Edgar Filing: ONE Gas, Inc.

ONE Gas 10-K 2014

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014.

__ 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

Securities registered pursuant to Section 12(b) of the Act:



Common stock, par value of $0.01	New York Stock Exchange
(Title of each class)	(Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X

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 if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X

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. (Check one) 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 Act). Yes__ No X

The aggregate market value of the equity securities held by nonaffiliates based on the closing trade price of the registrant on June 30, 2014, was $1.9 billion.

On February 6, 2015, we had 51,145,396 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 21, 2015, are incorporated by reference in Part III.

ONE Gas, Inc.

2014 ANNUAL REPORT



Part I.		Page No.
Item 1.	Business	5
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	43
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
Item 9A.	Controls and Procedures	80
Item 9B.	Other Information	80
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	80
Item 11.	Executive Compensation	81
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	81
Item 13.	Certain Relationships and Related Transactions, and Director Independence	82
Item 14.	Principal Accounting Fees and Services	82
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	83
Signatures		87

As used in this Annual 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.

GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:



ACA	Annual Cost Adjustment
AFUDC	Allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2014
ATSR	Ad Valorem Tax Surcharge Rider
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
CERCLA	Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CFTC	Commodities Futures Trading Commission
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
COG	Cost of gas
COGR	Cost of gas rider
COSA	Cost-of-Service Adjustment
DOT	United States Department of Transportation
Dth	Dekatherm
EPA	United States Environmental Protection Agency
EPARR	El Paso Annual Rate Review
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
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
IASB	International Accounting Standards Board
IFRS	International Financial Reporting Standards
IRS	U.S. Internal Revenue Service
IRS Ruling	Private Letter Ruling from IRS
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
LDCs	Local distribution companies
LIBOR	London Interbank Offered Rate
Moody’s	Moody’s Investors Service, Inc.
MMcf	Million cubic feet
NYSE	New York Stock Exchange
OCC	Oklahoma Corporation Commission
ONE Gas	ONE Gas, Inc.
ONE Gas Credit Agreement	ONE Gas’ $700 million revolving credit agreement, which expires in January, 2019
ONE Gas Predecessor	ONE Gas’ predecessor for accounting purposes that consists of the business attributable to ONEOK’s natural gas distribution segment that was transferred to ONE Gas in connection with its separation from ONEOK
ONEOK	ONEOK, Inc. and its subsidiaries
ONEOK Partners	ONEOK Partners, L.P. and its subsidiaries
OSHA	Occupational Safety and Health Administration
PBRC	Performance-Based Rate Change



PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
Pipeline Safety Improvement Act	Pipeline Safety Improvement Act of 2002, as amended
Pipeline Safety, Regulatory Certainty and Job Creation Act	Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
ROE	Return on equity calculated consistent with utility ratemaking in each jurisdiction
RRC	Railroad Commission of Texas
S&P	Standard and Poor’s Rating Services
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
Tax Matters Agreement	Tax Matters Agreement dated January 14, 2014, between ONEOK and ONE Gas
Transition Services Agreement	Transition Services Agreement dated January 14, 2014, between ONEOK and ONE Gas
WNA	Weather normalization adjustments
XBRL	eXtensible Business Reporting Language

The statements in this Annual 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 and 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 1A, “Risk Factors,” and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation and “Forward-Looking Statements,” in this Annual Report.

PART I

ITEM 1. BUSINESS

SEPARATION FROM ONEOK, INC.

On January 8, 2014, ONEOK’s board of directors approved the distribution of all the shares of our common stock to holders of ONEOK common stock.

In order for ONEOK to effect the distribution, we requested, and the SEC declared effective, our Registration Statement on Form 10 on January 10, 2014. ONEOK transferred all of the assets and liabilities primarily related to its natural gas distribution business to us. Assets and liabilities included accounts receivable and payable, natural gas in storage, regulatory assets and liabilities, pipeline and other natural gas distribution facilities, customer deposits, employee-related assets and liabilities, including amounts attributable to pension and other postretirement benefits, tax-related assets and liabilities and other assets and liabilities primarily associated with providing natural gas distribution service in Oklahoma, Kansas and Texas. Certain corporate assets, such as office space in the corporate headquarters and certain IT hardware and software, were not transferred to us; however, the Transition Services Agreement between ONEOK and us provided temporary access to such corporate assets as necessary to operate our business prior to obtaining applicable corporate assets on our own.

Immediately prior to the contribution of the natural gas distribution business to us, ONEOK contributed to the capital of the natural gas distribution business all of the amounts outstanding on the natural gas distribution business’s short-term note payable to and long-term line of credit with ONEOK. We received approximately $1.19 billion of cash from a private placement of senior notes (which were later exchanged for registered notes), then used a portion of those proceeds to fund a cash payment of approximately $1.13 billion to ONEOK. On January 31, 2014, ONEOK distributed one share of our common stock for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of business on January 21, 2014, the record date of the distribution. At the close of business on January 31, 2014, ONE Gas, Inc. became an independent, publicly traded company as a result of the distribution. Our common stock began trading “regular-way” under the ticker symbol “OGS” on the NYSE on February 3, 2014. ONEOK has not retained any ownership interest in our company.

OUR BUSINESS

We are an independent, publicly traded, 100 percent regulated natural gas distribution utility. We are one of the largest natural gas utilities in the United States. We are an Oklahoma corporation and are comprised of ONEOK’s former natural gas distribution business and are the successor to the company founded in 1906 as Oklahoma Natural Gas Company. Our company was incorporated under the laws of the state of Oklahoma on August 30, 2013. We are the largest natural gas distributor in Oklahoma and Kansas and the third largest in Texas, providing service as a regulated public utility. We serve residential, commercial and industrial, transportation and wholesale and public authority customers in all three states. Our largest natural gas distribution markets in terms of customers are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita and Topeka, Kansas; and Austin and El Paso, Texas. Our three divisions, Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, distribute natural gas as public utilities to approximately 87 percent, 72 percent and 14 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively.

Prior to our separation from ONEOK, our financial statements were derived from ONEOK’s financial statements, which included its natural gas distribution business as if we, for accounting purposes, had been a separate company for all periods presented. The assets and liabilities in the financial statements have been reflected on a historical basis. The financial statements for periods prior to the separation also include expense allocations for certain corporate functions historically performed by ONEOK, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, information technology and other services. We believe our assumptions underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from ONEOK, are reasonable. However, the financial statements may not include all of the actual expenses that would have been incurred by us and may not reflect our results of operations, financial position and cash flows had we been a separate publicly traded company during the periods presented prior to the separation.

OUR STRATEGY

Our business objective is focused on operating our systems in a safe, reliable and environmentally sensitive manner, growing our business responsibly, while delivering quality customer service, which enables us to - over time - generate a competitive total return for our shareholders and maintain our financial stability. We intend to accomplish this objective by executing on the strategies listed below:

•

Focus on Safety - We are committed to pursuing a zero-incident safety culture with a focus on mitigating risk and eliminating incidents that may harm our employees, contractors, the public or the environment. Comparing 2014 with 2009, we have experienced steady improvement across several key safety metrics, including a 61 percent reduction in our total recordable incident rate and a 43 percent reduction in our preventable vehicle incident rate. In addition, a significant portion of our capital spending is focused on the safety, reliability and efficiency of our natural gas distribution system.

•

Increase Our Achieved ROE - We continually seek to improve our achieved ROE through improved operational performance and regulatory mechanisms. For 2014, our achieved ROE was 7.6 percent across all of our service territories. The difference between our achieved and allowed ROE is related primarily to regulatory lag. We make investments that increase our rate base and we incur increases in our costs that are above the amounts reflected in the rates we charge for our service.

We have several initiatives underway to improve our operational performance. These initiatives include leveraging and implementing technology that is expected to result in increased efficiency, thereby helping lower and/or reduce the rate of increase in operating expenses.

•

Focus on Our Credit Metrics and Our Balanced Approach to Capital Management - We believe that maintaining an investment-grade credit rating is prudent for our business as we seek to access the capital markets to finance capital investments. As a 100 percent regulated utility, we intend to maintain strong credit metrics while we pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

•

Advocate Constructive Relationships with Key Stakeholders - We plan to continue our constructive, transparent relationships with our key stakeholders, which include our employees, customers, investors and regulators. Our strategy includes seeking outcomes in future rate proceedings that provide a fair return on our infrastructure investments, while also meeting the needs of our customers through safe, reliable and efficient service.

•

Identify and Pursue Growth Opportunities - Our growth opportunities are a result of capital investments related to safety and reliability of our existing system, and system growth related to the economic and population growth in our service territories. As a result of our commitment to enhance the integrity, reliability and safety of our existing infrastructure, we are making significant investments in our existing system, which will lead to further growth of our rate base. In addition, as our service territories continue to experience economic growth, we expect to grow our rate base through capital investments in new service lines and main line extensions, predominately in the major metropolitan areas. As a result of overall trends in the natural gas and energy industries, we believe that the competitiveness of natural gas is increasing relative to other energy alternatives, creating new market opportunities for natural gas as an energy source within our existing service territories. We remain committed to staying a 100 percent regulated company, but will evaluate strategic acquisition opportunities that fall within that guideline based on our disciplined financial and operating approach, while weighing these alternatives against future investment opportunities with respect to our existing rate base.

REGULATORY OVERVIEW

We are subject to the regulations and oversight of the state and local regulatory agencies of the territories in which we operate. Rates and charges for natural gas distribution services are established by the OCC for Oklahoma Natural Gas and by the KCC for Kansas Gas Service. Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Rates in unincorporated areas of Texas and all appellate matters are subject to regulatory oversight by the RRC. These regulatory authorities have the responsibility of ensuring that the utilities in their jurisdictions provide safe and reliable service at a reasonable cost, while providing utility companies the opportunity to earn a fair and reasonable return on their investments.

Generally, a utility’s rates and charges are established in rate case proceedings. Regulatory authorities may also approve mechanisms that allow for adjustments for specific costs or investments made between rate cases. Due to the nature of the regulatory process, there is an inherent lag between the time that a utility makes investments or incurs additional costs and the setting of new rates and/or charges to recover those investments or costs. Additionally, we are not allowed recovery of certain costs we incur. The delay between the time investments are made or increases in costs are incurred and the time that our rates are adjusted to reflect these investments and costs is referred to as regulatory lag. The following provides additional detail on the regulatory mechanisms in the jurisdictions we serve.

Oklahoma - Oklahoma Natural Gas currently operates under a PBRC mechanism, which provides for streamlined annual rate reviews between rate cases and includes adjustments for incremental capital investment and certain expenses. Under this mechanism, we have a targeted ROE of between 10 percent and 11 percent. If our achieved ROE is below 10 percent, our base rates are increased upon OCC approval to an amount necessary to restore the ROE to 10.5 percent. If our achieved ROE exceeds 11 percent, the portion of the earnings above 11 percent is shared with our customers, who receive the benefit of 75 percent of the earnings above 11 percent. We receive the benefit of the remaining 25 percent. Other regulatory mechanisms in Oklahoma include the following:


•	Purchased Gas Adjustment Clause (PGA) - Oklahoma Natural Gas’ commodity, transportation, storage and gas purchase operations and maintenance costs are passed through to its sales customers without markup via the PGA. Any costs associated with natural gas that is lost, used or unaccounted for in operations and the fuel-related portion of bad debts are also recovered through the PGA.


•	Temperature Adjustment Clause (TAC) - The TAC is designed to reduce customers’ bills for the additional volumes used when the actual heating degree days exceed the normalized heating degree days and to increase the customers’ bills for volumes not used when actual heating degree days are less than the normal heating degree days. The TAC is in effect from November through April.

•

Energy Efficiency Programs - Oklahoma Natural Gas has an Energy-Efficiency Program, available to all of its gas sales customers. The costs associated with these programs and an incentive to offer these programs are recovered through a monthly surcharge on customer bills. Oklahoma Natural Gas collects approximately $11 million each year from natural gas sales customers to fund the program, which provides education, heating system check-ups and appliance rebates to promote energy efficiency.

•

Rate Design for Residential Customers - Oklahoma Natural Gas is authorized to utilize a rate structure with two choices. Rate Choice “A” is designed for customers whose annual normalized volume is less than 50 Dth. The tariff for these customers contains both a fixed monthly service charge and a per Dth delivery fee. Although a portion of the net margin for customers in Rate Choice “A” is dependent on usage, these customers use relatively small quantities of natural gas and therefore the net margin that is dependent on usage is not significant. The fixed monthly residential customer charge for Oklahoma Natural Gas is $14.73 for Rate Choice “A” customers. Rate Choice “B” is designed for customers whose annual normalized volume is 50 Dth or greater. The tariff for these customers contains only a fixed monthly service charge of $30.28. For the year ended December 31, 2014, approximately 86 percent of Oklahoma Natural Gas’ net margin from its sales customers was recovered from fixed charges. At December 31, 2014, 70 percent of Oklahoma Natural Gas’ residential customers are on Rate Choice “B.”

•

Rate Design for Commercial and Industrial Customers - Oklahoma Natural Gas is authorized to utilize a rate structure with two different rate choices for its Small Commercial and Industrial, or SCI, customers. Rate Choice “A” is designed for SCI customers whose annual normalized volume is less than 40 Dth. The tariff for these customers contains both a fixed monthly service charge of $20.12 and a delivery fee of $4.5599 per Dth. Rate Choice “B” is designed for SCI customers whose annual normalized volume is 40 Dth or greater but less than 150 Dth. The tariff for these customers contains only a fixed monthly service charge of $35.32. All of Oklahoma Natural Gas’ Large Commercial and Industrial, or LCI, customers are on a fixed monthly service charge of $81.02. At December 31, 2014, 73 percent of Oklahoma Natural Gas’ commercial and industrial customers are on either SCI Rate Choice “B” or LCI.

•

Compressed Natural Gas Rebate Program - The CNG Rebate Program is designed to promote and support the CNG market in the state of Oklahoma by offering rebates to Oklahoma residents who purchase dedicated and bi-fueled natural gas vehicles or install residential CNG fueling stations. The rebates are funded by a $0.25 per gasoline gallon equivalent surcharge that Oklahoma Natural Gas is authorized to collect on fuel purchased from a CNG dispenser owned by Oklahoma Natural Gas. In 2014, Oklahoma Natural Gas collected approximately $0.8 million from the surcharge to fund the program.

Kansas - Kansas Gas Service operates under a traditional regulatory framework, whereby periodic rate cases are filed with the KCC as needed to increase base rates to give Kansas Gas Service the opportunity to earn its authorized ROE. Other regulatory mechanisms in Kansas include the following:

•

COGR and ACA - These mechanisms allow Kansas Gas Service to recover the actual cost of the natural gas it sells to its customers. The COGR includes a monthly estimate of the cost Kansas Gas Service incurs in transporting, storing and purchasing natural gas supply for its sales customers, the ACA and other charges and credits. The ACA is an annual component of the COGR that compares the cost of gas recovered through the COGR for the preceding year with the actual natural gas supply costs and the fuel-related portion of bad debts for the same period. Any over or under recovery is reflected in the subsequent year’s COGR.

•

WNA Clause - This mechanism allows Kansas Gas Service to accrue the variation in net margin due to abnormal weather occurring from November through March. WNA is designed to reduce customers’ prospective bills for the additional volumes used when the actual heating degree days exceed the normalized heating degree days and to increase the customers’ prospective bills for the reduction in volumes used when actual heating degrees days are less than the normal heating degree days. Once a year, the amount of the adjustment is determined and is then applied to customers’ bills over the subsequent 12-month period.


•	ATSR - This rider allows Kansas Gas Service to recover the difference each year between the property tax costs built into its rates and its actual property tax costs without having to file a rate case. The amount of the adjustment is determined annually and recovered over the subsequent 12 months as a change in the delivery-charge component of customers’ bills.


•	Pension and Other Postretirement Benefits Trackers - These trackers allow Kansas Gas Service to track and defer for recovery in its next rate case the difference between the pension and other postretirement benefit costs included in base rates and actual expense as determined in accordance with GAAP.

•

GSRS - This surcharge allows Kansas Gas Service to file for a rate adjustment providing a recovery of and return on qualifying infrastructure investments (i.e., pipeline safety projects and relocation projects) incurred each year between rate case filings. However, rate adjustment filings cannot increase a monthly charge more than $0.40 per residential customer over the most recent GSRS filing. After five annual filings, Kansas Gas Service is required to file a rate case or cease collection of the surcharge.

The fixed monthly residential customer charge for Kansas Gas Service is $15.35. For the year ended December 31, 2014, approximately 54 percent of Kansas Gas Service’s net margin from its sales customers was recovered from fixed charges. Kansas experiences the highest heating degree days of all of our service territories, which brings a level of stability to net margin even though a significant portion is based on usage.

Texas - Texas Gas Service has grouped its customers into 10 service areas, each of which includes between two and 34 cities or jurisdictions. Periodic rate cases are filed with the cities, or the RRC, as needed, to give Texas Gas Service the opportunity to earn its authorized ROE. Other regulatory mechanisms and constructs in Texas include the following:

•

GRIP Statute - In two service areas, comprising 44 percent of Texas Gas Service’s customers, Texas Gas Service makes an annual filing under the GRIP statute, which allows it to recover return, taxes and depreciation on the annual net investment increase. After five annual GRIP filings, Texas Gas Service is required to file a full rate case. A full rate case may be filed at shorter intervals if desired by either Texas Gas Service or the regulator.

•

COSA Filings - In six service areas, comprising 18 percent of its customers, Texas Gas Service makes an annual COSA filing. COSA tariffs permit Texas Gas Service to recover return, taxes and depreciation on the annual increases in net investment, as well as annual increases or decreases in certain expenses and revenues. One COSA has no cap on the amount of the increase. Four of the COSAs have no cap on increases related to investment; but, have caps ranging from 3.5 percent to 5 percent or the change in the Consumer Price Index for expense increases. One COSA caps all increases at the increase in the Consumer Price Index. A full rate case may be filed when desired by Texas Gas Service or the regulator, but is not required.

