10-Q 1 onegas10-qx6302018.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 June 30, 2018.
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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
Yes X No __

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 __ 
(Do not check if a smaller reporting company)
 
 
 
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 July 24, 2018, the Company had 52,517,758 shares of common stock outstanding.




























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ONE Gas, Inc.
TABLE OF CONTENTS
Financial Information
Page No.
 
Consolidated Statements of Income - Three and Six Months Ended June 30, 2018 and 2017
 
Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2018 and 2017
 
Consolidated Balance Sheets - June 30, 2018 and December 31, 2017
 
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2018 and 2017
 
Consolidated Statement of Equity - Six Months Ended June 30, 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.


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INFORMATION AVAILABLE ON OUR WEBSITE

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

We also use Twitter®, LinkedIn® and Facebook® as additional channels of distribution to reach public investors. Information contained on our website, posted on our Facebook® page or disseminated through Twitter® or LinkedIn®, and any corresponding applications, are not incorporated by reference into this report.

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


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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, 2017
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
Texas Gas Reliability Infrastructure Program
GSRS
Kansas 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

KCC
Kansas Corporation Commission
KDHE
Kansas Department of Health and Environment
LDC
Local distribution company
MGP
Manufactured Gas Plant
MMcf
Million cubic feet
Moody’s
Moody’s Investors Service, Inc.
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, 2022
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
RRC
Railroad Commission of Texas
S&P
Standard & Poor’s Ratings Services
SAB
Staff Accounting Bulletin
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Senior Notes
ONE Gas’ registered notes consisting of $300 million of 2.07 percent senior notes due 2019, $300 million of 3.61 percent senior notes due 2024 and $600 million of 4.658 percent notes due 2044

Separation and Distribution Agreement
Separation and Distribution Agreement dated January 14, 2014, between ONEOK
and ONE Gas
WNA
Weather-normalization adjustments
XBRL
eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
ONE Gas, Inc.

 

 
 
 
 
 
CONSOLIDATED STATEMENTS OF INCOME

 

 
 
 
 
 


Three Months Ended
 
Six Months Ended
 

June 30,
 
June 30,
(Unaudited)

2018

2017
 
2018
 
2017


(Thousands of dollars, except per share amounts)
Revenues
 
 
 
 
 
 
 
 
Revenues from contracts with customers

$
291,168


$
274,033

 
$
926,405

 
$
810,193

Other revenues
 
1,353

 
5,656

 
4,580

 
19,904

Total revenues
 
292,521

 
279,689

 
930,985

 
830,097

Cost of natural gas

94,159


82,572

 
444,578

 
345,726

Net margin
 
198,362

 
197,117

 
486,407

 
484,371

 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Operations and maintenance

102,995


96,928

 
205,660

 
201,972

Depreciation and amortization

39,757


37,851

 
78,647

 
74,870

General taxes

14,567


13,973

 
30,767

 
29,719

Total operating expenses

157,319


148,752

 
315,074

 
306,561

Operating income

41,043


48,365

 
171,333

 
177,810

Other expense, net

(2,194
)

(3,900
)
 
(4,358
)
 
(7,307
)
Interest expense, net

(12,003
)

(11,305
)
 
(24,355
)
 
(22,786
)
Income before income taxes

26,846


33,160

 
142,620

 
147,717

Income taxes

(6,427
)

(12,537
)
 
(31,366
)
 
(50,638
)
Net income

$
20,419


$
20,623

 
$
111,254

 
$
97,079








 
 
 
 
Earnings per share






 
 
 
 
Basic

$
0.39


$
0.39

 
$
2.11

 
$
1.85

Diluted

$
0.39


$
0.39

 
$
2.10

 
$
1.83








 
 
 
 
Average shares (thousands)






 
 
 
 
Basic

52,692


52,553

 
52,648

 
52,565

Diluted

52,899


52,969

 
52,898

 
53,012

Dividends declared per share of stock

$
0.46


$
0.42

 
$
0.92

 
$
0.84

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(Unaudited)
2018
 
2017
 
2018
 
2017
 
(Thousands of dollars)
Net income
$
20,419

 
$
20,623

 
$
111,254

 
$
97,079

Other comprehensive income (loss), net of tax
 

 
 

 
 

 
 

Change in pension and other postemployment benefit plan liability, net of tax of $(68), $(81), $(419) and $(161), respectively
203

 
129

 
123

 
258

Total other comprehensive income (loss), net of tax
203

 
129

 
123

 
258

Comprehensive income
$
20,622

 
$
20,752

 
$
111,377

 
$
97,337

See accompanying Notes to Consolidated Financial Statements.


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ONE Gas, Inc.
 
 
 
 
CONSOLIDATED BALANCE SHEETS
 
 
 
 
 
 
 
 
 
 
 
June 30,
 
December 31,
(Unaudited)
 
2018
 
2017
Assets
 
(Thousands of dollars)
Property, plant and equipment
 
 

 
 

Property, plant and equipment
 
$
5,870,814

 
$
5,713,912

Accumulated depreciation and amortization
 
1,745,124

 
1,706,327

Net property, plant and equipment
 
4,125,690

 
4,007,585

Current assets
 
 
 
 
Cash and cash equivalents
 
12,580

 
14,413

Accounts receivable, net
 
163,967

 
298,768

Materials and supplies
 
36,124

 
39,672

Natural gas in storage
 
80,482

 
130,154

Regulatory assets
 
39,402

 
88,180

Other current assets
 
18,154

 
17,807

Total current assets
 
350,709

 
588,994

Goodwill and other assets
 
 

 
 

Regulatory assets
 
385,564

 
405,189

Goodwill
 
157,953

 
157,953

Other assets
 
48,003

 
47,157

Total goodwill and other assets
 
591,520

 
610,299

Total assets
 
$
5,067,919

 
$
5,206,878

See accompanying Notes to Consolidated Financial Statements.


