Company Quick10K Filing
Quick10K
One Gas
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$85.97 53 $4,530
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-05-23 Shareholder Vote
8-K 2019-05-08
8-K 2019-04-29
8-K 2019-04-03
8-K 2019-02-25
8-K 2019-02-20
8-K 2019-01-15
8-K 2019-01-10
8-K 2018-12-04
8-K 2018-11-30
8-K 2018-11-15 Other Events
8-K 2018-11-01 Off-BS Arrangement, Exhibits
8-K 2018-10-29
8-K 2018-10-10
8-K 2018-10-05 Enter Agreement, Exhibits
8-K 2018-09-20
8-K 2018-07-30
8-K 2018-07-24
8-K 2018-07-23 Officers, Amend Bylaw, Regulation FD, Exhibits
8-K 2018-07-11
8-K 2018-06-29
8-K 2018-05-30 Officers, Amend Bylaw, Shareholder Vote
8-K 2018-05-11
8-K 2018-04-30
8-K 2018-04-05
8-K 2018-02-26
8-K 2018-02-23
8-K 2018-02-21
8-K 2018-02-20
8-K 2018-01-17
8-K 2018-01-12
8-K 2018-01-09
GD General Dynamics 49,700
DOCU Docusign 9,270
CRSP Crispr Therapeutics Ag 2,120
BMCH BMC Stock Holdings 1,520
AMBR Amber Road 272
QHC Quorum Health 65
ONS Oncobiologics 0
CBNT C-Bond Systems 0
ZIMCF ZIM 0
CWI Carey Watermark Investors 0
OGS 2019-03-31
Part I - Financial Information
Item 1. Consolidated Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II - Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-31.1 ogsexhibit3111q10-q2019.htm
EX-31.2 ogsexhibit3121q10-q2019.htm
EX-32.1 ogsexhibit3211q10-q2019.htm
EX-32.2 ogsexhibit3221q10-q2019.htm

One Gas Earnings 2019-03-31

OGS 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 onegas10-qx3312019.htm 10-Q Document


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   001-36108

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

Oklahoma
46-3561936
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
 
15 East Fifth Street, Tulsa, OK
74103
(Address of principal executive offices)
(Zip Code)

Registrant’s telephone number, including area code   (918) 947-7000

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 52,686,634 shares of common stock outstanding.




























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ONE Gas, Inc.
TABLE OF CONTENTS
Financial Information
Page No.
 
Consolidated Statements of Income - Three Months Ended March 31, 2019 and 2018
 
Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2019 and 2018
 
Consolidated Balance Sheets - March 31, 2019 and December 31, 2018
 
Consolidated Statements of Cash Flows - Three Months Ended March 31, 2019 and 2018
 
Consolidated Statements of Equity - Three Months Ended March 31, 2019 and 2018
 
Notes to the Consolidated Financial Statements
 

As used in this Quarterly Report, references to “we,” “our,” “us” or the “company” refer to ONE Gas, Inc., an Oklahoma corporation, and its predecessors 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,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely,” 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 IA, “Risk Factors,” in our Annual Report.


3


AVAILABLE INFORMATION

We make available, free of charge, on our website (www.onegas.com) copies of our Annual Report, 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, which also makes these materials available on its website (www.sec.gov).  Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Certificate of Incorporation, bylaws, the written charters of our Audit Committee, Executive Compensation Committee, Corporate Governance Committee and Executive Committee and our Corporate Responsibility Report are also available on our website, and copies of these documents are available upon request.  

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



4


GLOSSARY - The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:
AAO
Accounting Authority Order
ADIT
Accumulated deferred income tax
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2018
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Bcf
Billion cubic feet
CERCLA
Federal Comprehensive Environmental Response, Compensation and Liability
  Act of 1980, as amended
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Amendments of 1972, as amended
Code
Internal Revenue Code of 1986, as amended
COSA
Cost-of-service Adjustment
DOT
United States Department of Transportation
EPA
United States Environmental Protection Agency
EPS
Earnings per share
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
GAAP
Accounting principles generally accepted in the United States of America
GPAC
Gas Pipeline Advisory Committee
GRIP
Gas Reliability Infrastructure Program
GSRS
Gas System Reliability Surcharge
Heating Degree Day or HDD

A measure designed to reflect the demand for energy needed for heating based on
  the extent to which the daily average temperature falls below a reference
  temperature for which no heating is required, usually 65 degrees Fahrenheit
IRS
U.S. Internal Revenue Service
KCC
Kansas Corporation Commission
KDHE
Kansas Department of Health and Environment
LDC
Local distribution company
Mcf
Thousand cubic feet
MGP
Manufactured gas plant
MMcf
Million cubic feet
Moody’s
Moody’s Investors Service, Inc.
Net margin
Non-GAAP measure defined as total revenues less cost of natural gas
NOL
Net operating loss
NPRM
Notice of Proposed Rulemaking
NYMEX
New York Mercantile Exchange
OCC
Oklahoma Corporation Commission
ONE Gas
ONE Gas, Inc.
ONE Gas Credit Agreement
ONE Gas’ $700 million amended and restated revolving credit agreement which expires on October 5, 2023
ONEOK
ONEOK, Inc. and its subsidiaries
PBRC
Performance-Based Rate Change
PHMSA
United States Department of Transportation Pipeline and Hazardous Materials
Safety Administration
Pipeline Safety, Regulatory Certainty
   and Job Creation Act
Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
ROE
Return on equity, calculated consistent with utility ratemaking principles in each jurisdiction in which we operate
RRC
Railroad Commission of Texas
S&P
Standard & Poor’s Ratings Services
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Senior Notes
ONE Gas’ registered notes consisting of $300 million of 3.61 percent senior notes due 2024, $600 million of 4.658 percent senior notes due 2044 and $400 million of 4.50 percent notes due 2048
Separation and Distribution Agreement
Separation and Distribution Agreement dated January 14, 2014, between ONEOK
and ONE Gas
XBRL
eXtensible Business Reporting Language

5


PART I - FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

ONE Gas, Inc.

 

 
CONSOLIDATED STATEMENTS OF INCOME

 

 


Three Months Ended
 

March 31,
(Unaudited)

2019

2018


(Thousands of dollars, except per share amounts)

 
 
 
 
Total revenues
 
$
661,000

 
$
638,464

 
 
 
 
 
Cost of natural gas

365,076


350,419

 
 
 
 
 
Operating expenses
 
 
 
 
Operations and maintenance

108,275


102,665

Depreciation and amortization

43,846


38,890

General taxes

16,184


16,200

Total operating expenses

168,305


157,755

Operating income

127,619


130,290

Other income (expense), net

429


(2,164
)
Interest expense, net

(15,786
)

(12,352
)
Income before income taxes

112,262


115,774

Income taxes

(18,602
)

(24,939
)
Net income

$
93,660


$
90,835








Earnings per share






Basic

$
1.77


$
1.73

Diluted

$
1.76


$
1.72








Average shares (thousands)






Basic

52,825


52,604

Diluted

53,206


52,897

Dividends declared per share of stock

$
0.50


$
0.46

See accompanying Notes to Consolidated Financial Statements.

6


ONE Gas, Inc.
 
 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
Three Months Ended
 
March 31,
(Unaudited)
2019
 
2018
 
(Thousands of dollars)
Net income
$
93,660

 
$
90,835

Other comprehensive income (loss), net of tax
 

 
 

Change in pension and other postemployment benefit plan liability, net of tax of $(53) and $(351), respectively
160

 
(80
)
Total other comprehensive income (loss), net of tax
160

 
(80
)
Comprehensive income
$
93,820

 
$
90,755

See accompanying Notes to Consolidated Financial Statements.


7



ONE Gas, Inc.
 
 
 
 
CONSOLIDATED BALANCE SHEETS
 
 
 
 
 
 
 
 
 
 
 
March 31,
 
December 31,
(Unaudited)
 
2019
 
2018
Assets
 
(Thousands of dollars)
Property, plant and equipment
 
 

 
 

Property, plant and equipment
 
$
6,148,394

 
$
6,073,143

Accumulated depreciation and amortization
 
1,816,480

 
1,789,431

Net property, plant and equipment
 
4,331,914

 
4,283,712

Current assets
 
 
 
 
Cash and cash equivalents
 
19,628

 
21,323

Accounts receivable, net
 
338,082

 
295,421

Materials and supplies
 
46,895

 
44,333

Natural gas in storage
 
51,475

 
107,295

Regulatory assets
 
38,760

 
54,420

Other current assets
 
21,430

 
20,495

Total current assets
 
516,270

 
543,287

Goodwill and other assets
 
 

 
 

Regulatory assets
 
429,518

 
437,479

Goodwill
 
157,953

 
157,953

Other assets
 
88,637

 
46,211

Total goodwill and other assets
 
676,108

 
641,643

Total assets
 
$
5,524,292

 
$
5,468,642

See accompanying Notes to Consolidated Financial Statements.