•

EPARR Filings - In the El Paso service area, comprising 38 percent of its customers, Texas Gas Service makes an annual rate review filing. The annual rate review tariff permits Texas Gas Service to recover return, taxes and depreciation on the annual increases in net investment, as well as annual increases or decreases in certain expenses and revenues. There is no cap on the amount of the increase, but the request is subject to review and possible adjustment by the regulator. Upon notice, a full rate case may be filed by Texas Gas Service or the regulator, but is not required.

•

WNA Clause - Texas Gas Service employs WNA clauses in eight of its services areas, comprising approximately 62 percent of its customers. In one of the service areas without WNA, which comprises approximately 38 percent of its customers, Texas Gas Service recovers 88 percent of net margin from fixed charges, making revenues in this service area less weather sensitive. WNA is designed to reduce customers’ bills for the additional volumes used when the actual heating degree days exceed the normalized heating degree days and to increase customers’ bills for the reduction in volumes used when actual heating degree days are less than the normal heating degree days. The WNA is in effect from September through May.


•	COG Clause - In all service areas, Texas Gas Service recovers 100 percent of its gas costs, including interest on natural gas in storage and the natural gas cost component of bad debts, via a COG mechanism, subject to a limitation of 5 percent on lost-and-unaccounted-for natural gas. The COG is reconciled annually to compare the revenues

recovered through the COG with the actual natural gas supply costs and any over or under recovery is refunded or recovered, as applicable, in the subsequent year.


•	Pension and Other Postretirement Benefits - Texas Gas Service is authorized by statute to defer pension and other postretirement benefit costs that exceed the amount recovered in base rates, and to seek recovery of the deferred costs in a future rate case.


•	Pipeline-Integrity Testing Riders - Texas Gas Service recovers approximately 90 percent of its pipeline-integrity testing expenses via riders, COSAs and the EPARR filing, with the remainder included in base rates.


•	Safety-Related Plant Replacements - Texas Gas Service is authorized by RRC rule to accrue a rate of return for regulatory accounting purposes, taxes and depreciation expense on safety-related plant replacements from the time the replacements are in service until the plant is reflected in base rates, and to seek recovery of those accrued amounts in a future rate proceeding.


•	Energy Conservation Program - Texas Gas Service has an Energy Conservation Program in its Central Texas service area, comprising 37 percent of total customers. Texas Gas Service collects approximately $2 million per year from customers to fund the program, which provides energy audits, weatherization and appliance rebates to promote energy efficiency.

The average fixed monthly residential customer charge for Texas Gas Service is $14.39, and for the year ended December 31, 2014, approximately 71 percent of Texas Gas Service’s net margin from its sales customers was recovered from fixed charges.

MARKET CONDITIONS AND SEASONALITY

Supply - We purchased 180 Bcf and 189 Bcf of natural gas supply in 2014 and 2013, respectively. The decrease in 2014 resulted primarily from additional supply requirements due to colder temperatures in 2013. Our natural gas supply portfolio consists of long-term, seasonal and short-term contracts from a diverse group of suppliers. We award these contracts through competitive-bidding processes to ensure reliable and competitively priced natural gas supply. We acquire our natural gas supply from natural gas processors, natural gas marketers and natural gas producers.

An objective of our supply-sourcing strategy is to provide value to our customers through reliable, competitively priced and flexible natural gas supply and transportation from multiple production areas and suppliers. This strategy is designed to mitigate the impact on our supply from physical interruption, financial difficulties of a single supplier, natural disasters and other unforeseen force majeure events, as well as to ensure these resources are reliable and flexible to meet the variations of customer demands.

We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were to occur, we have curtailment tariff provisions in place that allow us to reduce or discontinue natural gas service to large industrial users and to request that residential and commercial customers reduce their natural gas requirements to an amount essential for public health and safety. In addition, during times of critical supply disruptions, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal, state and local regulatory agencies.

Natural gas supply requirements are affected by weather conditions. In addition, economic conditions impact the requirements of our commercial and industrial customers. Natural gas usage per residential customer may decline as customers change their consumption patterns in response to a variety of factors, including:


•	more volatile and higher natural gas prices;


•	customers’ improving the energy efficiency of existing homes by replacing doors and windows, adding insulation, and replacing appliances with more efficient appliances;


•	more energy-efficient construction; and


•	fuel switching - from natural gas to electricity.

In each jurisdiction in which we operate, changes in customer-usage profiles are considered in the periodic redesign of our rates.

In managing our natural gas supply portfolios, we partially mitigate price volatility using a combination of financial derivatives and natural gas in storage. We have natural gas financial hedging programs that have been authorized by the regulatory authorities in each state in which we do business. We do not utilize financial derivatives for speculative purposes, nor do we have trading operations associated with our business. As of December 31, 2014, we had 52.3 Bcf of natural gas storage capacity under lease with remaining terms ranging from one to five years and maximum allowable daily withdrawal capacity of approximately 1.4 Bcf. This storage capacity allows us to purchase natural gas during the off peak season and store it for use in

the winter periods. Approximately 26 percent of our winter natural gas supply needs for our sales customers are expected to be supplied from storage.

Demand - See discussion below under “Seasonality,” “Competition” and “Compressed Natural Gas” for factors affecting demand for our services.

Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas requirements are for heating. Accordingly, the volume of natural gas sales is higher normally during the months of November through March than in other months of the year. The impact on our margins resulting from weather temperatures that are above or below normal is offset partially through our WNA mechanisms. See discussion above under “Regulatory Overview.”

Competition - We encounter competition based on customers’ preference for natural gas, compared with other energy alternatives and their comparative prices. We compete to supply energy for space and water heating, cooking, clothes drying and other general energy needs. Significant energy usage competition occurs between natural gas and electricity in the residential and small commercial markets. Customers and builders typically make the decision on the type of equipment, and therefore the energy source, at initial installation, generally locking in the chosen energy source for the life of the equipment. Changes in the competitive position of natural gas relative to electricity and other energy alternatives have the potential to cause a decline in consumption of natural gas or in the number of natural gas customers.

The Department of Energy issued a statement of policy that it will use full fuel-cycle measures of energy use and emissions when evaluating energy-conservation standards for appliances. In addition, the EPA has determined that source energy is the most equitable unit for evaluating energy consumption. Assessing energy efficiency in terms of a full fuel-cycle or source-energy analysis, which takes all energy use into account, including transmission, delivery and production losses, in addition to energy consumed at the site, highlights the high overall efficiency of natural gas in residential and commercial uses compared with electricity.

The below table contains data related to the cost of our delivered gas relative to electricity based on current market conditions:



Natural Gas vs. Electricity	Oklahoma		Kansas		Texas

Average retail price of electricity / kWh⁽¹⁾	9.63¢		12.21¢		11.94¢
Natural gas price equivalent of electricity / Dth⁽¹⁾	$	28.22	$	35.79	$	34.99
ONE Gas delivered cost of natural gas / Dth⁽²⁾	$	10.73	$	9.97	$	11.21
Natural gas advantage ratio⁽³⁾	2.6x		3.6x		3.1x

(1) Source: United States Energy Information Agency, www.eia.gov, for the eleven-month period ended November 30, 2014.

(2) Represents the average delivered cost of natural gas to a residential customer, including the cost of the natural gas supplied, fixed customer charge, delivery charges and charges for riders, surcharges and other regulatory mechanisms associated with the services we provide, for the year ended December 31, 2014.

(3) Calculated as the ratio of the natural gas price equivalent per dekatherm of the average retail price of electricity per kilowatt hour to the ONE Gas delivered average cost of natural gas per dekatherm.

We are subject to competition from other pipelines for our large industrial and commercial customers, and this competition has and may continue to impact margins. Under our transportation tariffs, qualifying industrial and commercial customers are able to purchase their natural gas needs from the supplier of their choice and have us transport it for a fee. A portion of the transportation services that we provide are at negotiated rates that are below the maximum approved transportation tariff rates. Reduced rate transportation service may be negotiated when a competitive pipeline is in close proximity or another viable energy option is available to the customer. Increased competition could potentially lower these rates.

Compressed Natural Gas (CNG) - In meeting increased interest in CNG for motor vehicle transportation, particularly from fleet operators, we have been developing an incremental source of transportation revenue by supplying natural gas to CNG fueling stations. The benefits of these programs are increased natural gas load, which could help mitigate future residential rate increases, enhanced competitive position and increased customer satisfaction. As of December 31, 2014, we supply 114 fueling stations, 31 of which we operate. Of the 83 remaining stations, we provide supply to 37 retail and 46 private CNG stations. We transported 2.0 million Dth to CNG stations in 2014, which represents an increase of 47 percent compared with 2013.

We will continue to support industry efforts to encourage development of more vehicle options by car and truck manufacturers, to support third-party investment in CNG fueling stations and to continue tax incentives for CNG. We continue to deploy a minimum amount of capital to connect CNG stations and allow the free market to build and operate the stations.

ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits 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.

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


•	an evaluation on whether 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.

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

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

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

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

Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in April 2012. Our pipeline facilities have been reviewed according to the current guidelines and no material changes have been required to date.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (1) developing and maintaining an accurate greenhouse gas emissions inventory according to current rules issued by the EPA; (2) improving the efficiency of our various pipelines; (3) following developing technologies for emission control; and (4) utilizing practices to reduce the loss of methane from our facilities.

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.

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

EMPLOYEES

We employed approximately 3,300 people at January 30, 2015, including approximately 700 people at Kansas Gas Service who are subject to collective bargaining agreements. The following table sets forth our contracts with collective bargaining units at February 1, 2015:



Union	Approximate Employees	Contract Expires
The United Steelworkers	400	October 28, 2016
International Brotherhood of Electrical Workers (IBEW)	300	June 30, 2017

EXECUTIVE OFFICERS

All executive officers are elected annually by our Board of Directors and each serves until such person resigns, is removed or is otherwise disqualified to serve or until such officer’s successor is duly elected. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.



Name and Position	Age*		Business Experience in Past Five Years
Pierce H. Norton II	54	2014 to present	President, Chief Executive Officer and Director
President, Chief Executive Officer and Director		2013 to 2014	Executive Vice President, Commercial, ONEOK and ONEOK Partners
		2012	Executive Vice President and Chief Operating Officer, ONEOK and ONEOK Partners
		2011	Chief Operating Officer, ONEOK
		2009 to 2011	President, ONEOK Distribution Companies, ONEOK
Curtis L. Dinan	47	2014 to present	Senior Vice President, Chief Financial Officer and Treasurer
Senior Vice President, Chief Financial Officer and Treasurer		2011 to 2014	Senior Vice President, Natural Gas, ONEOK Partners
		2007 to 2011	Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
		2007 to 2011	Board of Directors, ONEOK Partners
Joseph L. McCormick	55	2014 to present	Senior Vice President, General Counsel and Assistant Secretary
Senior Vice President, General Counsel and Assistant Secretary		2008 to 2014	Vice President and Associate General Counsel, ONEOK and ONEOK Partners
Caron A. Lawhorn	53	2014 to present	Senior Vice President, Commercial
Senior Vice President, Commercial		2013 to 2014	Senior Vice President, Commercial, Natural Gas Distribution, ONEOK
		2011 to 2012	President, ONEOK Distribution Companies, ONEOK
		2009 to 2011	Senior Vice President, Corporate Planning and Development, ONEOK and ONEOK Partners
Gregory A. Phillips	51	2014 to present	Senior Vice President, Operations
Senior Vice President, Operations		2013 to 2014	Senior Vice President, Operations, Natural Gas Distribution, ONEOK
		2011 to 2012	President, Oklahoma Natural Gas, ONEOK
		2008 to 2011	President, Texas Gas Service, ONEOK
* As of January 1, 2015

No family relationship exists between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

INFORMATION AVAILABLE ON OUR WEBSITE

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

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

ITEM 1A. RISK FACTORS

Our investors should consider the following risks that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Annual Report, including “Forward-Looking Statements,” which are included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

RISK FACTORS INHERENT IN OUR BUSINESS

Unfavorable economic and market conditions could affect adversely our earnings.

Weakening economic activity in our markets could result in a loss of existing customers, fewer new customers, especially in newly constructed homes, or a decline in energy consumption, any of which could affect adversely our revenues or restrict our future growth. It may become more difficult for customers to pay their natural gas bills, leading to slow collections and higher-than-normal levels of accounts receivable, which in turn could increase our financing requirements and bad debt expense. The foregoing could affect adversely our business, financial condition, results of operations and cash flows.

Increases in the wholesale price of natural gas could reduce our earnings, increase our working capital requirements and impact adversely our customer base.

The supply and demand balance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production in the U.S. of natural gas from shale formations has put downward pressure on the wholesale cost of natural gas; however, restrictions or regulations on shale natural gas production, increased demand from natural gas fueled electric power generation or natural gas exports could cause natural gas prices to increase. Additionally, the CFTC under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our natural gas supply.

An increase in the price of natural gas could cause us to experience a significant increase in short-term debt because we must pay suppliers for natural gas when purchased, and can be significantly in advance of when such costs may be recovered through the collection of customer bills, which could affect adversely our financial condition and cash flows.

Further, the volatility of natural gas prices may impact adversely our customers’ perception of natural gas. Natural gas costs are passed through to the customers of our LDCs based on the actual cost of the natural gas purchased by the particular LDC. Substantial fluctuations in natural gas prices can occur from year to year and sustained periods of high natural gas prices or of pronounced natural gas price volatility may lead to customers selecting other energy alternatives, such as electricity, and to increased scrutiny of the prudency of our natural gas procurement strategies and practices by our regulators. It may also cause new home developers, builders and new customers to select alternative sources of energy. Additionally, high natural gas prices may cause customers to conserve more and may also impact adversely our accounts receivable collections, resulting in higher bad debt expense. The occurrence of any of the foregoing could affect adversely our business, financial condition, results of operations and cash flows, as well as our future growth opportunities.

In addition, customer demand for natural gas may decrease due to technological advancements that increase the efficiency of and decrease energy consumption of appliances and equipment powered by natural gas.

Regulatory actions could impact our ability to earn a reasonable rate of return on our invested capital and to recover fully our operating costs.

In addition to regulation by other governmental authorities, we are subject to regulation by the OCC, KCC, RRC and various municipalities in Texas. These agencies set the rates that we charge our customers for our services. There can be no assurance that we will be able to obtain rate increases or that our authorized rates of return will continue at the current levels. We monitor and compare the rates of return we achieve with our allowed rates of return and initiate general and specific rate proceedings as needed. If a regulatory agency were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return by significantly lowering our allowed return or adversely altering our cost allocation, rate design or other

tariff provisions, modifying or eliminating cost trackers, prohibiting recovery of regulatory assets or disallowing portions of our expenses, then our earnings could be impacted adversely. Rate cases also involve a risk of rate reduction, because once rates have been filed, they are subject to challenge for their reasonableness by various interveners.

Further, accounting principles that govern our company permit certain assets that result from the regulatory process to be recorded on our balance sheets that could not be recorded under GAAP for nonregulated entities. We consider factors such as rate orders from regulators, previous rate orders for substantially similar costs, written approval from the regulators and analysis of recoverability from internal and external legal counsel to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time, which would also affect adversely our results of operations and cash flows. Regulatory authorities also review whether our natural gas costs are prudent and can adjust the amount of our natural gas costs that we pass through to our customers. If any of our natural gas costs were disallowed, our results of operations and cash flows would also be affected adversely.

In the normal course of business in the regulatory environment, assets are placed in service before regulatory action is taken, such as filing a rate case or for interim recovery under a capital tracking mechanism that could result in an adjustment of our returns. Once we make a regulatory filing, regulatory bodies have the authority to suspend implementation of the new rates while studying the filing. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return or may not be allowed recovery on such expenditures at all.

The profitability of our operations is dependent on our ability to recover timely the costs related to providing natural gas service to our customers. However, we are unable to predict the impact that new regulatory requirements will have on our operating expenses or the level of capital expenditures and we cannot assure you that our regulators will continue to allow recovery of such expenditures in the future. Changes in the regulatory environment applicable to our business could impair our ability to recover costs absorbed historically by our customers, and impact adversely our results of operations, financial condition and cash flows.

Our risk-management policies and procedures may not be effective, and employees may violate our risk-management policies.

We have implemented a set of policies and procedures that involve both our senior management and the Audit Committee of our Board of Directors to assist us in managing risks associated with our business. These risk policies and procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is managed throughout the organization. However, as conditions change and become more complex, current risk measures may fail to assess adequately the relevant risk due to changes in the market and the presence of risks previously unknown to us. Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended. Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have an adverse effect on our earnings, financial condition and cash flows.

We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on regulatory action.

We are subject to comprehensive regulation by several state and municipal utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility regulatory authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including organization, financing, affiliate transactions, customer service and the rates that we can charge customers. The profitability of our operations is dependent on our ability to pass through costs related to providing natural gas to our customers by filing periodic rate cases. The regulatory environment applicable to our operations could impair our ability to recover costs historically absorbed by our customers.

We are unable to predict the impact that the future regulatory activities of these agencies will have on our operations. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and results of operations. Further, the results of our operations could be impacted adversely if our authorized cost-recovery mechanisms do not function as anticipated.

Our business is subject to competition that could affect adversely our results of operations.

The natural gas distribution business is competitive, and we face competition from other companies that supply energy, including electric companies, propane dealers, renewable energy providers and coal companies in relation to sources of energy

for electric power plants, as well as nuclear energy. Significant competitive factors include efficiency, quality and reliability of the services we provide and price.