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ONE Gas, Inc.
 
 
 
 
CONSOLIDATED BALANCE SHEETS
 
 
 
 
(Continued)
 
 
 
 
 
 
June 30,
 
December 31,
(Unaudited)
 
2018
 
2017
Equity and Liabilities
 
(Thousands of dollars)
Equity and long-term debt
 
 
 
 
Common stock, $0.01 par value:
authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,516,828 shares at June 30, 2018; issued 52,598,005 and outstanding 52,312,516 shares at December 31, 2017
 
$
526

 
$
526

Paid-in capital
 
1,723,795

 
1,737,551

Retained earnings
 
308,652

 
246,121

Accumulated other comprehensive income (loss)
 
(5,370
)
 
(5,493
)
Treasury stock, at cost: 81,177 shares at June 30, 2018 and 285,489 shares at December 31, 2017
 
(5,259
)
 
(18,496
)
   Total equity
 
2,022,344

 
1,960,209

Long-term debt, excluding current maturities, and net of issuance costs of $7,614 and $8,033, respectively
 
893,671

 
1,193,257

Total equity and long-term debt

2,916,015


3,153,466

Current liabilities
 
 
 
 
Current maturities of long-term debt
 
300,008

 
8

Notes payable
 
185,000

 
357,215

Accounts payable
 
70,429

 
143,681

Accrued interest
 
19,028

 
18,776

Accrued taxes other than income
 
34,931

 
41,324

Accrued liabilities
 
20,724

 
30,058

Regulatory liabilities
 
47,867

 
9,438

Customer deposits
 
61,249

 
60,811

Other current liabilities
 
10,102

 
12,019

Total current liabilities
 
749,338

 
673,330

Deferred credits and other liabilities
 
 

 
 

Deferred income taxes
 
628,532

 
599,945

Regulatory liabilities
 
521,717

 
519,421

Employee benefit obligations
 
160,382

 
172,938

Other deferred credits
 
91,935

 
87,778

Total deferred credits and other liabilities
 
1,402,566

 
1,380,082

Commitments and contingencies
 


 


Total liabilities and equity
 
$
5,067,919

 
$
5,206,878

See accompanying Notes to Consolidated Financial Statements.



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ONE Gas, Inc.
 
 
 
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
Six Months Ended
 
 
June 30,
(Unaudited)
 
2018
 
2017
 
 
(Thousands of dollars)
Operating activities
 
 
 
 
Net income
 
$
111,254

 
$
97,079

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
78,647

 
74,870

Deferred income taxes
 
30,546

 
50,308

Share-based compensation expense
 
4,080

 
4,951

Provision for doubtful accounts
 
4,071

 
3,501

Changes in assets and liabilities:
 
 

 
 
Accounts receivable
 
130,730

 
135,165

Materials and supplies
 
3,548

 
(2,792
)
Natural gas in storage
 
49,672

 
10,436

Asset removal costs
 
(25,774
)
 
(22,837
)
Accounts payable
 
(68,428
)
 
(68,992
)
Accrued interest
 
252

 
104

Accrued taxes other than income
 
(6,393
)
 
(9,009
)
Accrued liabilities
 
(9,334
)
 
(6,729
)
Customer deposits
 
438

 
(686
)
Regulatory assets and liabilities
 
105,967

 
19,782

Other assets and liabilities
 
(9,319
)
 
(5,880
)
Cash provided by operating activities
 
399,957

 
279,271

Investing activities
 
 

 
 

Capital expenditures
 
(175,834
)
 
(154,666
)
Other
 

 
477

Cash used in investing activities
 
(175,834
)
 
(154,189
)
Financing activities
 
 

 
 

Repayments of notes payable, net
 
(172,215
)
 
(66,000
)
Repurchase of common stock
 

 
(17,512
)
Issuance of common stock
 
2,390

 
2,208

Dividends paid
 
(48,272
)
 
(44,042
)
Tax withholdings related to net share settlements of stock compensation
 
(7,859
)
 
(9,286
)
Cash used in financing activities
 
(225,956
)
 
(134,632
)
Change in cash and cash equivalents
 
(1,833
)
 
(9,550
)
Cash and cash equivalents at beginning of period
 
14,413

 
14,663

Cash and cash equivalents at end of period
 
$
12,580

 
$
5,113

See accompanying Notes to Consolidated Financial Statements.


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ONE Gas, Inc.
 
 
 
 
CONSOLIDATED STATEMENT OF EQUITY
 
 
 
 
 
 
 
 
 
(Unaudited)
 
Common Stock Issued
Common Stock
Paid-in Capital
 
 
(Shares)
(Thousands of dollars)
 
 
 
 
 
January 1, 2018
 
52,598,005

$
526

$
1,737,551

Net income
 



Other comprehensive income
 



Common stock issued and other
 


(14,207
)
Common stock dividends - $0.92 per share
 


451

June 30, 2018
 
52,598,005

$
526

$
1,723,795

See accompanying Notes to Consolidated Financial Statements.



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ONE Gas, Inc.
 
 
 
 
 
CONSOLIDATED STATEMENT OF EQUITY
 
 
 
(Continued)
 
 
 
 
 
(Unaudited)
 
Retained Earnings
Treasury Stock
Accumulated Other Comprehensive Income (Loss)
Total Equity
 
 
(Thousands of dollars)
 
 
 
 
 
 
January 1, 2018
 
$
246,121

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

Net income
 
111,254



111,254

Other comprehensive income
 


123

123

Common stock issued and other
 

13,237


(970
)
Common stock dividends - $0.92 per share
 
(48,723
)


(48,272
)
June 30, 2018
 
$
308,652

$
(5,259
)
$
(5,370
)
$
2,022,344

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 2017 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 and six months ended June 30, 2018, are not necessarily indicative of the results that may be expected for a 12-month period.

