarantor Subsidiaries” are all subsidiaries other than the Guarantor Subsidiary and Subsidiary Issuer and Guarantor.

The following unaudited supplemental condensed consolidating financial information is presented on an equity-method basis reflecting the separate accounts of ONEOK, ONEOK Partners and the Intermediate Partnership, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and our consolidated amounts for the periods indicated.

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Condensed Consolidating Statements of Income
 
Three Months Ended March 31, 2019
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
 
(Millions of dollars)
Revenues
 
 
 
 
 
 
 
 
 
 
 
Commodity sales
$

 
$

 
$

 
$
2,473.0

 
$

 
$
2,473.0

Services

 

 

 
307.5

 
(0.5
)
 
307.0

Total revenues

 

 

 
2,780.5

 
(0.5
)
 
2,780.0

Cost of sales and fuel (exclusive of items shown separately below)

 

 

 
1,956.4

 

 
1,956.4

Operating expenses

 

 

 
355.5

 
(0.5
)
 
355.0

Gain on sale of assets

 

 

 
(0.1
)
 

 
(0.1
)
Operating income

 

 

 
468.7

 

 
468.7

Equity in net earnings from investments
456.7

 
460.6

 
460.6

 
30.1

 
(1,364.5
)
 
43.5

Other income (expense), net
6.8

 
81.0

 
81.0

 
11.5

 
(162.0
)
 
18.3

Interest expense, net
(52.8
)
 
(81.0
)
 
(81.0
)
 
(62.6
)
 
162.0

 
(115.4
)
Income before income taxes
410.7

 
460.6

 
460.6

 
447.7

 
(1,364.5
)
 
415.1

Income taxes
(73.5
)
 

 

 
(4.4
)
 

 
(77.9
)
Net income
337.2

 
460.6

 
460.6

 
443.3

 
(1,364.5
)
 
337.2

Less: Preferred stock dividends
0.3

 

 

 

 

 
0.3

Net income available to common shareholders
$
336.9

 
$
460.6

 
$
460.6

 
$
443.3

 
$
(1,364.5
)
 
$
336.9

 
Three Months Ended March 31, 2018
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
 
(Millions of dollars)
Revenues
 
 
 
 
 
 
 
 
 
 
 
Commodity sales
$

 
$

 
$

 
$
2,820.0

 
$

 
$
2,820.0

Services

 

 

 
282.6

 
(0.5
)
 
282.1

Total revenues

 

 

 
3,102.6

 
(0.5
)
 
3,102.1

Cost of sales and fuel (exclusive of items shown separately below)

 

 

 
2,368.0

 

 
2,368.0

Operating expenses
(0.7
)
 

 

 
315.7

 
(0.5
)
 
314.5

Gain on sale of assets

 

 

 
(0.1
)
 

 
(0.1
)
Operating income
0.7

 

 

 
419.0

 

 
419.7

Equity in net earnings from investments
368.5

 
370.9

 
370.9

 
28.6

 
(1,098.7
)
 
40.2

Other income (expense), net
7.2

 
77.1

 
77.1

 
(9.6
)
 
(154.2
)
 
(2.4
)
Interest expense, net
(39.8
)
 
(77.1
)
 
(77.1
)
 
(75.9
)
 
154.2

 
(115.7
)
Income before income taxes
336.6

 
370.9

 
370.9

 
362.1

 
(1,098.7
)
 
341.8

Income taxes
(72.1
)
 

 

 
(3.7
)
 

 
(75.8
)
Net income
264.5

 
370.9

 
370.9

 
358.4

 
(1,098.7
)
 
266.0

Less: Net income attributable to noncontrolling interests

 

 

 
1.5

 

 
1.5

Net income attributable to ONEOK
264.5

 
370.9

 
370.9

 
356.9

 
(1,098.7
)
 
264.5

Less: Preferred stock dividends
0.3

 

 

 

 

 
0.3

Net income available to common shareholders
$
264.2

 
$
370.9

 
$
370.9

 
$
356.9

 
$
(1,098.7
)
 
$
264.2




31

Table of Contents

Condensed Consolidating Statements of Comprehensive Income
 
Three Months Ended March 31, 2019
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
 
(Millions of dollars)
Net income
$
337.2

 
$
460.6

 
$
460.6

 
$
443.3

 
$
(1,364.5
)
 
$
337.2

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 

 
 

 
 

Unrealized gains (losses) on derivatives, net of tax
(52.3
)
 
(21.6
)
 
(21.6
)
 
(16.7
)
 
43.3

 
(68.9
)
Realized (gains) losses on derivatives recognized in net income, net of tax
(1.1
)
 
(14.4
)
 
(18.9
)
 
(15.5
)
 
37.7

 
(12.2
)
Change in retirement and other postretirement benefit plan liability, net of tax
2.4

 
(0.1
)
 

 

 

 
2.3

Other comprehensive income (loss) on investments in unconsolidated affiliates, net of tax

 
(3.3
)
 
(3.3
)
 
(2.5
)
 
6.6

 
(2.5
)
Total other comprehensive income (loss), net of tax
(51.0
)
 
(39.4
)
 
(43.8
)
 
(34.7
)
 
87.6

 
(81.3
)
Comprehensive income
$
286.2

 
$
421.2

 
$
416.8

 
$
408.6

 
$
(1,276.9
)
 
$
255.9


 
Three Months Ended March 31, 2018
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
 
(Millions of dollars)
Net income
$
264.5

 
$
370.9

 
$
370.9

 
$
358.4

 
$
(1,098.7
)
 
$
266.0

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 

 
 

 
 

Unrealized gains (losses) on derivatives, net of tax
18.4

 
20.9

 
20.9

 
16.1

 
(41.8
)
 
34.5

Realized (gains) losses on derivatives recognized in net income, net of tax
0.9

 
14.3

 
11.6

 
8.3

 
(23.1
)
 
12.0

Change in retirement and other postretirement benefit plan liability, net of tax
3.2

 
(0.6
)
 

 

 

 
2.6

Other comprehensive income (loss) on investments in unconsolidated affiliates, net of tax

 
3.7

 
3.7

 
2.8

 
(7.4
)
 
2.8

Total other comprehensive income (loss), net of tax
22.5

 
38.3

 
36.2

 
27.2

 
(72.3
)
 
51.9

Comprehensive income
287.0

 
409.2

 
407.1

 
385.6

 
(1,171.0
)
 
317.9

Less: Comprehensive income attributable to noncontrolling interests

 

 

 
1.5

 

 
1.5

Comprehensive income attributable to ONEOK
$
287.0

 
$
409.2

 
$
407.1

 
$
384.1

 
$
(1,171.0
)
 
$
316.4



32

Table of Contents

Condensed Consolidating Balance Sheets
 
March 31, 2019
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
Assets
(Millions of dollars)
Current assets
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
27.8

 
$

 
$

 
$

 
$

 
$
27.8

Accounts receivable, net

 

 

 
812.9

 

 
812.9

Materials and supplies

 

 

 
163.7

 

 
163.7

Natural gas and natural gas liquids in storage

 

 

 
243.2

 

 
243.2

Other current assets
12.1

 

 

 
83.1

 

 
95.2

Total current assets
39.9

 

 

 
1,302.9

 