8


ONE Gas, Inc.
 
 
 
 
CONSOLIDATED BALANCE SHEETS
 
 
 
 
(Continued)
 
 
 
 
 
 
March 31,
 
December 31,
(Unaudited)
 
2019
 
2018
Equity and Liabilities
 
(Thousands of dollars)
Equity and long-term debt
 
 
 
 
Common stock, $0.01 par value:
authorized 250,000,000 shares; issued and outstanding 52,686,634 shares at March 31, 2019; issued 52,598,005 and outstanding 52,564,902 shares at December 31, 2018
 
$
527

 
$
526

Paid-in capital
 
1,720,220

 
1,727,492

Retained earnings
 
389,177

 
320,869

Accumulated other comprehensive loss
 
(5,144
)
 
(4,086
)
Treasury stock, at cost: 33,103 shares at December 31, 2018
 

 
(2,145
)
   Total equity
 
2,104,780

 
2,042,656

Long-term debt, excluding current maturities, and net of issuance costs of $11,368 and $11,457, respectively
 
1,285,587

 
1,285,483

Total equity and long-term debt

3,390,367


3,328,139

Current liabilities
 
 
 
 
Notes payable
 
295,500

 
299,500

Accounts payable
 
119,629

 
174,510

Accrued taxes other than income
 
51,903

 
47,640

Regulatory liabilities
 
54,791

 
48,394

Customer deposits
 
62,401

 
61,183

Other current liabilities
 
73,967

 
67,664

Total current liabilities
 
658,191

 
698,891

Deferred credits and other liabilities
 
 

 
 

Deferred income taxes
 
666,438

 
652,426

Regulatory liabilities
 
511,743

 
520,866

Employee benefit obligations
 
173,296

 
178,720

Other deferred credits
 
124,257

 
89,600

Total deferred credits and other liabilities
 
1,475,734

 
1,441,612

Commitments and contingencies
 


 


Total liabilities and equity
 
$
5,524,292

 
$
5,468,642

See accompanying Notes to Consolidated Financial Statements.




















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10


ONE Gas, Inc.
 
 
 
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
Three Months Ended
 
 
March 31,
(Unaudited)
 
2019
 
2018
 
 
(Thousands of dollars)
Operating activities
 
 
 
 
Net income
 
$
93,660

 
$
90,835

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
43,846

 
38,890

Deferred income taxes
 
4,828

 
24,077

Share-based compensation expense
 
1,954

 
1,945

Provision for doubtful accounts
 
2,263

 
2,722

Changes in assets and liabilities:
 
 
 
 
Accounts receivable
 
(44,924
)
 
(7,447
)
Materials and supplies
 
(2,562
)
 
4,610

Natural gas in storage
 
55,820

 
79,598

Asset removal costs
 
(11,169
)
 
(7,436
)
Accounts payable
 
(53,172
)
 
(56,409
)
Accrued taxes other than income
 
4,263

 
6,147

Customer deposits
 
1,218

 
1,050

Regulatory assets and liabilities
 
29,090

 
83,724

Other assets and liabilities
 
(2,824
)
 
(39,022
)
Cash provided by operating activities
 
122,291

 
223,284

Investing activities
 
 

 
 

Capital expenditures
 
(83,303
)
 
(86,599
)
Other
 
(3,040
)
 

Cash used in investing activities
 
(86,343
)
 
(86,599
)
Financing activities
 
 

 
 

Repayments of notes payable, net
 
(4,000
)
 
(74,608
)
Dividends paid
 
(26,343
)
 
(24,137
)
Tax withholdings related to net share settlements of stock compensation
 
(7,300
)
 
(7,817
)
Cash used in financing activities
 
(37,643
)
 
(106,562
)
Change in cash and cash equivalents
 
(1,695
)
 
30,123

Cash and cash equivalents at beginning of period
 
21,323

 
14,413

Cash and cash equivalents at end of period
 
$
19,628

 
$
44,536

See accompanying Notes to Consolidated Financial Statements.


11


ONE Gas, Inc.
 
 
 
 
CONSOLIDATED STATEMENTS OF EQUITY
 
 
 
 
 
 
 
 
 
(Unaudited)
 
Common Stock Issued
Common Stock
Paid-in Capital
 
 
(Shares)
(Thousands of dollars)
 
 
 
 
 
January 1, 2019
 
52,598,005

$
526

$
1,727,492

Net income
 



Other comprehensive income
 



Reclassification of stranded tax effects

 



Common stock issued and other
 
88,629

1

(7,499
)
Common stock dividends - $0.50 per share
 


227

March 31, 2019
 
52,686,634

$
527

$
1,720,220

 
 
 
 
 
January 1, 2018
 
52,598,005

$
526

$
1,737,551

Net income
 



Other comprehensive income
 



Common stock issued and other

 


(16,074
)
Common stock dividends - $0.46 per share
 


224

March 31, 2018
 
52,598,005

$
526

$
1,721,701

See accompanying Notes to Consolidated Financial Statements.



12


ONE Gas, Inc.
 
 
 
 
 
CONSOLIDATED STATEMENTS OF EQUITY
 
 
 
(Continued)
 
 
 
 
 
(Unaudited)
 
Retained Earnings
Treasury Stock
Accumulated Other Comprehensive Loss
Total Equity
 
 
(Thousands of dollars)
 
 
 
 
 
 
January 1, 2019
 
$
320,869

$
(2,145
)
$
(4,086
)
$
2,042,656

Net income
 
93,660



93,660

Other comprehensive income
 


160

160

Reclassification of stranded tax effects
 
1,218


(1,218
)

Common stock issued and other
 

2,145


(5,353
)
Common stock dividends - $0.50 per share
 
(26,570
)


(26,343
)
March 31, 2019
 
$
389,177

$

$
(5,144
)
$
2,104,780

 
 
 
 
 
 
January 1, 2018
 
$
246,121

$
(18,496
)
$
(5,493
)
$
1,960,209

Net income
 
90,835



90,835

Other comprehensive income
 


(80
)
(80
)
Common stock issued and other
 

10,195


(5,879
)
Common stock dividends - $0.46 per share
 
(24,361
)


(24,137
)
March 31, 2018
 
$
312,595

$
(8,301
)
$
(5,573
)
$
2,020,948

See accompanying Notes to Consolidated Financial Statements.


13


ONE Gas, Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.
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 also 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 audited consolidated financial statements, but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and footnotes in our Annual Report. Our significant accounting policies are described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2019, are not necessarily indicative of the results that may be expected for a 12-month period.

We provide natural gas distribution services to our 2.2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states.

Use of Estimates - 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 amount 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 revenues and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis using historical experience and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known to us.

Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial and transportation customers. The accounting policies for our segment are the same as those described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three months ended March 31, 2019, and 2018, we had no single external customer from which we received 10 percent or more of our gross revenues.

Reclassification of Prior Year Presentation - Certain prior year amounts have been reclassified for consistency with the current year presentation. Adjustments have been made to the consolidated balance sheets and consolidated statements of cash flows for the year ended December 31, 2018, to include accrued interest and accrued liabilities in other current liabilities. These reclassifications had no effect on the reported results of operations in the consolidated statements of income or previously reported cash flows from operating activities in the consolidated statements of cash flows.

Recently Issued Accounting Standards Update - In August 2018, the FASB issued ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force)”. Under this guidance, a company should defer implementation costs that it incurs if the company would capitalize those same costs under the internal-use software guidance for an arrangement that is a software license. This standard is effective for interim and annual periods in fiscal years beginning after December 15, 2019, and early adoption is permitted. We will adopt this standard January 1, 2020, and are currently assessing the potential impacts to our consolidated financial statements.

In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” which allows a reclassification from accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. We adopted this new guidance in the first quarter 2019 and our adoption did not result in a material impact to our consolidated financial statements. This change is reflected in our consolidated statements of equity.