We provide natural gas distribution services to more than 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. In addition, we also provide natural gas distribution services to wholesale and public authority customers. In 2017, we formed a wholly-owned captive insurance company in the state of Oklahoma to provide insurance to our divisions.

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, wholesale, public authority 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 and six months ended June 30, 2018, and 2017, we had no single external customer from which we received 10 percent or more of our gross revenues.

Recently Issued Accounting Standards Update - In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,” which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period. See Note 10 for additional discussion regarding SAB 118.

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. The new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard, but do not expect a material impact to our consolidated financial statements.

In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and

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(3) reporting of the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization for GAAP, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities.

We adopted this guidance in the first quarter of 2018. The presentation changes required for net periodic benefit costs did not impact previously reported net income; however, the reclassification of the other components of benefits costs resulted in an increase in operating income and an increase in other expenses of $2.4 million and $4.3 million for the three months ended June 30, 2018 and 2017, respectively, and an increase in operating income and other expenses of $4.1 million and $8.6 million for the six months ended June 30, 2018 and 2017, respectively. We elected the practical expedient to use the retroactive presentation of the amounts disclosed for the various components of net benefit cost in our Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we updated our information systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification.

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),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements.  A modified retrospective transition approach is required for leases existing at the time of adoption. The FASB has issued multiple practical expedients that may be elected, but must be elected as a package and applied consistently to all leases.  These practical expedients allow lessees and lessors 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.  The FASB has also issued several practical expedients that may be elected separately or in conjunction with the previously mentioned practical expedients.  These practical expedients allow (1) lessees to not separate nonlease components from lease components and instead account for each separate lease component and the nonlease components associated with that lease component as a single lease component and (2) lessees and lessors to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.  These expedients are only for leases in place at the transition date and cannot be applied to leases that are modified. At this time, we are evaluating these expedients.

In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842)” to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements to provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easement and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption.

In July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842) Targeted Improvements” which provides entities with 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. The amendment also provides a practical expedient for lessors. At this time, we are evaluating these expedients.

We are continuing to evaluate our population of leases, analyze lease agreements, and hold meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. While we are currently evaluating the full impact of the standard, we expect to recognize additional assets and liabilities arising from current operating leases to our financial position upon adoption. We will adopt this new guidance in the first quarter of 2019.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. We have evaluated all of our sources of revenue to determine the effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We adopted this new guidance in the first quarter 2018, using the modified

15


retrospective method. Our adoption did not result in a cumulative adjustment to our opening retained earnings. Our adoption resulted in a reclassification of certain revenues associated with certain regulatory mechanisms that do not meet the requirements under ASC 606 as revenue from contracts with customers, but will continue to be reflected as other revenues in determining total revenues. The reclassified revenues relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we reflect variations in weather in our rates billed to customers. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is delivered and simultaneously consumed. The majority of our revenues that meet the requirements under ASC 606 are considered implied contracts, as established by our tariff rates approved by regulatory authorities. Our sources of revenue are disaggregated by natural gas sales (including sales to residential, commercial, industrial, wholesale and public authority customers), transportation revenues, and other utility revenues, which are primarily one-time service fees, that meet the requirements under ASC 606. The reclassification of certain revenues that do not meet the requirements under ASC 606 have been classified as other revenues on the Consolidated Income Statement and in our Notes to Consolidated Financial Statements. Additionally, for our natural gas sales and transportation revenues, our customers receive 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 and consumes the natural gas. For our other utility revenues, the performance obligation of one-time services are satisfied at a point in time when services are rendered to the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice.

See Note 2 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.

2.
REVENUE
 
The following table sets forth our revenues disaggregated by source for the periods indicated:
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(Thousands of dollars)
Natural gas sales to customers
 
$
261,347

 
$
247,494

 
$
856,273

 
$
747,663

Transportation revenues
 
24,062

 
21,343

 
57,605

 
51,549

Miscellaneous revenues
 
5,759

 
5,196

 
12,527

 
10,981

Total revenues from contracts with customers
 
291,168

 
274,033

 
926,405

 
810,193

Other revenues - natural gas sales related
 
(1,108
)
 
3,377

 
(78
)
 
15,540

Other revenues
 
2,461

 
2,279

 
4,658

 
4,364

Total other revenues
 
1,353

 
5,656

 
4,580

 
19,904

Total revenues
 
$
292,521

 
$
279,689

 
$
930,985

 
$
830,097


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 and includes residential, commercial, industrial, wholesale and public authority customers. 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.

Our miscellaneous revenues from contracts with customers represent implied contracts established by our tariff rates approved by the regulatory authorities and includes miscellaneous service charges 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 under ASC 606 as revenue from contracts with customers, but authorize us to accrue revenues earned based on tariffs approved by the regulatory authorities. Total other revenues primarily reflect our natural gas sales related 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 have elected to use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice for our natural gas sales, transportation revenues and other utility revenues. For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenue upon the delivery of the 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. Revenue is accrued for natural gas delivered and services rendered to

16


customers, but not yet billed. 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 June 30, 2018 and December 31, 2017, were $52.0 million and $138.5 million, respectively.

We collect and remit other taxes on behalf of government authorities, and we record these amounts in accrued taxes other than income in our Consolidated Balance Sheets on a net basis.

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, our cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Our revenues will fluctuate with the cost of gas that we purchase.

3.
REGULATORY ASSETS AND LIABILITIES

The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
 
 
 
 
June 30, 2018
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
6,741

 
$

 
$
6,741

Pension and postemployment benefit costs
 

 
25,109

 
367,751

 
392,860

Reacquired debt costs
 

 
812

 
6,892

 
7,704

MGP remediation costs
 
 
 

 
7,724

 
7,724

Ad valorem tax
 
 
 
662

 

 
662

Other
 

 
6,078

 
3,197

 
9,275

Total regulatory assets, net of amortization
 
 
 
39,402

 
385,564

 
424,966

Federal income tax rate changes (a)
 
 
 
(16,183
)
 
(521,717
)
 
(537,900
)
Over-recovered purchased-gas costs
 

 
(31,457
)
 

 
(31,457
)
Weather normalization
 
 
 
(227
)
 

 
(227
)
Total regulatory liabilities
 
 
 
(47,867
)
 
(521,717
)
 
(569,584
)
Net regulatory assets (liabilities)
 
 
 
$
(8,465
)
 
$
(136,153
)
 
$
(144,618
)
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.
 