 
1,342.8

Property, plant and equipment
 

 
 

 
 

 
 

 
 

 
 

Property, plant and equipment
148.6

 

 

 
18,739.1

 

 
18,887.7

Accumulated depreciation and amortization
93.9

 

 

 
3,275.8

 

 
3,369.7

Net property, plant and equipment
54.7

 

 

 
15,463.3

 

 
15,518.0

Investments and other assets
 

 
 

 
 

 
 

 
 

 
 

Investments
6,251.4

 
3,631.9

 
10,109.9

 
783.1

 
(19,825.4
)
 
950.9

Intercompany notes receivable
6,523.9

 
7,189.5

 
711.5

 

 
(14,424.9
)
 

Other assets
127.6

 

 

 
995.9

 
(0.9
)
 
1,122.6

Total investments and other assets
12,902.9

 
10,821.4

 
10,821.4

 
1,779.0

 
(34,251.2
)
 
2,073.5

Total assets
$
12,997.5

 
$
10,821.4

 
$
10,821.4

 
$
18,545.2

 
$
(34,251.2
)
 
$
18,934.3

Liabilities and equity
 

 
 

 
 

 
 

 
 

 
 

Current liabilities
 

 
 

 
 

 
 

 
 

 
 

Current maturities of long-term debt
$

 
$
300.0

 
$

 
$
7.7

 
$

 
$
307.7

Accounts payable
6.2

 

 

 
1,021.1

 

 
1,027.3

Other current liabilities
73.1

 
64.0

 

 
217.6

 

 
354.7

Total current liabilities
79.3

 
364.0

 

 
1,246.4

 

 
1,689.7

 
 
 
 
 
 
 
 
 
 
 
 
Intercompany debt

 

 
7,189.5

 
7,235.4

 
(14,424.9
)
 

 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, excluding current maturities
5,942.7

 
4,042.3

 

 
19.3

 

 
10,004.3

 
 
 
 
 
 
 
 
 
 
 
 
Deferred credits and other liabilities
533.5

 

 

 
265.7

 
(0.9
)
 
798.3

 
 
 
 
 
 
 
 
 
 
 
 
Commitments and contingencies


 


 


 


 


 


 
 
 
 
 
 
 
 
 
 
 
 
Equity
6,442.0

 
6,415.1

 
3,631.9

 
9,778.4

 
(19,825.4
)
 
6,442.0

Total liabilities and equity
$
12,997.5


$
10,821.4


$
10,821.4


$
18,545.2


$
(34,251.2
)

$
18,934.3


33

Table of Contents

 
December 31, 2018
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
Assets
(Millions of dollars)
Current assets
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
12.0

 
$

 
$

 
$

 
$

 
$
12.0

Accounts receivable, net

 

 

 
819.0

 

 
819.0

Materials and supplies

 

 

 
141.2

 

 
141.2

Natural gas and natural gas liquids in storage

 

 

 
296.7

 

 
296.7

Other current assets
29.1

 

 

 
100.6

 

 
129.7

Total current assets
41.1



 

 
1,357.5

 


1,398.6

Property, plant and equipment
 

 
 

 
 

 
 

 
 

 
 

Property, plant and equipment
145.5

 

 

 
17,885.5

 

 
18,031.0

Accumulated depreciation and amortization
92.0

 

 

 
3,172.3

 

 
3,264.3

Net property, plant and equipment
53.5

 

 

 
14,713.2

 

 
14,766.7

Investments and other assets
 

 
 

 
 

 
 

 
 

 
 

Investments
6,153.5

 
3,548.1

 
9,721.6

 
791.1

 
(19,245.1
)
 
969.2

Intercompany notes receivable
5,308.6

 
7,701.5

 
1,528.0

 

 
(14,538.1
)
 

Other assets
115.9

 

 

 
982.3

 
(1.0
)
 
1,097.2

Total investments and other assets
11,578.0

 
11,249.6

 
11,249.6

 
1,773.4

 
(33,784.2
)
 
2,066.4

Total assets
$
11,672.6

 
$
11,249.6

 
$
11,249.6

 
$
17,844.1

 
$
(33,784.2
)
 
$
18,231.7

Liabilities and equity
 

 
 

 
 

 
 

 
 

 
 

Current liabilities
 

 
 

 
 

 
 

 
 

 
 

Current maturities of long-term debt
$

 
$
500.0

 
$

 
$
7.7

 
$

 
$
507.7

Accounts payable
31.3

 

 

 
1,085.0

 

 
1,116.3

Other current liabilities
123.2

 
81.0

 

 
280.2

 

 
484.4

Total current liabilities
154.5

 
581.0

 

 
1,372.9

 

 
2,108.4

 
 
 
 
 
 
 
 
 
 
 
 
Intercompany debt

 

 
7,701.5

 
6,836.6

 
(14,538.1
)
 

 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, excluding current maturities
4,510.7

 
4,341.4

 

 
21.2

 

 
8,873.3

 
 
 
 
 
 
 
 
 
 
 
 
Deferred credits and other liabilities


 


 


 


 


 


Deferred income taxes
112.3

 

 

 
108.4

 
(1.0
)
 
219.7

Other deferred credits
315.6

 

 

 
135.2

 

 
450.8

Total deferred credits and other liabilities
427.9

 




243.6


(1.0
)

670.5

 
 
 
 
 
 
 
 
 
 
 
 
Commitments and contingencies


 


 


 


 


 


 
 
 
 
 
 
 
 
 
 
 
 
Equity
6,579.5

 
6,327.2

 
3,548.1

 
9,369.8

 
(19,245.1
)
 
6,579.5

Total liabilities and equity
$
11,672.6

 
$
11,249.6

 
$
11,249.6

 
$
17,844.1

 
$
(33,784.2
)
 
$
18,231.7


34

Table of Contents

Condensed Consolidating Statements of Cash Flows
 
Three Months Ended March 31, 2019
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
 
(Millions of dollars)
Operating activities
 
 
 
 
 
 
 
 
 
 
 
Cash provided by operating activities
$
207.4

 
$
320.6

 
$
20.8

 
$
470.8

 
$
(666.0
)
 
$
353.6

Investing activities
 

 
 

 
 

 
 

 
 

 
 

Capital expenditures
(6.4
)
 

 

 
(883.3
)
 

 
(889.7
)
Contributions to unconsolidated affiliates

 

 

 
(1.0
)
 

 
(1.0
)
Other investing activities

 

 
7.7

 
18.2

 

 
25.9

Cash used in investing activities
(6.4
)
 

 
7.7

 
(866.1
)
 

 
(864.8
)
Financing activities
 

 
 

 
 

 
 

 
 

 
 

Dividends paid
(354.2
)
 
(333.0
)
 
(333.0
)
 

 
666.0

 
(354.2
)
Intercompany borrowings (advances), net
(1,214.6
)
 
512.4

 
304.5

 
397.7

 

 

Issuance of long-term debt, net of discounts
1,442.8

 

 

 

 

 
1,442.8

Repayment of long-term debt

 
(500.0
)
 

 
(1.9
)
 

 
(501.9
)
Issuance of common stock
4.8

 

 

 

 

 
4.8

Other, net
(64.0
)
 

 

 
(0.5
)
 

 
(64.5
)
Cash provided by financing activities
(185.2
)
 