14



In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments,’’ which introduces new guidance to the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted for fiscal years beginning after December 15, 2018. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2020.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” as amended, “Topic 842” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements. We adopted this new guidance effective January 1, 2019, and applied the modified retrospective approach to all existing leases. Upon adoption we recognized lease liabilities of approximately $32 million, with corresponding right-of-use assets of the same amount based on the present value of the remaining minimum rental payments for existing operating leases. Our adoption did not result in a material impact to our results of operations or cash flows. We utilized the practical expedients that allow us to: (1) not reassess expired or existing contracts to determine whether they are subject to lease accounting guidance, (2) not reconsider lease classification at transition, and (3) not evaluate previously capitalized initial direct costs under the revised requirements. We also utilized the practical expedients that allow us to: (1) not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in ASC Topic 840 (“Topic 840”) and (2) use an additional transition method in which an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We adopted an accounting policy that exempts leases with terms of less than one year from the recognition requirements of Topic 842, and disclose such leases in our interim and annual disclosures upon adoption. Our adoption did not result in a cumulative adjustment to our opening retained earnings. See Note 6 for additional information regarding our leases.
 
Property, Plant and Equipment - Accounts payable for construction work in process and asset removal costs decreased by approximately $1.7 million and $9.7 million for the three months ended March 31, 2019 and 2018, respectively. Such amounts are not included in capital expenditures in our consolidated statements of cash flows.


2.REVENUE

We recognize revenue from contracts with customers to depict the transfers of goods and services to customers at an amount that we expect to be entitled to receive in exchange for these goods and services. Our sources of revenue are disaggregated by natural gas sales, transportation revenues, and miscellaneous revenues, which are primarily one-time service fees, that meet the requirements of FASB’s ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”). Certain revenues that do not meet the requirements of ASC 606 are classified as other revenues in our Notes to Consolidated Financial Statements in this Quarterly Report.

Our natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities. For natural gas sales, the customer receives the benefits of our performance when the commodity is received and simultaneously consumed by the customer. The performance obligation is satisfied over time as the customer consumes the natural gas.

Our transportation revenues represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities and tariff-based negotiated contracts. The customer receives the benefits of our performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the customer receives the natural gas.

For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues upon the delivery of natural gas commodity or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet billed at the end of an accounting period. We use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. As a result, we estimate unbilled revenues at the end of each accounting period consistent with past practice. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at March 31, 2019 and December 31, 2018, were $88.7 million and $127.6 million, respectively, and are included in accounts receivable in our consolidated balance sheets.

Our miscellaneous revenues from contracts with customers represent implied contracts established by our tariff rates approved

15


by the regulatory authorities and includes miscellaneous utility services with the performance obligation satisfied at a point in time when services are rendered to the customer.

Total other revenues consist of revenues associated with regulatory mechanisms that do not meet the requirements of ASC 606 as revenue from contracts with customers, but authorize us to accrue revenues earned based on tariffs approved by the regulatory authorities. Other revenues - natural gas sales related primarily reflect our weather normalization mechanism in Kansas. This mechanism adjusts our revenues earned for the variance between actual and normal HDDs. This mechanism can have either positive (warmer than normal) or negative (colder than normal) effects on revenues.

We collect and remit other taxes on behalf of governmental authorities, and we record these amounts in accrued taxes other than income in our consolidated balance sheets on a net basis.

The following table sets forth our revenues disaggregated by source for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
 
 
2019
 
2018
 
 
(Thousands of dollars)
Natural gas sales to customers
 
$
621,492

 
$
594,926

Transportation revenues
 
35,028

 
33,543

Miscellaneous revenues
 
5,428

 
6,768

Total revenues from contracts with customers
 
661,948

 
635,237

Other revenues - natural gas sales related
 
(2,944
)
 
1,030

Other revenues
 
1,996

 
2,197

Total other revenues
 
(948
)
 
3,227

Total revenues
 
$
661,000

 
$
638,464



3.
REGULATORY ASSETS AND LIABILITIES

The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
 
 
 
 
March 31, 2019
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Pension and postemployment benefit costs
 

 
$
22,967

 
$
414,253

 
$
437,220

Reacquired debt costs
 

 
812

 
6,285

 
7,097

MGP remediation costs
 

 
98

 
7,611

 
7,709

Other
 

 
14,883

 
1,369

 
16,252

Total regulatory assets, net of amortization
 
 
 
38,760

 
429,518

 
468,278

Federal corporate income tax rate changes (a)
 
 
 
(32,312
)
 
(511,743
)
 
(544,055
)
Over-recovered purchased-gas costs
 
 
 
(14,197
)
 

 
(14,197
)
Weather normalization
 
 
 
(8,282
)
 

 
(8,282
)
Total regulatory liabilities
 
 
 
(54,791
)
 
(511,743
)
 
(566,534
)
Net regulatory liabilities
 
 
 
$
(16,031
)
 
$
(82,225
)
 
$
(98,256
)
(a) See Note 11 for additional information regarding our federal corporate income tax rate changes to regulatory liabilities.

16


 
 
 
 
December 31, 2018
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
25,083

 
$

 
$
25,083

Pension and postemployment benefit costs
 

 
23,384

 
421,726

 
445,110

Reacquired debt costs
 

 
812

 
6,487

 
7,299

MGP remediation costs
 
 
 

 
7,724

 
7,724

Other (a)
 

 
5,141

 
1,542

 
6,683

Total regulatory assets, net of amortization
 
 
 
54,420

 
437,479

 
491,899

Federal corporate income tax rate changes (b)
 
 
 
(30,934
)
 
(520,866
)
 
(551,800
)
Over-recovered purchased-gas costs
 

 
(13,668
)
 

 
(13,668
)
Weather normalization
 
 
 
(3,792
)
 

 
(3,792
)
Total regulatory liabilities
 
 
 
(48,394
)
 
(520,866
)
 
(569,260
)
Net regulatory assets (liabilities)
 
 
 
$
6,026

 
$
(83,387
)
 
$
(77,361
)
(a) Includes reclassification of ad-valorem tax for consistency with the current year presentation.
(b) See Note 11 for additional information regarding our federal corporate income tax rate changes to regulatory liabilities.

Regulatory assets in our consolidated balance sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates and certain riders are designed to provide a recovery of costs during the period such rates are in effect, but do not generally provide for a return on investment for amounts we have deferred as regulatory assets. All of our regulatory assets are subject to review by the respective regulatory authorities during future regulatory proceedings. We are not aware of any evidence that these costs will not be recoverable through either riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries.

4.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

In October 2018, we exercised a one-year extension on the ONE Gas Credit Agreement. The ONE Gas Credit Agreement remains a $700 million revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We are able to request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2023, and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At March 31, 2019, our total debt-to-capital ratio was 43 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement.

At March 31, 2019, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, resulting in $698.8 million of remaining credit available under the ONE Gas Credit Agreement.

We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor. At March 31, 2019, we had $295.5 million of commercial paper outstanding. The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary.

5.
LONG-TERM DEBT

In November 2018, ONE Gas issued $400 million of 4.50 percent senior notes due 2048. The proceeds from the issuance were used to retire the $300 million of 2.07 percent senior notes due 2019, to reduce the amount of outstanding commercial paper and for general corporate purposes.

Our long-term debt includes $300 million of 3.61 percent senior notes due in 2024, $600 million of 4.658 percent senior notes due 2044, and $400 million of 4.50 percent senior notes due 2048. The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee

17


or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

6.
LEASES

A lease is a contract that conveys the right to control the use and obtain substantially all the economic benefits from the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is a lease at inception and, if so, whether the arrangement is an operating lease or a finance lease. We identify a lease as a finance lease if the agreement includes any of the following criteria: transfer of ownership by the end of the lease term; an option to purchase the underlying asset that the lessee is reasonably certain to exercise; a lease term that represents 75 percent or more of the remaining economic life of the underlying asset; a present value of lease payments and any residual value guaranteed by the lessee that equals or exceeds 90 percent of the fair value of the underlying asset; or an underlying asset that is so specialized in nature that there is no expected alternative use to the lessor at the end of the lease term. A lease that does not meet any of these criteria is considered an operating lease.
Lease right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and liabilities are recognized at the commencement date of a lease based on the present value of lease payments over the lease term. Our lease terms may include options to extend or terminate the lease. We include these extension or termination options in the determination of the lease term when it is reasonably certain that we will exercise that option. We have lease agreements with lease and non-lease components, which are accounted for separately. Additionally, for certain office equipment leases, we apply a portfolio approach to effectively account for the operating lease right-of-use assets and liabilities. We do not recognize leases having a term of less than one year in our consolidated balance sheets.
For purposes of determining the present value of the lease payments, we use a lease’s implicit interest rate when readily determinable. As most of our leases do not provide an implicit interest rate, we use a discount rate commensurate with borrowing rates for defined terms that are reviewed annually on December 31st. Lease cost for operating leases is recognized on a straight-line basis over the lease term.
We have operating leases for office facilities, gas storage facilities, information technology equipment and right-of-way contracts. Our leases have remaining lease terms of 1 year to 15 years, some of which include options to extend the leases for up to 10 years, and some of which include options to terminate the leases within specified time frames. We have not entered into any finance leases.
Our right-of-use asset is $38.5 million as of March 31, 2019, and is reported within other assets in our consolidated balance sheets. Current operating lease liabilities are reported within our other current liabilities and other liabilities in our consolidated balance sheets. Total operating lease cost including immaterial amounts attributable to short-term operating leases was $2.0 million for the three months ended March 31, 2019.
 