The most significant product competition occurs between natural gas and electricity in the residential and small commercial markets. Natural gas competes with electricity for water and space heating, cooking, clothes drying and other general energy needs. Increases in the price of natural gas or decreases in the price of other energy sources could impact adversely our competitive position by decreasing the price benefits of natural gas to the consumer. Customers and builders typically make the decision on the type of equipment at initial installation and use the chosen energy source for the life of the equipment. Changes in the competitive position of natural gas relative to electricity and other energy products have the potential to cause a decline in consumption or in the number of natural gas customers.

Consumer or government-mandated conservation efforts, higher natural gas costs or decreases in the price of other energy sources also may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other nonprice factors. Technological improvements in other energy sources and events that impair the public perception of the nonprice attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business and affecting adversely our financial condition, results of operations and cash flows.

Our business activities are concentrated in three states.

We provide natural gas distribution services to customers in Oklahoma, Kansas and Texas. Changes in the regional economies, politics, regulations and weather patterns of these states could impact adversely the growth opportunities available to us and the usage patterns and financial condition of our customers. This could affect adversely our financial condition, results of operations and cash flows.

The availability of adequate natural gas pipeline transportation and storage capacity and natural gas supply may decrease and impair our ability to meet customers’ natural gas requirements and reduce our earnings.

In order to meet customers’ natural gas demands, we must obtain sufficient natural gas supplies, pipeline transportation and storage capacity. If we are unable to obtain these, our ability to meet our customers’ natural gas requirements could be impaired and our financial condition and results of operations may be impacted adversely. A significant disruption to or reduction in natural gas supply, pipeline capacity or storage capacity due to events including, but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions, could reduce our normal supply of natural gas and thereby reduce our earnings.

A downgrade in our credit ratings could affect adversely our cost of and ability to access capital.

Our ability to obtain adequate and cost-effective financing depends in part on our credit ratings. A negative change in our ratings by our rating agencies could affect adversely our costs of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit our access to public and private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, it could limit our ability to obtain additional financing in the future for working capital, capital expenditures and acquisitions. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could affect adversely our results of operations and cash flows by limiting our ability to earn our allowed rate of return.

We are subject to new and existing laws and regulations that may require significant expenditures or significant increases in operating costs or result in significant fines or penalties for noncompliance.

Our business and operations are subject to regulation by a number of federal agencies, including FERC, DOT, OSHA, EPA, CFTC and various regulatory agencies in Oklahoma, Kansas and Texas, and we are subject to numerous federal and state laws and regulations. Future changes to laws, regulations and policies may impair our ability to compete for business or to recover costs and may increase the cost of our operations. Furthermore, because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting our operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under

the Natural Gas Act of 1938, as amended, to impose penalties for current violations of up to $1 million per day for each violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. Our failure to comply with applicable regulations could result in a material adverse effect on our business, financial condition, results of operations and cash flows.

We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could affect adversely our financial results.

The workplaces associated with our facilities are subject to the requirements of DOT and OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. The failure to comply with DOT, OSHA and state requirements or general industry standards, including keeping adequate records or preventing occupational exposure to regulated substances, could expose us to civil or criminal liability, enforcement actions, and regulatory fines and penalties and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are subject to environmental regulations, which could affect adversely our operations or financial results.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to environmental and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. The failure to comply with these laws, regulations and other requirements could expose us to civil or criminal liability, enforcement actions and regulatory fines and penalties and could have a material adverse effect on our business, financial condition, results of operations and cash flows. We also own or retain liability for certain environmental conditions at 12 former manufactured natural gas sites in Kansas, and expenses related to these sites could affect adversely our business, results of operations and cash flows.

We are subject to pipeline safety and system integrity laws and regulations that may require significant expenditures, significant increases in operating costs or, in the case of noncompliance, substantial fines.

We are subject to the Pipeline Safety Improvement Act, which requires companies like us that operate high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. Further, the Pipeline Safety, Regulatory Certainty and Job Creation Act increased the maximum penalties for violating federal pipeline safety regulations and directed the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. Compliance with existing or new laws and regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our customers or may impact materially our competitive position relative to other energy providers. Failure to comply with such laws and regulations may result in fines, penalties or injunctive measures that would not be recoverable from customers in rates and could result in a material adverse effect on our financial condition, results of operations and cash flows. The failure to comply with these laws, regulations and other requirements could expose us to civil or criminal liability, enforcement actions, and regulatory fines and penalties and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Climate change, carbon neutral or energy-efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, affecting adversely our growth, cash flows and results of operations.

The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide. Such laws or regulations could impose costs tied to carbon emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could impact adversely the reputation of fossil fuel products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new or existing customers, affecting adversely our business, results of operations and cash flows.

We are subject to physical and financial risks associated with climate change.

There is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues and cash flows. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues and cash flows by affecting natural gas prices. Severe weather impacts our operating territories primarily through thunderstorms, tornados and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could affect adversely our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits related to or against greenhouse gas emitters based on the claimed connection between greenhouse gas emissions and climate change, which could impact adversely our business, results of operations and cash flows.

Demand for natural gas is highly weather sensitive and seasonal, and weather conditions may cause our earnings to vary from year to year.

Our earnings can vary from year to year, depending in part on weather conditions, which directly influence the volume of natural gas delivered to customers. Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas requirements are for heating during the winter months. Warmer-than-normal weather can reduce our utility margins as customer consumption declines. We have implemented weather normalization mechanisms in Oklahoma, Kansas and portions of Texas, which are designed to limit our earnings sensitivity to weather. Weather normalization mechanisms allow us to increase customer billings to offset lower natural gas usage when weather is warmer than normal and decrease customer billings to offset higher natural gas usage when weather is colder than normal. If our rates and tariffs are modified to curtail such weather protection programs, then we would be exposed to additional risk associated with weather. As a result of occurrences of the foregoing, our results of operations and cash flows could vary and be impacted adversely.

We may not be able to complete necessary or desirable pipeline expansion or infrastructure development projects, which may delay or prevent us from serving our customers or expanding our business.

In order to serve new customers or expand our service to existing customers, we may need to maintain, expand or upgrade our distribution and/or transmission infrastructure, including laying new distribution lines. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to construction or other material components of an infrastructure development project. As a result, we may not be able to serve adequately existing customers or support customer growth, which would impact adversely our business, stakeholder perception, financial condition, results of operations and cash flows.

We may pursue acquisitions, divestitures and other strategic opportunities, the success of which may impact adversely our results of operations, cash flows and financial condition.

As part of our strategic objectives, we may pursue acquisitions to complement or expand our business, as well as divestures and other strategic opportunities. We may not be able to successfully negotiate, finance or receive regulatory approval for future acquisitions or integrate the acquired businesses with our existing business and services. Future acquisitions could result in potentially dilutive issuances of equity securities, a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition, the incurrence of debt, contingent liabilities and amortization expenses and substantial goodwill. The effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may affect adversely the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved by regulators) to the detriment of the company. We may be affected materially and adversely if we are unable to integrate successfully businesses that we acquire.

An impairment of goodwill and long-lived assets could reduce our earnings.

At December 31, 2014, we had approximately $158 million of goodwill recorded on our balance sheet. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on our equity and balance sheet leverage as measured by debt to total capitalization, which could impact adversely our financial condition and results of operations.

We may be unable to access capital or our cost of capital may increase significantly.

Our ability to obtain adequate and cost-effective financing is dependent upon the liquidity of the financial markets, in addition to our financial condition and credit ratings. Disruptions in the capital and credit markets could affect adversely our ability to access short-term and long-term capital. Access to funds under our ONE Gas Credit Agreement will be dependent on the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity. Disruptions and volatility in the global credit markets could cause the interest rate we pay on our ONE Gas Credit Agreement, which is based on LIBOR, to increase. This could result in higher interest rates on future financings, and could impact the liquidity of the lenders under our ONE Gas Credit Agreement, potentially impairing their ability to meet their funding commitments to us. Disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation or failures of significant financial institutions could affect adversely our access to capital needed for our business. The inability to access adequate capital or an increase in the cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate our dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.

Changes in federal and state fiscal, tax and monetary policy could increase significantly our costs or decrease our cash flows.

Changes in federal and state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and capital spending and decrease our cash flows if we are not able to recover or recover timely such increased costs from our customers. This series of events may increase our rates to customers and thus may impact adversely customer billings and customer growth. Changes in tax rules could affect adversely our cash flows. Any of these events may cause us to increase debt, conserve cash, affect adversely our ability to make capital expenditures to grow the business or other discretionary uses of cash, and could affect adversely our cash flows.

Federal, state and local jurisdictions may challenge our tax return positions.

The preparation of our federal and state tax return filings may require significant judgments, use of estimates and the interpretation and application of complex tax laws. Significant judgment also is required in assessing the timing and amounts of deductible and taxable items. Despite management’s expectation that our tax return positions will be fully supportable, certain positions may be challenged successfully by federal, state and local jurisdictions.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

The terms of our debt agreements contain cross-default provisions, which provide that we will be in default under such agreements in the event of certain defaults under other debt agreements. Accordingly, should an event of default occur under any of those agreements, we would face the prospect of being in default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness simultaneously. In such an event, we may not be able to obtain alternative financing or, if we are able to obtain such financing, we may not be able to obtain it on terms acceptable to us, which would affect adversely our ability to implement our business plan, have flexibility in planning for, or reacting to, changes in our business, make capital expenditures and finance our operations.

The cost of providing pension and other postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase. In addition, the passage of the Patient Protection and Affordable Care Act in 2010 could increase the cost of health care benefits for our employees. Further, the costs to us of providing such benefits and related funding requirements are subject to the continued and timely recovery of such costs through our rates.

We have defined benefit pension plans and other postretirement welfare plans for certain employees. Liabilities related to employee and retiree benefit plans following our separation from ONEOK generally were assigned based on the individual’s last employment, so each individual who retired from ONEOK while providing service to the natural gas distribution segment or was assigned to ONE Gas following our separation had his or her benefit plan liabilities assigned to ONE Gas. Employee and retiree benefit liabilities relating to all other personnel not meeting one of the two criteria above remained the liability of ONEOK. Assets in the benefit plans were assigned in accordance with the applicable rules and regulations associated with the division of a single plan into separate plans.

Our defined benefit plans are closed to new participants, and our other postretirement welfare plans only subsidize costs for providing postretirement medical benefits for certain grandfathered participants. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and other postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries, and changes in health care costs.

Any sustained declines in equity markets and reductions in bond yields may have a material adverse effect on the value of our pension and other postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension and other postretirement benefit plans may be required, which could have a material adverse impact on our financial condition and cash flows.

In addition, the costs of providing health care benefits to our employees could increase over the next five to ten years due in large part to the Patient Protection and Affordable Care Act of 2010. The future costs of compliance with its provisions are difficult to measure at this time. Also, our costs of providing such benefits and related funding requirements could also increase materially in the future, depending on the timing of the recovery, if any, of such costs through our rates, which could impact adversely our financial condition and cash flows.

Our business is subject to operational hazards and unforeseen interruptions that could affect materially and adversely our business and for which we may not be insured adequately.

We are subject to all of the risks and hazards typically associated with the natural gas distribution business. Operating risks include, but are not limited to, leaks, pipeline ruptures and the breakdown or failure of equipment or processes. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision of equipment with our pipeline facilities (for example, this may occur if a third-party were to perform excavation or construction work near our facilities) and catastrophic events, such as tornados, hurricanes, earthquakes, floods or other similar events beyond our control. It is also possible that our facilities could be direct targets or indirect casualties of an act of terrorism, including cyber attacks. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage caused to or by employees, customers, contractors, vendors and other third parties. The location of pipeline facilities near populated areas, including residential areas, commercial business centers and industrial gathering places, could increase the level of damages resulting from these risks. Liabilities incurred and interruptions to the operations of our pipelines or other facilities caused by such an event could reduce revenues generated by us and increase expenses, which could have a material adverse effect on our financial condition, results of operations and cash flows. Additionally, our regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would affect adversely our earnings and cash flows.

While we have general liability and property insurance currently in place in amounts that we consider appropriate based on our assessment of business risk and best practices in our industry and in general business, such policies are subject to certain limits and deductibles. Further, we are not fully insured against all risks inherent in our business. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all.

The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The

occurrence of any of the foregoing could have a material adverse effect on our financial condition, results of operations and cash flows.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be affected adversely. Our financial results could also be affected adversely if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations organizations, and this may subject our business to increased risks. Any future cyber security attacks that affect our distribution facilities, our customers or any financial data could have a material adverse effect on our businesses. In addition, cyber attacks on our customer and employee data may result in a financial loss and may impact adversely our reputation. Third-party systems on which we rely could also suffer operational system failure.

The foregoing events could affect adversely our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our business, financial condition and results of operations could be affected adversely.

Our business could be affected adversely by strikes or work stoppages by our unionized employees.

At February 1, 2015, approximately 700 of our estimated 3,300 employees were represented by collective-bargaining units under collective-bargaining agreements. We are involved periodically in discussions with collective-bargaining units representing some of our employees to negotiate or renegotiate labor agreements. We cannot predict the results of these negotiations, including whether any failure to reach new agreements will have a negative effect on our business, financial condition and results of operations or whether we will be able to reach any agreement with the collective-bargaining units. Any failure to reach agreement on new labor contracts might result in a work stoppage. Any future work stoppage could, depending on the operations and the length of the work stoppage, have a material adverse effect on our financial condition and results of operations.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could affect adversely operations and cash flows. Further, we may be unable to attract and retain professional and technical employees, which could impact adversely our earnings.

Our operations require skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the natural gas distribution business has caused us to conduct certain operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the difficulty of attracting new workers to the natural gas distribution industry. This shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on labor productivity and costs and our ability to meet the needs of our customers in the event there is an increase in the demand for our products and services, which could affect adversely our business and cash flows.

Our ability to implement our business strategy and serve our customers is dependent upon our ability to employ talented professionals and attract and retain a skilled, high-performing workforce. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of retiring employees. Without a skilled workforce, our ability to provide quality service to our customers and meet our regulatory requirements will be challenged, and this could impact adversely our business, financial condition, results of operations and cash flows.

Changes in accounting standards may impact adversely our financial condition and results of operations.

The SEC is considering whether issuers in the United States should be required to prepare financial statements in accordance with IFRS instead of the current GAAP. IFRS is a comprehensive set of accounting standards promulgated by the IASB, which are currently in effect for most other countries in the world. Unlike GAAP, IFRS does not provide currently an industry

accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other potential changes associated with the adoption of IFRS, may impact adversely our reported financial condition and results of operations should adoption of IFRS be required.

Our financing arrangements subject us to various restrictions that could limit our operating flexibility.

The covenants in the indenture governing our senior notes and our ONE Gas Credit Agreement restrict our ability to create or permit certain liens, to consolidate or merge or to convey, transfer or lease substantially all of our properties and assets.

The ONE Gas Credit Agreement includes a requirement that our debt to total capital ratio may not exceed 70 percent as of the end of any calendar quarter. Events beyond our control could impair our ability to satisfy this requirement. As long as our indebtedness remains outstanding, these restrictive covenants could impair our ability to expand or pursue our growth strategy. In addition, the breach of any covenants or any payment obligations in any of these debt agreements will result in an event of default under the applicable debt instrument. If there were an event of default under one of our debt agreements, the holders of the defaulted debt may have the ability to cause all amounts outstanding with respect to that debt to be due and payable, subject to applicable grace periods. This could trigger cross-defaults under our other debt agreements, including our senior notes. Forced repayment of some or all of our indebtedness would reduce our available cash and have an adverse impact on our financial condition and results of operations.

Some of our debt, including borrowings under our ONE Gas Credit Agreement, is based on variable rates of interest, which could result in higher interest expenses in the event of an increase in interest rates.

In the future, we could be exposed to fluctuations in variable interest rates. This increases our exposure to fluctuations in market interest rates. Amounts borrowed under the ONE Gas Credit Agreement are based on variable rates of interest. The interest rates on those borrowings will vary depending on a fluctuating base rate or a rate based off of LIBOR at our selection. If these rates rise, the interest rate on this debt will also increase. Therefore, an increase in these rates may increase our interest payment obligations and have a negative effect on our cash flows and financial position.

RISKS RELATING TO THE SEPARATION

We may be unable to achieve some or all of the benefits that we expect to achieve from our separation from ONEOK.

We may be unable to achieve the full strategic and financial benefits that we expect will result from our separation from ONEOK or such benefits may be delayed or may not occur at all. For example, there can be no assurance that analysts and investors will regard our corporate structure as clearer and simpler than the ONEOK corporate structure prior to the separation or place a greater value on our company as a stand-alone company than on our business as a part of ONEOK. In addition, we may not be able to allocate capital more efficiently or attract a more focused investor base.

We were recently separated from ONEOK, our former parent company, and, therefore, we have limited operating history as a separate, publicly traded company.

The historical financial information prior to our separation from ONEOK included in this Annual Report does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate, publicly traded company during those periods primarily as a result of the following factors:

•

Prior to the separation our business was operated by ONEOK as part of its broader corporate organization, rather than as a separate, publicly traded company. ONEOK or one of its affiliates performed various corporate functions for us, including, but not limited to, information technology, accounts payable, cash management, treasury, tax administration, legal, regulatory, certain governance functions (including compliance with the Sarbanes-Oxley Act of 2002, Dodd-Frank Wall Street Reform and the Consumer Protection Act of 2010), and internal audit and external reporting. Our historical financial results prior to the separation reflect allocations of corporate expenses from ONEOK for these and similar functions. These allocations may be inconsistent with what our expenses would have been as a separate, publicly traded company.

•

Prior to the separation we shared economies of scope and scale in costs, employees and vendor relationships with ONEOK. While we entered into a short-term transition agreement that will govern certain commercial and other relationships among us and ONEOK, those contractual arrangements may not capture the benefits our business historically received. The loss of these benefits of scope and scale may have an adverse effect on our business,

results of operations, financial condition and liquidity.

