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EX-31.2 - DINAN CERTIFICATION SECTION 302 - ONE Gas, Inc.ogsexhibit3123q10-q2016.htm
EX-32.2 - DINAN CERTIFICATION SECTION 906 - ONE Gas, Inc.ogsexhibit3223q10-q2016.htm
EX-32.1 - NORTON CERTIFICATION SECTION 906 - ONE Gas, Inc.ogsexhibit3213q10-q2016.htm
EX-31.1 - NORTON CERTIFICATION SECTION 302 - ONE Gas, Inc.ogsexhibit3113q10-q2016.htm


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

FORM 10-Q

X Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2016.
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, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer X             Accelerated filer __             Non-accelerated filer __             Smaller reporting company__

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

On October 25, 2016, the Company had 52,245,273 shares of common stock outstanding.





























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ONE Gas, Inc.
TABLE OF CONTENTS
Financial Information
Page No.
 
Statements of Income - Three and Nine Months Ended September 30, 2016 and 2015
 
Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2016 and 2015
 
Balance Sheets - September 30, 2016 and December 31, 2015
 
Statements of Cash Flows - Nine Months Ended September 30, 2016 and 2015
 
Statement of Equity - Nine Months Ended September 30, 2016
 
Notes to the 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 subsidiary, unless the context indicates otherwise.

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


3


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


4


GLOSSARY

The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2015
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
DOT
United States Department of Transportation
EPA
United States Environmental Protection Agency
EPARR
El Paso Annual Rate Review
EPS
Earnings per share
EPSA
El Paso Service Area
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
GRIP
Texas Gas Reliability Infrastructure Program
GSRS
Gas System Reliability Surcharge
Heating Degree Day or HDD

A measure designed to reflect the demand for energy needed for heating based on
  the extent to which the daily average temperature falls below a reference
  temperature for which no heating is required, usually 65 degrees Fahrenheit

KCC
Kansas Corporation Commission
KDHE
Kansas Department of Health and Environment
LDCs
Local distribution companies
MMcf
Million cubic feet
Moody’s
Moody’s Investors Service, Inc.
NYMEX
New York Mercantile Exchange
OCC
Oklahoma Corporation Commission
ONE Gas
ONE Gas, Inc.
ONE Gas Credit Agreement
ONE Gas’ $700 million revolving credit agreement, which expires January, 2019
ONEOK
ONEOK, Inc. and its subsidiaries
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
S&P Global Ratings
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Separation and Distribution Agreement
Separation and Distribution Agreement dated January 14, 2014, between ONEOK
and ONE Gas
XBRL
eXtensible Business Reporting Language


5


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

 

 




STATEMENTS OF INCOME

 

 






Three Months Ended

Nine Months Ended
 

September 30,

September 30,
(Unaudited)

2016

2015

2016

2015


(Thousands of dollars, except per share amounts)
Revenues

$
232,191


$
225,226


$
986,479


$
1,158,543

Cost of natural gas

52,253


54,724


344,439


548,226

Net margin

179,938


170,502


642,040


610,317

Operating expenses

 


 







Operations and maintenance

99,402


98,698


302,652


304,681

Depreciation and amortization

36,241


33,956


106,490


98,592

General taxes

13,403


12,897


42,311


41,818

Total operating expenses

149,046


145,551


451,453


445,091

Operating income

30,892


24,951


190,587


165,226

Other income

911


166


1,345


1,051

Other expense

(357
)

(1,884
)

(1,126
)

(2,840
)
Interest expense, net

(10,809
)

(11,233
)

(32,504
)

(33,592
)
Income before income taxes

20,637


12,000


158,302


129,845

Income taxes

(7,900
)

(4,629
)

(60,521
)

(50,017
)
Net income

$
12,737


$
7,371


$
97,781


$
79,828














Earnings per share












Basic

$
0.24


$
0.14


$
1.86


$
1.52

Diluted

$
0.24


$
0.14


$
1.85


$
1.50














Average shares (thousands)












Basic

52,453


52,408


52,452


52,627

Diluted

52,942


53,072


52,962


53,315

Dividends declared per share of stock

$
0.35


$
0.30


$
1.05


$
0.90

See accompanying Notes to the Financial Statements.

6


ONE Gas, Inc.
 
 
 
 
 
 
 
STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
(Unaudited)
2016
 
2015
 
2016
 
2015
 
(Thousands of dollars)
Net income
$
12,737

 
$
7,371

 
$
97,781

 
$
79,828

Other comprehensive income (loss), net of tax
 

 
 

 
 

 
 

Change in pension and other postemployment benefit plan liability, net of tax of $(72), $(88), $(217) and $(264), respectively
116

 
141

 
347

 
423

Total other comprehensive income (loss), net of tax
116

 
141

 
347

 
423

Comprehensive income
$
12,853

 
$
7,512

 
$
98,128

 
$
80,251

See accompanying Notes to the Financial Statements.