Three Months Ended
 
March 31,
Other information related to operating leases
2019
 
(Millions of dollars)
 
 
Weighted-average remaining lease term
7 years
 
 
Weighted-average discount rate
3.66%
 
 
Supplemental cash flows information
 
Lease payments
$
(2.2
)
Right-of-use assets obtained in exchange for lease obligations
$
8.7



18


 
 
 
 
 
March 31,
Future minimum lease payments under non-cancellable operating leases
 
2019
 
 
(Millions of dollars)
2019 (excluding the three months ended March 31, 2019)
 
$
5.7

2020
 
7.4

2021
 
7.0

2022
 
6.7

2023
 
5.7

Thereafter
 
11.6

Total future minimum lease payments
 
$
44.1

Imputed interest
 
(5.6
)
Total operating lease liability
 
$
38.5

 
 
 
Consolidated balance sheets as of March 31, 2019
 
 
Current operating lease liability
 
$
6.2

Long-term operating lease liability
 
32.3

Total operating lease liability

 
$
38.5


The following table sets forth the required disclosures under Topic 842 for the comparative period under Topic 840, as reported in Note 15 of our Notes to the Consolidated Financial Statements in our Annual Report:
 
 
December 31,
Future minimum lease payments under non-cancellable operating leases
 
2018
 
 
(Millions of dollars)
2019
 
$
6.3

2020
 
5.1

2021
 
4.5

2022
 
4.3

2023
 
4.2

Thereafter
 
3.8

Total future minimum lease payments
 
$
28.2


7.
EQUITY

Dividends Declared - In April 2019, we declared a dividend of $0.50 per share ($2.00 per share on an annualized basis) for shareholders of record as of May 15, 2019, payable May 31, 2019.


19


8.
ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the effect of reclassifications from accumulated other comprehensive loss in our consolidated statements of income for the periods indicated:
 
 
Three Months Ended
 
Affected Line Item in the
Details About Accumulated Other
 
March 31,
 
 Consolidated Statements
Comprehensive Loss Components
 
2019
2018
 
of Income
 
 
(Thousands of dollars)
 
 
Pension and other postemployment benefit plan obligations (a)
 
 
 
 
 
Amortization of net loss
 
$
8,821

$
10,950

 
 
Amortization of unrecognized prior service credit
 
(168
)
(1,142
)
 
 
 
 
8,653

9,808

 
 
Reclassification of stranded tax effects (b)

 
(1,218
)

 
 
Regulatory adjustments (c)
 
(7,222
)
(9,537
)
 
 
 
 
213

271

 
Income before income taxes
 
 
(53
)
(351
)
 
Income tax expense
Total reclassifications for the period
 
$
160

$
(80
)
 
Net income
(a) These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note 10 for additional detail of our net periodic benefit cost.
(b) Reflects the impact of the adoption of ASU 2018-02 in fiscal year 2019 related to stranded tax effects in accumulated other comprehensive income as a result of the Tax Cuts and Jobs Act of 2017. See Note 1 of the Notes to Consolidated Financial Statements for additional information regarding our adoption of this standard.
(c) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 3 for additional disclosures of regulatory assets and liabilities.

9.
EARNINGS PER SHARE

Basic EPS is based on net income and is calculated based upon the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Diluted EPS includes basic EPS, plus unvested stock awards granted under our compensation plans, but only to the extent these instruments dilute earnings per share.

The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
 
Three Months Ended March 31, 2019
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
93,660

 
52,825

 
$
1.77

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
381

 
 

Net income available for common stock and common stock equivalents
$
93,660

 
53,206

 
$
1.76


 
Three Months Ended March 31, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
90,835

 
52,604

 
$
1.73

Diluted EPS Calculation
 
 
 

 
 

Effect of dilutive securities

 
293

 
 

Net income available for common stock and common stock equivalents
$
90,835

 
52,897

 
$
1.72




20



10.
EMPLOYEE BENEFIT PLANS

The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated:
 
Pension Benefits
 
Three Months Ended
 
March 31,
 
2019
2018
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
Service cost
$
3,008

$
3,230

Interest cost (a)
10,168

9,200

Expected return on assets (a)
(15,485
)
(15,145
)
Amortization of net loss (a)
8,260

9,978

Net periodic benefit cost
$
5,951

$
7,263

(a) These amounts, net of any amounts capitalized as a regulatory asset since adoption of ASU 2017-07 on January 1, 2018, have been recognized as other income (expense), net in the consolidated statements of income. See Note 12 for additional detail of our other income (expense).

 
Other Postemployment Benefits
 
Three Months Ended
 
March 31,
 
2019
2018
 
(Thousands of dollars)
Components of net periodic benefit cost (credit)
 
 
Service cost
$
434

$
589

Interest cost (a)
2,329

2,279

Expected return on assets (a)
(3,147
)
(3,571
)
Amortization of unrecognized prior service credit (a)
(168
)
(1,142
)
Amortization of net loss (a)
561

972

Net periodic benefit cost (credit)
$
9

$
(873
)
(a) These amounts, net of any amounts capitalized as a regulatory asset since adoption of ASU 2017-07 on January 1, 2018, have been recognized as other income (expense), net in the consolidated statements of income. See Note 12 for additional detail of our other income (expense).

We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable regulatory authorities. Regulatory deferrals related to net periodic benefit cost were not material for the three months ended March 31, 2019.

Since adoption of ASU 2017-07 on January 1, 2018, we continue to capitalize all eligible service cost and non-service cost components under the accounting requirements of ASC Topic 980 (Regulated Operations) for rate-regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. We have recognized a regulatory asset of $2.2 million and $1.5 million as of March 31, 2019 and December 31, 2018, respectively. See Note 3 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.

11.
INCOME TAXES

We use an estimated annual effective tax rate for purposes of determining the income tax provision during interim reporting periods. In calculating our estimated annual effective tax rate, we consider forecasted annual pre-tax income and estimated permanent book versus tax differences, as well as tax credits. Adjustments to the effective tax rate and estimates will occur as information and assumptions change.


21


Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date.

As a result of the enactment of the Tax Cuts and Jobs Act of 2017, we remeasured our ADIT. As a regulated entity, the change in ADIT was recorded as a regulatory liability and is subject to refund to our customers. The Tax Cuts and Jobs Act of 2017 retains the tax normalization provisions of the Code that stipulate how these excess deferred income taxes for certain accelerated tax depreciation benefits are to be refunded to customers. Our customers will receive refunds as determined by our regulators beginning in 2019. In each state, we received accounting orders requiring us to refund the reduction in ADIT due to the remeasurement and to establish a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35 percent federal corporate income tax rate and the new 21 percent federal corporate income tax rate effective in January 2018.

We have completed or made a reasonable estimate for the measurement and accounting of the effects of the Tax Cuts and Jobs Act of 2017, which were reflected in our December 31, 2018, consolidated financial statements. While we still expect additional guidance from the U.S. Department of the Treasury and the IRS, we have finalized our calculations using available guidance. Any additional issued guidance or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the Tax Cuts and Jobs Act of 2017.

In January 2019, the OCC issued an order in response to Oklahoma Natural Gas’ March 2018 PBRC filing requiring Oklahoma Natural Gas to credit customers for the reduction in ADIT based upon an amortization period in compliance with the tax normalization rules for the portions of excess ADIT stipulated by the Code and ten years for all other components of excess ADIT. In February 2019, the KCC issued an order adjusting Kansas Gas Service’s base rates, which included an amortization credit associated with the refund of ADIT based on an amortization period in compliance with the tax normalization rules for the portion of excess ADIT stipulated by the Code and five years for all other components of excess ADIT. In Texas, we continue to work with our regulators to address the reduction in ADIT due to the remeasurement. As a result of the orders in Oklahoma and Kansas, the estimated excess ADIT is being returned to customers beginning in 2019. During the first quarter of fiscal 2019, we credited income tax expense $6.8 million for the amortization of the regulatory liability associated with excess ADIT that was returned to customers. The treatment of our excess ADIT in Texas and the degree to which it impacts us will be determined as we work with our regulators.