 
 
 
December 31, 2017
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
41,238

 
$

 
$
41,238

Pension and postemployment benefit costs
 

 
25,156

 
387,582

 
412,738

Weather normalization
 
 
 
17,461

 

 
17,461

Reacquired debt costs
 

 
812

 
7,298

 
8,110

MGP remediation costs
 
 
 

 
6,104

 
6,104

Other
 

 
3,513

 
4,205

 
7,718

Total regulatory assets, net of amortization
 
 
 
88,180

 
405,189

 
493,369

Federal income tax rate changes (a)
 
 
 

 
(519,421
)
 
(519,421
)
Over-recovered purchased-gas costs
 

 
(9,434
)
 

 
(9,434
)
Ad valorem tax
 
 
 
(4
)
 

 
(4
)
Total regulatory liabilities
 
 
 
(9,438
)
 
(519,421
)
 
(528,859
)
Net regulatory assets (liabilities)
 
 
 
$
78,742

 
$
(114,232
)
 
$
(35,490
)
(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.

Regulatory assets on our Consolidated Balance Sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates 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

17


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

The ONE Gas Credit Agreement is a $700 million revolving unsecured credit facility. 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 2022, 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 June 30, 2018, our total debt-to-capital ratio was 41 percent and we were in compliance with all covenants 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.

The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement.

At June 30, 2018, we had $185.0 million of commercial paper with no borrowings and $514.2 million of remaining credit available under the ONE Gas Credit Agreement.

5.
LONG-TERM DEBT

We have senior notes consisting of $300 million of 2.07 percent senior notes due in 2019, $300 million of 3.61 percent senior notes due in 2024 and $600 million of 4.658 percent senior notes due in 2044. 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.

6.
EQUITY

Dividends Declared - In July 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of August 13, 2018, payable September 4, 2018.


18


7.
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Consolidated Statements of Income for the periods indicated:
 
 
Three Months Ended
 
Six Months Ended
 
Affected Line Item in the
Details about Accumulated Other
 
June 30,
 
June 30,
 
 Consolidated Statements
Comprehensive Income (Loss) Components
 
2018
2017
 
2018
2017
 
of Income
 
 
(Thousands of dollars)
 
 
Pension and other postemployment benefit plan obligations (a)
 
 
 
 
 
 
 
 
Amortization of net loss
 
$
10,950

$
10,648

 
$
21,900

$
21,296

 
 
Amortization of unrecognized prior service cost
 
(1,142
)
(1,149
)
 
(2,284
)
(2,298
)
 
 
 
 
9,808

9,499

 
19,616

18,998

 
 
Regulatory adjustments (b)
 
(9,537
)
(9,289
)
 
(19,074
)
(18,579
)
 
 
 
 
271

210

 
542

419

 
Income before income taxes
 
 
(68
)
(81
)
 
(419
)
(161
)
 
Income tax expense
Total reclassifications for the period
 
$
203

$
129

 
$
123

$
258

 
Net income
(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 9 for additional detail of our net periodic benefit cost.
(b) 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.

8.
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 June 30, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
20,419

 
52,692

 
$
0.39

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
207

 
 

Net income available for common stock and common stock equivalents
$
20,419

 
52,899

 
$
0.39


 
Three Months Ended June 30, 2017
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
20,623

 
52,553

 
$
0.39

Diluted EPS Calculation
 
 
 

 
 

Effect of dilutive securities

 
416

 
 

Net income available for common stock and common stock equivalents
$
20,623

 
52,969

 
$
0.39



19


 
Six Months Ended June 30, 2018
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
111,254

 
52,648

 
$
2.11

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
250

 
 

Net income available for common stock and common stock equivalents
$
111,254

 
52,898

 
$
2.10


 
Six Months Ended June 30, 2017
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
97,079

 
52,565

 
$
1.85

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
447

 
 

Net income available for common stock and common stock equivalents
$
97,079

 
53,012

 
$
1.83


9.
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
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
2017
 
2018
2017
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
 
 
 
Service cost
$
3,230

$
3,044

 
$
6,460

$
6,088

Interest cost (a)
9,200

10,113

 
18,400

20,226

Expected return on assets (a)
(15,145
)
(14,624
)
 
(30,290
)
(29,248
)
Amortization of net loss (a)
9,978

9,027

 
19,956

18,054

Net periodic benefit cost
$
7,263

$
7,560

 
$
14,526

$
15,120

(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense).

 
Other Postemployment Benefits
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
2017
 
2018
2017
 
(Thousands of dollars)
Components of net periodic benefit (credit) cost
 
 
 
 
 
Service cost
$
589

$
627

 
$
1,178

$
1,254

Interest cost (a)
2,279

2,472

 
4,558

4,944

Expected return on assets (a)
(3,571
)
(3,147
)
 
(7,142
)
(6,294
)
Amortization of unrecognized prior service cost (a)
(1,142
)
(1,149
)
 
(2,284
)
(2,298
)
Amortization of net loss (a)
972

1,621

 
1,944

3,242

Net periodic benefit (credit) cost
$
(873
)
$
424

 
$
(1,746
)
$
848

(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense).


20


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 and six months ended June 30, 2018.

Upon 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 Topic 980 (Regulated Operations) for rate regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. See Note 3 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.

10.
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.