(320.6
)
 
(28.5
)

395.3

 
666.0

 
527.0

Change in cash and cash equivalents
15.8

 

 

 

 

 
15.8

Cash and cash equivalents at beginning of period
12.0

 

 

 

 

 
12.0

Cash and cash equivalents at end of period
$
27.8

 
$

 
$

 
$

 
$

 
$
27.8



35

Table of Contents

 
Three Months Ended March 31, 2018
(Unaudited)
Parent
Issuer &
Guarantor
 
Subsidiary
Issuer &
Guarantor
 
Guarantor
Subsidiary
 
Combined
Non-Guarantor
Subsidiaries
 
Consolidating
Entries
 
Total
 
(Millions of dollars)
Operating activities
 
 
 
 
 
 
 
 
 
 
 
Cash provided by operating activities
$
266.8

 
$
319.7

 
$
17.1

 
$
557.7

 
$
(666.0
)
 
$
495.3

Investing activities
 

 
 

 
 

 
 

 
 

 
 

Capital expenditures
(5.7
)
 

 

 
(258.8
)
 

 
(264.5
)
Contributions to unconsolidated affiliates

 

 

 
(0.1
)
 

 
(0.1
)
Other investing activities

 

 
5.0

 
4.0

 

 
9.0

Cash used in investing activities
(5.7
)
 

 
5.0

 
(254.9
)
 

 
(255.6
)
Financing activities
 

 
 

 
 

 
 

 
 

 
 

Dividends paid
(316.4
)
 
(333.0
)
 
(333.0
)
 

 
666.0

 
(316.4
)
Distributions to noncontrolling interests

 

 

 
(1.5
)
 

 
(1.5
)
Intercompany borrowings (advances), net
(514.5
)
 
513.3

 
310.9

 
(309.7
)
 

 

Borrowing (repayment) of short-term borrowings, net
(614.7
)
 

 

 

 

 
(614.7
)
Repayment of long-term debt

 
(500.0
)
 

 
(1.9
)
 

 
(501.9
)
Issuance of common stock
1,182.1

 

 

 

 

 
1,182.1

Other, net
(17.3
)
 

 

 
10.3

 

 
(7.0
)
Cash used in financing activities
(280.8
)
 
(319.7
)
 
(22.1
)
 
(302.8
)
 
666.0

 
(259.4
)
Change in cash and cash equivalents
(19.7
)
 

 

 

 

 
(19.7
)
Cash and cash equivalents at beginning of period
37.2

 

 

 

 

 
37.2

Cash and cash equivalents at end of period
$
17.5

 
$

 
$

 
$

 
$

 
$
17.5



36

Table of Contents

ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report.

RECENT DEVELOPMENTS

Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Quarterly Report for additional information.

Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable segments, and we expect our consolidated earnings to be approximately 85% fee-based in 2019. We are connected to supply in growing basins and have significant basin diversification, including the Williston, Permian, Powder River and DJ Basins and the STACK and SCOOP areas. While our Natural Gas Gathering and Processing and Natural Gas Liquids segments generate primarily fee-based earnings, those segments’ results of operations are exposed to volumetric risk. Our exposure to volumetric risk can result from declining well productivity, reduced drilling activity, severe weather disruptions, operational outages and ethane rejection. Commodity prices decreased in the fourth quarter 2018 with a moderate recovery in the first quarter 2019 and are expected to continue to fluctuate in 2019. However, we do not expect supply volumes in our three business segments to be materially impacted.

Volumes increased across our operating regions in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the first quarter 2019, compared with the same period in 2018, as a result of continued improvements in production due to enhanced completion techniques and increased demand for NGL products from petrochemical and NGL export facilities in the Gulf Coast. To date, we have spent approximately $2.7 billion of our announced capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas infrastructure supported by a combination of long-term primarily fee-based contracts, volume commitments and/or acreage dedications. Our NGL projects in the Gulf Coast also allow flexibility to construct additional NGL fractionators, storage and potentially, new export facilities in the future. We expect these projects to meet the needs of natural gas processors and producers and the petrochemical industry that require additional midstream infrastructure to accommodate increasing supply and demand in the areas in which we operate.

In the first quarter 2019, compared with the same period in 2018, we benefited from favorable NGL location price differentials as available pipeline and fractionation capacity in and between the Conway, Kansas, and Mont Belvieu, Texas, market centers tightened due to growing NGL supply from the Mid-Continent and Rocky Mountain regions, combined with increased petrochemical and NGL export demand in the Gulf Coast, resulting in higher earnings from our Natural Gas Liquids segment’s optimization and marketing activities. While we expect NGL location price differentials to fluctuate in 2019, we expect that they will be wider than historical norms due to additional NGL supply growth delivered to the Mid-Continent region, additional demand in the Gulf Coast and continuing fractionation and pipeline constraints. We expect these wider NGL location price differentials to continue until announced NGL pipeline and fractionation infrastructure projects, including our Arbuckle II pipeline, are completed in early 2020.

Rocky Mountain Region - We expect each of our business segments to benefit from increased production in this region, which includes the Williston, Powder River and DJ Basins. In our Natural Gas Gathering and Processing segment, gathered and processed volumes in this region increased in the first quarter 2019, compared with the same period in 2018, due primarily to increased producer activity and completion of new well connections. With continued volume growth expected, we are constructing our Demicks Lake I and Demicks Lake II natural gas processing plants. These projects will provide an additional 400 MMcf/d of processing capacity, increasing our total to more than 1.4 Bcf/d in the Williston Basin, which is expected to help producers meet North Dakota’s natural gas capture targets, add incremental NGLs to our NGL gathering system and supply natural gas to our 50 percent-owned Northern Border Pipeline. Our Demicks Lake I plant is expected to reach capacity soon after its completion in the fourth quarter 2019 due to more than 275 MMcf/d of natural gas currently flaring on our dedicated acreage due primarily to lack of processing capacity. In our Natural Gas Liquids segment, the volume growth in this region has resulted in the Overland Pass pipeline, of which we own 50%, and our Bakken NGL pipeline operating at or near full capacity. We are constructing our Elk Creek pipeline to support expected supply growth and provide needed infrastructure to transport NGLs out of the region to the Mid-Continent with connectivity to the Gulf Coast. We expect the southern section of our Elk Creek pipeline to be complete early in the third quarter 2019, which would allow NGL production from the Powder River Basin to be transported on this section of pipeline before the entire Elk Creek pipeline project is complete, creating available capacity on our Bakken NGL pipeline to transport additional NGL volumes from the Williston Basin. We expect the

37

Table of Contents

Elk Creek pipeline to reach 100 MBbl/d in the first quarter 2020 due to a combination of volumes from our processing plants, third-party processing plants and volumes currently transported by rail. We recently announced a project to extend our Bakken NGL pipeline into an area of the Williston Basin with no current access to raw feed NGL pipeline takeaway capacity. This project will provide connectivity for third-party processing plants to key NGL market centers as well as provide additional volumes to our Elk Creek pipeline.