7



ONE Gas, Inc.
 
 
 
 
BALANCE SHEETS
 
 
 
 
 
 
 
 
 
 
 
September 30,
 
December 31,
(Unaudited)
 
2016
 
2015
Assets
 
(Thousands of dollars)
Property, plant and equipment
 
 

 
 

Property, plant and equipment
 
$
5,338,591

 
$
5,132,682

Accumulated depreciation and amortization
 
1,658,266

 
1,620,771

Net property, plant and equipment
 
3,680,325

 
3,511,911

Current assets
 
 
 
 
Cash and cash equivalents
 
4,513

 
2,433

Accounts receivable, net
 
105,060

 
216,343

Materials and supplies
 
30,098

 
33,325

Income tax receivable
 
6,952

 
38,877

Natural gas in storage
 
144,230

 
142,153

Regulatory assets
 
73,863

 
32,925

Other current assets
 
12,457

 
16,789

Total current assets
 
377,173

 
482,845

Goodwill and other assets
 
 

 
 

Regulatory assets
 
431,086

 
435,863

Goodwill
 
157,953

 
157,953

Other assets
 
47,142

 
46,193

Total goodwill and other assets
 
636,181

 
640,009

Total assets
 
$
4,693,679

 
$
4,634,765

See accompanying Notes to the Financial Statements.


8


ONE Gas, Inc.
 
 
 
 
BALANCE SHEETS
 
 
 
 
(Continued)
 
 
 
 
 
 
September 30,
 
December 31,
(Unaudited)
 
2016
 
2015
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 52,245,273 shares at
   September 30, 2016; issued 52,598,005 and outstanding 52,259,224 shares at December 31, 2015
 
$
526

 
$
526

Paid-in capital
 
1,748,965

 
1,764,875

Retained earnings
 
137,221

 
95,046

Accumulated other comprehensive income (loss)
 
(4,054
)
 
(4,401
)
Treasury stock, at cost: 352,732 shares at September 30, 2016 and 338,781 shares at December 31, 2015
 
(20,314
)
 
(14,491
)
   Total equity
 
1,862,344

 
1,841,555

Long-term debt, excluding current maturities and net of issuance costs of $9,051 and $9,645, respectively
 
1,192,248

 
1,191,660

Total equity and long-term debt

3,054,592


3,033,215

Current liabilities
 
 
 
 
Current maturities of long-term debt
 
7

 
7

Notes payable
 
41,000

 
12,500

Accounts payable
 
70,562

 
107,482

Accrued interest
 
7,691

 
18,873

Accrued taxes other than income
 
39,919

 
37,249

Accrued liabilities
 
17,812

 
31,470

Customer deposits
 
60,425

 
60,325

Regulatory liabilities
 
13,204

 
24,615

Other current liabilities
 
8,212

 
11,700

Total current liabilities
 
258,832

 
304,221

Deferred credits and other liabilities
 
 

 
 

Deferred income taxes
 
1,011,691

 
951,785

Employee benefit obligations
 
291,230

 
272,309

Other deferred credits
 
77,334

 
73,235

Total deferred credits and other liabilities
 
1,380,255

 
1,297,329

Commitments and contingencies
 


 


Total liabilities and equity
 
$
4,693,679

 
$
4,634,765

See accompanying Notes to the Financial Statements.



9



























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10


ONE Gas, Inc.
 
 
 
 
STATEMENTS OF CASH FLOWS
 
 
 
 
Nine Months Ended
 
 
September 30,
(Unaudited)
 
2016
 
2015
 
 
(Thousands of dollars)
Operating activities
 
 
 
 
Net income
 
$
97,781

 
$
79,828

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
106,490

 
98,592

Deferred income taxes
 
59,771

 
19,384

Share-based compensation expense
 
9,341

 
3,863

Provision for doubtful accounts
 
3,521

 
2,951

Changes in assets and liabilities:
 
 

 
 

Accounts receivable
 
107,762

 
220,392

Materials and supplies
 
3,227

 
(5,889
)
Income tax receivable
 
31,925

 
20,075

Natural gas in storage
 
(2,077
)
 
25,388

Asset removal costs
 
(40,715
)
 
(33,744
)
Accounts payable
 
(32,923
)
 
(104,948
)
Accrued interest
 
(11,182
)
 
(11,225
)
Accrued taxes other than income
 
2,670

 
(4,313
)
Accrued liabilities
 
(13,658
)
 
(8,019
)
Customer deposits
 
100

 
(1,672
)
Regulatory assets and liabilities
 
(18,726
)
 
64,368

Other assets and liabilities
 
(21,877
)
 
(15,493
)
Cash provided by operating activities
 
281,430

 
349,538

Investing activities
 
 

 
 

Capital expenditures
 
(231,336
)
 
(199,678
)
Other
 
492

 

Cash used in investing activities
 
(230,844
)
 
(199,678
)
Financing activities
 
 

 
 

Borrowings (repayments) of notes payable, net
 
28,500

 
(42,000
)
Repurchase of common stock
 
(24,066
)
 
(24,122
)
Issuance of common stock
 
1,983

 
4,471

Dividends paid
 
(54,923
)
 
(47,178
)
Cash used in financing activities
 
(48,506
)
 
(108,829
)
Change in cash and cash equivalents
 
2,080

 
41,031

Cash and cash equivalents at beginning of period
 
2,433

 
11,943

Cash and cash equivalents at end of period
 
$
4,513

 
$
52,974

See accompanying Notes to the Financial Statements.