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

Tax Reform - In December 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. Substantially all of the provisions of the new law are effective for taxable years beginning after December 31, 2017. The new law includes significant changes to the Code, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated utilities. The more significant changes that impact us include reductions in the corporate federal statutory income tax rate to 21 percent from 35 percent, and several technical provisions including, among others, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, the continuation of certain rate normalization requirements for accelerated depreciation benefits and the general allowance for the continued deductibility of interest expense. Additionally, the new law limits the utilization of NOLs arising after December 31, 2017, to 80 percent of taxable income with an indefinite carryforward.

The staff of the SEC issued guidance in SAB 118 which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one-year period in which to complete the required analyses and accounting. 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, 2017, consolidated financial statements. We are still analyzing certain aspects of the Tax Cuts and Jobs Act of 2017, refining our calculations and expect additional guidance from the U.S. Department of the Treasury and the Internal Revenue Service. 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.

Reductions in our ADIT balances to reflect the reduced corporate income tax rate of 21 percent will result in amounts previously collected from our customers for these deferred income taxes to be refunded to our customers. The Tax Cuts and Jobs Act of 2017 retains the provisions of the Code that stipulate how these excess deferred income taxes are to be refunded, as well as the timing of any such refunds, to customers for certain accelerated tax depreciation benefits. Potential refunds of these and other deferred income taxes will be determined by our regulators. At June 30, 2018, the regulatory liability associated with the remeasurement of our ADIT totaled $521.7 million.

We are working with our regulators in Oklahoma, Kansas and Texas to address the impact of the Tax Cuts and Jobs Act of 2017 on our rates. In each state, we have received accounting orders requiring us to refund the remeasurement of our ADIT 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 statutory income tax rate and the new 21 percent federal statutory income tax rate effective in January 2018. The establishment of this separate regulatory liability associated with the change in tax rates collected in our rates resulted in a reduction to our revenues of $9.2 million and $21.5 million for the three and six months ended June 30, 2018, respectively. The amount, period and timing of the return of these regulatory liabilities to our customers will be determined by the regulators in each of our jurisdictions.


21


11.
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
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(Thousands of dollars)
Net periodic benefit cost other than service cost
 
$
(2,403
)
 
$
(4,313
)
 
$
(4,137
)
 
$
(8,626
)
Other, net
 
209

 
413

 
(221
)
 
1,319

Total other income (expense), net
 
$
(2,194
)
 
$
(3,900
)
 
$
(4,358
)
 
$
(7,307
)

12.
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 and six months ended June 30, 2018 and 2017.

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.

We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. 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. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred. We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.

With regard to one of our former MGP sites, 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. Additional testing and work plan development continued in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. 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 an adjustment to the reserve of $1.6 million for this site in the second quarter of 2018, 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, the 12 former MGP sites which we own or retain responsibility for certain environmental conditions.

22


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 that are necessary for investigation and remediation at the 12 former MGP sites 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 have been accrued at January 1, 2017.

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 and six months ended June 30, 2018 and 2017. 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. 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. The next GPAC meeting, scheduled for September 2018, will focus on gas gathering. 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); and
the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering.

23


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 the first and second final rules 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.

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.

13.
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 recognized in, and
recoverable 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.

24



Derivative Instruments -  At June 30, 2018, we held purchased natural gas call options for the heating season ending March 31, 2019, with total notional amounts of 15.1 Bcf, for which we paid premiums of $3.6 million, and had a fair value of $3.8 million. At December 31, 2017, we held purchased natural gas call options for the heating season ended March 31, 2018, with total notional amounts of 14.1 Bcf, for which we paid premiums of $5.5 million, and had a fair value of $1.1 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 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 and six months ended June 30, 2018 and 2017.

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.

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 $1.2 billion at both June 30, 2018 and December 31, 2017. The estimated fair value of our long-term debt, including current maturities, was $1.2 billion and 1.3 billion at June 30, 2018 and December 31, 2017, respectively. The estimated fair value of our Senior Notes at June 30, 2018 and December 31, 2017, was determined using quoted market prices, and are classified as Level 2.

25




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 and six months ended June 30, 2018, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Tax Reform - In December 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. Substantially all the provisions of the new law are effective for taxable years beginning after December 31, 2017. The new law includes significant changes to the Code, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated utilities. The more significant changes that impact us include reductions in the corporate federal statutory income tax rate to 21 percent from 35 percent, and several technical provisions including, among others, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, the continuation of certain rate normalization requirements for accelerated depreciation benefits and the general allowance for the continued deductibility of interest expense. Additionally, the new law limits the utilization of NOLs arising after December 31, 2017, to 80 percent of taxable income with an indefinite carryforward.

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 provisions of the Code that stipulate how these excess deferred income taxes are to be refunded, as well as the timing of any such refunds, to customers for certain accelerated tax depreciation benefits. Potential refunds of these and other deferred income taxes will be determined by our regulators. At June 30, 2018, the regulatory liability associated with the remeasurement of our ADIT totaled $521.7 million.

We are working with our regulators in Oklahoma, Kansas and Texas to address the impact of the Tax Cuts and Jobs Act of 2017 on our rates. In each state, we have received accounting orders requiring us to refund the remeasurement of our ADIT 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 statutory income tax rate and the new 21 percent federal statutory income tax rate effective in January 2018. The establishment of this separate regulatory liability associated with the change in tax rates collected in our rates resulted in a reduction to our revenues of $9.2 million and $21.5 million for the three and six months ended June 30, 2018, respectively. The amount, period and timing of the return of these regulatory liabilities to our customers will be determined by the regulators in each of our jurisdictions.

See additional information on the impact of the Tax Cuts and Jobs Act of 2017 below under Regulatory Activities.

Dividend - In July 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of August 13, 2018, payable September 4, 2018.