STACK and SCOOP - As producers continue to develop the STACK and SCOOP areas in Oklahoma, we expect increased demand for our services from producers that need incremental takeaway capacity for natural gas and NGLs out of the Mid-Continent region. In our Natural Gas Gathering and Processing segment, natural gas gathered and processed volumes increased in the first quarter 2019, compared with the same period in 2018, due primarily to the completion of the 200 MMcf/d expansion of our Canadian Valley natural gas processing plant, which increased our total processing capacity to 1.2 Bcf/d in the Mid-Continent region. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the STACK and SCOOP areas. We are constructing our Arbuckle II pipeline to support expected supply growth and transport NGLs to the Gulf Coast market. We also plan to construct an extension of our Arbuckle II pipeline further north along with additional NGL gathering infrastructure, as well as an expansion of our Arbuckle II pipeline by 100 MBbl/d to a total capacity of 500 MBbl/d. In our Natural Gas Pipelines segment, we are connected to more than 30 natural gas processing plants in Oklahoma, and we completed expansions in 2018 to provide increased westbound transportation services from the STACK area. In the first quarter 2019, we completed an additional expansion of our ONEOK Gas Transportation pipeline with a 150 MMcf/d eastbound expansion from the STACK and SCOOP areas to an eastern Oklahoma interstate pipeline delivery point.

Permian Basin - We expect our Natural Gas Liquids and Natural Gas Pipelines business segments to benefit from increased production in the Permian Basin from the highly productive Delaware and Midland Basins. In our Natural Gas Liquids segment, we are well-positioned in the Permian Basin through our West Texas LPG pipeline system. Due to the recent expansion of the system and new plant connections, volumes increased in the first quarter 2019, compared with the same period in 2018. We expect volumes to continue to increase on our West Texas LPG pipeline system when the second expansion is completed, which will increase the mainline capacity out of the Permian Basin by 80 MBbl/d as well as connect our West Texas LPG pipeline with our Arbuckle II pipeline. These projects are expected to position our West Texas LPG pipeline system for significant future NGL volume growth and are backed by long-term acreage and/or plant dedications. In our Natural Gas Pipelines segment, our Roadrunner joint venture and our WesTex pipeline are well-positioned to serve growth in the Permian Basin. The Roadrunner pipeline connects with our existing natural gas pipeline and storage infrastructure in Texas and, together with our completed WesTex intrastate natural gas pipeline expansion project, creates future opportunities for us to deliver natural gas supply to Mexico and transport natural gas to other markets in the region.

Gulf Coast - Demand for NGLs is expected to continue to increase at the Mont Belvieu, Texas, NGL market center as new world-scale ethylene production projects, petrochemical plant expansions and NGL export facilities continue to be completed. NGL supply growth and new NGL pipelines recently completed or being constructed, including our Elk Creek pipeline, Arbuckle II pipeline and West Texas LPG pipeline projects, are increasing NGL deliveries to Mont Belvieu, Texas. While we have significant NGL fractionation and storage assets in this area, additional capacity is needed to accommodate expected volume growth. To respond to this need, we are constructing two additional 125 MBbl/d fractionators with related infrastructure in Mont Belvieu, Texas, MB-4 and MB-5, which are both fully contracted. Following the completion of MB-4 and MB-5, we expect our Gulf Coast NGL fractionation capacity to be approximately 600 MBbl/d and more than 1 million Bbl/d across our entire system. Our MB-5 project also includes system expansions that provide infrastructure capacity to support additional assets as we continue to evaluate opportunities for fractionation, storage and, potentially, export facilities to meet the supply and demand for NGLs.

Ethane Opportunity - Ethane volumes delivered to our NGL system generally have been increasing since 2016, primarily as a result of NGL demand increasing from exports and petrochemical companies completing ethylene production projects and plant expansions. Ethane volumes across our system increased to 410 MBbl/d in the first quarter 2019, compared with 355 MBbl/d in the first quarter 2018. Our NGL capital-growth projects are expected to help alleviate system constraints, enabling additional NGLs, including ethane, to reach the Mont Belvieu, Texas, market center. We expect the amount of ethane delivered to our system to continue to fluctuate as NGL supply continues to increase, petrochemical companies complete expansion projects and exports increase.


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Growth Projects - Our announced large capital-growth projects are outlined in the tables below:
Project
Scope
Approximate Costs (a)
Expected
Completion
Natural Gas Gathering and Processing
(In millions)
 
Canadian Valley expansion and related infrastructure
200 MMcf/d processing plant expansion in the STACK area and related gathering infrastructure
160
Complete
 
Increases capacity to more than 400 MMcf/d
 
 
 
20 MBbl/d additional NGL volume
 
 
 
Supported by acreage dedications, long-term primarily fee-based contracts and minimum volume commitments
 
 
Demicks Lake I plant and related infrastructure
200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin
400
Fourth Quarter 2019
 
Supported by acreage dedications with long-term primarily fee-based contracts
 
 
Demicks Lake II plant and related infrastructure
200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin
410
First Quarter 2020
 
Supported by acreage dedications with long-term primarily fee-based contracts
 
 
Total Natural Gas Gathering and Processing
$970
 
 
 
 

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Project
Scope
Approximate Costs (a)
Expected
Completion
Natural Gas Liquids
 
(In millions)
 
West Texas LPG pipeline expansion
120-mile pipeline lateral extension with capacity of 110 MBbl/d in the Permian Basin
$200 (b)
Complete
 
Supported by long-term dedicated NGL production from two planned third-party natural gas processing plants
 
 
Sterling III pipeline expansion and Arbuckle connection
60 MBbl/d NGL pipeline expansion
130
Complete
Increases capacity to 250 MBbl/d
 
 
 
Includes additional NGL gathering system expansions
 
 
 
Supported by long-term third-party contracts
 
 
Elk Creek pipeline and related infrastructure
900-mile NGL pipeline from the Williston Basin to the Mid-Continent region, with capacity of up to 240 MBbl/d, and related infrastructure
1,400
Fourth Quarter 2019 (c)
 
Anchored by long-term contracts supported primarily by minimum volume commitments
 
 
 
Expansion capability up to 400 MBbl/d with additional pump facilities
 
 
Arbuckle II pipeline and related infrastructure
530-mile NGL pipeline from the STACK area to Mont Belvieu, Texas, with initial capacity up to 400 MBbl/d, and related infrastructure
1,360
First Quarter 2020
 
Supported by long-term contracts
 
 
 
Expansion capability up to 1,000 MBbl/d
 
 
West Texas LPG pipeline expansion and Arbuckle II connection
Increasing mainline capacity by 80 MBbl/d with additional pump facilities and pipeline looping
295
First Quarter 2020
Connecting West Texas LPG pipeline system to the previously announced Arbuckle II pipeline
 
 
 
Supported by long-term dedicated production from six third-party processing plants expected to produce up to 60 MBbl/d
 
 
MB-4 fractionator and related infrastructure
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu
575
First Quarter 2020
 
Fully contracted with long-term contracts
 
 
Bakken NGL pipeline extension
75-mile NGL pipeline in the Williston Basin connecting to a third-party processing plant
100
Fourth Quarter 2020
 
Supported by a long-term contract with a minimum volume commitment
 
 
Arbuckle II extension project and additional gathering infrastructure
Provide additional takeaway capacity in the STACK area
240
First Quarter 2021
Allow increasing volumes on the Elk Creek pipeline access to fractionation capacity at Mont Belvieu
 
 
Arbuckle II pipeline expansion
Increasing mainline capacity by 100 MBbl/d with additional pump facilities
60
First Quarter 2021
 
Increases capacity to 500 MBbl/d
 
 
MB-5 fractionator and related infrastructure
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu
750
First Quarter 2021
 
Fully contracted with long-term contracts
 
 
Total Natural Gas Liquids
 
$5,110
 
Total
 
$6,080
 
(a) - Excludes capitalized interest/AFUDC.
(b) - Reflects total project cost. In July 2018, we acquired the remaining 20% interest in WTLPG.
(c) - We expect the southern section of the pipeline to be complete early in the third quarter 2019.