In 2018, we accrued a separate regulatory liability associated with the change in the federal corporate income tax rates collected in our rates resulting in a reduction to our revenues of $36.6 million for the year ended December 31, 2018. In January 2019, the OCC issued an order that resulted in the establishment of a $15.8 million liability, including interest, at December 31, 2018 for the estimated impact on customer rates of earnings, including amounts attributable to tax savings, above the 9.5 percent approved ROE in the 2018 review period to be returned to customers within the 2019 PBRC filing. In a separate order issued in February 2019, the KCC required Kansas Gas Service to refund the regulatory liability for the portion of its revenue representing the difference between the 21 percent and 35 percent federal corporate income tax rate for the period between January 1, 2018, and through the date on which the KCC issued a final order in Kansas Gas Service’s June 2018 rate case. In the first quarter 2019, we accrued an additional $2.4 million reduction to revenues for the period until new rates were implemented in Kansas. The refund of $16.6 million will be issued through a bill credit in the second quarter 2019. In 2018, Texas Gas Service issued one-time refunds totaling $6.6 million for the reduction in the federal corporate income tax rate for the period between January 1, 2018, to the dates new rates were implemented in its service areas.

12.
OTHER INCOME AND OTHER EXPENSE

The following table sets forth the components of other income and other expense for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
 
 
2019
 
2018
 
 
(Thousands of dollars)
Net periodic benefit cost other than service cost
 
$
(1,599
)
 
$
(1,734
)
Other, net
 
2,028

 
(430
)
Total other income (expense), net
 
$
429

 
$
(2,164
)


22


13.
COMMITMENTS AND CONTINGENCIES

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. 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. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three months ended March 31, 2019 and 2018.

We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites contain contaminants generally associated with MGP sites and are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. During the first quarter of 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. We are also finalizing a study of the feasibility of various options to address the remainder of the site.

With regard to one of our former MGP sites in Kansas, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. In 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. We have submitted a remediation plan to the KDHE for this site. The KDHE is currently reviewing our plan. In the second quarter of 2018, we revised our estimate of the potential costs associated with additional investigation and remediation to be in the range of $5.6 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded in the second quarter of 2018 an adjustment to the reserve of $1.6 million bringing the total to $5.6 million for this site, which also increased our regulatory asset pursuant to our AAO in Kansas.

In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, these 12 former MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC.  The agreement allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at these sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC issued an order approving the settlement agreement in November 2017. A regulatory asset of approximately $5.9 million was recorded for estimated costs that were accrued at January 1, 2017.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the Texas Commission on Environmental Quality, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Until the investigation is complete, we are unable to determine what, if any, active remediation will be

23


required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of contamination.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three months ended March 31, 2019 and 2018. A number of environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows. However, we do not expect expenditures for these matters to have a material adverse effect on our financial condition, results of operations or cash flows.

Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:

an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;
a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity-management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines.  The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The GPAC has met five times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The next GPAC meeting, scheduled in June 2019, will focus on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA announced they will split this NPRM into three separate final rulemakings:

the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and
the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.

A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and gathering pipelines. The timing of each final rule being published is unknown, but they are expected to be published during 2019.  The potential capital and operating expenditures associated with compliance with the proposed rules are currently being evaluated and could be significant depending on the final regulations.


24


Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses 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 results of operations, financial position or cash flows.

14.
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory rulings require a different accounting treatment.

If certain conditions are met, we may elect to designate a derivative instrument as a hedge to mitigate the risk of exposure to changes in fair values or cash flows.

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
 
 
Recognition and Measurement
Accounting Treatment
 
Balance Sheet
 
Income Statement
Normal purchases and
normal sales
-
Recorded at historical cost
-
Change in fair value not recognized in earnings
Mark-to-market
-
Recorded at fair value
-
Change in fair value deferred through the purchased-gas cost adjustment mechanisms

We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.

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

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our consolidated financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and
Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data.

We recognize transfers into and out of the levels as of the end of each reporting period.

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.

Derivative Instruments -  At March 31, 2019, we had no purchased natural gas call options. At December 31, 2018, we held purchased natural gas call options for the heating season ended March 31, 2019, with total notional amounts of 14.3 Bcf, for which we paid premiums of $4.1 million, and had a fair value of $2.1 million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Additionally, changes in fair value associated

25


with these contracts are deferred as part of our unrecovered purchased-gas costs in our consolidated balance sheets. Our natural gas call options are classified as Level 1, as fair value amounts are based on unadjusted quoted prices in active markets including NYMEX-settled prices. There were no transfers between levels for the three months ended March 31, 2019 and 2018.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts, and are classified as Level 1. Our other current assets include $1.5 million of corporate bonds and $1.4 million of United States treasury notes, for which the fair value approximates our cost and are also classified as Level 1.

Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $1.3 billion at both March 31, 2019 and December 31, 2018. The estimated fair value of our long-term debt, including current maturities, was $1.4 billion at both March 31, 2019 and December 31, 2018. The estimated fair value of our long-term debt at March 31, 2019 and December 31, 2018, was determined using quoted market prices, and is classified as Level 2.

26




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 the Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report.  Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2019, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Tax Reform - We continue to work with our regulators to address the impact of the Tax Cuts and Jobs Act of 2017 on our rates. As a result of the enactment of the Tax Cuts and Jobs Act of 2017, we remeasured our ADIT. As a regulated entity, the change in ADIT was recorded as a regulatory liability and is subject to refund to our customers. The Tax Cuts and Jobs Act of 2017 retains the tax normalization provisions of the Code that stipulate how these excess ADIT for certain accelerated tax benefits are to be refunded to customers. In each state, we received accounting orders requiring us to refund the reduction in ADIT due to the remeasurement and to establish a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35 percent federal corporate income tax rate and the new 21 percent federal corporate income tax rate effective in January 2018. As a result of the rate orders received in Oklahoma and Kansas in the first quarter 2019, we began to return the estimated excess ADIT to customers. The treatment of our excess ADIT in Texas and the degree to which it impacts us will be determined as we work with our regulators. Additionally, we established a separate regulatory liability associated with the change in federal corporate income tax rates collected in our rates which resulted in a reduction to our revenues of $36.6 million for the year ended December 31, 2018. In the first quarter 2019, we accrued an additional $2.4 million reduction to revenues for the period until new rates were implemented in Kansas. See Regulatory Activities below for information regarding the amount, period and timing of the return of these regulatory liabilities to our customers, as well as additional information on the impact of the Tax Cuts and Jobs Act of 2017.

For further discussion see “Liquidity and Capital Resources - Tax Reform” below.

Dividend - In April 2019, we declared a dividend of $0.50 per share ($2.00 per share on an annualized basis) for shareholders of record as of May 15, 2019, payable May 31, 2019.

REGULATORY ACTIVITIES

Oklahoma - On March 15, 2019, Oklahoma Natural Gas filed its third annual PBRC application following the general rate case that was approved in January 2016. This filing was based on a calendar test year of 2018 and includes two proposed customer credits. Oklahoma Natural Gas has proposed a PBRC credit of $15.4 million to be spread over a 12-month period and a credit of $12.7 million associated with excess ADIT. This filing has been made in compliance with the January 8, 2019, OCC order settling tax issues resulting from the Tax Cuts and Jobs Act of 2017. This order requires that all earnings, including amounts attributable to tax savings, occurring in the 2018 calendar year that are above the authorized ROE of 9.5% be returned to customers, with interest at the cost of capital rate. As required, PBRC filings are made annually on or before March 15, until the next general rate case, which is currently required to be filed on or before June 30, 2021, based on a calendar 2020 test year.

Kansas - In August 2018, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.4 million related to its GSRS. In November 2018, the KCC approved the increase effective December 2018.