11


ONE Gas, Inc.
 
 
 
 
STATEMENT OF EQUITY
 
 
 
 
 
 
 
 
 
(Unaudited)
 
Common Stock Issued
Common Stock
Paid-in Capital
 
 
(Shares)
(Thousands of dollars)
 
 
 
 
 
January 1, 2016
 
52,598,005

$
526

$
1,764,875

Net income
 



Other comprehensive income
 



Repurchase of common stock
 



Common stock issued and other
 


(16,593
)
Common stock dividends - $1.05 per share
 


683

September 30, 2016
 
52,598,005

$
526

$
1,748,965

See accompanying Notes to the Financial Statements.



12


ONE Gas, Inc.
 
 
 
 
 
STATEMENT OF EQUITY
 
 
 
(Continued)
 
 
 
 
 
(Unaudited)
 
Retained Earnings
Treasury Stock
Accumulated Other Comprehensive Income (Loss)
Total Equity
 
 
(Thousands of dollars)
 
 
 
 
 
 
January 1, 2016
 
$
95,046

$
(14,491
)
$
(4,401
)
$
1,841,555

Net income
 
97,781



97,781

Other comprehensive income
 


347

347

Repurchase of common stock
 

(24,066
)

(24,066
)
Common stock issued and other
 

18,243


1,650

Common stock dividends - $1.05 per share
 
(55,606
)


(54,923
)
September 30, 2016
 
$
137,221

$
(20,314
)
$
(4,054
)
$
1,862,344

See accompanying Notes to the Financial Statements.


13


ONE Gas, Inc.
NOTES TO THE FINANCIAL STATEMENTS

1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited 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 2015 year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. These unaudited financial statements should be read in conjunction with the audited financial statements and footnotes in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2016, 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 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.

Use of Estimates - The preparation of our 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 financial statements. These estimates and assumptions also affect the reported amounts of revenue 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.

Segments - We operate in one reportable 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 described in Note 1 of our Notes to the Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and nine months ended September 30, 2016, and 2015, we had no single external customer from which we received 10 percent or more of our gross revenues.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually as of July 1. At July 1, 2016, we assessed qualitative factors to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.

Recently Issued Accounting Standards Update - In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard will modify several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. This new guidance is required to be adopted for our interim and annual reports for periods beginning after December 15, 2016, but may be adopted early. We are evaluating the impact of this guidance and the timing of adoption.

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. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-divisional teams to determine the potential impact of this accounting standard on our financial position, results of operations and cash flows and the transition approach we will utilize. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted.


14


In August 2015, the FASB issued ASU 2015-15, “Interest-Imputation of Interest (Subtopic 835-30),” which addresses the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We adopted this guidance in the first quarter 2016, and it did not have an impact on our financial position or results of operations.

In April 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. We adopted this guidance in the first quarter of 2016, and have applied the changes retrospectively to all periods presented. We have presented such amounts as a direct deduction from the face amount of our long-term debt, rather than in other assets as a deferred charge in our Balance Sheets. Amortization of the debt issuance costs continues to be reported as interest expense in our Statements of Income.   

In April 2015, the FASB issued ASU 2015-05, “Intangibles-Goodwill and Other-Internal-Use Software,” which helps entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. We adopted this guidance prospectively in the first quarter of 2016, and it did not have a material impact on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We are evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations and cash flows and the transition approach we will utilize. We are monitoring the FASB for additional implementation guidance that may impact the final conclusions of our evaluation. We are required to adopt this guidance for our interim and annual reports beginning with the first quarter 2018.

2.
REGULATORY ASSETS AND LIABILITIES

The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
 
 
 
 
September 30, 2016
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
29,109

 
$

 
$
29,109

Pension and postemployment benefit costs
 

 
24,706

 
416,327

 
441,033

Weather normalization
 
 
 
17,004

 

 
17,004

Reacquired debt costs
 

 
812

 
8,312

 
9,124

Other
 

 
2,232

 
6,447

 
8,679

Total regulatory assets, net of amortization
 
 
 
73,863

 
431,086

 
504,949

Accumulated removal costs (a)
 

 

 
(7,019
)
 
(7,019
)
Over-recovered purchased-gas costs
 

 
(11,538
)
 

 
(11,538
)
Ad valorem tax
 
 
 
(1,666
)
 

 
(1,666
)
Total regulatory liabilities
 
 
 
(13,204
)
 
(7,019
)
 
(20,223
)
Net regulatory assets (liabilities)
 
 
 
$
60,659

 
$
424,067

 
$
484,726

(a) Included in other deferred credits in our Balance Sheets.