Debt Issuances - In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $700 million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued interest, were $1.23 billion. The proceeds were used for general corporate purposes, which included repayment of existing indebtedness and funding capital expenditures.

Dividends - In February 2019, we paid quarterly dividends of $0.86 per share ($3.44 per share on an annualized basis), an increase of 12% compared with the same quarter in the prior year. We declared a quarterly dividend of $0.865 per share ($3.46

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per share on an annualized basis) in April 2019. The quarterly dividend will be paid May 15, 2019, to shareholders of record at the close of business on April 29, 2019.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Financial Results
2019
 
2018
 
Increase (Decrease)
 
(Millions of dollars)
Revenues
 
 
 
 
 
 
 
Commodity sales
$
2,473.0

 
$
2,820.0

 
$
(347.0
)
 
(12
%)
Services
307.0

 
282.1

 
24.9

 
9
%
Total revenues
2,780.0

 
3,102.1


(322.1
)

(10
%)
Cost of sales and fuel (exclusive of items shown separately below)
1,956.4

 
2,368.0


(411.6
)

(17
%)
Operating costs
240.8

 
210.3


30.5


15
%
Depreciation and amortization
114.2

 
104.2

 
10.0

 
10
%
Gain on sale of assets
(0.1
)
 
(0.1
)
 

 
%
Operating income
$
468.7

 
$
419.7

 
$
49.0

 
12
%
Equity in net earnings from investments
$
43.5

 
$
40.2


$
3.3


8
%
Interest expense, net of capitalized interest
$
(115.4
)
 
$
(115.7
)
 
$
(0.3
)
 
%
Net income
$
337.2

 
$
266.0

 
$
71.2

 
27
%
Adjusted EBITDA
$
637.5

 
$
570.3

 
$
67.2

 
12
%
Capital expenditures
$
889.7

 
$
264.5


$
625.2


*

* Percentage change is greater than 100%.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements of Income, and, therefore, the impact is largely offset between the two line items.

Operating income increased for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:
an increase of $69.2 million due to volume growth, primarily in the Williston and Permian Basins and STACK and SCOOP areas in our Natural Gas Liquids segment and the Williston Basin in our Natural Gas Gathering and Processing segment;
an increase of $26.5 million due to higher optimization and marketing earnings primarily from the sale of NGL products previously held in inventory and wider location price differentials in our Natural Gas Liquids segment; and
an increase of $15.7 million from higher transportation services due primarily to firm transportation capacity contracted in our Natural Gas Pipelines segment; offset partially by
an increase in operating costs of $30.5 million due primarily to higher employee-related costs associated with labor and benefits and the growth of our operations;
an increase of $21.7 million in rail transportation and third-party fractionation costs in our Natural Gas Liquids segment; and
an increase in depreciation expense of $10.0 million due to capital projects placed in service.

Net income increased due to the items discussed above, higher allowance for equity funds used during construction due to our capital-growth projects and was favorably impacted by a higher tax deduction associated with our equity incentive plan.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to spending on our announced capital-growth projects.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.


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Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are sold and delivered through natural gas liquids pipelines to fractionation facilities for further processing.

Our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, but we have some direct commodity price exposure related primarily to POP contracts. To mitigate the impact of this commodity price exposure, we have hedged a significant portion of our Natural Gas Gathering and Processing segment’s commodity price risk for 2019 and 2020. This segment has substantial long-term acreage dedications in some of the most productive areas of the Williston Basin and Mid-Continent region, specifically the STACK and SCOOP areas, which helps to mitigate volumetric risk.

Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas, including the Bakken Shale and Three Forks formations in the Williston Basin and the STACK and SCOOP areas, that we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. See “Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results - The following table sets forth certain selected financial results for our Natural Gas Gathering and Processing segment for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Financial Results
2019
 
2018
 
Increase (Decrease)
 
(Millions of dollars)
NGL sales
$
287.4

 
$
362.8

 
$
(75.4
)
 
(21
%)
Condensate sales
44.9

 
50.4

 
(5.5
)
 
(11
%)
Residue natural gas sales
319.0

 
255.0

 
64.0

 
25
%
Gathering, compression, dehydration and processing fees and other revenue
43.4

 
39.8

 
3.6

 
9
%
Cost of sales and fuel (exclusive of depreciation and operating costs)
(450.9
)
 
(492.6
)
 
(41.7
)
 
(8
%)
Operating costs, excluding noncash compensation adjustments
(89.3
)
 
(85.5
)
 
3.8

 
4
%
Equity in net earnings (loss) from investments
(1.2
)
 
1.7

 
(2.9
)
 
*

Other
(1.1
)
 
(1.0
)
 
(0.1
)
 
(10
%)
Adjusted EBITDA
$
152.2

 
$
130.6

 
$
21.6

 
17
%
Capital expenditures
$
215.1

 
$
111.7

 
$
103.4

 
93
%
* Percentage change is greater than 100%.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.

Adjusted EBITDA increased $21.6 million for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:
an increase of $24.4 million due primarily to natural gas volume growth in the Williston Basin, offset partially by natural production declines; and
an increase of $4.0 million due primarily to higher realized natural gas prices, net of hedges; offset partially by
an increase of $3.8 million in operating costs due primarily to higher employee-related costs due to growth of our operations, offset partially by lower materials and supplies expense; and
a decrease of $2.9 million due primarily to lower equity in net earnings from investments due to a decrease in supply volumes in the coal-bed methane area of the Powder River Basin.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due to our announced capital-growth projects.

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Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
 
Three Months Ended
 
March 31,
Operating Information
2019
 
2018
Natural gas gathered (BBtu/d) (a)
2,636

 
2,460

Natural gas processed (BBtu/d) (b)
2,442

 
2,285

NGL sales (MBbl/d) (a)
214

 
194

Residue natural gas sales (BBtu/d) (b)
1,130

 
964

Average fee rate ($/MMBtu) (a)
$
0.91

 
$
0.88

(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes we processed at company-owned and third-party facilities.

Our natural gas gathered and processed volumes increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to continued producer improvements in production due to enhanced completion techniques, offset partially by natural production declines.
Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk in this Quarterly Report.

Natural Gas Liquids

Overview - Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, Powder River and DJ Basins, where we provide midstream services to producers of NGLs and deliver those products to the two primary market centers, one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports refined petroleum products, including unleaded gasoline and diesel, from Kansas to Iowa. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas Panhandle are connected to our natural gas liquids gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation and pipeline assets.

Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region and the Permian Basin. Crude oil, natural gas and NGL production from this activity; higher petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital investments to expand our infrastructure to bring these commodities from supply basins to market.