REGULATORY ACTIVITIES

Oklahoma - On March 15, 2018, Oklahoma Natural Gas filed its second annual PBRC application following the general rate case that was approved in January 2016. This filing was based on a calendar test year of 2017. The PBRC filing identified a $5.6 million credit to base rates primarily due to the reduction in the corporate federal statutory income tax rate. If approved as filed, this credit will be applied to customers’ bills over a 12-month period following receipt of an order. The filing also requested an energy efficiency program true-up and utility incentive adjustment of approximately $2.1 million. A hearing before the administrative law judge was held on July 27, 2018, with an order expected in the third quarter of 2018. 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 test year of 2020.


26


Kansas - 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. Kansas Gas Service’s request, if approved, represents a net base rate increase of $42.7 million. Kansas Gas Service is already recovering $2.9 million from customers through the GSRS, resulting in a total base rate increase of $45.6 million. The filing is based on a 10.0 percent return on equity and a 62.2 percent common equity ratio. The filing represents a rate base of $1 billion, compared with $947 million included in existing base rates plus previously approved GSRS-eligible investments. Since the last general rate case in 2016, Kansas Gas Service has invested $179 million in its natural gas distribution system. Benefits of the corporate income tax cuts associated with the Tax Cuts and Jobs Act of 2017 are also reflected in Kansas Gas Service’s filing. Kansas Gas Service’s filing includes a Revenue Normalization Adjustment that is designed to ensure that Kansas Gas Service collects the amount of revenue set by the KCC from residential, general sales and small transport customers, regardless of customer usage. In accordance with Kansas law, the KCC has 240 days to consider Kansas Gas Service’s filing.

In April 2018, a bill amending the GSRS statute was approved. Beginning January 1, 2019, the scope of projects eligible for recovery under the statute will include all investments to replace, upgrade or modernize obsolete facilities, as well as projects that enhance the integrity of pipeline system components or extend the useful life of such assets. Safety-related investments will also include expenditures for physical and cyber security. Additionally, the cap on the monthly residential surcharge will increase to 80 cents from 40 cents.

In August 2017, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.9 million related to its GSRS. In November 2017, the KCC approved the increase effective December 2017.

Texas - West Texas Service Area - 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 an increase of $3.5 million, and new rates became effective in July 2018.

In March 2017, Texas Gas Service made GRIP filings for all customers in the West Texas service area. The RRC and the cities approved an increase of $4.3 million, and new rates became effective in July 2017.

Rio Grande Valley Service Area - In April 2018, Texas Gas Service filed an annual COSA for the incorporated areas of the Rio Grande Valley service area. The cities approved an increase of $1.1 million, and new rates will become effective in August 2018.

In March 2018, the RRC approved an increase in base rates of $0.5 million for the unincorporated areas of the Rio Grande Valley service area, with new rates effective in April 2018. This rate case settlement reflects a corporate federal statutory income tax rate of 21 percent and required Texas Gas Service to calculate, defer and refund to customers $0.1 million associated with the changes to the corporate income tax rate for the period between January 1, 2018, and the implementation of the new rates in April 2018.

In June 2017, Texas Gas Service filed a rate case for customers in its Rio Grande Valley service area. In October 2017, Texas Gas Service and the cities in the Rio Grande Valley service area agreed to an increase of $3.6 million, and new rates became effective in October 2017.

Central Texas Service Area - 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 an increase of $3.3 million, and new rates became effective in July 2018.
 
In March 2017, Texas Gas Service made GRIP filings for all customers in the Central Texas service area. The cities and the RRC approved an increase of $4.9 million, and new rates became effective in June 2017.

North Texas Service Area - In June 2018, Texas Gas Service filed a rate case for customers in its North Texas service area for an increase of $1.0 million. If approved, new rates are expected to take effect in December 2018.

In April 2017, Texas Gas Service filed an annual COSA in its North Texas service area. In October 2017, Texas Gas Service and the cities in the North Texas service area agreed to an increase of $0.8 million, and new rates became effective in August 2017.

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

27


adjustments associated with these filings that were approved totaled $(0.7) million for the six months ended June 30, 2018 and $0.6 million for the year ended December 31, 2017.

Tax Reform - Oklahoma - In December 2017, the Oklahoma Attorney General filed a motion on behalf of customers in Oklahoma requesting that the OCC take action for an immediate reduction in rates and protection of rate payers’ interests. On January 9, 2018, the OCC approved an order directing Oklahoma Natural Gas to record a deferred liability beginning on the effective date of the order, January 9, 2018, to reflect the reduced federal corporate 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 directs 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 until issuance of a final order in the upcoming PBRC proceeding. This order also dismissed the Oklahoma Attorney General’s motion.

In compliance with the order, Oklahoma Natural Gas’ March 15, 2018, PBRC filing contains two deferred liabilities subject to review and potential refund. First, a regulatory liability has been established reflecting the revaluation of ADIT for the change in the federal corporate income tax rate. This liability will be returned to customers over an amortization period in compliance with tax normalization rules included in the Code, as amended. An additional $2.9 million liability, including interest, has been established for the estimated impact on customer rates of the reduced tax rate for the period between January 9, 2018, and the date new rates are expected to go into effect following receipt of an order in the PBRC filing. A hearing before the administrative law judge was held on July 27, 2018.

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 tax rate for its last KCC-approved revenue determination instead of the new lower federal corporate tax rate; (2) deferrals are to commence on the effective date of the new federal corporate 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 tax rates.

In March 2018, Kansas Gas Service reached a settlement with the KCC Staff and the Citizens’ Utility Ratepayer Board related to the impact of 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 agrees 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 corporate tax rate. The annual amount of the regulatory liability is $14.1 million, excluding interest. The agreement also established the interest rate to be applied as the customer deposit interest rate, currently 1.62 percent. The disposition of the actual amount to be refunded to customers will be determined by the KCC in its final order at the completion of Kansas Gas Service’s next general rate case filing. Through this agreement, Kansas Gas Service also established a regulatory liability to account for the revaluation of ADIT for the change in the federal corporate income tax rate. Issues regarding the treatment of this regulatory liability will also be determined in Kansas Gas Service’s next general rate proceeding. As part of the agreement, Kansas Gas Service is required to file a general rate case no later than 150 days from the date of a KCC order approving the settlement agreement. Kansas Gas Service filed a general rate case in June 2018.