15


 
 
 
 
December 31, 2015
 
 
 
 
Current
 
Noncurrent
 
Total
 
 
 
 
(Thousands of dollars)
Under-recovered purchased-gas costs
 

 
$
13,336

 
$

 
$
13,336

Pension and postemployment benefit costs
 

 
15,670

 
425,175

 
440,845

Weather normalization
 
 
 
2,198

 

 
2,198

Reacquired debt costs
 

 
812

 
8,919

 
9,731

Other
 

 
909

 
1,769

 
2,678

Total regulatory assets, net of amortization
 
 
 
32,925

 
435,863

 
468,788

Accumulated removal costs (a)
 

 

 
(9,032
)
 
(9,032
)
Over-recovered purchased-gas costs
 

 
(22,884
)
 

 
(22,884
)
Ad valorem tax
 
 
 
(1,731
)
 

 
(1,731
)
Total regulatory liabilities
 
 
 
(24,615
)
 
(9,032
)
 
(33,647
)
Net regulatory assets (liabilities)
 
 
 
$
8,310

 
$
426,831

 
$
435,141

(a) Included in other deferred credits in our Balance Sheets.

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

In January 2016, as a result of the OCC’s approval of our rate case in Oklahoma, we recorded a regulatory asset of $2.4 million to recover certain information technology costs incurred as a result of our separation from ONEOK in 2014, which will be recovered over four years.

3.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2016, our debt-to-capital ratio was 40 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 September 30, 2016, we had $41.0 million in short-term borrowings, $1.0 million in letters of credit issued under the ONE Gas Credit Agreement and $658.0 million of remaining credit available under the ONE Gas Credit Agreement.

4.
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 (collectively, our “Senior Notes”). 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.

5.
EQUITY

In the first quarter of 2016, we repurchased approximately 407 thousand shares of our common stock for approximately $24.1 million.


16


In October 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for shareholders of record on November 14, 2016, payable December 1, 2016.

6.
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Statements of Income for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
Details about Accumulated Other Comprehensive
 
September 30,
 
September 30,
 
Affected Line Item in the
 Income (Loss) Components
 
2016
2015
 
2016
2015
 
 Statements of Income
 
 
(Thousands of dollars)
 
 
Pension and other postemployment benefit plan obligations (a)
 
 
 
 
 
 
 
 
Amortization of net loss
 
$
10,040

$
12,564

 
$
30,113

$
37,694

 
 
Amortization of unrecognized prior service cost
 
(909
)
(374
)
 
(2,725
)
(1,120
)
 
 
 
 
9,131

12,190

 
27,388

36,574

 
 
Regulatory adjustments (b)
 
(8,943
)
(11,961
)
 
(26,824
)
(35,887
)
 
 
 
 
188

229

 
564

687

 
Income before income taxes
 
 
(72
)
(88
)
 
(217
)
(264
)
 
Income tax expense
Total reclassifications for the period
 
$
116

$
141

 
$
347

$
423

 
Net income
(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 8 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 2 for additional disclosures of regulatory assets and liabilities.

7.
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 September 30, 2016
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
12,737

 
52,453

 
$
0.24

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
489

 
 

Net income available for common stock and common stock equivalents
$
12,737

 
52,942

 
$
0.24


 
Three Months Ended September 30, 2015
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
7,371

 
52,408

 
$
0.14

Diluted EPS Calculation
 
 
 

 
 

Effect of dilutive securities

 
664

 
 

Net income available for common stock and common stock equivalents
$
7,371

 
53,072

 
$
0.14



17


 
Nine Months Ended September 30, 2016
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
97,781

 
52,452

 
$
1.86

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
510

 
 

Net income available for common stock and common stock equivalents
$
97,781

 
52,962

 
$
1.85


 
Nine Months Ended September 30, 2015
 
Income
 
Shares
 
Per Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation
 
 
 
 
 
Net income available for common stock
$
79,828

 
52,627

 
$
1.52

Diluted EPS Calculation
 

 
 

 
 

Effect of dilutive securities

 
688

 
 

Net income available for common stock and common stock equivalents
$
79,828

 
53,315

 
$
1.50


8.
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
 
Nine Months Ended
 
September 30,
 
September 30,
 
2016
2015
 
2016
2015
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
 
 
 
Service cost
$
3,014

$
3,497

 
$
9,042

$
10,518

Interest cost
11,387

10,652

 
34,162

31,956

Expected return on assets
(15,296
)
(15,363
)
 
(45,888
)
(46,087
)
Amortization of unrecognized prior service cost

66

 