Our Natural Gas Liquids segment invests in NGL-related projects to transport, fractionate, store and deliver to the market NGL supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers and to meet increasing petrochemical industry and NGL export demand in the Gulf Coast. See “Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.

In the first quarter 2019, one third-party natural gas processing plant connected to our system was expanded in the STACK and SCOOP areas of the Mid-Continent region.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.


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Table of Contents

Selected Financial Results - The following table sets forth certain selected financial results for our Natural Gas Liquids segment for the periods indicated:
 
Three Months Ended

Three Months
 
March 31,
 
2019 vs. 2018
Financial Results
2019
 
2018

Increase (Decrease)
 
(Millions of dollars)
NGL and condensate sales
$
2,158.1

 
$
2,552.8


$
(394.7
)
 
(15
%)
Exchange service revenues and other
101.1

 
86.2


14.9

 
17
%
Transportation and storage revenues
52.3

 
53.5


(1.2
)
 
(2
%)
Cost of sales and fuel (exclusive of depreciation and operating costs)
(1,846.7
)
 
(2,281.1
)

(434.4
)
 
(19
%)
Operating costs, excluding noncash compensation adjustments
(103.4
)
 
(84.6
)

18.8

 
22
%
Equity in net earnings from investments
17.5

 
16.4


1.1

 
7
%
Other
(1.3
)
 
(1.1
)
 
(0.2
)
 
(18
%)
Adjusted EBITDA
$
377.6

 
$
342.1


$
35.5

 
10
%
Capital expenditures
$
639.3

 
$
124.9


$
514.4

 
*

* Percentage change is greater than 100%.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.

Adjusted EBITDA increased $35.5 million for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:
an increase of $30.5 million in exchange services due to $44.8 million in higher volumes primarily in the Williston and Permian Basins and the STACK and SCOOP areas and $21.6 million in higher average fee rates primarily in the Permian Basin, offset partially by $21.7 million in higher rail transportation and third-party fractionation costs, $7.5 million due primarily to narrower product price differentials and $4.7 million related to unfractionated NGLs in inventory; and
an increase of $26.5 million in optimization and marketing due primarily to higher earnings on the sale of NGL products previously held in inventory and wider location price differentials; offset partially by
an increase of $18.8 million in operating costs due primarily to higher employee-related costs associated with labor and benefits and spending on routine maintenance projects.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to our announced capital-growth projects.

Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Liquids segment for the periods indicated:
 
Three Months Ended
 
March 31,
Operating Information
2019
 
2018
Raw feed throughput (MBbl/d) (a)
1,028

 
949

NGLs transported-gathering lines (MBbl/d) (b)
944

 
855

NGLs fractionated (MBbl/d) (c)
729

 
693

Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)
$
0.10

 
$
0.09

(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.
(b) - Includes volumes for consolidated entities only.
(c) - Includes volumes at company-owned and third-party facilities.

Volumes increased for the three months ended March 31, 2019, compared with the same period in 2018, primarily from the Williston and Permian Basins and the STACK and SCOOP areas. While overall volumes, including ethane, increased, a portion of the contractual fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.


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Table of Contents

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment provides transportation and storage services to end users through its wholly owned assets and its 50% ownership interests in Northern Border Pipeline and Roadrunner.

Our natural gas pipelines primarily serve end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. The development of shale and other resource areas has continued to increase available natural gas supply, and we expect producers to demand incremental transportation services in the future as additional supply is developed.

Growth Projects - We recently expanded our natural gas pipeline infrastructure in Oklahoma and the Permian Basin. The projects included an eastbound expansion of our ONEOK Gas Transportation system by 150 MMcf/d from the STACK and SCOOP areas to an interstate pipeline delivery point in eastern Oklahoma, a westbound expansion of our ONEOK Gas Transportation system by 100 MMcf/d from the STACK area to multiple interstate pipeline delivery points in western Oklahoma, and an expansion of our WesTex Transmission system by 300 MMcf/d from the Permian Basin to interstate pipeline delivery points in the Texas Panhandle. Additionally, we completed an expansion project on our Roadrunner joint venture to make the pipeline bidirectional, which resulted in 750 MMcf/d of eastbound transportation capacity, expanding to approximately 1.0 Bcf/d in third quarter 2019, from the Delaware Basin to the Waha area.

Selected Financial Results - The following table sets forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Financial Results
2019
 
2018
 
Increase (Decrease)
 
(Millions of dollars)
Transportation revenues
$
86.9

 
$
81.8

 
$
5.1

 
6
%
Storage revenues
16.6

 
16.5

 
0.1

 
1
%
Residue natural gas sales and other revenues
12.9

 
11.6

 
1.3

 
11
%
Cost of sales and fuel (exclusive of depreciation and operating costs)
(1.8
)
 
(5.5
)
 
(3.7
)
 
(67
%)
Operating costs, excluding noncash compensation adjustments
(34.2
)
 
(31.9
)
 
2.3

 
7
%
Equity in net earnings from investments
27.1

 
22.1

 
5.0

 
23
%
Other
(0.9
)
 
(1.0
)
 
0.1

 
10
%
Adjusted EBITDA
$
106.6

 
$
93.6

 
$
13.0

 
14
%
Capital expenditures
$
28.7

 
$
19.9

 
$
8.8

 
44
%
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Adjusted EBITDA increased $13.0 million for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:
an increase of $15.7 million from transportation services due primarily to higher firm transportation capacity contracted; and
an increase of $5.0 million due primarily to higher equity in net earnings from investments due to increased seasonal transportation capacity contracted on Northern Border Pipeline; offset partially by
a decrease of $4.6 million from lower net retained fuel and timing of equity gas sales; and
an increase of $2.3 million in operating costs due primarily to employee-related costs associated with labor and benefits.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to capital-growth projects.


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Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Pipelines segment for the periods indicated:
 
Three Months Ended
 
March 31,
Operating Information (a)
2019
 
2018
Natural gas transportation capacity contracted (MDth/d)
7,480

 
6,779

Transportation capacity subscribed
99
%
 
97
%
(a) - Includes volumes for consolidated entities only.

Natural gas transportation capacity contracted increased for the three months ended March 31, 2019, compared with the same period in 2018, due to increased available capacity from our completed expansion projects on our ONEOK Gas Transportation and WesTex Transmission systems.

Roadrunner, in which we have a 50% ownership interest, has contracted all of its westbound capacity through 2041.

Northern Border Pipeline, in which we have a 50% ownership interest, has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2020.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and other noncash items. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, earnings per share or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.

The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
 
 
2019
 
2018
Reconciliation of net income to adjusted EBITDA
 
(Thousands of dollars)
Net income
 
$
337,208

 
$
266,049

Add:
 
 
 
 
Interest expense, net of capitalized interest
 
115,420

 
115,725

Depreciation and amortization
 
114,158

 
104,237

Income taxes
 
77,934

 
75,771

Noncash compensation expense
 
5,540

 
9,226

Equity AFUDC and other noncash items
 
(12,778
)
 
(672
)
Adjusted EBITDA
 
$
637,482

 
$
570,336

Reconciliation of segment adjusted EBITDA to adjusted EBITDA
 
 
 
 
Segment adjusted EBITDA:
 
 
 
 
Natural Gas Gathering and Processing
 
$
152,244

 
$
130,551

Natural Gas Liquids
 
377,639

 
342,079

Natural Gas Pipelines
 
106,648

 
93,625

Other
 
951

 
4,081

Adjusted EBITDA
 
$
637,482

 
$
570,336



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CONTINGENCIES

See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for a discussion of developments concerning the Gas Index Pricing Litigation.