In June 2018, Kansas Gas Service filed a request with the KCC for an increase in base rates, reflecting investments in system improvements and changes in operating costs necessary to maintain the safety and reliability of its natural gas distribution system. In February 2019, the KCC issued an order that included a net base rate increase of $18.6 million and a GSRS pre-tax carrying charge of approximately 9.1%. Kansas Gas Service was already recovering $2.9 million from customers through the GSRS, therefore, this order represents a total base rate increase of $21.5 million. The increase in base rates reflects an amortization credit for the refund of excess ADIT over a period in compliance with the tax normalization rules for the portions stipulated by the Code and five years for all other components of excess ADIT. Additionally, the settlement provides for extending application of the weather normalization adjustment rider to small transportation customers and the implementation of a cybersecurity cost tracker. The residential service charge will be $18.70 per month and the delivery charge will be $2.3485 per Mcf. See additional discussion under Tax Reform regarding the regulatory liability for the difference between the 21 percent and 35 percent federal corporate income tax rate for the period between January 1, 2018, and through the date on which the KCC issued a final order in Kansas Gas Service’s June 2018 rate case.

27



Texas - West Texas Service Area - In March 2019, Texas Gas Service made GRIP filings for all customers in the West Texas service area requesting an increase of $4.1 million to be effective in July 2019.

In March 2018, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2018, the RRC and the cities in the West Texas service area agreed to the increase of $3.5 million, and new rates became effective in July 2018.

Central Texas Service Area - In March 2019, Texas Gas Service made GRIP filings for all customers in the Central Texas service area requesting an increase of $5.5 million to be effective in July 2019.
 
In March 2018, Texas Gas Service made GRIP filings for all customers in the Central Texas service area. In June 2018, the RRC and the cities in the Central Texas service area agreed to the increase of $3.3 million, and new rates became effective in July 2018.

Other Texas Service Areas - In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate increases associated with these filings that were approved totaled $0.1 million for the three months ended March 31, 2019 and $1.6 million for the year ended December 31, 2018.

Tax Reform - Oklahoma - On January 9, 2018, the OCC approved an order directing Oklahoma Natural Gas to record a deferred liability to reflect the reduced federal corporate income tax rate of 21 percent and the associated savings in excess ADIT and any other tax implications of the Tax Cuts and Jobs Act of 2017 on an interim basis, subject to refund, until utility rates are adjusted to reflect the federal tax savings and a final order is issued in Oklahoma Natural Gas’ next scheduled PBRC proceeding. This order also directed Oklahoma Natural Gas, to the extent not already accounted for in Oklahoma Natural Gas’ current PBRC tariff, to accrue interest at a rate equivalent to Oklahoma Natural Gas’ cost of capital as recognized in the most recent PBRC filing on the amounts of any refunds determined to be owed to customers.

In compliance with the order, Oklahoma Natural Gas’ March 15, 2018, PBRC filing contained two deferred liabilities subject to review and potential refund. First, a regulatory liability was established reflecting the remeasurement of ADIT for the change in the federal corporate income tax rate. Second, a regulatory liability was established reflecting a credit for earnings above the top of the ROE dead-band of 10%. In January 2019, the OCC issued an order requiring Oklahoma Natural Gas to lower base rates by $11.3 million to reflect the lower federal corporate income tax rate and the authorized ROE of 9.5% prospectively and to credit customers for excess ADIT based upon an amortization period in compliance with the tax normalization rules for the portions of excess ADIT stipulated by the Code and ten years for all other components. This order also requires the March 15, 2019, PBRC filing to include the return of all earnings above 9.5% occurring in the 2018 test year.
  
Kansas - On January 18, 2018, the KCC opened a general investigation for the purposes of examining the financial impact of the Tax Cuts and Jobs Act of 2017 on regulated public utilities operating in Kansas and made the following findings and conclusions: (1) utilities are to track and accumulate, in a deferred revenue account, the portion of their revenue that results from the use of a 35 percent federal corporate income tax rate for their last KCC-approved revenue determination instead of the new lower federal corporate income tax rate; (2) deferrals are to commence on the effective date of the new federal corporate income tax rate; (3) excess ADIT should be captured in a manner consistent with tax normalization rules; and (4) the portion of current rates affected by the Tax Cuts and Jobs Act of 2017 should be considered interim and subject to refund, with interest compounded monthly at the rate for customer deposits, until the KCC has an opportunity to evaluate the reasonableness of those rates with new lower federal corporate income tax rates.

In March 2018, the KCC approved a settlement with Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board related to the Tax Cuts and Jobs Act of 2017. The agreement indicates for the period between January 1, 2018, and through the date on which the KCC issues a final order in Kansas Gas Service’s next general rate case, Kansas Gas Service agreed to accrue monthly, as a regulatory liability on its general ledger, the portion of its revenue representing the difference between the 21 percent and 35 percent federal corporate income tax rate. Through this agreement, Kansas Gas Service also established a regulatory liability to account for the remeasurement of ADIT for the change in the federal corporate income tax rate. The treatment of these regulatory liabilities was determined in Kansas Gas Service’s general rate proceeding filed in June 2018.

The KCC issued an order in February 2019 approving the unanimous settlement agreement regarding Kansas Gas Service’s rate case filed in June 2018. As provided for in the agreement, the base rates approved for Kansas Gas Service include an amortization credit associated with the refund of excess ADIT based on an amortization period in compliance with the tax normalization rules for the portion of excess ADIT stipulated by the Code and five years for all other components. In a

28


separate order issued by the KCC, Kansas Gas Service is required to refund to customers the amount of the regulatory liability for the decrease in the federal corporate income tax rate in 2018 through the date on which Kansas Gas Service’s new rates went into effect in February 2019. The refund of $16.6 million will be issued through a bill credit in the second quarter 2019.
 
Texas - In February 2018, the RRC issued an accounting order for determining how the impact of the Tax Cuts and Jobs Act of 2017 would be reflected in gas utility rates in Texas. Gas utilities were ordered to either file a new rate case or voluntarily reduce rates by September 1, 2018, to reflect the reduction of the federal corporate income tax rate to 21 percent from 35 percent. Gas utilities were further ordered to calculate, defer and refund rate reductions resulting from changes to the corporate tax rate that occurred between January 1, 2018, and the effective date of new rates. Per the order, the impact of the Tax Cuts and Jobs Act of 2017 on ADIT remeasurement is to be determined in the next rate case in each jurisdiction.

In 2018, Texas Gas Service requested a total of $11.1 million of decreases to rates for customers in its service areas due to the reduction of the federal corporate income tax rate, and one-time refunds totaling $6.6 million for the reduction in the federal corporate income tax rate for the period between January 1, 2018, to the dates new rates were implemented. The requests for the decreases in rates and the one-time refunds were approved and new rates, where applicable, became effective in the second half of 2018.

We continue to work with our regulators in Texas to address excess ADIT. The treatment of excess ADIT in Texas and the degree to which it impacts us will be determined as we work with our regulators.

The treatment of excess ADIT by our regulators is not expected to have a material impact on earnings, as any reduction or credit in rates is offset by the amortization of the regulatory liability as a credit in income tax expense. During the first quarter of fiscal 2019, we credited income tax expense $6.8 million for the amortization of the regulatory liability associated with excess ADIT that was returned to customers. See “Liquidity and Capital Resources - Tax Reform” and Note 11 of the Notes to Consolidated Financial Statements for additional discussion of the Tax Cuts and Jobs Act of 2017.


29


FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable and operating business segment: regulated utilities that deliver natural gas to residential, commercial, industrial and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income.

Selected Financial Results - For the three months ended March 31, 2019, net income was $93.7 million, or $1.76 per diluted share, compared with $90.8 million, or $1.72 per diluted share in the same period last year.

The following table sets forth certain selected financial results for our operations for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Financial Results
2019
 
2018
 
Increase (Decrease)
 
(Millions of dollars, except percentages)
Natural gas sales
$
618.6

 
$
596.0

 
$
22.6

 
4
 %
Transportation revenues
35.0

 
33.5

 
1.5

 
4
 %
Other revenues
7.4

 
8.9

 
(1.5
)
 
(17
)%
Total revenues
661.0

 
638.4

 
22.6

 
4
 %
Cost of natural gas
365.1

 
350.4

 
14.7

 
4
 %
Net margin
295.9

 
288.0

 
7.9

 
3
 %
Operating costs
124.5

 
118.8

 
5.7

 
5
 %
Depreciation and amortization
43.8

 
38.9

 
4.9

 
13
 %
Operating income
$
127.6

 
$
130.3

 
$
(2.7
)
 
(2
)%
Capital expenditures
$
83.3

 
$
86.6

 
$
(3.3
)
 
(4
)%
Asset removal costs
$
11.1

 
$
7.4

 
$
3.7

 
50
 %


Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales that do not meet the requirements under ASC 606, which are included in the consolidated statements of income and in our footnotes as other revenues.