200

Amortization of net loss
8,886

11,054

 
26,657

33,164

Net periodic benefit cost
$
7,991

$
9,906

 
$
23,973

$
29,751


 
Other Postemployment Benefits
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2016
2015
 
2016
2015
 
(Thousands of dollars)
Components of net periodic benefit cost
 
 
 
 
 
Service cost
$
637

$
849

 
$
1,913

$
2,547

Interest cost
2,626

2,665

 
7,880

7,997

Expected return on assets
(3,070
)
(2,908
)
 
(9,212
)
(8,724
)
Amortization of unrecognized prior service cost
(909
)
(440
)
 
(2,725
)
(1,320
)
Amortization of net loss
1,154

1,510

 
3,456

4,530

Net periodic benefit cost
$
438

$
1,676

 
$
1,312

$
5,030


We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain utility commissions 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

18


liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable utility commission. Regulatory deferrals related to net periodic benefit cost were not material for the three and nine months ended September 30, 2016.

In October 2015, we announced to certain pre-65 participants in our postretirement medical plans a change from a self-insured postretirement medical plan to a plan providing participants an annual benefit that would allow them to select coverage on a healthcare exchange beginning January 1, 2017. In September 2016, due to uncertain market conditions with health insurance exchange providers, we elected not to move the eligible pre-65 participants in our postemployment medical plans to a healthcare exchange. As a result, we remeasured the respective plan assets and benefit obligations, effective September 30, 2016, which resulted in an increase in benefit obligations of our postemployment benefit plan of $31.5 million. The remeasurement will increase the net periodic benefit cost of our postemployment benefit plan by $0.8 million for the three months ending December 31, 2016.

The following table sets forth the weighted-average assumptions used in the remeasurement of the benefit obligations for postemployment benefits for the periods indicated:
 
 
September 30, 2016
 
December 31, 2015
Discount rate
 
3.75%
 
4.75%
Expected long-term return on plan assets
 
7.75%
 
8.00%

The following table sets forth the weighted-average assumptions used in the remeasurement to determine periodic benefit costs for the periods indicated:
 
 
Three Months Ended December 31,
 
Nine Months Ended September 30,
 
 
2016
 
2016
Discount rate - other postemployment plans
 
3.75%
 
4.75%
Expected long-term return on plan assets
 
7.75%
 
8.00%

There were no other changes in assumptions for the other postemployment benefits calculations, which are described in our Annual Report. There was no impact to our previously disclosed obligations and benefit costs for our pension plan.

9.
COMMITMENTS AND CONTINGENCIES

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. 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, results of operations and cash flows.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all work at these sites. The terms of the consent agreement allow 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 according to plans approved by the KDHE. Regulatory closure has been achieved at three of the sites. We have begun site assessment at the remaining site where no active remediation has occurred.

19



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 nine months ended September 30, 2016 and 2015. 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 notice of proposed rulemaking (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. The potential capital and operating expenditures associated with the NPRM 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.

10.
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 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.


20


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

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

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

Derivative Instruments -  At September 30, 2016, we held purchased natural gas call options for the heating season ending March 2017, with total notional amounts of 30.5 Bcf, for which we paid premiums of $9.4 million, and had a fair value of $8.1 million. At December 31, 2015, we held purchased natural gas call options for the heating season ended March 2016, with total notional amounts of 17.0 Bcf, for which we paid premiums of $5.8 million, and had a fair value of $0.4 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 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 nine months ended September 30, 2016 and 2015.

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 deposits 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 September 30, 2016 and December 31, 2015. The estimated fair value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion at September 30, 2016 and December 31, 2015, respectively. The estimated fair value of our Senior Notes at September 30, 2016 and December 31, 2015, was determined using quoted market prices, and are considered Level 2.

21



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 financial statements and the Notes to the 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 nine months ended September 30, 2016, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Dividend - In October 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for shareholders of record on November 14, 2016, payable December 1, 2016.

Regulatory Activities - Oklahoma - In March 2016, Oklahoma Natural Gas filed its energy-efficiency program true-up application for its 2015 program year, requesting a utility incentive of $1.9 million and a program true-up adjustment of $3.1 million. This filing also sought approval for the demand portfolio of conservation and energy efficiency programs for calendar years 2017 through 2019. In July 2016, the staff of the OCC filed testimony in support of the filing. In August 2016, a stipulation and settlement agreement was filed and supporting testimony was heard by the administrative law judge. In October 2016, the OCC approved the joint stipulation and settlement agreement.

In July 2015, Oklahoma Natural Gas filed a request with the OCC for an increase in base rates, reflecting system investments and operating costs necessary to maintain the safety and reliability of its natural gas distribution system. In January 2016, the OCC approved a joint stipulation and settlement agreement to allow an increase in revenue of $29,995,000. We also recorded a regulatory asset of $2.4 million to recover certain information technology costs incurred as a result of our separation from ONEOK in 2014, which will be recovered over four years. The agreement set Oklahoma Natural Gas’ authorized return on equity at 9.5 percent, which represents the midpoint of the allowed range of 9.0 to 10.0 percent, and approved a rate base of approximately $1.2 billion. The agreement includes the continuation, with certain modifications, of the Performance-Based Rate Change tariff that was established in 2009. Oklahoma Natural Gas expects to make its next Performance-Based Rate Change filing on or before March 15, 2017.