Other 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 these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from 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.

LIQUIDITY AND CAPITAL RESOURCES

General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In addition, we expect cash outflows related to (i) capital expenditures, (ii) interest and repayment of debt maturities and (iii) dividends paid to shareholders. We expect our cash outflows related to capital expenditures and dividends paid to increase due to our announced capital-growth projects and higher anticipated dividends per share, subject to board of directors’ approval.

We expect our sources of cash inflow to provide sufficient resources to finance our operations, capital expenditures and quarterly cash dividends, including expected future dividend increases. Our $2.5 Billion Credit Agreement and the remaining $750 million available to be drawn on our $1.5 Billion Term Loan Agreement provide significant liquidity to fund capital expenditures and repay existing indebtedness. We may access the capital markets to issue debt or equity securities as we consider prudent to provide additional liquidity to refinance existing debt, improve credit metrics or to fund capital expenditures. Although we expect to continue to fund capital projects primarily with cash from operations, short-term borrowings and long-term debt, we continue to have access to $550 million available through our “at-the-market” equity program and the ability to issue equity and other securities under our universal shelf registration statement.

We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock contracts. For additional information on our interest-rate swaps, see Note C of the Notes to Consolidated Financial Statements in this Quarterly Report.

Cash Management - We use a centralized cash management program that concentrates the cash assets of our operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments, proceeds from our commercial paper program, our $2.5 Billion Credit Agreement and the remaining $750 million available to be drawn on our $1.5 Billion Term Loan Agreement. As of March 31, 2019, we are in compliance with all covenants of the $2.5 Billion Credit Agreement and the $1.5 Billion Term Loan Agreement.

At March 31, 2019, we had $27.8 million of cash and cash equivalents and $2.5 billion of borrowing capacity under the $2.5 Billion Credit Agreement.

We had working capital (defined as current assets less current liabilities) deficits of $346.9 million and $709.8 million as of March 31, 2019, and December 31, 2018, respectively. Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) scheduled debt payments, (b) the collection and payment of accounts receivable and payable, and (c) equity and debt issuances, and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at March 31, 2019 and December 31, 2018, was driven primarily by current maturities of long-term debt. We may have working capital deficits in future periods as we continue to finance our capital-growth projects and repay long-term debt, often initially with short-term borrowings. Our decision to utilize short-term borrowings rather than long-term debt, due

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to more favorable interest rates, may also contribute to our working capital deficit. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.

For additional information on our $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes. Other options to obtain financing include, but are not limited to, issuance of common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

Debt Issuances - In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $700 million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued interest, were $1.23 billion. The proceeds were used for general corporate purposes, which included repayment of existing indebtedness and funding capital expenditures.

In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which matures in November 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. As of March 31, 2019, we had borrowings totaling $750 million outstanding under our $1.5 Billion Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures. We expect to draw the remaining $750 million in May 2019.

Debt Repayments - We repaid our $500 million, 8.625% senior notes due March 2019 with a combination of cash on hand and short-term borrowings.

For additional information on our long-term debt, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as capital-growth expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our existing assets and operations and do not generate additional revenues. Maintenance capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity.

Capital expenditures, excluding AFUDC and capitalized interest, were $889.7 million and $264.5 million for the three months ended March 31, 2019 and 2018, respectively.

We expect our total 2019 growth capital expenditures to range from $2.5 billion to $3.7 billion and our maintenance capital expenditures to range from $160 million to $200 million, excluding AFUDC and capitalized interest. See discussion of our announced capital-growth projects in the “Recent Developments” section.

Credit Ratings - Our long-term debt credit ratings as of April 22, 2019, are shown in the table below:
Rating Agency
Long-Term Rating
Short-Term Rating
Outlook
Moody’s
Baa3
Prime-3
Stable
S&P
BBB
A-2
Stable

Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under our $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement would increase and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $1.5 Billion Term Loan Agreement until fully drawn or through May 2019, as well as our $2.5 Billion Credit Agreement, which expires in 2023. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement or our $1.5 Billion Term Loan Agreement. We do not expect a downgrade in our credit rating to have a material impact on our results of operations.


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In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.

Dividends - Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of outstanding preferred stock. In February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share on an annualized basis), an increase of 12% compared with the same quarter in the prior year. A dividend of $0.865 per share was declared for the shareholders of record at the close of business on April 29, 2019, payable May 15, 2019.

Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. In February 2019, we paid dividends totaling $0.3 million for the Series E Preferred Stock. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable May 15, 2019.

For the three months ended March 31, 2019, our cash dividends paid slightly exceeded our cash flows from operations, and, as a result, we utilized our other sources of short-term liquidity to fund an immaterial portion of our dividends. We expect increases in cash flows from operations in the remainder of 2019 due primarily to expected volume increases across our systems and from the completion of capital-growth projects.

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items can include depreciation and amortization, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
 
 
 
Variances
 
Three Months Ended
 
2019 vs. 2018
 
March 31,
 
Favorable
(Unfavorable)
 
2019
 
2018
 
 
(Millions of dollars)
Total cash provided by (used in):
 
 
 
 
 
Operating activities
$
353.6

 
$
495.3

 
$
(141.7
)
Investing activities
(864.8
)
 
(255.6
)
 
(609.2
)
Financing activities
527.0

 
(259.4
)
 
786.4

Change in cash and cash equivalents
15.8

 
(19.7
)
 
35.5

Cash and cash equivalents at beginning of period
12.0

 
37.2

 
(25.2
)
Cash and cash equivalents at end of period
$
27.8

 
$
17.5

 
$
10.3


Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our natural gas and NGL inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

Cash flows from operating activities, before changes in operating assets and liabilities for the three months ended March 31, 2019, increased $69.1 million, compared with the same period in 2018. This increase is due primarily to higher earnings resulting from volume growth in the Williston and Permian Basins and STACK and SCOOP areas in our Natural Gas Liquids segment and the Williston Basin in our Natural Gas Gathering and Processing segment and higher optimization and marketing

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earnings due primarily to the sales of NGL products previously held in inventory and wider location price differentials in our Natural Gas Liquids segment, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $160.1 million for the three months ended March 31, 2019, compared with an increase of $50.7 million for the same period in 2018. This change is due primarily to the change in natural gas and NGLs in storage, which vary from period to period and vary with changes in commodity prices, and the change in accounts receivable, accounts payable, and other accruals and deferrals resulting from the timing of receipt of cash from customers and payments to vendors, suppliers and other third parties.

Investing Cash Flows - Cash used in investing activities for the three months ended March 31, 2019, increased $609.2 million compared with the same period in 2018, due primarily to increased capital expenditures related to our capital-growth projects.

Financing Cash Flows - Cash from financing activities for the three months ended March 31, 2019, increased $786.4 million compared with the same period in 2018, due primarily to the issuance of $1.25 billion in senior unsecured notes, the $200 million draw on our $1.5 Billion Term Loan Agreement and the repayment of short-term borrowings in 2018, offset partially by a decrease due to issuances of common stock in 2018.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to a variety of historical 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 and waterways preservation, cultural resource protection, 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.