•

Prior to the separation, ONEOK incurred separation costs for professional services, including financial advisors, legal, accounting, information technology, human resources and other business consultants. ONEOK did not allocate these separation costs to us. Subsequent to the separation, we have incurred additional expenses as a result of being a stand-alone publicly traded company. Under the terms of the Separation and Distribution Agreement between us and ONEOK, we are responsible for all costs and expenses that we incur as a stand-alone company after the separation.

We are responsible for certain contingent and other liabilities related to the historical natural gas distribution business of ONEOK, as well as a portion of any contingent corporate liabilities of ONEOK that do not relate to either the natural gas distribution business or ONEOK’s remaining businesses.

Under the Separation and Distribution Agreement between us and ONEOK, we assumed and are responsible for certain contingent and other corporate liabilities related to the historical natural gas distribution business of ONEOK (including associated costs and expenses, whether arising prior to, at, or after our separation). In addition, under the Separation and Distribution Agreement we are also responsible for a portion of any contingent corporate liabilities of ONEOK that do not relate to either our business or the business of ONEOK following the separation (for example, liabilities associated with certain corporate activities not specifically attributable to either business). If we are required to indemnify ONEOK or are otherwise liable for these liabilities, they may have a material adverse effect on our financial condition, results of operations and cash flows.

Third parties may seek to hold us responsible for liabilities of ONEOK that we did not assume in our agreements.

Third parties may seek to hold us responsible for retained liabilities of ONEOK. Under our agreements with ONEOK, ONEOK has agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure that we will be able to recover the full amount of our losses from ONEOK.

Our prior and continuing relationship with ONEOK exposes us to risks attributable to businesses of ONEOK.

ONEOK is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of ONEOK. Any claims made against us that are properly attributable to ONEOK in accordance with these arrangements require us to exercise our rights under our agreements with ONEOK to obtain payment from ONEOK. We are exposed to the risk that, in these circumstances, ONEOK cannot, or will not, make the required payment.

The ownership by our executive officers and some of our directors of shares of common stock of ONEOK and limited partnership units of ONEOK Partners and the service of certain of our directors on the boards of ONEOK and ONEOK Partners may create, or may create the appearance of, conflicts of interest.

Because of their current or former positions with ONEOK, substantially all of our executive officers, including our chief executive officer, and some of our nonemployee directors, own shares of ONEOK common stock and limited partnership units of ONEOK Partners. Accordingly, immediately following ONEOK’s distribution of all of the shares of our outstanding common stock to ONEOK shareholders, these officers and nonemployee directors owned, and may continue to own, shares of both ONEOK and our common stock. The individual holdings of common stock and limited partnership units may be significant for some of these persons compared with these persons’ total assets. Certain of our directors, who currently comprise a minority of the overall composition of our board, also serve on the boards of ONEOK and/or ONEOK Partners. Ownership by our directors and officers of common stock of ONEOK and limited partnership units of ONEOK Partners and board service on the ONEOK and/or ONEOK Partners boards may create, or may create the appearance of, conflicts of interest when these directors and officers are faced with decisions that could have different implications for ONEOK and ONEOK Partners than the decisions do for us.

If the distribution, together with certain related transactions, were to fail to qualify as a tax-free transaction for U.S. federal income tax purposes under Sections 355, 368(a)(1)(D) and other related provisions of the Code, then ONEOK and/or its shareholders could incur significant U.S. federal income tax liabilities, and we could incur significant indemnity obligations.

ONEOK received an IRS Ruling to the effect that the distribution, together with certain related transactions, qualified as tax-free to ONEOK, us and the ONEOK shareholders under Sections 355, 368(a)(1)(D) and other related provisions of the Code. ONEOK also received an opinion of Skadden, Arps, Slate, Meagher & Flom LLP, tax counsel to ONEOK, which opinion relies

on the continued validity of the IRS Ruling, with respect to certain issues relating to the tax-free nature of the transactions that were not addressed in or covered by the IRS Ruling.

The IRS Ruling and the tax opinion rely upon certain assumptions, as well as statements, representations and certain undertakings made by our officers and the officers of ONEOK regarding the past and future conduct of the companies’ respective businesses and other matters. If any of those statements, representations or assumptions are incorrect or untrue in any material respect or any of those undertakings are not complied with, the conclusions reached in the IRS Ruling or the opinion could be affected adversely, and ONEOK and/or its shareholders could be subject to significant tax liabilities. Notwithstanding the IRS Ruling and opinion of tax counsel, the IRS could determine on audit that the distribution, together with certain related transactions, was taxable if it determines that any of these statements, representations, assumptions, or undertakings were not correct or have been violated or if it disagrees with the conclusions in the opinion that were not covered by the IRS Ruling, or for other reasons, including as a result of certain significant changes in the stock ownership of ONEOK or us after the distribution.

If the distribution were subsequently determined, for whatever reason, not to qualify as a transaction that is tax-free for U.S. federal income tax purposes under Sections 355, 368(a)(1)(D), and other related provisions of the Code, ONEOK and/or the holders of ONEOK common stock immediately prior to the distribution could incur significant tax liabilities, and, in certain circumstances as described further under "Certain Relationships and Related Transactions, and Director Independence - Tax Matters Agreement," we will be required to indemnify ONEOK, its subsidiaries, and certain related persons for taxes and related expenses resulting from the distribution, which could be material. Any such indemnity obligation could have a materially adverse impact on our financial condition.

To preserve the tax-free treatment to ONEOK and/or its shareholders of the distribution and certain related transactions, we may not be able to engage in certain transactions.

To preserve the tax-free treatment to ONEOK and/or its shareholders of the distribution and certain related transactions, we are restricted, under the Tax Matters Agreement between us and ONEOK, from taking any action that prevents such transactions from being tax-free for U.S. federal, state and local income tax purposes. These restrictions may limit our ability to pursue certain strategic transactions or engage in other transactions, including using our common stock to make acquisitions and in connection with equity capital market transactions that might increase the value of our business.

RISKS RELATING TO OUR COMMON STOCK

Provisions in our certificate of incorporation, our bylaws, Oklahoma law and certain of the agreements into which we have entered as part of the separation may prevent or delay an acquisition of our company, which could decrease the trading price of our common stock.

Our certificate of incorporation, bylaws and Oklahoma law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the raider and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include, among others:


•	a board of directors that is divided into three classes with staggered terms;


•	rules regarding how shareholders may present proposals or nominate directors for election at shareholder meetings;


•	the right of our board of directors to issue preferred stock without shareholder approval; and


•	limitations on the right of shareholders to remove directors.

Oklahoma law also imposes some restrictions on mergers and other business combinations between us and any holder of 15 percent or more of our outstanding common stock.

We believe these provisions are important for a new public company and protect our shareholders from coercive or otherwise potentially unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make our company immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some shareholders and could delay or prevent an acquisition that our board of directors determines is not in the best interests of our company and our shareholders.

Our ability to pay dividends on our common stock will depend on our ability to generate sufficient positive earnings and cash flows.

Our ability to pay dividends in the future will depend upon, among other things, our future earnings, cash flows and restrictive covenants, if any, under future credit agreements to which we may be a party. Our cash available for dividends will principally be generated from our operations. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to maintain future dividends at the levels we expect or at all. Our ability to pay dividends depends primarily on cash flows, including cash flows from changes in working capital, and not solely on profitability, which is affected by noncash items. As a result, we may pay dividends during periods when we record net losses and may be unable to pay cash dividends during periods when we record net income.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We own approximately 19,000 miles of pipeline and other natural gas distribution facilities in Oklahoma; approximately 13,500 miles of pipeline and other natural gas distribution facilities in Kansas; and approximately 10,000 miles of pipeline and other natural gas distribution facilities in Texas. We lease approximately 1.2 million square feet of office space and other facilities for our operations. In addition, we have 52.3 Bcf of natural gas storage capacity under lease, with maximum allowable daily withdrawal capacity of approximately 1.4 Bcf/d.

ITEM 3. 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.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION, HOLDERS AND DIVIDENDS

Our common stock is listed on the NYSE under the trading symbol “OGS.” The following table sets forth the high and low closing prices of our common stock for the period indicated



	Year Ended
	December 31, 2014*
	High		Low		Dividends
First Quarter	$	35.80	$	31.53	$	—
Second Quarter	$	37.98	$	34.25	$	0.28
Third Quarter	$	37.77	$	34.00	$	0.28
Fourth Quarter	$	44.19	$	34.03	$	0.28
*Our common stock began regular-way trading on February 3, 2014.

At February 6, 2015, there were 15,197 holders of record of our 52,145,396 outstanding shares of common stock.

In January 2015, we declared a dividend of $0.30 per share ($1.20 per share on an annualized basis), payable on March 2, 2015, to shareholders of record as of February 20, 2015.

Employee Stock Award Program

Under the Employee Stock Award Program, we have issued, for no monetary consideration, one share of our common stock to all eligible employees when the per-share closing price of our common stock on the NYSE closes for the first time at or above each $1.00 increment above $34. Shares issued to employees under this program during 2014 totaled 35,324, and compensation expense related to the Employee Stock Award Program was $2.5 million.

The total number of shares of our common stock available for issuance under this program is 125,000. The shares issued under this program have not been registered under the Securities Act, in reliance upon the position taken by the SEC (see Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not require registration under the Securities Act. See Note 11 of the Notes to Financial Statements in this Annual Report for additional information.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth ONE Gas selected financial data for each of the periods indicated:



	Years Ended December 31,
	2014		2013		2012		2011		2010
	(Millions of dollars except per share data)
Revenues	$	1,818.9	$	1,690.0	$	1,376.6	$	1,621.3	$	1,817.4
Net margin	$	827.0	$	813.0	$	756.4	$	751.8	$	754.9
Operating income	$	225.3	$	220.3	$	215.7	$	199.7	$	225.6
Net income	$	109.8	$	99.2	$	96.5	$	86.8	$	106.4
Total assets	$	4,649.2	$	3,846.5	$	3,491.3	$	3,285.5	$	3,095.1
Long-term line of credit with ONEOK	$	—	$	1,027.6	$	1,027.6	$	912.4	$	756.4
Long-term debt, including current maturities	$	1,201.3	$	1.3	$	1.5	$	1.9	$	2.2
Basic earnings per share	$	2.10	$	1.90	$	1.84	$	1.66	$	2.03
Diluted earnings per share	$	2.07	$	1.90	$	1.84	$	1.66	$	2.03
Dividends declared per common share	$	0.84	—		—		—		—

Prior to 2014, historical basic and diluted earnings per share for the periods presented were calculated based on the number of shares distributed to ONEOK shareholders on separation plus any shares associated with fully vested stock awards that had not been issued and considered outstanding as of the beginning of each period prior to the separation. See Note 1 of the Notes to Financial Statements in this Annual Report for additional information on earnings per share.


ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our audited financial statements and Notes to Financial Statements in this Annual Report.

EXECUTIVE SUMMARY

We are a 100 percent regulated natural gas utility. As such, our regulators determine the rates we are allowed to charge for our service based on our revenue requirements needed to achieve our authorized rates of return. We earn revenues from the delivery of natural gas, but do not earn a profit on the natural gas that we deliver, as those costs are passed through to our customers at cost. The primary components of our revenue requirements are the amount of capital invested in our business, which is also known as rate base, our allowed rate of return on our capital investments and our recoverable operating expenses, including depreciation and income taxes. Our rates have both a fixed and a variable component, with approximately 71 percent and 69 percent of our natural gas sales net margin in 2014 and 2013, respectively, derived from fixed monthly charges to our customers. The variable component of our rates is dependent on the consumption of natural gas, which is impacted primarily by the weather and, to a lesser extent, economic activity. While we have weather normalization mechanisms in most jurisdictions, which adjust customers’ bills when the actual heating degree days differ from normalized heating degree days, these mechanisms are in place for only a portion of the year and do not offset all fluctuations in usage resulting from weather variability. Accordingly, the weather can have either a positive or negative impact on our financial performance.

Our financial performance is thus contingent on a number of factors, including: (1) regulatory outcomes, which dictate the returns we are authorized to earn and the rates we are allowed to charge for our service; (2) the performance of the financial markets, which influences the rates of return authorized by our regulators; (3) the consumption of natural gas, which impacts the amount of our net margin derived from the variable component of our rates; (4) our operating performance, which impacts our operating expenses; and (5) the perceived value of natural gas relative to other energy sources, particularly electricity, which influences our customers’ choice of natural gas to provide a portion of their energy needs.

We are subject to regulatory requirements for pipeline safety and environmental compliance. These requirements impact our operating expenses and the level of capital expenditures required for compliance. Historically, our regulators have allowed recovery of these expenditures. However, we are unable to predict the impact that new regulatory requirements will have on our operating expenses or the level of our capital expenditures. Although we believe our regulators will continue to allow recovery of such expenditures in the future, we cannot be assured of that outcome.

RECENT DEVELOPMENTS

Distribution - On January 8, 2014, ONEOK’s board of directors approved the distribution of all the shares of our common stock to holders of ONEOK common stock.

In order to allow ONEOK to effect the distribution, we requested, and the SEC declared effective, our Registration Statement on Form 10 on January 10, 2014. ONEOK transferred all of the assets and liabilities primarily related to its natural gas distribution business to us. Assets and liabilities included accounts receivable and payable, natural gas in storage, regulatory assets and liabilities, pipeline and other natural gas distribution facilities, customer deposits, employee-related assets and liabilities, including amounts attributable to pension and other postretirement benefits, tax-related assets and liabilities and other assets and liabilities primarily associated with providing natural gas distribution service in Oklahoma, Kansas and Texas. Cash and certain corporate assets, such as office space in the corporate headquarters and certain IT hardware and software, were not transferred to us; however, the Transition Services Agreement between ONEOK and us provided temporary access to such corporate assets as necessary to operate our business prior to obtaining the applicable corporate assets on our own.

Immediately prior to the contribution of the natural gas distribution business to us, ONEOK contributed to the capital of the natural gas distribution business all of the amounts outstanding on the natural gas distribution business’ short-term note payable to and long-term line of credit with ONEOK. We received approximately $1.19 billion of cash from a private placement of senior notes, which were later exchanged for registered notes, then used a portion of those proceeds to fund a cash payment of approximately $1.13 billion to ONEOK. On January 31, 2014, ONEOK distributed one share of our common stock for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of business on January 21, 2014, the record date of the distribution. At the close of business on January 31, 2014, ONE Gas, Inc. became an independent, publicly traded company as a result of the distribution. Our common stock began trading “regular-way” under the ticker symbol “OGS” on the NYSE on February 3, 2014.

In December 2013, we entered into a $700 million revolving credit agreement, which became effective upon the separation.

Dividend - In 2014, we paid dividends totaling $0.84 per share ($0.28 per share in each of our second, third and fourth quarters) on our common stock. In January 2015, a dividend of $0.30 per share ($1.20 per share on an annualized basis) was declared for shareholders of record on February 20, 2015, payable March 2, 2015.

REGULATORY ACTIVITIES

Oklahoma - In October 2013, Oklahoma Natural Gas, together with the Public Utility Division of the OCC, filed a joint application to postpone its 2014 rate case. The joint stipulation and settlement agreement in support of this application was approved by the OCC in January 2014. As a result, Oklahoma Natural Gas filed a PBRC application on March 14, 2014, and will file a rate case in 2015 based on a test year consisting of the 12 months ending March 31, 2015. The March 2014, PBRC filing demonstrated that Oklahoma Natural Gas was earning below the range of allowable return on equity. In June 2014, a joint stipulation and settlement agreement associated with our PBRC filing was reached and contained an increase in base rates of approximately $13.7 million, and an energy-efficiency program true-up and a utility incentive adjustment of $0.9 million. In August 2014, the settlement was approved by the OCC.

In June 2013, the OCC approved the extension of a portfolio of conservation and energy-efficiency programs and authorized recovery of costs and performance incentives through 2016, as well as adjustments to rebate amounts and targets that were requested by Oklahoma Natural Gas. The agreement allows Oklahoma Natural Gas to pursue key energy-efficiency programs and earn up to approximately $1.2 million annually, if program objectives are achieved.

In July 2012, a joint stipulation settling Oklahoma Natural Gas’ annual PBRC filing was approved by the OCC. The settlement granted a $9.5 million rate increase and modified Oklahoma Natural Gas’ PBRC tariff. The modified tariff narrows the range of allowed ROE to a range of 10.0 percent to 11.0 percent from our previous range of 9.75 percent to 11.25 percent, increases the ROE reflected in any rate increase resulting from a revenue deficiency to 10.5 percent from 10.25 percent, and reduces the number of allowed pro forma adjustments that can be proposed by Oklahoma Natural Gas.

Kansas - In August 2014, Kansas Gas Service submitted an application to the KCC requesting an increase in base rates of approximately $3.5 million related to its GSRS. This surcharge is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return on incremental safety-related and government-mandated capital investments made between rate cases. On November 25, 2014, the KCC approved an increase of $3.5 million, which became effective on December 1, 2014.

In December 2013, the KCC approved a settlement agreement between ONEOK, the staff of the KCC, and the Citizens’ Utility Ratepayer Board for the separation from ONEOK of our Kansas Gas Service natural gas distribution business. Among other things, the terms of the settlement agreement include the following:


•	Kansas Gas Service shall not change its base rates prior to January 1, 2017. The time limitation on filing a general rate case to change base rates does not preclude Kansas Gas Service from changing rates or tariffs to recover appropriate costs under its current approved riders and tariffs, including its COGR, ACA, WNA, ATSR and GSRS tariffs;


•	Kansas Gas Service agreed to expense certain costs associated with ONEOK’s acquisition of Kansas Gas Service in 1997 that were previously recorded as a regulatory asset and were being amortized and recovered in rates over a 40-year period. As such, we recorded a noncash charge to income of approximately $10.2 million in the fourth quarter of 2013;


•	The level of pension and other postretirement benefit costs used to calculate Kansas Gas Service’s Pension and Other Postretirement Benefit Trackers was adjusted to $13.6 million from $16.6 million, with a corresponding reduction to revenues; and


•	A one-time contribution to 501(c)(3) organizations of $1.2 million to provide financial assistance for weatherization of housing for low income natural gas customers of Kansas Gas Service that was accrued in the fourth quarter of 2013.