Kansas - In May 2016, Kansas Gas Service filed a request with the KCC for an increase in base rates, reflecting system investments and operating costs necessary to maintain the safety and reliability of its natural gas distribution system. Kansas Gas Service’s request represented a net base rate increase of $28.0 million. Kansas Gas Service is already recovering approximately $7.4 million from customers through the GSRS, resulting in a total base rate increase of $35.4 million. The filing was based on a 10.0 percent return on equity and a common equity ratio of 55.0 percent. The filing represented a rate base of $903 million, compared with $826 million included in existing base rates plus previously approved GSRS-eligible investments. In October 2016, Kansas Gas Service reached a unanimous settlement agreement with all parties for a net increase in base rates of approximately $8.1 million. Including the GSRS of approximately $7.4 million, the total base rate increase is $15.5 million. The agreement is a “black-box settlement,” meaning the parties agreed to a specific revenue number but no specific return on equity. The KCC has until December 28, 2016, to make a ruling, with new rates effective no earlier than January 1, 2017.

In August 2015, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.4 million related to its GSRS. In November 2015, the KCC approved the $2.4 million increase effective December 2015.

Texas - In June 2016, Texas Gas Service filed a rate case requesting an increase in revenues of $11.6 million for its Central Texas and South Texas service areas. The filing included a request to consolidate the South Texas service area with the Central Texas service area. Texas Gas Service filed this rate case directly with the incorporated cities of the Central Texas service area, which includes the city of Austin, and the RRC for the unincorporated areas. In October 2016, all parties to the filing reached a unanimous settlement agreement for an increase in revenues of $6.8 million for the new consolidated service area. New rates will be effective in November 2016, for customers in the incorporated cities of the former Central Texas service area. Upon RRC approval, new rates will be effective for customers in the unincorporated areas of the new consolidated Central Texas service area, which is expected by January 9, 2017. Texas Gas Service expects to file for the same rates in the incorporated areas of the former South Texas service area by January 2017. In the agreement, the parties established a 9.5 percent return on equity and 60.1 percent common equity ratio.
   
In November 2015, Texas Gas Service notified the EPSA that it would be filing a full rate case in 2016 in lieu of the EPARR. In March 2016, Texas Gas Service filed a rate case requesting an increase in revenues of $12.8 million for the EPSA and its

22


Dell City and Permian service areas. The filing included a request to consolidate these three service areas into a new West Texas service area. Texas Gas Service filed this rate case directly with the incorporated cities of the EPSA and Dell City service area and the RRC for the unincorporated areas. In July 2016, several incorporated cities, including the city of El Paso, denied the request and Texas Gas Service appealed the denial to the RRC. In September 2016, the RRC approved consolidation of the three service areas into the new West Texas service area and a base rate increase of $8.8 million, which was based on a 9.5 percent return on equity and a 60.1 percent common equity ratio. In October 2016, rates went into effect for all service areas, except for the incorporated cities in the former Permian service area, for which Texas Gas Service expects to file for these new rates in the fourth quarter of 2016. Also in October 2016, Texas Gas Service filed a motion for rehearing asking the RRC to reconsider incentive compensation cost recovery. The City of El Paso also filed a motion for rehearing to address the issues of  consolidation, depreciation rates, capital structure and inclusion of certain invested capital in rate base.  The RRC has until January 5, 2017, to make a ruling.

In December 2015, Texas Gas Service filed a rate case requesting an increase in revenues of $3.1 million for its Galveston and South Jefferson County service areas. The filing included a request to consolidate these two service areas into a new Gulf Coast service area. Texas Gas Service filed this rate case directly with the incorporated cities and the RRC for the unincorporated areas. Texas Gas Service reached a unanimous settlement agreement with representatives of the incorporated cities and the staff of the RRC on behalf of the unincorporated areas for an increase in revenues of $2.3 million. New rates became effective in May 2016.

In March 2015, Texas Gas Service filed under the annual rate review mechanism called EPARR, requesting an increase in revenues totaling $11.2 million in the city of El Paso and surrounding incorporated cities in the EPSA. In August 2015, Texas Gas Service and the incorporated cities in the EPSA reached an agreement on a rate increase of $8.0 million to take effect in August 2015. In April 2015, Texas Gas Service filed with the RRC under the GRIP statute, requesting an increase of $0.4 million in revenues for the unincorporated areas of the EPSA. GRIP is a capital-recovery mechanism that allows for a rate adjustment providing recovery of and a return on incremental capital investments made between rate cases. The RRC approved the filing in July 2015.