Transportation revenues represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities and tariff-based negotiated contracts.

Other utility revenues include primarily miscellaneous service charges which represent implied contracts with customers established by our tariff rates approved by the regulatory authorities and other revenues from regulatory mechanisms that do not meet the requirements of ASC 606.

Non-GAAP Financial Measure - We have disclosed net margin, which is considered a non-GAAP financial measure, in our selected financial data and selected financial results. Net margin is comprised of total revenues less cost of natural gas. Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization.  In addition, these regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our customers, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we routinely use net margin in the analysis of our financial performance. We believe that net margin provides investors a more relevant and useful measure to analyze our financial performance as a 100 percent regulated natural gas utility than total revenues because the change in the cost of natural gas from period to period does not impact our operating income. As such, the following discussion and analysis of our financial performance will reference net margin rather than total revenues and cost of natural gas individually.

 

30


The following table sets forth a reconciliation of net margin to the most directly comparable GAAP measure for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Non-GAAP Reconciliation
2019
 
2018
 
Increase (Decrease)
 
(Millions of dollars, except percentages)
Total revenues
$
661.0

 
$
638.4

 
$
22.6

 
4
%
Cost of natural gas
365.1

 
350.4

 
14.7

 
4
%
Net margin
$
295.9

 
$
288.0

 
$
7.9

 
3
%

The following table sets forth our net margin by type of customer for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Net Margin
2019
 
2018
 
Increase (Decrease)
Natural gas sales
(Millions of dollars, except percentages)
Residential
$
208.7

 
$
204.1

 
$
4.6

 
2
 %
Commercial and industrial
42.1

 
39.7

 
2.4

 
6
 %
Wholesale and public authority
2.7

 
1.8

 
0.9

 
50
 %
Net margin on natural gas sales
253.5

 
245.6

 
7.9

 
3
 %
Transportation revenues
35.0

 
33.5

 
1.5

 
4
 %
Other revenues
7.4

 
8.9

 
(1.5
)
 
(17
)%
Net margin
$
295.9

 
$
288.0

 
$
7.9

 
3
 %

Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes delivered and billed and the effects of weather normalization. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:
 
Three Months Ended
 
Three Months
 
March 31,
 
2019 vs. 2018
Net Margin on Natural Gas Sales
2019
 
2018
 
Increase (Decrease)
Net margin on natural gas sales
(Millions of dollars, except percentages)
 
 
 
Fixed margin
$
142.2

 
$
136.4

 
$
5.8

 
4
%
Variable margin
111.3

 
109.2

 
2.1

 
2
%
Net margin on natural gas sales
$
253.5

 
$
245.6

 
$
7.9

 
3
%

Net margin increased $7.9 million for the three months ended March 31, 2019, compared with the same period last year, due primarily to the following:
an increase of $3.9 million from new rates primarily in Kansas, which includes the effect of crediting customers for the amortization of excess ADIT in tax expense;
an increase of $3.3 million due to higher sales volumes, net of weather normalization, in Texas and Kansas; and
an increase of $1.4 million in residential sales due primarily to net customer growth in Oklahoma and Texas; offset by
a decrease of $0.9 million due to the impact of the retroactive 2017 compressed natural gas federal excise tax credit enacted in February 2018.

Operating costs increased $5.7 million for the three months ended March 31, 2019, compared with the same period last year, due primarily to the following:

an increase of $4.3 million in employee-related costs; and
an increase of $1.6 million in legal-related costs.


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Depreciation and amortization expense increased $4.9 million for the three months ended March 31, 2019, compared with the same period last year, due primarily to an increase in depreciation from our capital expenditures being placed in service, higher depreciation rates in Kansas and an increase in the amortization of the ad-valorem surcharge rider in Kansas.

Other Factors Affecting Net Income - Other factors that affect net income include other income, net, interest expense, and income tax expense for the three months ended March 31, 2019 compared with the same period last year include the following:

an increase of $2.6 million in other income, net, due primarily to change in earnings on investments associated with nonqualified employee benefit plans, which offset the increase in costs for the plans included in operating costs; and
an increase of $3.4 million in interest expense resulting primarily from the refinancing of our $300 million Senior Notes, with a 2.07 percent interest rate due February 2019 with $400 million Senior Notes, with a 4.50 percent interest rate due November 2048; and
a decrease of $6.3 million in income tax expense due primarily to the amortization of the excess ADIT we are crediting to customers which is offset in revenues.

Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities and information technology assets. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations. Asset removal costs include expenditures associated with the replacement or retirement of long-lived assets, primarily our pipeline assets.

Capital expenditures decreased $3.3 million for the three months ended March 31, 2019, compared with the same period last year, due primarily to the timing of cash expenditures for system integrity and extension into new service areas. Our capital expenditures and asset removal costs are expected to be approximately $450.0 million for 2019.

Selected Operating Information - The following tables set forth certain selected operating information for the periods indicated:
 
 
Three Months Ended
Variances
 
 
March 31,
2019 vs. 2018
(in thousands)
 
2019
2018
Increase (Decrease)
Average Number of Customers
 
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Residential
 
808

591

628

2,027

803

590

623

2,016

5

1

5

11

Commercial and industrial
 
76

50

36

162

75

51

36

162

1

(1
)


Wholesale and public authority
 


3

3



3

3





Transportation
 
5

6

1

12

5

6

1

12





Total customers
 
889

647

668

2,204

883

647

663

2,193

6


5

11


The following table reflects the total volumes delivered, excluding the effects of weather normalization mechanisms on sales volumes.
 
 
Three Months Ended
 
 
March 31,
Volumes (MMcf)
 
2019
 
2018
Natural gas sales
 
 
 
 
Residential
 
65,697

 
60,985

Commercial and industrial
 
19,272

 
17,990

Wholesale and public authority
 
1,143

 
867

Total sales volumes delivered
 
86,112

 
79,842

Transportation
 
65,585

 
64,916

Total volumes delivered
 
151,697

 
144,758


Total sales volumes delivered increased for the three months ended March 31, 2019, compared with the same period last year, due primarily to colder weather in the first quarter 2019. Transportation volumes increased for the three months ended March 31, 2019, compared with the same period last year, due to colder temperatures in our service areas. The impact of weather on residential and commercial net margin is mitigated by weather-normalization mechanisms in all jurisdictions.

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Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. The impact to net margin from changes in volumes associated with these customers is minimal.
 
 
Three Months Ended
 
 
March 31,
 
 
2019
 
2018
 
2019 vs. 2018
 
2019
 
2018
Heating Degree Days
 
Actual
 
Normal
 
Actual
 
Normal
 
Actual Variance
 
Actual as a percent of Normal
Oklahoma
 
2,077

 
1,775

 
1,870

 
1,775

 
11
%
 
117
%
 
105
%
Kansas
 
2,751

 
2,528

 
2,489

 
2,528

 
11
%
 
109
%
 
98
%
Texas
 
1,003

 
1,006

 
903

 
1,008

 
11
%
 
100
%
 
90
%

Normal HDDs are established through rate proceedings in each of our rate jurisdictions for use primarily in weather-normalization billing calculations. See further discussion on weather normalization in our Regulatory Overview section in Part 1, Item 1, “Business,” of our Annual Report. Normal HDDs disclosed above are based on:

Oklahoma - For years 2016-2019, 10-year weighted average HDDs as of December 31, 2014, for years 2005-2014, as calculated using 11 weather stations across Oklahoma and weighted on average customer count.
Kansas - For years 2017-2019, 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using four weather stations across Kansas and weighted on HDDs by weather station and customers.
Texas - An average of HDDs authorized in our most recent rate proceeding in each jurisdiction and weighted using a rolling 10-year average of actual natural gas distribution sales volumes by jurisdiction.

Actual HDDs are based on the quarter-to-date and year-to-date weighted average of:

11 weather stations and customers by month for Oklahoma;
4 weather stations and customers by month for Kansas; and
9 weather stations and natural gas distribution sales volumes by service area for Texas.

CONTINGENCIES

We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses 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 results of operations, financial position or cash flows.

LIQUIDITY AND CAPITAL RESOURCES

General - We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource requirements. We fund operating expenses, working capital requirements, including purchases of natural gas, and capital expenditures primarily with cash from operations and commercial paper.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. Because the energy consumption of residential customers is less volatile compared with commercial and industrial customers, our business historically has generated stable and predictable earnings and cash flows. Additionally, we have several regulatory rate mechanisms in place to reduce the lag in earning a return on our capital expenditures. We anticipate that our cash flow generated from operations and our expected short- and long-term financing arrangements will enable us to maintain our current and planned level of operations and provide us flexibility to finance our infrastructure investments.

Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions and our financial condition and credit ratings. By maintaining a conservative financial profile and stable revenue base, we believe

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that we will be able to maintain an investment-grade credit rating, which we believe will provide us access to diverse sources of capital at favorable rates in order to finance our infrastructure investments.

Tax Reform - The Tax Cuts and Jobs Act of 2017 had an overall negative impact on our operating cash flow due to several dynamics. The reduction in the federal corporate income tax rate resulted in less revenues collected from customers related to the recovery of tax expense included in our rates. Although cash collected from this revenue is ultimately used to remit our income tax expense payments, under the new law, we will lose a portion of the timing benefit when we collect and remit tax payments, thereby reducing cash that may have been retained for several years. Under the new tax law, natural gas utilities are not eligible to take bonus depreciation, but they are also not subject to the new limitations on the deduction of interest expense. The loss of bonus depreciation will result in earlier cash tax payments, as compared to the previous tax law, once accumulated NOLs are utilized. Additionally, the lowering of the federal corporate income tax rate effectively resulted in an over-collection of tax expenses, as customers’ rates include tax expenses based on the statutory federal corporate income tax rate.

We have addressed excess ADIT in Oklahoma and Kansas. In Texas, the timing of these changes in our cash flows and the degree to which it impacts us will be determined as we finalize our regulatory filings in 2019. We expect cash flows in 2019 will be reduced by approximately $15.9 million as we begin refunding the excess ADIT regulatory liability to customers.

We believe that our capital structure and available liquidity resources are adequate to adjust for these changes. See additional discussion under Regulatory Activities - Tax Reform and Note 11 of Notes to Consolidated Financial Statements in this Quarterly Report.
 
Short-term Financing - In October 2018, we exercised a one-year extension on the ONE Gas Credit Agreement. The ONE Gas Credit Agreement remains a $700 million revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We are able to request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2023, and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At March 31, 2019, our total debt-to-capital ratio was 43 percent, and we were in compliance with all covenants under the ONE Gas Credit Agreement.

We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

At March 31, 2019, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement. At March 31, 2019, we had approximately $19.6 million of cash and cash equivalents and $698.8 million of remaining credit available under the ONE Gas Credit Agreement.

We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor. At March 31, 2019, we had $295.5 million of commercial paper outstanding. The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary.

Long-Term Debt - In November 2018, we issued $400 million of 4.50 percent senior notes due 2048. The proceeds from the issuance were used to retire the $300 million 2.07 percent senior notes due 2019, to reduce the amount of outstanding commercial paper and for general corporate purposes.

The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full. At March 31, 2019, our long-term debt-to-capital ratio was 38 percent.

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Credit Ratings - Our credit ratings as of March 31, 2019, were:
Rating Agency
Rating
Outlook
Moody’s
A2
Stable
S&P
A
Stable

Our commercial paper is currently rated Prime-1 by Moody’s and A-1 by S&P. We intend to maintain strong credit metrics while we pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

Pension and Other Postemployment Benefit Plans - Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 12 of the Notes to the Consolidated Financial Statements in our Annual Report. See Note 10 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.

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 impact net income but may not result in actual cash receipts or payments and changes in our assets and liabilities not classified as investing or financing activities during the period. Items that impact net income but may not result in actual cash receipts or payments include, but are not limited to, depreciation and amortization, deferred income taxes, share-based compensation expense and provision for doubtful accounts.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
 
Three Months Ended
 
 
 
March 31,
 
Variance
 
2019
 
2018
 
2019 vs. 2018
 
(Millions of dollars)
Total cash provided by (used in):
 
 
 
 
 
Operating activities
$
122.3

 
$
223.3

 
$
(101.0
)
Investing activities
(86.3
)
 
(86.6
)
 
0.3

Financing activities
(37.7
)
 
(106.6
)
 
68.9

Change in cash and cash equivalents
(1.7
)
 
30.1

 
(31.8
)
Cash and cash equivalents at beginning of period
21.3

 
14.4

 
6.9

Cash and cash equivalents at end of period
$
19.6

 
$
44.5

 
$
(24.9
)

Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information and changes in working capital. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

Operating cash flows were lower for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to working capital changes resulting from the timing of customer collections, payments for natural gas purchases, and gas cost recoveries from our purchased gas cost mechanisms, which vary from period to period and vary with changes in commodity prices.

Investing Cash Flows - Cash used in investing activities was consistent for the three months ended March 31, 2019, compared with the prior period.

Financing Cash Flows - Cash used in financing activities decreased for the three months ended March 31, 2019, compared with the prior period, due primarily to smaller repayments of notes payable in the current period.


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ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. 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. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three months ended March 31, 2019 and 2018.

We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites contain contaminants generally associated with MGP sites and are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. During the first quarter 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. We are also finalizing a study of the feasibility of various options to address the remainder of the site.

With regard to one of our former MGP sites in Kansas, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. In 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. We have submitted a remediation plan to the KDHE for this site. The KDHE is currently reviewing our plan. In the second quarter of 2018, we revised our estimate of the potential costs associated with additional investigation and remediation to be in the range of $5.6 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded in the second quarter of 2018 an adjustment to the reserve of $1.6 million bringing the total to $5.6 million for this site, which also increased our regulatory asset pursuant to our AAO in Kansas.

In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, these 12 former MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC.  The agreement allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at these sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC issued an order approving the settlement agreement in November 2017. A regulatory asset of approximately $5.9 million was recorded for estimated costs that were accrued at January 1, 2017.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the Texas Commission on Environmental Quality, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Until the investigation is complete, we are unable to determine what, if any, active remediation will be

36


required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of contamination.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three months ended March 31, 2019 and 2018. A number of environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows. However, we do not expect expenditures for these matters to have a material adverse effect on our financial condition, results of operations or cash flows.

Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:

an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;
a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity-management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines.  The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The GPAC has met five times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The next GPAC meeting, scheduled in June 2019, will focus on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA announced they will split this NPRM into three separate final rulemakings:

the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and
the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.

A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and gathering pipelines. The timing of each final rule being published is unknown, but they are expected to be published during 2019. The potential capital and operating expenditures associated with compliance with the proposed rules are currently being evaluated and could be significant depending on the final regulations.


37


Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations promulgated thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. We do not expect that these expenditures will have a material impact on our respective results of operations, financial position or cash flows. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to regulate greenhouse gas emissions. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted for natural gas distribution that assesses any costs, fees or expenses on any of these emissions.

CERCLA - CERCLA, also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) that caused and/or contributed to the release of a hazardous substance into the environment. These persons include, but are not limited to, the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. We do not expect that our responsibilities under CERCLA will have a material impact on our respective results of operations, financial position or cash flows.

Pipeline Security - The U.S. Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in March 2018. Our pipeline facilities have been reviewed according to the current guidelines and no material changes have been required to date.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (1) developing and maintaining an accurate greenhouse gas emissions inventory according to current rules issued by the EPA; (2) improving the integrity of our various pipelines; and (3) utilizing practices to reduce the loss of methane from our facilities.

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Additionally, in March 2016, we were one of 40 founding partners to launch the EPA’s Natural Gas STAR Methane Challenge Program, whereby oil and natural gas companies agree to promote and track commitments to reduce methane emissions beyond what is federally required. Our Methane Challenge Program commitment to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe aligns with our planned system integrity expenditures for infrastructure replacements. We exceeded our goal by achieving an overall replacement rate between six and seven percent in both 2017 and 2016. We anticipate reporting in 2019 our calendar year 2018 performance relative to our commitment.

Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 13 of the Notes to the Consolidated Financial Statements in this Quarterly Report.

Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional information regarding our regulatory initiatives in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards, if any, is included in Note 1 of the Notes to the Consolidated Financial Statements in this Quarterly Report.

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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 revenues 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 within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act.  The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, 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 the Private Securities Litigation Reform Act of 1995.  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,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Quarterly Report.  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:

our ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our regulated rates;
our ability to manage our operations and maintenance costs;
changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
the economic climate and, particularly, its effect on the natural gas requirements of our residential and commercial industrial customers;
competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power, geothermal energy and biofuels;
conservation and energy storage efforts of our customers;
variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate change;
indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors;
<
our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of existing supply and transportation and storage arrangements that are not replaced with contracts with similar terms and pricing;