In December 2017, Kansas Industrial Consumers (“KIC”) filed a complaint against all utilities asking the KCC to act to ensure that KIC members are not charged unreasonable rates because of the Tax Cuts and Jobs Act of 2017. In January 2018, the Citizens’ Utility Ratepayer Board filed a complaint stating that the change in tax rates requires the KCC to not only address the reduction in the corporate tax rate to 21 percent from 35 percent, but also excess ADIT. In March 2018, the KCC granted the Citizens’ Utility Ratepayer Board’s motion to dismiss its complaint.

Texas - In February 2018, the RRC issued an accounting order for determining how the impact of the Tax Cuts and Jobs Act of 2017 will be reflected in gas utility rates in Texas. Gas utilities were ordered to either file a new rate case or file to 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 is to be determined in the next rate case in each jurisdiction.


28


Central Texas Service Area - In March 2018, Texas Gas Service requested a $4.9 million decrease to rates for customers in the Central Texas service area due to the reduction of the corporate income tax rate, and a one-time refund of $2.5 million for the reduction in the corporate income tax rate for the period between January 1, 2018, to the date new rates are implemented. The request was approved by the RRC and the cities, and new rates became effective in July 2018.

West Texas Service Area - In March 2018, Texas Gas Service requested a $4.7 million decrease to rates for customers in the West Texas service area due to the reduction of the corporate income tax rate, and a one-time refund of $2.4 million for changes to the corporate income tax rate for the period between January 1, 2018, to the date new rates are implemented. The request was approved by the RRC and the cities, and new rates became effective in July 2018.

Rio Grande Valley Service Area - In March 2018, Texas Gas Service requested a $1.5 million decrease to rates for customers in the incorporated areas of the Rio Grande Valley service area due to the reduction of the corporate income tax rate, and a one-time refund of $0.4 million for changes to the corporate income tax rate for the period between January 1, 2018, to the implementation of new rates, which became effective in April 2018.

Gulf Coast Service Area - In April 2018, Texas Gas Service filed for a one-time refund of $0.6 million for changes to the corporate income tax rate for the period between January 1, 2018, to the implementation of new rates, which will become effective in August 2018.

See Liquidity and Capital Resources - Tax Reform for additional discussion of the Tax Cuts and Jobs Act of 2017.

OTHER

In 2017, we formed a wholly-owned captive insurance company in the state of Oklahoma to provide insurance to our divisions.


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, wholesale, public authority 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 June 30, 2018, net income was $20.4 million, or $0.39 per diluted share, compared with $20.6 million, or $0.39 per diluted share in the same period last year. For the six months ended June 30, 2018, net income was $111.3 million, or $2.10 per diluted share, compared with $97.1 million, or $1.83 per diluted share in the same period last year.

Our results for the three and six months ended June 30, 2018, reflect lower income tax expense due primarily to a $3.8 million and $20.0 million decrease, respectively, associated with the reduction in the federal statutory income tax rate to 21 percent in 2018 from 35 percent in 2017 as a result of the Tax Cuts and Jobs Act of 2017. This decrease is offset partially by the change in the tax benefits on vested long-term incentive awards which vested in the first quarter of 2018 compared to the awards that vested in the first quarter of 2017. The tax benefits on our vested long-term incentive awards are reflected in income tax expense due to the share-based compensation accounting standard adopted in the first quarter of 2017. The following table sets forth certain selected financial results for our operations for the periods indicated:
 
Three Months Ended
 
Six Months Ended
 
Three Months
 
Six Months
 
June 30,
 
June 30,
 
2018 vs. 2017
 
2018 vs. 2017
Financial Results
2018
 
2017
 
2018
 
2017
 
Increase (Decrease)
 
Increase (Decrease)
 
(Millions of dollars, except percentages)
Natural gas sales to customers
$
260.2

 
$
250.9

 
$
856.2

 
$
763.2

 
$
9.3

 
4
 %
 
$
93.0

 
12
 %
Transportation revenues
24.1

 
21.4

 
57.6

 
51.6

 
2.7

 
13
 %
 
6.0

 
12
 %
Cost of natural gas
94.2

 
82.5

 
444.6

 
345.7

 
11.7

 
14
 %
 
98.9

 
29
 %
Net margin, excluding other revenues
190.1

 
189.8

 
469.2

 
469.1

 
0.3

 
 %
 
0.1

 
 %
Other utility revenues
8.3

 
7.4

 
17.2

 
15.3

 
0.9

 
12
 %
 
1.9

 
12
 %
Net margin
198.4

 
197.2

 
486.4

 
484.4

 
1.2

 
1
 %
 
2.0

 
 %
Operating costs
117.6

 
110.9

 
236.4

 
231.7

 
6.7

 
6
 %
 
4.7

 
2
 %
Depreciation and amortization
39.8

 
37.9

 
78.7

 
74.9

 
1.9

 
5
 %
 
3.8

 
5
 %
Operating income
$
41.0

 
$
48.4

 
$
171.3

 
$
177.8

 
$
(7.4
)
 
(15
)%
 
$
(6.5
)
 
(4
)%
Capital expenditures
$
89.2

 
$
84.2

 
$
175.8

 
$
154.7

 
$
5.0

 
6
 %
 
$
21.1

 
14
 %

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. Natural gas sales includes residential, commercial, industrial, wholesale and public authority customers.

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.

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, our cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. As a result, changes in the cost of gas are offset by a corresponding change in revenues.