Texas Gas Service received approval under the GRIP statute with the city of Austin, Texas, and surrounding communities in May 2015, for an increase in revenues of approximately $3.7 million. The new rates were effective in June 2015.

In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and cost of service adjustments in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate increases associated with these filings totaling $4.8 million were approved in 2015. To date in 2016, the increases approved total $2.0 million.

FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. We evaluate our financial performance principally on operating income.

Selected Financial Results - The following table sets forth certain selected financial results for our operations for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
Three Months
 
Nine Months
 
September 30,
 
September 30,
 
2016 vs. 2015
 
2016 vs. 2015
Financial Results
2016
 
2015
 
2016
 
2015
 
Increase (Decrease)
 
Increase (Decrease)
 
(Millions of dollars, except percentages)
Natural gas sales
$
204.3

 
$
197.9

 
$
892.9

 
$
1,063.7

 
$
6.4

 
3
 %
 
$
(170.8
)
 
(16
)%
Transportation revenues
21.2

 
20.9

 
72.2

 
72.9

 
0.3

 
1
 %
 
(0.7
)
 
(1
)%
Cost of natural gas
52.2

 
54.7

 
344.4

 
548.2

 
(2.5
)
 
(5
)%
 
(203.8
)
 
(37
)%
Net margin, excluding other revenues
173.3

 
164.1

 
620.7

 
588.4

 
9.2

 
6
 %
 
32.3

 
5
 %
Other revenues
6.6

 
6.4

 
21.3

 
21.9

 
0.2

 
3
 %
 
(0.6
)
 
(3
)%
Net margin
179.9

 
170.5

 
642.0

 
610.3

 
9.4

 
6
 %
 
31.7

 
5
 %
Operating costs
112.7

 
111.6

 
344.9

 
346.5

 
1.1

 
1
 %
 
(1.6
)
 
 %
Depreciation and amortization
36.3

 
34.0

 
106.5

 
98.6

 
2.3

 
7
 %
 
7.9

 
8
 %
Operating income
$
30.9

 
$
24.9

 
$
190.6

 
$
165.2

 
$
6.0

 
24
 %
 
$
25.4

 
15
 %
Capital expenditures
$
86.5

 
$
74.3

 
$
231.3

 
$
199.7

 
$
12.2

 
16
 %
 
$
31.6

 
16
 %


23


The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:
 
Three Months Ended
 
Nine Months Ended
 
Three Months
 
Nine Months
Net Margin, Excluding Other
September 30,
 
September 30,
 
2016 vs. 2015
 
2016 vs. 2015
Revenues
2016
 
2015
 
2016
 
2015
 
Increase (Decrease)
 
Increase (Decrease)
Natural gas sales
(Millions of dollars, except percentages)
Residential
$
126.9

 
$
118.9

 
$
454.4

 
$
425.8

 
$
8.0

 
7
%
 
$
28.6

 
7
 %
Commercial and industrial
24.1

 
23.3

 
89.6

 
85.4

 
0.8

 
3
%
 
4.2

 
5
 %
Wholesale and public authority
1.1

 
1.0

 
4.5

 
4.3

 
0.1

 
10
%
 
0.2

 
5
 %
Net margin on natural gas sales
152.1

 
143.2

 
548.5

 
515.5

 
8.9

 
6
%
 
33.0

 
6
 %
Transportation revenues
21.2

 
20.9

 
72.2

 
72.9

 
0.3

 
1
%
 
(0.7
)
 
(1
)%
Net margin, excluding other revenues
$
173.3

 
$
164.1

 
$
620.7

 
$
588.4

 
$
9.2

 
6
%
 
$
32.3

 
5
 %

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. 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, which include weather normalization, 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
 
Nine Months Ended
 
Three Months
 
Nine Months
 
September 30,
 
September 30,
 
2016 vs. 2015
 
2016 vs. 2015
Net Margin on Natural Gas Sales
2016
 
2015
 
2016
 
2015
 
Increase (Decrease)
 
Increase (Decrease)
Net margin on natural gas sales
(Millions of dollars, except percentages)
 
 
 
 
Fixed margin
$
137.0

 
$
128.0

 
$
418.8

 
$
387.8

 
$
9.0

 
7
 %
 
$
31.0

 
8
%
Variable margin
15.1

 
15.2

 
129.7

 
127.7

 
(0.1
)
 
(1
)%
 
2.0

 
2
%
Net margin on natural gas sales
$
152.1

 
$
143.2

 
$
548.5

 
$
515.5

 
$
8.9

 
6
 %
 
$
33.0

 
6
%

Net margin increased $9.4 million for the three months ended September 30, 2016, compared with the same period last year, due primarily to the following:
an increase of $8.2 million from new rates primarily in Oklahoma and Texas; and
an increase of $1.1 million in residential sales due primarily to customer growth in Oklahoma and Texas.