Additional information about our regulatory, environmental and safety matters can be found in “Regulatory, Environmental and Safety Matters” under Part I, Item 1, Business, in our Annual Report.

IMPACT OF NEW ACCOUNTING STANDARDS

See Note A of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of new accounting standards.

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

Information about our estimates and critical accounting policies is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Estimates and Critical Accounting Policies,” in our Annual Report.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional

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natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;
the capital intensive nature of our businesses;
the profitability of assets or businesses acquired or constructed by us;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
the uncertainty of estimates, including accruals and costs of environmental remediation;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;
the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to drill and obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;
the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change;
the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns;
our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;
actions by rating agencies concerning our credit;
the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, the EPA and CFTC;
our ability to access capital at competitive rates or on terms acceptable to us;
risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling or extended periods of ethane rejection;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
the impact and outcome of pending and future litigation;
the timing and extent of changes in energy commodity prices;
the ability to market pipeline capacity on favorable terms, including the effects of:
future demand for and prices of natural gas, NGLs and crude oil;
competitive conditions in the overall energy market;

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availability of supplies of United States natural gas and crude oil; and
availability of additional storage capacity;
performance of contractual obligations by our customers, service providers, contractors and shippers;
the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
the mechanical integrity of facilities operated;
demand for our services in the proximity of our facilities;
our ability to control operating costs and make cost-saving changes;
acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’ or shippers’ facilities;
economic climate and growth in the geographic areas in which we do business;
the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
the impact of recently issued and future accounting updates and other changes in accounting policies;
the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
the impact of uncontracted capacity in our assets being greater or less than expected;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
the impact of potential impairment charges;
the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
our ability to control construction costs and completion schedules of our pipelines and other projects; and
the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in our Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in our Annual Report.

COMMODITY PRICE RISK

As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts described in Note C of the Notes to Consolidated Financial Statements in this Quarterly Report to reduce the impact of near-term price fluctuations of natural gas, NGLs and condensate.

Although our businesses are primarily fee-based, in our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our contractual fees and POP percentage may increase or decrease if

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production volumes, delivery pressures or commodity prices change relative to specified thresholds. We are exposed to basis risk between the various production and market locations where we buy and sell commodities.

The following tables set forth hedging information for our Natural Gas Gathering and Processing segment’s forecasted equity volumes for the periods indicated:
 
Nine Months Ending December 31, 2019
 
Volumes
Hedged
 
Average Price
 
Percentage
Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu
7.6

 
$
0.71

/ gallon
 
74%
Condensate (MBbl/d) - WTI-NYMEX
2.7

 
$
58.55

/ Bbl
 
90%
Natural gas (BBtu/d) - NYMEX and basis
82.0

 
$
2.30

/ MMBtu
 
80%
 
Year Ending December 31, 2020
 
Volumes
Hedged
 
Average Price
 
Percentage
Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu
2.6

 
$
0.63

/ gallon
 
29%
Condensate (MBbl/d) - WTI-NYMEX
0.8

 
$
55.25

/ Bbl
 
26%
Natural gas (BBtu/d) - NYMEX and basis
51.6

 
$
2.52

/MMBtu
 
65%

Our Natural Gas Gathering and Processing segment’s commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2019. Condensate sales are typically based on the price of crude oil. Assuming normal operating conditions, we estimate the following for our forecasted equity volumes:
a $0.01 per-gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the nine months ending December 31, 2019, and for the year ending December 31, 2020, by approximately $1.2 million and $1.7 million, respectively;
a $1.00 per-barrel change in the price of crude oil would change adjusted EBITDA for the nine months ending December 31, 2019, and for the year ending December 31, 2020, by approximately $1.1 million and $1.6 million, respectively; and
a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the nine months ending December 31, 2019, and for the year ending December 31, 2020, by approximately $3.0 million and $3.6 million, respectively.

These estimates do not include any effects of hedging or effects on demand for our services or natural gas processing plant operations that might be caused by, or arise in conjunction with, commodity price fluctuations. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing financial results for certain contracts.

INTEREST-RATE RISK

We are exposed to interest-rate risk through our $2.5 Billion Credit Agreement, $1.5 Billion Term Loan Agreement, commercial paper program and long-term debt issuances. Future increases in LIBOR, corporate commercial paper rates or corporate bond rates could expose us to increased interest costs on future borrowings. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock contracts. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. In March 2019, we settled $1.0 billion of our forward-starting interest-rate swaps related to our underwritten public offering of $1.25 billion senior unsecured notes.

At March 31, 2019, and December 31, 2018, we had forward-starting interest-rate swaps with notional amounts totaling $2.0 billion and $3.0 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At March 31, 2019, and December 31, 2018, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of our LIBOR-based interest payments. All of our interest-rate swaps are designated as cash flow hedges.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.


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COUNTERPARTY CREDIT RISK

We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Certain of our counterparties may be impacted by a relatively low commodity price environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could impact adversely our results of operations.

The creditworthiness of our counterparties and our customer concentration are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in our Annual Report.

ITEM 4.
CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rule 13a-15(e) and 15d-15(e) of the Exchange Act.

Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the quarter ended March 31, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

Additional information about our legal proceedings is included in Note J of the Notes to Consolidated Financial Statements in this Quarterly Report and under Note N of the Notes to Consolidated Financial Statements in our Annual Report.

ITEM 1A.
RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors, of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should consider carefully the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4.
MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.
OTHER INFORMATION

Not applicable.

ITEM 6.
EXHIBITS

Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be

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viewed as material for securities law purposes, or may no longer continue to be true as of any given date. All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC. Other than the certifications made by our officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this Quarterly Report, all exhibits are included only to provide information to investors regarding their respective terms and should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.

The following exhibits are filed as part of this Quarterly Report:
Exhibit No.
Exhibit Description
 
 
3.1
 
 
3.2
 
 
4.1
 
 
4.2
 
 
4.3
 
 
10.1
 
 
10.2
 
 
10.3
 
 
31.1
 
 
31.2
 
 
32.1
 
 
32.2
 
 
101.INS
XBRL Instance Document.
 
 
101.SCH
XBRL Taxonomy Extension Schema Document.
 
 
101.CAL
XBRL Taxonomy Calculation Linkbase Document.

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101.DEF
XBRL Taxonomy Extension Definitions Document.
 
 
101.LAB
XBRL Taxonomy Label Linkbase Document.
 
 
101.PRE
XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2019 and 2018; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2019 and 2018; (iv) Consolidated Balance Sheets at March 31, 2019, and December 31, 2018; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018; (vi) Consolidated Statements of Changes in Equity for the three months ended March 31, 2019 and 2018; and (vii) Notes to Consolidated Financial Statements.



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SIGNATURE

Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
ONEOK, Inc.
 
Registrant
 
 
 
 
 
 
Date: May 1, 2019
By:
/s/ Walter S. Hulse III
 
 
Walter S. Hulse III
 
 
Chief Financial Officer, Treasurer and
 
 
Executive Vice President, Strategic Planning
 
 
and Corporate Affairs
 
 
(Principal Financial Officer)

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