The agreement authorized the transfer of ONEOK’s existing Kansas natural gas distribution assets, certificates of convenience and necessity, franchises and tariffs to us.

In August 2013, Kansas Gas Service filed an application to increase the GSRS by $1.5 million. The KCC approved the final ruling that became effective December 1, 2013.

In October 2012, Kansas Gas Service, the staff of the KCC and the Citizens’ Utility Ratepayer Board filed a joint motion to approve a stipulated settlement agreement granting a $28 million increase in base rates and an $18 million reduction in amounts currently recovered through surcharges, effectively increasing its annual revenues by a net amount of $10 million. The KCC approved this settlement in December 2012, and the new rates were effective January 2013.

In September 2012, the KCC denied Kansas Gas Service’s application to implement an infrastructure-replacement program that would have allowed Kansas Gas Service to accelerate the rate at which it is replacing cast-iron pipe. Costs incurred by Kansas Gas Service to replace cast-iron pipe are eligible for the GSRS.

The KCC approved an application from Kansas Gas Service to increase the GSRS by an additional $2.9 million, effective January 2012.

Texas - GRIP is a capital-recovery mechanism that allows for an interim rate adjustment providing recovery of and a return on incremental capital investments made between rate cases. Texas Gas Service filed requests for interim rate relief under the GRIP statute with the City of Austin, Texas, and surrounding communities in February 2015, for approximately $3.7 million. If approved by the cities, new rates will become effective in April 2015.

In March 2014, Texas Gas Service and the City of El Paso agreed to enter into an annual rate review mechanism called the EPARR in lieu of a filing under the GRIP statute with the City of El Paso. Texas Gas Service filed under the GRIP statute for other cities in the El Paso service area. The EPARR provides for a streamlined review of Texas Gas Service’s revenue requirement based upon an agreed upon capital structure and return on equity. In April 2014, Texas Gas Service filed under the EPARR for an increase in revenues in the City of El Paso, and under the GRIP statute for the remainder of the El Paso service area. In July 2014, the City of El Paso approved an annual increase in revenues of $3.5 million, resulting from the EPARR filing. The GRIP filing for the remainder of the El Paso service area was approved with an increase in revenues of $0.6 million.

Texas Gas Service filed requests for interim rate relief under the GRIP statute with the City of Austin, Texas, and surrounding communities in February 2014 for approximately $5.2 million. The city councils approved the requested increase effective May 2014.

Texas Gas Service filed requests for interim rate relief under the GRIP statute with the cities of Austin, Texas, and surrounding communities in February 2013 and with El Paso, Texas, in April 2013 for approximately $4.1 million and $4.9 million, respectively. In May 2013, the City of Austin approved the requested increase. In July 2013, the City of El Paso denied Texas Gas Service’s GRIP request, which Texas Gas Service appealed to the RRC. In September 2013, the RRC approved Texas Gas Service’s requested increase.

Texas Gas Service filed requests for interim rate relief under the GRIP statute with the cities of Austin, Texas, and surrounding communities in February 2012 and with El Paso, Texas, in April 2012 for approximately $3.5 million and $1.9 million, respectively. In May 2012, the City of Austin approved the requested increase. In July 2012, the City of El Paso approved an increase of $1.3 million.

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 expense. Annual rate increases totaling $4.0 million, $4.2 million and $10.1 million associated with these filings were approved in 2014, 2013 and 2012, respectively.

General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for recognition and accordingly, a writeoff of regulatory assets and stranded costs may be required. In 2013, as part of the KCC settlement for the separation of our Kansas Gas Service assets from ONEOK, we expensed $10.2 million for the remaining balance of certain costs associated with ONEOK’s acquisition of Kansas Gas Service in 1997. There were no writeoffs of regulatory assets resulting from the failure to meet the criteria for capitalization during 2014 or 2012.

Selected Financial Results - The following table sets forth certain selected financial results for our operations for the periods indicated:



							Variances					Variances
	Years Ended December 31,						2014 vs. 2013					2013 vs. 2012
Financial Results	2014		2013		2012		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars, except percentages)
Natural gas sales	$	1,680.1	$	1,558.5	$	1,252.0	$	121.6		8	%	$	306.5		24	%
Transportation revenues	102.3		98.7		88.8		3.6			4	%	9.9			11	%
Cost of natural gas	991.9		876.9		620.2		115.0			13	%	256.7			41	%
Net margin, excluding other revenues	790.5		780.3		720.6		10.2			1	%	59.7			8	%
Other revenues	36.5		32.7		35.8		3.8			12	%	(3.1		)	(9	)%
Net margin	827.0		813.0		756.4		14.0			2	%	56.6			7	%
Operating costs	476.0		447.9		410.5		28.1			6	%	37.4			9	%
Depreciation and amortization	125.7		144.8		130.2		(19.1		)	(13	)%	14.6			11	%
Operating income	$	225.3	$	220.3	$	215.7	$	5.0		2	%	$	4.6		2	%
Capital expenditures	$	297.1	$	292.1	$	272.0	$	5.0		2	%	$	20.1		7	%

The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:



							Variances				Variances
	Years Ended December 31,						2014 vs. 2013				2013 vs. 2012
Net Margin, Excluding Other Revenues	2014		2013		2012		Increase (Decrease)				Increase (Decrease)
Natural gas sales	(Millions of dollars, except percentages)
Residential	$	569.7	$	564.5	$	523.4	$	5.2	1	%	$	41.1	8	%
Commercial and industrial	112.9		111.5		103.8		1.4		1	%	7.7		7	%
Wholesale and public authority	5.6		5.6		4.6		—		—	%	1.0		22	%
Net margin on natural gas sales	688.2		681.6		631.8		6.6		1	%	49.8		8	%
Transportation revenues	102.3		98.7		88.8		3.6		4	%	9.9		11	%
Net margin, excluding other revenues	$	790.5	$	780.3	$	720.6	$	10.2	1	%	$	59.7	8	%

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 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:



							Variances					Variances
	Years Ended December 31,						2014 vs. 2013					2013 vs. 2012
Net Margin on Natural Gas Sales	2014		2013		2012		Increase (Decrease)					Increase (Decrease)
Net margin on natural gas sales	(Millions of dollars, except percentages)
Fixed margin	$	490.4	$	470.6	$	439.3	$	19.8		4	%	$	31.3	7	%
Variable margin	197.8		211.0		192.5		(13.2		)	(6	)%	18.5		10	%
Net margin on natural gas sales	$	688.2	$	681.6	$	631.8	$	6.6		1	%	$	49.8	8	%

2014 vs. 2013 - Net margin increased $14.0 million due primarily to the following:


•	an increase of $16.8 million from new rates, primarily in Texas and Oklahoma;


•	an increase of $5.6 million in residential sales due primarily to customer growth;


•	an increase of $4.7 million from higher volumes due primarily to weather-sensitive transportation customers; and


•	an increase of $2.8 million in CNG revenue and higher line extension revenue from commercial and industrial customers in Oklahoma; offset partially by


•	a decrease of $12.8 million in rider and surcharge recoveries due to a lower ad-valorem surcharge in Kansas and the expiration of the rider associated with the recovery of take-or-pay settlements in Oklahoma, both of which are offset by lower regulatory amortization in depreciation and amortization expense; and


•	a decrease of $3.7 million due primarily to warmer weather in all three states compared with colder-than-normal weather in 2013, net of weather normalization.

Operating costs increased $28.1 million due primarily to the following:


•	an increase of $13.0 million in outside service costs related primarily to $6.8 million of costs associated with our separation from ONEOK and $3.7 million in pipeline maintenance activities;


•	an increase of $12.6 million in insurance, information technology and rent expenses;


•	an increase of $11.0 million in employee-related expenses resulting from higher labor and compensation costs; and


•	an increase of $1.7 million in bad debt expense; offset partially by


•	a decrease of $8.0 million in benefit costs related primarily to lower pension and other postretirement benefit costs resulting from an annual change in the estimated discount rate.

Depreciation and amortization expense decreased due to a decrease in the amortization associated with the ad-valorem surcharge rider in Kansas and the expiration of the take-or-pay rider in Oklahoma, and a decrease associated with the settlement agreement approved by the KCC in 2013 authorizing the separation of the Kansas Gas Service assets from ONEOK to us, whereby Kansas Gas Service agreed to expense a $10.2 million regulatory asset related to a transaction cost recovery offset partially by increased depreciation from our capital expenditures.

2013 vs. 2012 - Net margin increased $56.6 million due primarily to the following:


•	an increase of $36.8 million from new rates in all three states;


•	an increase of $12.5 million due to higher sales volumes due primarily to colder-than-normal weather in all three states compared with warmer than normal weather in 2012; and


•	an increase of $5.9 million from higher transportation volumes due primarily to higher demand from weather-sensitive customers in Kansas.

Operating costs increased $37.4 million due primarily to the following:


•	an increase of $14.3 million in employee-related expense, primarily pension cost increases resulting from an annual change in the estimated discount rate;


•	an increase of $10.1 million in share-based compensation related to share-based compensation awards granted to our direct employees and general and administrative personnel of ONEOK providing services on our behalf due to the appreciation of ONEOK’s share price in 2013;


•	an increase of $7.0 million in ad valorem tax expense primarily as a result of an increase in the level of ad valorem tax expense recovered in base rates, which is offset in net margin. For Kansas Gas Service, actual ad valorem taxes incurred that differ from the level of ad valorem taxes recovered currently in base rates are deferred and recovered or refunded through the ATSR; and


•	an increase of $2.9 million in bad debt expense.

Depreciation and amortization expense increased due primarily to the settlement agreement approved by the KCC authorizing the separation of the Kansas Gas Service assets from ONEOK to us, whereby Kansas Gas Service agreed to expense a $10.2 million regulatory asset related to a transaction cost recovery and an increase in the amortization of amounts previously deferred for ad valorem taxes, which is offset in net margin.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, automated meter reading, extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements and information technology hardware and software. 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 for 2014, compared with 2013, primarily as a result of an increase in information technology hardware and software. Capital expenditures increased $20.1 million for 2013, compared with 2012, primarily as a result of extending service to new areas. Our capital expenditures are expected to be approximately $300 million for 2015.

Selected Operating Information - The following tables set forth certain selected operating information for the periods indicated:



	Years Ended								Variances
	December 31,								2014 vs. 2013
(in thousands)	2014				2013				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	776	578	601	1,955	770	577	597	1,944	6	1	4	11
Commercial and industrial	72	50	34	156	72	50	33	155	—	—	1	1
Wholesale and public authority	—	—	4	4	—	—	3	3	—	—	1	1
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	853	634	640	2,127	847	633	634	2,114	6	1	6	13



	Years Ended								Variances
	December 31,								2013 vs. 2012
(in thousands)	2013				2012				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	770	577	597	1,944	764	577	591	1,932	6	—	6	12
Commercial and industrial	72	50	33	155	71	50	33	154	1	—	—	1
Wholesale and public authority	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	847	633	634	2,114	840	633	628	2,101	7	—	6	13



	Years Ended December 31,
Volumes (MMcf)	2014	2013	2012
Natural gas sales
Residential	125,337	122,855	103,799
Commercial and industrial	38,555	36,956	31,459
Wholesale and public authority	2,454	4,403	6,135
Total volumes sold	166,346	164,214	141,393
Transportation	213,456	205,915	199,408
Total volumes delivered	379,802	370,129	340,801

Residential and commercial and industrial natural gas sales volumes increased for 2014, compared with 2013, due primarily to colder temperatures in the first quarter of 2014. Residential and commercial and industrial natural gas sales volumes increased for 2013, compared with 2012, due primarily to colder temperatures in 2013. The impacts on margins for the periods presented were mitigated largely by weather-normalization mechanisms.

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.



	Years Ended
	December 31,
	2014		2013		2014 vs 2013		2014		2013
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	3,720	3,317	3,848	3,317	(3	)%	112	%	116	%
Kansas	5,179	4,860	5,246	4,860	(1	)%	107	%	108	%
Texas	1,716	1,788	1,942	1,793	(12	)%	96	%	108	%



	Years Ended
	December 31,
	2013		2012		2013 vs 2012		2013		2012
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	3,848	3,317	2,721	3,334	41	%	116	%	82	%
Kansas	5,246	4,860	3,796	4,801	38	%	108	%	79	%
Texas	1,942	1,793	1,492	1,789	30	%	108	%	83	%

Normal HDDs are established through rate proceedings in each of our rate jurisdictions for use primarily in weather normalization billing calculations. Normal HDDs disclosed above are based on:


•	10-year weighted average HDDs as of December 31, 2008, for years 1999-2008, as calculated using 11 weather stations across Oklahoma and weighted on average customer count for Oklahoma;


•	30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using 13 weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas; and


•	HDDs, which are used primarily in the weather normalization billing calculations for each service area of Texas, are weighted using a rolling 10-year average of actual natural gas distribution sales volumes by service area for Texas.

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


•	11 weather stations and customers by month for Oklahoma;


•	13 weather stations and customers by month for Kansas; and


•	9 weather stations and natural gas distribution sales volumes by service area for Texas.

CONTINGENCIES

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.

LIQUIDITY AND CAPITAL RESOURCES

General - From the date of the separation, we have funded operating expenses, working capital requirements, including purchases of natural gas, and capital expenditures primarily with cash from operations, the retained proceeds from our private placement of senior notes in January 2014 and our commercial paper program. Prior to the separation, we relied primarily on operating cash flow and participation in ONEOK’s cash management program for our liquidity and capital resource requirements.

We entered into the ONE Gas Credit Agreement, which is a $700 million unsecured revolving credit facility that became effective upon our separation from ONEOK. In July 2014, we entered into a commercial paper program to support our working capital requirements and general corporate needs.

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

Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions and our financial condition and credit ratings. We believe that stronger credit ratings will provide a significant advantage to our business. By maintaining a conservative financial profile and stable revenue base, we believe that we will be able to maintain an investment-grade credit rating, which we believe will provide us access to diverse sources of capital at more favorable rates in order to finance our infrastructure investments. Credit rating agencies perform independent analyses when assigning credit

ratings. A downgrade of our investment-grade rating would increase our future cost of borrowing and affect adversely our available liquidity.

Short-term Financing - We entered into the ONE Gas Credit Agreement, which is scheduled to expire in January 2019. 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. The ONE Gas Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, indebtedness of subsidiaries, investments, changes in the nature of business, fundamental changes, transactions with affiliates, burdensome agreements, and use of proceeds. In the event of a breach of certain covenants by ONE Gas, amounts outstanding under the ONE Gas Credit Agreement may become due and payable immediately. At December 31, 2014, our total debt-to-capital ratio was 41 percent, and we were in compliance with all covenants under the ONE Gas Credit Agreement.

The ONE Gas Credit Agreement includes a $50 million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.2 billion from $700 million, upon satisfaction of customary conditions, including receipt of commitments from new lenders or increased commitments from existing lenders. Borrowings made under the facility are available for general corporate purposes. The ONE Gas Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Based on our current credit ratings, borrowings, if any, will accrue interest at LIBOR plus 79.5 basis points, and the annual facility fee is 8 basis points.

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

In July 2014, we entered into a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor.

At December 31, 2014, we had issued $42.0 million in the form of commercial paper, $1.0 million in letters of credit outstanding and had approximately $11.9 million of cash and cash equivalents. At December 31, 2014, we had no borrowings and $657.0 million of credit available under the ONE Gas Credit Agreement. The weighted-average interest rate on our commercial paper was 0.32 percent at December 31, 2014.

Debt Issuance - In January 2014, we completed a private placement of senior 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 senior notes due 2044 (collectively, our “Senior Notes”). The net proceeds from the private placement were approximately $1.19 billion and were used to fund a one-time cash payment to ONEOK of approximately $1.13 billion as part of the separation. The remaining portion of the net proceeds was retained in order to provide sufficient financial flexibility and to support working capital requirements and capital expenditures.

In connection with the issuance of our privately placed senior notes, we entered into a registration rights agreement, pursuant to which we were obligated to use our commercially reasonable efforts to file with the SEC and cause to become effective a registration statement with respect to an offer to exchange each series of our privately placed senior notes for new notes via a noncash exchange, with terms substantially identical in all material respects to each such series of our privately placed senior notes. Our registration statement, as amended, was declared effective by the SEC on September 5, 2014. We completed the noncash exchange of our privately placed senior notes for our registered Senior Notes in October 2014.

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.

We may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, we may redeem these Senior Notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective Senior Notes plus

accrued and unpaid interest to the redemption date. Our Senior Notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.

Treasury Shares - In February 2015, our Board of Directors authorized us to purchase treasury shares to be used to offset shares issued under our employee and non-employee director equity compensation, dividend reinvestment and employee stock purchase plans. The Board of Directors established an annual limit of $20 million of treasury stock purchases, exclusive of funds received through the dividend reinvestment and employee stock purchase plans. Stock purchases may be made in the open market or in private transactions at times, and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we may purchase, and we can terminate or limit the program at any time.

Credit Ratings - Our credit ratings as of January 31, 2015 were:



Rating Agency	Rating	Outlook
Moody’s	A2	Stable
S&P	A-	Stable

Our commercial paper is currently rated Prime-1 by Moody’s and A-2 by S&P. We intend to maintain strong credit metrics while we pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

Capitalization structure - As of December 31, 2014, our total capitalization structure is 41 percent debt to 59 percent equity.