Net margin is comprised of total revenues less cost of natural gas. While our revenues will fluctuate with the cost of natural gas that we recover, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we believe net margin is a better indicator of our financial performance than total revenues, as it provides a useful and more relevant measure to analyze our financial performance. 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 our net margin, excluding other revenues, by type of customer, for the periods indicated:
 
Three Months Ended
 
Six Months Ended
 
Three Months
 
Six Months
Net Margin, Excluding Other
June 30,
 
June 30,
 
2018 vs. 2017
 
2018 vs. 2017
Revenues
2018
 
2017
 
2018
 
2017
 
Increase (Decrease)
 
Increase (Decrease)
Natural gas sales
(Millions of dollars, except percentages)
Residential
$
137.1

 
$
139.7

 
$
341.2

 
$
347.9

 
$
(2.6
)
 
(2
)%
 
$
(6.7
)
 
(2
)%
Commercial and industrial
27.5

 
27.5

 
67.2

 
66.4

 

 
 %
 
0.8

 
1
 %
Wholesale and public authority
1.4

 
1.2

 
3.2

 
3.2

 
0.2

 
17
 %
 

 
 %
Net margin on natural gas sales
166.0

 
168.4

 
411.6

 
417.5

 
(2.4
)
 
(1
)%
 
(5.9
)
 
(1
)%
Transportation revenues
24.1

 
21.4

 
57.6

 
51.6

 
2.7

 
13
 %
 
6.0

 
12
 %
Net margin, excluding other revenues
$
190.1

 
$
189.8

 
$
469.2

 
$
469.1

 
$
0.3

 
 %
 
$
0.1

 
 %

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. We believe that the combination of the significant residential component of our customer base, the fixed charge component of our sales margin and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:
 
Three Months Ended
 
Six Months Ended
 
Three Months
 
Six Months
 
June 30,
 
June 30,
 
2018 vs. 2017
 
2018 vs. 2017
Net Margin on Natural Gas Sales
2018
 
2017
 
2018
 
2017
 
Increase (Decrease)
 
Increase (Decrease)
Net margin on natural gas sales
(Millions of dollars, except percentages)
 
 
 
 
Fixed margin
$
137.7

 
$
141.5

 
$
274.1

 
$
280.7

 
$
(3.8
)
 
(3
)%
 
$
(6.6
)
 
(2
)%
Variable margin
28.3

 
26.9

 
137.5

 
136.8

 
1.4

 
5
 %
 
0.7

 
1
 %
Net margin on natural gas sales
$
166.0

 
$
168.4

 
$
411.6

 
$
417.5

 
$
(2.4
)
 
(1
)%
 
$
(5.9
)
 
(1
)%

Net margin increased $1.2 million for the three months ended June 30, 2018, compared with the same period last year, due primarily to the following:
an increase of $3.8 million from new rates in Texas and Kansas;
an increase of $2.4 million due to higher sales volumes, net of weather normalization, primarily from colder weather in 2018 compared with 2017;
an increase of $2.1 million due primarily to higher transportation volumes; and
an increase of $1.1 million in residential sales due primarily to net customer growth in Oklahoma and Texas; offset by
a decrease of $9.2 million related to the deferral of potential refund obligations associated with the Tax Cuts and Jobs Act of 2017.

Net margin increased $2.0 million for the six months ended June 30, 2018, compared with the same period last year, due primarily to the following:
an increase of $8.9 million from new rates in Texas and Kansas;
an increase of $4.8 million due to higher sales volumes, net of weather normalization, primarily from colder weather in 2018 compared with 2017;
an increase of $4.6 million due primarily to higher transportation volumes;
an increase of $2.4 million in residential sales due primarily to net customer growth in Oklahoma and Texas;
an increase of $1.1 million in rider and surcharge recoveries due to higher ad-valorem surcharge in Kansas, offset by higher regulatory amortization in depreciation and amortization expense below; and
an increase of $0.9 million due to the benefit of the retroactive 2017 compressed natural gas federal excise tax credit enacted in February 2018; offset by
a decrease of $21.5 million related to the deferral of potential refund obligations associated with the Tax Cuts and Jobs Act of 2017.

Operating costs increased $6.7 million for the three months ended June 30, 2018, compared with the same period last year, due primarily to the following:

31



an increase of $7.9 million in employee-related costs; offset by
a decrease of $1.3 million in outside service costs associated with pipeline maintenance activities.

Operating costs increased $4.7 million for the six months ended June 30, 2018, compared with the same period last year, due primarily to the following:

an increase of $7.9 million in employee-related costs; offset by
a decrease of $2.4 million in outside service costs associated with pipeline maintenance activities.

Depreciation and amortization expense increased $1.9 million and $3.8 million for the three and six months ended June 30, 2018, respectively, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed in service and an increase in the amortization of the ad-valorem surcharge rider in Kansas.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements, 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.

Capital expenditures increased $5.0 million and $21.1 million for the three and six months ended June 30, 2018, respectively, compared with the same periods last year, due primarily to increased system integrity activities and extending service to new areas.

Selected Operating Information - The following tables set forth certain selected operating information for the periods indicated:
 
 
Three Months Ended
Variances
 
 
June 30,
2018 vs. 2017
(in thousands)
 
2018
2017
Increase (Decrease)
Average Number of Customers
 
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Residential
 
798

586

624

2,008

794

584

619

1,997

4

2

5

11

Commercial and industrial
 
74

50

35

159

73

50

35

158

1



1

Wholesale and public authority
 


3

3



3

3





Transportation
 
5

6

1

12

5

6

1

12





Total customers
 
877

642

663

2,182

872

640

658

2,170

5

2

5

12


 
 
Six Months Ended
Variances
 
 
June 30,
2018 vs. 2017
(in thousands)
 
2018
2017
Increase (Decrease)
Average Number of Customers
 
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Residential
 
801

588

624

2,013

796

587

618

2,001

5

1

6

12

Commercial and industrial
 
74

50

35

159

74

50

35

159





Wholesale and public authority
 


3

3



3

3





Transportation
 
5

6

1

12

5

6

1

12





Total customers
 
880

644

663

2,187

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