Net margin increased $31.7 million for the nine months ended September 30, 2016, compared with the same period last year, due primarily to the following:
an increase of $32.6 million from new rates primarily in Oklahoma and Texas;
an increase of $2.9 million in residential sales due primarily to customer growth in Oklahoma and Texas; and
an increase of $1.2 million in ad valorem recoveries in Kansas, which is offset with higher related amortization expense; offset partially by
a decrease of $3.0 million due to lower sales volumes, net of weather normalization, primarily from warmer weather for the nine months ended September 30, 2016, compared with the same period last year; and
a decrease of $1.3 million due primarily to lower transportation volumes from weather-sensitive customers in Kansas and Oklahoma.

Operating costs increased $1.1 million for the three months ended September 30, 2016, compared with the same period last year, due primarily to an increase of $0.8 million in outside services and fleet and materials expense.

24


Operating costs decreased $1.6 million for the nine months ended September 30, 2016, compared with the same period last year, due primarily to the following:
a decrease of $3.8 million in outside service costs and fleet and materials expense;
a decrease of $2.6 million in information technology costs; and
a decrease of $2.4 million from the deferral of certain information technology costs incurred as a result of our separation from ONEOK in 2014, which was approved in Oklahoma as a regulatory asset; offset partially by
an increase of $4.9 million in employee-related costs; and
an increase of $2.7 million in legal-related costs.

Depreciation and amortization expense increased $2.3 million and $7.9 million for the three and nine months ended September 30, 2016, respectively, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed into service.

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 $12.2 million and $31.6 million for the three and nine months ended September 30, 2016, respectively, compared with the same respective 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
 
 
September 30,
2016 vs. 2015
(in thousands)
 
2016
2015
Increase (Decrease)
Average Number of Customers
 
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Residential
 
782

576

612

1,970

776

573

606

1,955

6

3

6

15

Commercial and industrial
 
71

50

34

155

71

50

33

154



1

1

Wholesale and public authority
 


3

3



3

3





Transportation
 
6

6

1

13

6

6

1

13





Total customers
 
859

632

650

2,141

853

629

643

2,125

6

3

7

16


 
 
Nine Months Ended
Variances
 
 
September 30,
2016 vs. 2015
(in thousands)
 
2016
2015
Increase (Decrease)
Average Number of Customers
 
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Residential
 
788

582

612

1,982

783

580

607

1,970

5

2

5

12

Commercial and industrial
 
73

50

35

158

73

50

34

157



1

1

Wholesale and public authority
 


3

3



3

3





Transportation
 
5

6

1

12

5

6

1

12





Total customers
 
866

638

651

2,155

861

636

645

2,142

5

2

6

13




25


 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Volumes (MMcf)
 
2016
 
2015
 
2016
 
2015
Natural gas sales
 
 
 
 
 
 
 
 
Residential
 
7,425

 
7,476

 
69,687

 
78,987

Commercial and industrial
 
3,590

 
3,676

 
22,408

 
25,460

Wholesale and public authority
 
261

 
247

 
1,542

 
1,719

Total volumes sold
 
11,276

 
11,399

 
93,637

 
106,166

Transportation
 
46,036

 
43,056

 
154,857

 
150,611

Total volumes delivered
 
57,312

 
54,455

 
248,494

 
256,777


Total volumes delivered decreased for the nine months ended September 30, 2016, compared with the same period last year, due primarily to warmer temperatures in 2016. The impact on residential and commercial margins was mitigated significantly by weather-normalization mechanisms. Transportation volumes increased for the nine months ended September 30, 2016, compared with the same period last year, due to a large industrial customer’s facility undergoing maintenance in the prior year, offset by a decrease in transportation volumes associated with smaller weather-sensitive customers.

Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. The impact to net margin from changes in volumes associated with these customers is minimal.

 
 
Three Months Ended
 
 
September 30,
 
 
2016
 
2015
 
2016 vs 2015
 
2016
 
2015
Heating Degree Days
 
Actual
 
Normal
 
Actual
 
Normal
 
Actual Variance
 
Actual as a percent of Normal
Oklahoma
 
3

 
2

 

 
14

 
100
%
 
150
%
 
%
Kansas
 
19

 
52

 
9

 
52

 
111
%
 
37
%
 
17
%
Texas
 
2

 
1

 

 
1

 
100
%
 
200
%
 
%

 
 
Nine Months Ended
 
 
September 30,
 
 
2016
 
2015
 
2016 vs 2015
 
2016
 
2015
Heating Degree Days
 
Actual
 
Normal
 
Actual
 
Normal
 
Actual Variance
 
Actual as a percent of Normal
Oklahoma
 
1,730

 
1,968

 
2,067

 
2,012

 
(16
)%
 
88
%
 
103
%
Kansas
 
2,459

 
2,965

 
2,824

 
2,965

 
(13
)%
 
83
%
 
95
%
Texas
 
899