Pension and Other Postretirement Benefit Plans - Information about our pension and other postretirement benefits plans, including anticipated contributions, is included under Note 12 of the Notes to Financial Statements in this Annual Report.

CASH FLOW ANALYSIS

Prior to the separation, we utilized ONEOK’s centralized cash management program that concentrated the cash assets of its operating divisions and subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Under this cash management program, depending on whether we had a short-term cash surplus or cash requirement, we provided cash to ONEOK or ONEOK provided cash to us when necessary. Subsequent to the separation, we maintain separate cash accounts from ONEOK, and our interest expense is related only to our borrowings.

We use the indirect method to prepare our Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments and changes in our assets and liabilities not classified as investing or financing activities during the period. Items that impact net income but may not result in actual cash receipts or payments include, but are not limited to, depreciation and amortization, deferred income taxes, share-based compensation expense and provision for doubtful accounts.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:



										Variances			Variances
	Years Ended December 31,									2014 vs. 2013			2013 vs. 2012
	2014			2013			2012			Increase (Decrease)			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	246.6		$	154.2		$	196.6		$	92.4		$	(42.4	)
Investing activities	(297.1		)	(290.7		)	(270.6		)	(6.4		)	(20.1		)
Financing activities	59.2			135.7			73.5			(76.5		)	62.2
Change in cash and cash equivalents	8.7			(0.8		)	(0.5		)	9.5			(0.3		)
Cash and cash equivalents at beginning of period	3.2			4.0			4.5			(0.8		)	(0.5		)
Cash and cash equivalents at end of period	$	11.9		$	3.2		$	4.0		$	8.7		$	(0.8	)

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

2014 vs. 2013 - Cash flows from operating activities increased in 2014, compared to 2013, due primarily to the collection of trade receivables, payment of trade payables and the recovery of natural gas purchase costs through our purchased-gas cost adjustment mechanisms. The timing of cash collections from customers and payments to vendors and suppliers vary from period to period in the normal course of business and directly impact our cash flows from operations.

2013 vs. 2012 - Cash flows from operating activities decreased in 2013, compared to 2012, due primarily to the collection of trade receivables, payment of trade payables and the recovery of natural gas purchase costs through our purchased-gas cost adjustment mechanisms. The timing of cash collections from customers and payments to vendors and suppliers vary from period to period in the normal course of business and directly impact our cash flows from operations.

Investing Cash Flows - 2014 vs. 2013 - Cash used in investing activities increased for 2014, compared to 2013, due primarily to capital expenditures for information technology hardware and software associated with our separation from ONEOK.

2013 vs. 2012 - Cash used in investing activities increased for 2013, compared to 2012, due primarily to capital expenditures for pipeline replacements.

Financing Cash Flows - 2014 vs. 2013 - Cash used in financing activities decreased for 2014, compared with 2013 due primarily to the $1.19 billion debt issuance and $1.13 billion cash payment to ONEOK in connection with our separation from ONEOK in 2014, compared with our participation in ONEOK’s cash management program and our distributions to ONEOK in 2013.

2013 vs. 2012 - The changes in cash flows from financing activities is the result of our participation in ONEOK’s cash management program and distributions to ONEOK.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

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 involves typically 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 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.

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 2014, 2013 and 2012. We do not expect to incur material expenditures for these matters in the future.

Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. The Pipeline Safety Improvement Act requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act 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.

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

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

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

Additional information about our environmental matters is included in the sections entitled “Environmental and Safety Matters” and “Environmental Matters” in Item 1 and Note 14 of the Notes to Financial Statements in this Annual Report, respectively. 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 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 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 2014, 2013 and 2012. We do not expect to incur material expenditures for these matters in the future.

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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 amounts 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. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

The following summary sets forth what our management considers to be our most critical accounting policies. Our critical accounting policies are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and that require management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters.

Regulation - Our operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. We account for the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in our financial statements. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable and regulatory liabilities when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. As a result, certain costs that would normally be expensed under GAAP are capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Discontinuing the application of this method of accounting for regulatory assets and liabilities could significantly increase our operating expenses, as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. The impact of regulation on our operations may be affected by decisions of the regulatory authorities or the issuance of new regulations.

For further discussion of regulatory assets and liabilities, see Note 9 of the Notes to Financial Statements in the Annual Audited Financial Statements included elsewhere in this Annual Report.

Impairment of Goodwill - We assess our goodwill for impairment at least annually as of July 1. Our goodwill impairment analysis performed in 2014 and 2013, utilized a qualitative assessment and did not result in any impairment indicators. Subsequent to July 1, 2014, no event has occurred indicating that the fair value is less than the carrying value.

As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that our fair value is less than our carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill. In the first step, an initial assessment is made by comparing our fair value with our book value, including goodwill. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds the implied fair value of the goodwill, we will record an impairment charge.

flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply acquisition multiples to forecasted cash flows. The acquisition multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows over a period of years.

Our impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.

See Note 1 of the Notes to Financial Statements in the Annual Audited Financial Statements for our goodwill disclosure.

Pension and Other Postretirement Benefits - We have defined benefit retirement plans covering certain full-time employees. We also sponsor welfare plans that provide other postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. In connection with the separation from ONEOK, we entered into an Employee Matters Agreement with ONEOK, which provides that our employees no longer participate in benefit plans sponsored or maintained by ONEOK as of the separation date. Effective January 1, 2014, the ONEOK defined benefit pension plans and other postretirement benefit plans transferred assets and obligations related to those employees transferring to ONE Gas and vested participants who are no longer employees to the new ONE Gas plans. As a result, we recorded sponsored pension and other postretirement plan obligations of approximately $1.1 billion, and sponsored pension and other postretirement plan assets of approximately $1.0 billion. Additionally, as a result of the transfer of unrecognized losses from ONEOK, our regulatory assets and deferred income taxes increased $331 million and $86 million, respectively.

Prior to the separation, certain employees participated in similar defined benefit pension plans and other postretirement health and welfare plans (the Plans) sponsored by ONEOK. We accounted for these plans as multiemployer benefit plans. Accordingly, we did not record an asset or liability to recognize the funded status of the Plans. We recognized a liability only for any required contributions to the Plans that were accrued and unpaid at the balance sheet date. The related pension and other postretirement expenses were allocated to us based on plan participants who directly supported our operations. These pension and other postretirement benefit costs included amounts associated with vested participants who are no longer employees. As described in Note 2 of the Notes to Financial Statements in this Annual Report, prior to 2014, ONEOK also charged us for the allocated cost of certain employees of ONEOK who provided general and administrative services on our behalf. ONEOK included an allocation of the benefit costs associated with these ONEOK employees based upon its allocation methodology, not necessarily specific to the employees providing general and administrative services on our behalf. See Note 2 of the Notes to Financial Statements included in this Annual Report for discussion of ONEOK’s allocation methodology.

An actuarial consultant calculates the expense related to our plans, and the Plans, and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit costs, assumptions can change from period to period and may result in material changes in the costs we recognize. As of December 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014. See Note 12 of the Notes to Financial Statements in this Annual Report for additional information.

During 2014, we recorded net periodic benefit costs of $27.1 million and $5.9 million related to our pension plans and other postretirement benefit plans, respectively. We estimate that in 2015, we will record $39.7 million and $6.7 million related to pension plans and other postretirement benefit plans, respectively, prior to regulatory deferrals.

The following table sets forth the weighted-average assumptions used to determine our estimated 2015 net periodic benefit cost related to our defined pension and other postretirement benefit plans, and sensitivity to changes with respect to these assumptions:



	Rate Used		Cost Sensitivity (a)		Obligation Sensitivity (b)
			(Millions of dollars)
Discount rate	4.25	%	$	4.3	$	41.6
Expected long-term return on plan assets	7.75	%	$	2.4	$	—

(a) Approximate impact a quarter percentage point decrease in the assumed rate would have on net periodic pension costs.

(b) Approximate impact a quarter percentage point decrease in the assumed rate would have on defined benefit pension obligation.

Assumed health care cost-trend rates have a significant effect on the amounts reported for our other postretirement benefit plans. A one percentage point change in assumed health care cost trend rates would have the following effects:



	One Percentage Point Increase		One Percentage Point Decrease
	(Millions of dollars)
Effect on total of service and interest cost	$	1.5	$	(1.4	)
Effect on other postretirement benefit obligation	$	6.9	$	(6.7	)

During 2014, we contributed approximately $0.9 million and approximately $9.2 million to our pension plans and other postretirement benefit plans, respectively. In 2015, we expect to contribute approximately $0.9 million and approximately $3.9 million to our defined benefit pension plans and other postretirement benefit plans, respectively.

Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues upon the delivery of natural gas commodity or services rendered to customers. Revenues are accrued for natural gas delivered and services rendered to customers, but not yet billed, based on estimates from the last meter-reading date to month end (accrued unbilled revenue). The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet billed at the end of an accounting period. 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.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect on earnings or cash flows for 2014, 2013 and 2012. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

See Note 14 of the Notes to Financial Statements in the Annual Audited Financial Statements included elsewhere in this Annual Report for additional discussion of contingencies.

CONTRACTUAL OBLIGATIONS

The following table sets forth our contractual obligations at December 31, 2014:



	Contractual Obligations
		(Millions of dollars)
		2015		2016		2017		2018		2019		Thereafter		Total
Commercial paper		$	42.0	$	—	$	—	$	—	$	—	$	—	$	42.0
Long-term debt, including current maturities		—		—		—		—		300.0		901.3		1,201.3
Interest payments on debt		45.1		45.1		45.1		45.1		39.4		688.1		907.9
Firm transportation and storage capacity contracts		192.4		176.5		142.8		100.7		44.7		44.4		701.5
Natural gas purchase commitments		199.4		4.1		4.1		4.1		4.1		3.0		218.8
Employee benefit plans		4.8		7.2		6.5		5.9		5.3		—		29.7
Operating leases		4.7		4.5		4.3		4.0		3.4		10.4		31.3
Total		$	488.4	$	237.4	$	202.8	$	159.8	$	396.9	$	1,647.2	$	3,132.5

Commercial paper - Commercial paper includes short-term notes payable with maturities that may vary but may not exceed 270 days from the date of issue.

Long-term debt and interest payments on debt - Long-term debt includes our three debt issuances at their due dates. Interest payments on debt are calculated by multiplying our long-term debt by the respective coupon rates.

Firm transportation and storage contracts - We are party to fixed-price contracts providing us with firm transportation and storage capacity. The commitments associated with these contracts are recoverable through our purchased-gas cost mechanisms as allowed by the applicable regulatory authority.

Natural gas purchase commitments - We are party to fixed-price and variable-price contracts for the purchase of natural gas. Future variable-price natural gas purchase commitments are estimated based on market price information. Actual future variable-price purchase commitments may vary depending on market prices at the time of delivery. As market information changes daily and is potentially volatile, these values may change significantly. The commitments associated with these contracts are recoverable through our purchased-gas cost mechanisms as allowed by the applicable regulatory authority.

Employee benefit plans - Employee benefit plans include our anticipated contribution to maintain the minimum required funding level for our pension and other postretirement benefit plans for 2015. See Note 12 of the Notes to Financial Statements in this Annual Report for discussion of employee benefit plans.

Operating leases - Our operating leases include leases for office space, facilities and information technology hardware and software.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Annual Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Annual Report identified by 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.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Annual Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:


•	our ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our regulated rates;


•	our ability to manage our operations and maintenance costs;


•	changes in regulation, including the application of market rates by state and local agencies;


•	the economic climate and, particularly, its effect on the natural gas requirements of our residential and

commercial industrial customers;


•	competition from alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels;


•	variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate change;


•	indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors;


•	our ability to secure reliable, competitively priced and flexible natural gas supply;


•	the mechanical integrity of facilities operated;


•	operational hazards and unforeseen operational interruptions;


•	adverse labor relations;


•	the effectiveness of our strategies to reduce earnings lag, margin protection strategies and risk mitigation strategies;


•	our ability to generate sufficient cash flows to meet all of our cash needs;


•	changes in the financial markets during the periods covered by the forward-looking statements, particularly those affecting the availability of capital and our ability to refinance existing debt and fund investments and acquisitions;


•	actions of rating agencies, including the ratings of debt, general corporate ratings and changes in the rating agencies’ ratings criteria;


•	changes in inflation and interest rates;


•	our ability to purchase and sell assets at attractive prices and on other attractive terms;


•	our ability to recover the costs of natural gas purchased for our customers;


•	impact of potential impairment charges;


•	volatility and changes in markets for natural gas;


•	possible loss of LDC franchises or other adverse effects caused by the actions of municipalities;


•	payment and performance by counterparties and customers as contracted and when due;


•	changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;


•	changes in law resulting from new federal or state energy legislation;


•	changes in environmental, safety, tax and other laws to which we and our subsidiaries are subject;


•	advances in technology;


•	population growth rates and changes in the demographic patterns of the markets we serve;


•	acts of nature and the potential effects of threatened or actual terrorism, including cyber attacks and war;


•	the sufficiency of insurance coverage to cover losses;


•	the effects of our strategies to reduce tax payments;


•	the effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries;


•	changes in accounting standards and corporate governance;


•	our ability to attract and retain talented management and directors;


•	the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions;


•	declines in the market prices of debt and equity securities and resulting funding requirements for our defined benefit pension plans;


•	the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;


•	the final resolutions or outcomes with respect to our contingent and other corporate liabilities related to the natural gas distribution business and any related actions for indemnification made pursuant to the Separation and Distribution Agreement;


•	our ability to operate effectively as a separate, publicly traded company; and


•	the costs associated with increased regulation and enhanced disclosure and corporate governance requirements pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Item 1A, Risk Factors, in this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk discussed below includes forward-looking statements. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.

Commodity Price Risk

Our commodity price risk, driven primarily by fluctuations in the price of natural gas, is mitigated by our purchased-gas cost adjustment mechanisms. We use derivative instruments to economically hedge the cost of anticipated natural gas purchases during the winter heating months to protect our customers from upward market price volatility of natural gas. Additionally, we inject natural gas into storage during the summer months and withdraw the natural gas during the winter heating season. Gains or losses associated with these derivative instruments and storage activities are included in, and recoverable through our purchased-gas cost adjustment mechanisms, which are subject to review by regulatory authorities.

Interest-Rate Risk

We are exposed to interest-rate risk primarily associated with new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. We expect to manage interest-rate risk on future borrowings through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates.

Counterparty Credit Risk

We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to provide security, including deposits and other forms of collateral, when appropriate. With more than 2 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. In most jurisdictions, we are able to recover natural gas costs related to uncollectible accounts through our purchased-gas cost adjustment mechanisms.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of ONE Gas, Inc.:

In our opinion, the accompanying balance sheets and the related statements of income, comprehensive income, equity and cash flows present fairly in all material respects, the financial position of ONE Gas, Inc. (the Company) at December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our audits (which were integrated audits in 2014 and 2013). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 19, 2015



ONE Gas, Inc.
STATEMENTS OF INCOME

	Years Ended December 31,
	2014			2013			2012
	(Thousands of dollars, except per share amounts)

Revenues	$	1,818,906		$	1,689,952		$	1,376,649
Cost of natural gas	991,949			876,944			620,260
Net margin	826,957			813,008			756,389
Operating expenses
Operations and maintenance	420,686			393,072			363,120
Depreciation and amortization	125,722			144,758			130,150
General taxes	55,255			54,830			47,405
Total operating expenses	601,663			592,660			540,675
Operating income	225,294			220,348			215,714
Other income	1,625			6,165			3,664
Other expense	(2,949		)	(3,680		)	(2,225		)
Interest expense	(45,842		)	(61,366		)	(60,793		)
Income before income taxes	178,128			161,467			156,360
Income taxes	(68,338		)	(62,272		)	(59,851		)
Net income	$	109,790		$	99,195		$	96,509

Earnings per share (Note 7)
Basic	$	2.10		$	1.90		$	1.84
Diluted	$	2.07		$	1.90		$	1.84

Average shares (thousands)
Basic	52,364			52,319			52,319
Diluted	52,946			52,319			52,319
Dividends declared per share of stock	$	0.84		$	—		$	—

See accompanying Notes to Financial Statements.



ONE Gas, Inc.
STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2014			2013		2012
	(Thousands of dollars)
Net income	$	109,790		$	99,195	$	96,509
Other comprehensive income (loss), net of tax
Change in pension and other postretirement benefit plans liability, net of tax of $1,244, $0, and $0, respectively	(1,781		)	—		—
Total other comprehensive income (loss), net of tax	(1,781		)	—		—
Comprehensive income	$	108,009		$	99,195	$	96,509

See accompanying Notes to Financial Statements.



ONE Gas, Inc.
BALANCE SHEETS

	December 31,		December 31,
	2014		2013
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	4,850,201	$	4,534,074
Accumulated depreciation and amortization	1,556,481		1,489,216
Net property, plant and equipment (Note 10)	3,293,720		3,044,858
Current assets
Cash and cash equivalents	11,943		3,171
Accounts receivable, net	326,749		356,988
Income tax receivable	43,800		—
Natural gas in storage	185,300		166,128
Regulatory assets (Note 9)	50,193		21,657
Other current assets	49,516		54,240
Total current assets	667,501		602,184
Goodwill and other assets
Regulatory assets (Note 9)	478,723		23,822
Goodwill	157,953		157,953
Other assets	51,313		17,658
Total goodwill and other assets	687,989		199,433
Total assets	$	4,649,210	$	3,846,475

See accompanying Notes to Financial Statements.



ONE Gas, Inc.
BALANCE SHEETS
(Continued)
	December 31,			December 31,
	2014			2013
Equity and Liabilities	(Thousands of dollars)
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 52,083,859 shares at December 31, 2014; authorized 1,000 shares, issued and outstanding 100 shares at December 31, 2013	$	521		$	—
Paid-in capital	1,758,796			—
Retained earnings	39,894			—
Accumulated other comprehensive income (loss)	(5,174		)	—
Owner’s net investment	—			1,239,023
Total equity	1,794,037			1,239,023
Long-term debt, excluding current maturities	1,201,311			1,318
Long-term line of credit with ONEOK	—			1,027,631
Total equity and long-term debt	2,995,348			2,267,972
Current liabilities
Current maturities of long-term debt	6			6
Notes payable	42,000			—
Short-term note payable to ONEOK	—			444,960
Affiliate payable	—			22,403
Accounts payable	159,064			169,500
Accrued taxes other than income	44,742			32,426
Accrued liabilities	26,019			4,791
Customer deposits	60,003			57,360
Regulatory liabilities	32,467			17,796
Other current liabilities	28,132			19,835
Total current liabilities	392,433			769,077
Deferred credits and other liabilities
Deferred income taxes	894,585			743,452
Employee benefit obligations	287,779			—
Other deferred credits	79,065			65,974
Total deferred credits and other liabilities	1,261,429			809,426
Commitments and contingencies (Note 14)
Total liabilities and equity	$	4,649,210		$	3,846,475

See accompanying Notes to Financial Statements.

This page intentionally left blank.



ONE Gas, Inc.
STATEMENTS OF CASH FLOWS
	Years Ended December 31,
	2014			2013			2012
	(Thousands of dollars)
Operating activities
Net income	$	109,790		$	99,195		$	96,509
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	125,722			144,758			130,150
Deferred income taxes	49,935			62,205			59,491
Share-based compensation expense	7,613			—			—
Provision for doubtful accounts	7,195			5,460			2,528
Changes in assets and liabilities:
Accounts receivable	23,044			(102,142		)	10,016
Income tax receivable	(43,800		)	—			—
Natural gas in storage	(19,172		)	(63,139		)	30,154
Asset removal costs	(47,125		)	(46,567		)	(47,658		)
Affiliate payable	—			(8,140		)	(7,229		)
Accounts payable	(6,881		)	37,241			(3,950		)
Accrued taxes other than income	12,316			2,449			174
Accrued liabilities	21,228			(5,443		)	(4,511		)
Customer deposits	2,643			(727		)	(1,254		)
Regulatory assets and liabilities	30,067			29,436			(59,338		)
Employee benefit obligation	(10,102		)	—			—
Other assets and liabilities	(15,810		)	(378		)	(8,495		)
Cash provided by operating activities	246,663			154,208			196,587
Investing activities
Capital expenditures	(297,103		)	(292,080		)	(272,014		)
Proceeds from sale of assets	—			1,327			1,462
Cash used in investing activities	(297,103		)	(290,753		)	(270,552		)
Financing activities
Settlement of short-term notes payable to ONEOK, net	—			150,851			58,692
Borrowings on notes payable, net	42,000			—			—
Issuance of debt, net of discounts	1,199,994			—			—
Long-term debt financing costs	(11,087		)	—			—
Borrowings on long-term line of credit with ONEOK	—			—			115,235
Cash payment to ONEOK upon separation	(1,130,000		)	—			—
Issuance of common stock	2,001			—			—
Dividends paid	(43,696		)	—			—
Repayment of long-term debt	—			(206		)	(330		)
Distributions to ONEOK	—			(14,969		)	(100,067		)
Cash provided by financing activities	59,212			135,676			73,530
Change in cash and cash equivalents	8,772			(869		)	(435		)
Cash and cash equivalents at beginning of period	3,171			4,040			4,475
Cash and cash equivalents at end of period	$	11,943		$	3,171		$	4,040
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized	$	21,066		$	—		$	—
Cash paid to ONEOK for interest, net of amounts capitalized	$	—		$	61,366		$	60,793
Cash paid for income taxes	$	44,603		$	—		$	—
Cash paid to ONEOK for income taxes	$	—		$	67		$	360

See accompanying Notes to Financial Statements.



ONE Gas, Inc.
STATEMENTS OF EQUITY

	Common Stock Issued	Common Stock		Paid-in Capital			Retained Earnings
	(Shares)	(Thousands of dollars)

January 1, 2012	—	$	—	$	—		$	—
Net Income	—	—		—			—
Distributions to ONEOK	—	—		—			—
December 31, 2012	—	—		—			—
Net Income	—	—		—			—
Distributions to ONEOK	—	—		—			—
Common stock issued	100	—		—			—
December 31, 2013	100	—		—			—
Net income	—	—		—			84,214
Other comprehensive loss	—	—		—			—
Net transfers from ONEOK (Note 2)	—	—		—			—
Reclassification of Owner’s net investment to paid-in capital	—	—		1,749,078			—
Issuance of common stock at the separation	51,941,136	520		(520		)	—
Common stock issued	142,623	1		9,614			—
Common stock dividends - $0.84 per share	—	—		624			(44,320		)
December 31, 2014	52,083,859	$	521	$	1,758,796		$	39,894

See accompanying Notes to Financial Statements.



ONE Gas, Inc.
STATEMENTS OF EQUITY
(Continued)
	Owner’s Net Investment			Accumulated Other Comprehensive Income (Loss)			Total Equity
	(Thousands of dollars)

January 1, 2012	$	1,158,355		$	—		$	1,158,355
Net Income	96,509			—			96,509
Distributions to ONEOK	(100,067		)	—			(100,067		)
December 31, 2012	1,154,797			—			1,154,797
Net Income	99,195			—			99,195
Distributions to ONEOK	(14,969		)	—			(14,969		)
Common stock issued	—			—			—
December 31, 2013	1,239,023			—			1,239,023
Net income	25,576			—			109,790
Other comprehensive loss	—			(1,781		)	(1,781		)
Net transfers from ONEOK (Note 2)	484,479			(3,393		)	481,086
Reclassification of Owner’s net investment to paid-in capital	(1,749,078		)	—			—
Issuance of common stock at the separation	—			—			—
Common stock issued	—			—			9,615
Common stock dividends - $0.84 per share	—			—			(43,696		)
December 31, 2014	$	—		$	(5,174	)	$	1,794,037

See accompanying Notes to Financial Statements.

ONE Gas, Inc.

NOTES TO FINANCIAL STATEMENTS


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations - ONE Gas, Inc. was a wholly owned subsidiary of ONEOK as of December 31, 2013. We are comprised of ONEOK’s former natural gas distribution business. On January 8, 2014, ONEOK’s board of directors approved the distribution of all the shares of our common stock to holders of ONEOK common stock. On January 31, 2014, we became an independent, publicly traded company as a result of a distribution by ONEOK of our common stock to ONEOK’s shareholders. Our common stock began trading “regular-way” under the ticker symbol “OGS” on the NYSE on February 3, 2014.

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.

Basis of Presentation - Prior to our separation from ONEOK, our financial statements were derived from ONEOK’s financial statements, which included its natural gas distribution business as if we, for accounting purposes, had been a separate company for all periods presented. The assets and liabilities in the financial statements have been reflected on a historical basis. The financial statements for periods prior to the separation also include expense allocations for certain corporate functions historically performed by ONEOK, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, information technology and other services. We believe our assumptions underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from ONEOK, are reasonable. However, the financial statements may not include all of the actual expenses that would have been incurred by us and may not reflect our results of operations, financial position and cash flows had we been a separate publicly traded company during the periods presented prior to the separation.

Because the operations of the natural gas distribution business within ONEOK were conducted through separate divisions, ONEOK’s net investment in us, excluding the long-term line of credit with ONEOK, is shown as owner’s net investment in lieu of equity in the financial statements prior to the separation. Transactions between ONEOK and us that were not part of the long-term line of credit with ONEOK or the short-term note payable to ONEOK have been identified in the Statements of Equity as a net transfer from ONEOK. Transactions with ONEOK’s other operating businesses, which generally settled monthly, are shown as accounts receivable-affiliate or accounts payable-affiliate in periods prior to the separation.

All financial information presented after the separation represents the results of operations, financial position and cash flows of ONE Gas. Accordingly:

•

Our Statements of Income and Comprehensive Income for the year ended December 31, 2014, consist of the results of ONE Gas for the eleven months ended December 31, 2014, and the results of ONE Gas Predecessor for the one month ended January 31, 2014. Our Statements of Income and Comprehensive Income for the year ended December 31, 2013 and 2012, consist entirely of the results of ONE Gas Predecessor. Our net income for the period prior to January 31, 2014, was recorded to owner’s net investment.


•	Our balance sheet at December 31, 2014, consists of the balances of ONE Gas, while at December 31, 2013, it consists of the balances of ONE Gas and ONE Gas Predecessor.


•	Our Statement of Cash Flows for the year ended December 31, 2014, consists of the results of ONE Gas for the eleven months ended December 31, 2014, and the results of ONE Gas Predecessor for the one month ended January 31, 2014. Our Statements of Cash Flows for the year ended December 31, 2013 and 2012, consist entirely of the results of ONE Gas Predecessor.


•	Our Statements of Equity for the year ended December 31, 2014, consists of both the activity for ONE Gas Predecessor prior to January 31, 2014, and the activity for ONE Gas completed in connection with, and subsequent to, the separation on January 31, 2014. Our Statements of Equity for the years ended December 31, 2013 and 2012, consist entirely of the results of ONE Gas Predecessor.

The financial statements include the accounts of the natural gas distribution business as set forth in “Organization and Nature of Operations” above. All significant balances and transactions between our divisions have been eliminated.

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, provisions for doubtful accounts receivable, 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.

Fair Value Measurements - 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. See Note 8 for additional disclosures of our fair value measurements.

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. Prior to our separation, we participated in ONEOK’s cash management program rather than maintaining significant cash equivalent balances. Amounts due to ONEOK resulting from the cash management program were recorded as a short-term note payable to ONEOK. See Note 2 for additional information on the cash management program.

Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues 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. Revenues are accrued for natural gas delivered and services rendered to 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 amounts of accrued unbilled natural gas sales revenues at December 31, 2014 and 2013, were $141.7 million and $143.7 million, respectively.

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for natural gas sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to provide security, including deposits and other forms of collateral, when appropriate. With more than 2 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. In Oklahoma, Kansas and most jurisdictions we serve in Texas, we are able to recover natural gas costs related to doubtful accounts through purchased-gas cost adjustment

mechanisms. At December 31, 2014 and 2013, our allowance for doubtful accounts was $4.0 million and $3.3 million, respectively.

Inventories - Natural gas in storage is maintained on the basis of weighted-average cost. Natural gas inventories that are injected into storage are recorded in inventory based on actual purchase costs, including storage and transportation costs. Natural gas inventories that are withdrawn from storage are accounted for in our purchased-gas cost adjustment mechanisms at the weighted-average inventory cost.

Materials and supplies inventories, which are included in other current assets on our balance sheets, are stated at the lower of weighted-average cost or net realizable value. Our materials and supplies inventories totaled $27.5 million and $16.6 million at December 31, 2014 and 2013, respectively.

Derivatives and Risk Management Activities - 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 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	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms

We have not elected to designate any of our derivative instruments as hedges. Gains or losses associated with the fair value of commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.

See Note 8 for more discussion of our fair value measurements and hedging activities using derivatives.

Property, Plant and Equipment - Our properties are stated at cost, which includes direct construction costs such as direct labor, materials, burden and AFUDC. Generally, the cost of our property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or retirement of an entire operating unit or system of our properties are recognized in income. Maintenance and repairs are charged directly to expense.

AFUDC represents the cost of borrowed funds used to finance construction activities. We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense.

Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances. We periodically conduct depreciation studies to assess the economic lives of our assets. These depreciation studies are completed as a part of our rate proceedings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are effective. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position, results of operations or cash flows.

Property, plant and equipment on our balance sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note 10 for disclosures of our property, plant and equipment.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually as of July 1. Total goodwill was $158.0 million at December 31, 2014 and 2013, respectively. Our goodwill impairment analysis performed in 2014, 2013 and 2012, utilized a qualitative assessment and did not result in any impairment indicators. Subsequent to July 1, 2014, no event has occurred indicating that it is more likely that not that our fair value is less than our carrying value of our net assets.

To estimate our fair value, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply acquisition multiples to forecasted cash flows. The acquisition multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows over a period of years.

We assess our long-lived assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no asset impairments in 2014, 2013 or 2012.

Regulation - We are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. We follow the accounting and reporting guidance for regulated operations. During the ratemaking process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time, as opposed to expensing such costs as incurred. Examples include weather normalization, unrecovered purchased-gas costs, pension and postemployment benefit costs and ad valorem taxes. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer:


•	established by independent regulators;


•	designed to recover the specific entity’s costs of providing regulated services; and


•	set at levels that will recover our costs when considering the demand and competition for our services.

See Note 9 for our regulatory asset and liability disclosures.

Pension and Other Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We also sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize.

Prior to the separation, certain employees participated in the Plans sponsored by ONEOK. We accounted for these plans as multiemployer benefit plans. Accordingly, we did not record an asset or liability to recognize the funded status of the Plans. We recognized a liability only for any required contributions to the Plans that were accrued and unpaid at the balance sheet date. The related pension and other postretirement expenses were allocated to us based on plan participants who directly supported our operations. These pension and other postretirement benefit costs included amounts associated with vested participants who are no longer employees.

Prior to the separation, certain benefit costs associated with employees who directly supported our operations were determined based on a specific employee basis. We were also allocated benefit costs associated with employees of ONEOK that provided general corporate services. These amounts were charged to us by ONEOK as described in Note 2. Prior to the separation, we were not the plan sponsor for the Plans. Accordingly, our balance sheets prior to the separation do not reflect any assets or liabilities related to the Plans. See Note 12 for additional information regarding pension and other postretirement employee benefit plans.

Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the periods prescribed by our regulators.

A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, as well as the current and forecasted business economics of our industry. We had no valuation allowance at December 31, 2014 and 2013.

We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute. There were no material uncertain tax positions at December 31, 2014 and 2013.

See Note 13 for additional discussion of income taxes.

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain long-lived assets that comprise our natural gas distribution systems, primarily our pipeline assets, are subject to agreements or regulations that give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the natural gas distribution system. We recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our assets because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We expect our natural gas distribution systems will continue in operation as long as natural gas supply and demand for natural gas distribution service exists. Based on the widespread use of natural gas for heating and cooking activities by residential and commercial customers in our service areas, management expects supply and demand to exist for the foreseeable future.

In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs collected through our rates include costs attributable to legal and nonlegal removal obligations; however, the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory liability for financial reporting purposes. Historically, with the exception of the regulatory authority in Kansas, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify or disclose this amount; rather, these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, for financial reporting purposes, significant uncertainty exists regarding the future disposition of this regulatory liability, pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory requirements, and the liability may be adjusted as more information is obtained. We record the estimated asset removal obligation in noncurrent liabilities in other deferred credits on our balance sheets. To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.

and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note 14 for additional discussion of contingencies.

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

Prior to the separation, ONEOK charged us for compensation expense related to stock-based compensation awards granted to our employees that directly supported our operations. Share-based compensation was also a component of allocated amounts charged to us by ONEOK for general and administrative personnel providing services on our behalf.

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 the above, plus unvested stock awards granted under our compensation plans, but only to the extent these instruments dilute earnings per share.

Segments - We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial and transportation customers. We define reportable business segments as components of an organization for which discrete financial information is available and operating results are evaluated on a regular basis by the chief operating decision maker (CODM) in order to assess performance and allocate resources. Our CODM is our Chief Executive Officer (CEO). Characteristics of our organization that were relied upon in making this determination include the similar nature of services we provide, the functional alignment of our organizational structure, and the reports that are regularly reviewed by the CODM for the purpose of assessing performance and allocating resources. Our management is functionally aligned and centralized, with performance evaluated based upon results of the entire distribution business. Capital allocation decisions are driven by asset integrity management and operating efficiency, not geographic location.

We evaluate performance based principally on operating income. Affiliate sales are recorded on the same basis as sales to unaffiliated customers and are discussed in further detail in Note 2. Net margin is comprised of total revenues less cost of natural gas. Cost of natural gas includes commodity purchases, fuel, storage and transportation costs and does not include an allocation of general operating costs or depreciation and amortization.

In 2014, 2013 and 2012, we had no single external customer from which we received 10 percent or more of our gross revenues.

Recently Issued Accounting Standards Update - 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. We are evaluating the impact of this recently issued guidance, which is required to be adopted for our quarterly and annual reports beginning with the first quarter 2017.


2.	SEPARATION & RELATED-PARTY TRANSACTIONS

Distribution - On January 8, 2014, ONEOK’s board of directors approved the distribution of our common stock to holders of ONEOK common stock.

In order for ONEOK to effect the separation, we requested, and the SEC declared effective, our registration statement on Form 10 on January 10, 2014. ONEOK transferred all of the assets and liabilities primarily related to its natural gas distribution business to us. Assets and liabilities included accounts receivable and payable, natural gas in storage, regulatory assets and liabilities, pipeline and other natural gas distribution facilities, customer deposits, employee-related assets and liabilities, including amounts attributable to pension and other postretirement benefits, tax-related assets and liabilities and other assets and liabilities primarily associated with providing natural gas distribution service in Oklahoma, Kansas and Texas. Cash and certain corporate assets, such as office space in the corporate headquarters and certain IT hardware and software, were not transferred to us; however, the Transition Services Agreement between ONEOK and us provides access to such corporate assets as necessary to operate our business for a period of time to enable us to obtain the applicable corporate assets.

approximately $1.13 billion to ONEOK. Effective January 31, 2014, the number of our authorized shares increased to 250 million shares of common stock and 50 million of preferred stock. On January 31, 2014, ONEOK distributed one share of our common stock for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of business on January 21, 2014, the record date of the distribution. At the close of business on January 31, 2014, ONE Gas, Inc. became an independent, publicly traded company as a result of the distribution. Our common stock began trading “regular-way” under the ticker symbol “OGS” on the NYSE on February 3, 2014.

Reorganization Adjustments - In accordance with the terms of the Separation and Distribution Agreement, ONEOK contributed the assets and liabilities of its natural gas distribution business to us. The noncash contributions below represent ONEOK assets and liabilities attributable to pension and other postretirement employee benefits, general corporate assets and liabilities and related deferred taxes not included previously in the ONE Gas Predecessor balance sheet, but the costs for which were included in ONE Gas Predecessor’s results of operations. The table below also includes the contribution of the short-term note payable to and long-term line of credit with ONEOK previously included in ONE Gas Predecessor balance sheets. The assets and liabilities below were recorded at historical cost as the reorganization was among entities under common control. Net transfers from ONEOK included:



(Thousands of dollars)
Property, plant and equipment, net	$	21,459
Regulatory assets, pension and other postretirement benefits	331,148
Other assets	80,700
Long-term line of credit with ONEOK	1,027,631
Short-term note payable to ONEOK	397,857
Pension and other postretirement benefits - liabilities	(123,800		)
Other liabilities	(34,404		)
Deferred taxes	(86,112		)
Accumulated other comprehensive loss	(3,393		)
Net contribution of assets (liabilities)	$	1,611,086
Less: Cash paid to ONEOK	1,130,000
Net transfers from ONEOK	$	481,086

Affiliate Transactions - Prior to our separation, we had certain transactions with ONEOK and its subsidiaries. We purchased a portion of our natural gas supply and natural gas transportation and storage services from ONEOK and its affiliates. These contracts were awarded through a competitive-bidding process, and the costs were recoverable through our purchased-gas cost adjustment mechanisms.

Prior to our separation, the Statements of Income included expense allocations for certain corporate functions historically performed by ONEOK and allocated to its natural gas distribution business, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, information technology and facilities maintenance. Where costs were incurred specifically on our behalf, the costs were billed directly to us by ONEOK. In other situations, the costs were allocated to us through a variety of methods, depending upon the nature of the expenses. For example, a service that applied equally to all employees of ONEOK was allocated based upon the number of employees in each ONEOK affiliate. An expense benefiting us but having no direct basis for allocation was allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and payroll expense. It is not practicable to determine what these general overhead costs would be on a stand-alone basis. These allocations included the following costs:

Corporate Services - These represent costs for certain employees of ONEOK who provided general and administrative services on our behalf. These charges were either directly identifiable or allocated based upon usage factors for our operations. In addition, we received other allocated costs for our share of general corporate expenses of ONEOK, which were determined based on our relative use of the service or, if there was no direct basis for allocation, were allocated by the modified Distrigas method. All of these costs are reflected in operations and maintenance and depreciation expense in the Statements of Income.

Benefit Plans and Incentives - These represent benefit costs and other incentives, including group health and welfare benefits, pension plans, other postretirement benefit plans and employee stock-based compensation plans. Costs associated with incentive and stock-based compensation plans were determined on a specific identification basis for certain employees who directly supported our operations. All other employee benefit costs historically were allocated using a percentage factor

derived from a ratio of benefit costs to salary costs for ONEOK’s employees. These expenses are included in operations and maintenance expenses in the Statements of Income.

Total compensation cost, which included costs for both employees who directly supported our operations and allocations for corporate services, charged to us by ONEOK related to share-based payment plans was $15.5 million and $12.4 million during 2013 and 2012, respectively. Compensation costs charged to us by ONEOK in 2014 were not material. See Note 11 for additional information regarding share-based payments. Total cost charged to us by ONEOK related to pension and other postretirement health and welfare plans was $52.1 million and $43.4 million during 2013 and 2012, respectively, which is net of amounts deferred through regulatory mechanisms of $1.8 million and $4.1 million during 2013 and 2012, respectively. Cost related to pension and other postretirement health and welfare plans which was charged to us by ONEOK in 2014 was not material. See Note 12 for additional information regarding employee benefit plans.

Interest Expense - ONEOK utilized a centralized approach to cash management and the financing of its businesses. Cash receipts and cash expenditures for costs and expenses from our operations were transferred to or from ONEOK on a regular basis and recorded as increases or decreases in the balance due in short-term note payable to ONEOK under an unsecured promissory note we had in place with ONEOK. The amounts outstanding under the long-term line of credit with ONEOK and the short-term note payable to ONEOK accrued interest based on ONEOK’s weighted-average cost of long-term and short-term debt, respectively.

The following table shows ONEOK’s and its subsidiaries’ transactions with us included in the statements of income for the periods indicated:



	Years Ended December 31,
	2013			2012
	(Thousands of dollars)
Cost of natural gas	$	226,582		$	135,650
Operations and maintenance
Direct employee labor and benefit costs	177,526			165,798
Allocated employee labor and benefit costs	29,955			24,994
Charges for general and administrative services	36,078			24,059
Depreciation and amortization	6,940			6,033
Other (income)/expense, net	(5,073		)	(2,668		)
Interest expense	60,930			60,305
Total	$	532,938		$	414,171

Employee labor and benefit costs capitalized totaled $49.3 million and $46.1 million for 2013 and 2012, respectively. In addition, we recorded regulated utility revenue from ONEOK and its subsidiaries. These amounts were immaterial for the periods presented.

Following the separation, we and ONEOK are still providing services to each other under the Transition Services Agreement, but these services are now considered third-party transactions. The remaining related party transactions prior to the separation were not material in 2014.

Cash Management - Prior to the separation, we participated in ONEOK’s centralized cash management program that concentrated the cash assets of its operating divisions and subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. The centralized cash management program provided that funds in excess of the daily needs of the operating divisions and subsidiaries were concentrated, consolidated or otherwise made available for use by other wholly owned entities of ONEOK. Under this cash management program, depending on whether a participating division or subsidiary had short-term cash requirements or cash surpluses, ONEOK provided cash to its respective divisions or subsidiaries or the divisions or subsidiaries provided cash to ONEOK. The amounts receivable, or due, under this program were due on demand. Activities under this program were reflected in the balance sheets as short-term note payable to ONEOK.

Principal under this note payable bears interest based on ONEOK’s weighted-average cost of short-term debt, plus a utilization fee of 50 basis points, calculated monthly. The weighted-average interest rates for this note payable were 0.92 percent and 0.96 percent for 2013 and 2012, respectively. Changes in this note payable represented any funding required from ONEOK for working capital or capital expenditures and after giving effect to the transfers to ONEOK from our cash flows from operations.

We had no affiliate receivables as of December 31, 2014. Affiliate receivables were not material as of December 31, 2013, and are included in accounts receivable on our balance sheets.

Long-Term Line of Credit with ONEOK - Prior to the separation, we had a $1.1 billion long-term line of credit with ONEOK. The weighted-average interest rate on the amounts outstanding for the year was 5.79 percent and 6.43 percent in 2013 and 2012, respectively. The interest rate on the revolver was reset each year based on ONEOK’s outstanding debt plus an adjustment of 50 basis points for ONEOK’s cost to administer the program. The amount utilized on the long-term line of credit was adjusted annually with an offset to owner’s net investment to adjust our debt-to-capital ratio to a level consistent with ONEOK’s debt-to-capital ratio.

Immediately prior to the contribution of the natural gas distribution business to us, ONEOK contributed to the capital of the natural gas distribution business all amounts outstanding under the note payable and long-term line of credit.

Agreements with ONEOK after the Separation - We entered into the Separation and Distribution Agreement and several other agreements with ONEOK to effect the separation and provide a framework for our relationships with ONEOK after the distribution. These agreements govern the relationship between ONEOK and us subsequent to the completion of the distribution, and provide for the allocation among ONEOK and us of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the natural gas distribution business attributable to periods prior to, at and after the distribution. In addition to the Separation and Distribution Agreement (which contains many of the key provisions related to our separation from ONEOK and the distribution of our shares of common stock to ONEOK shareholders), these agreements include:


•	Transition Services Agreement;


•	Tax Matters Agreement; and


•	Employee Matters Agreement.


3.	CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

ONE Gas Credit Agreement - In December 2013, we entered into the ONE Gas Credit Agreement, which became effective upon our separation from ONEOK on January 31, 2014, and is scheduled to expire on January 31, 2019. 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. The ONE Gas Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, indebtedness of subsidiaries, investments, changes in the nature of business, fundamental changes, transactions with affiliates, burdensome agreements, and use of proceeds. In the event of a breach of certain covenants by ONE Gas, amounts outstanding under the ONE Gas Credit Agreement may become due and payable immediately. At December 31, 2014, our total debt-to-capital ratio was 41 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement.

The ONE Gas Credit Agreement includes a $50 million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.2 billion from $700 million by either commitments from new lenders or increased commitments from existing lenders. Borrowings made under the facility are available for general corporate purposes. The ONE Gas Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Based on our current credit ratings, borrowings, if any, will accrue interest at LIBOR plus 79.5 basis points, and the annual facility fee is 8 basis points.

In July 2014, we entered into 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 sold generally 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 December 31, 2014, we had $42.0 million of commercial paper and $1.0 million in letters of credit issued under the ONE Gas Credit Agreement, with

no borrowings and $657.0 million of remaining credit available under the ONE Gas Credit Agreement. The weighted-average interest rate on our commercial paper was 0.32 percent at December 31, 2014.


4.	LONG-TERM DEBT

Senior notes issuance - In January 2014, we completed a private placement of senior 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 senior notes due 2044 (collectively, our “Senior Notes”). The net proceeds from the private placement were approximately $1.19 billion and were used to fund a one-time cash payment to ONEOK of approximately $1.13 billion as part of the separation. The remaining portion of the net proceeds was retained in order to provide sufficient financial flexibility and to support working capital requirements and capital expenditures.

In connection with the issuance of our Senior Notes, we entered into a registration rights agreement, pursuant to which we were obligated to use our commercially reasonable efforts to file with the SEC and cause to become effective a registration statement with respect to an offer to exchange each series of Senior Notes for new notes, with terms substantially identical in all material respects to such series of our Senior Notes. Our registration statement, as amended, was declared effective by the SEC on September 5, 2014. We completed the noncash exchange of our Senior Notes for our registered senior notes in October 2014.

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 the aggregate principal amount of the outstanding Senior Notes to declare those senior notes immediately due and payable in full.


5.	EQUITY

Preferred Stock - At December 31, 2014, we have 50 million, $0.01 par value, authorized shares of preferred stock available. We have not issued or established any classes or series of shares of preferred stock.

Common Stock - At December 31, 2014, we had approximately 197.9 million shares of authorized common stock available for issuance.

Treasury Shares - In February 2015, our Board of Directors authorized us to purchase treasury shares to be used to offset shares issued under our employee and non-employee director equity compensation, dividend reinvestment and employee stock purchase plans. The Board of Directors established an annual limit of $20 million of treasury stock purchases, exclusive of funds received through the dividend reinvestment and employee stock purchase plans. Stock purchases may be made in the open market or in private transactions at times, and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time. We may hold the purchased shares as treasury shares and will account for them using the cost method.

Dividends - Dividends paid totaled $43.7 million in 2014. The following table sets forth the dividends per share declared and paid on our common stock for the periods indicated:



	2014
First Quarter	$	—
Second Quarter	$	0.28
Third Quarter	$	0.28
Fourth Quarter	$	0.28
Total	$	0.84

Additionally, a dividend of $0.30 per share ($1.20 per share on an annualized basis) was declared in January 2015, payable in the first quarter 2015.


6.	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the balance in accumulated other comprehensive income (loss) for the period indicated:



	Accumulated Other Comprehensive Income (Loss)
January 1, 2014	$	—
Transfers in upon separation	(3,393		)
Pension and other postretirement benefit plans obligations
Other comprehensive income (loss) before reclassification, net of tax of $1,442	(2,096		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax of $(198)	315
Other comprehensive income (loss)	(1,781		)
December 31, 2014	$	(5,174	)

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) on our Statements of Income for the period indicated:



Details about Accumulated Other Comprehensive Income (Loss) Components	Year Ended December 31, 2014			Affected Line Item in the Statements of Income
	(Thousands of dollars)
Pension and other postretirement benefit plan obligations (a)
Amortization of net loss	$	34,169
Amortization of unrecognized prior service cost	(1,211		)
	32,958
Regulatory adjustments (b)	(32,445		)
	513			Income before income taxes
	(198		)	Income tax expense
Total reclassifications for the period	$	315		Net income

(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 12 for additional detail of our net periodic benefit cost.

(b) Regulatory adjustments represent pension and other postretirement benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 9 for additional disclosures of regulatory assets and liabilities.


7.	EARNINGS PER SHARE

The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:



	Year Ended December 31, 2014
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	109,790	52,364	$	2.10
Diluted EPS Calculation
Effect of dilutive securities	—		582
Net income available for common stock and common stock equivalents	$	109,790	52,946	$	2.07



	Year Ended December 31, 2013
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	99,195	52,319	$	1.90
Diluted EPS Calculation
Effect of dilutive securities	—		—
Net income available for common stock and common stock equivalents	$	99,195	52,319	$	1.90



	Year Ended December 31, 2012
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	96,509	52,319	$	1.84
Diluted EPS Calculation
Effect of dilutive securities	—		—
Net income available for common stock and common stock equivalents	$	96,509	52,319	$	1.84

On January 31, 2014, 51,941,236 shares of our common stock were distributed to ONEOK shareholders in conjunction with the separation. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed this amount and any shares associated with fully vested stock awards that have not been issued to be outstanding as of the beginning of each period prior to the separation presented in the calculation of weighted-average shares.


8.	DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Derivative Instruments - At December 31, 2014, we held purchased natural gas call options for the heating season ending March 2015, with total notional amounts of 16.0 Bcf, for which we paid premiums of $6.4 million, and had a fair value of $0.1 million. At December 31, 2013, we held purchased natural gas call options for the heating season ended March 2014, with total notional amounts of 26.6 Bcf, for which we paid premiums of $8.6 million, and had a fair value of $8.7 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 purchase 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 periods presented.

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.

The short-term notes payable were due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The estimated fair value and book value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion, respectively, at December 31, 2014. The estimated fair value of our Senior Notes was determined using quoted market prices, and are considered Level 2.

The estimated fair value and book value of our long-term line of credit with ONEOK at December 31, 2013, was $1.2 billion and $1.0 billion, respectively. The estimated fair value of our long-term line of credit with ONEOK was valued using the income approach by discounting the future payments and are considered Level 3. Significant unobservable inputs include the discount rate, which we estimated using a rate at which we could have borrowed at each measurement date.


9.	REGULATORY ASSETS AND LIABILITIES

The table below presents a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:



		December 31, 2014
	Remaining Recovery Period	Current			Noncurrent			Total
		(Thousands of dollars)
Under-recovered purchased-gas costs	1 year	$	28,712		$	—		$	28,712
Pension and other postretirement benefit costs	See Note 12	18,108			466,684			484,792
Reacquired debt costs	13 years	812			9,730			10,542
Other	1 to 24 years	2,561			2,309			4,870
Total regulatory assets, net of amortization		50,193			478,723			528,916
Accumulated removal costs (a)	up to 50 years	—			(15,451		)	(15,451		)
Weather normalization	1 year	(16,516		)	—			(16,516		)
Over-recovered purchased-gas costs	1 year	(13,055		)	—			(13,055		)
Ad valorem tax	1 year	(2,896		)	—			(2,896		)
Total regulatory liabilities		(32,467		)	(15,451		)	(47,918		)
Net regulatory assets and liabilities		$	17,726		$	463,272		$	480,998

(a) Included in other deferred credits in our balance sheets.



		December 31, 2013
	Remaining Recovery Period	Current			Noncurrent			Total
		(Thousands of dollars)
Under-recovered purchased-gas costs	1 year	$	12,393		$	—		$	12,393
Pension and other postretirement benefit costs	See Note 12	298			9,556			9,854
Reacquired debt costs	14 years	812			10,541			11,353
Other	1 to 25 years	8,154			3,725			11,879
Total regulatory assets, net of amortization		21,657			23,822			45,479
Accumulated removal costs (a)	up to 50 years	—			(21,375		)	(21,375		)
Over-recovered purchased-gas costs	1 year	(17,796		)	—			(17,796		)
Total regulatory liabilities		(17,796		)	(21,375		)	(39,171		)
Net regulatory assets and liabilities		$	3,861		$	2,447		$	6,308

(a) Included in other deferred credits in our balance sheets.

Regulatory assets on our balance sheets, as authorized by the various regulatory commissions, are probable of recovery. Base rates are designed to provide a recovery of cost 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 recoverable through base rates are subject to review by the respective regulatory commissions during future rate proceedings. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries.

Unrecovered purchased-gas costs represents the costs that have been over- or under-recovered from customers through the purchased-gas cost adjustment mechanisms and includes natural gas utilized in our operations, premiums paid and any cash settlements received from our purchased natural gas call options.

We amortize reacquired debt costs in accordance with the accounting guidelines prescribed by the OCC and KCC.

In December 2013, the KCC approved a settlement agreement between ONEOK, the staff of the KCC, and the Citizens’ Utility Ratepayer Board that authorized the transfer of ONEOK’s Kansas Gas Service natural gas distribution assets to us. As a result, Kansas Gas Service expensed certain transition costs associated with ONEOK’s acquisition of Kansas Gas Service in 1997 that previously had been recorded as a regulatory asset and amortized and recovered in rates over a 40-year period. As such, we recorded a noncash charge to income of approximately $10.2 million before taxes during 2013 in depreciation and amortization.

Weather normalization represents revenue over- or under-recovered through the weather normalization adjustment rider in Kansas. This amount is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.

Ad valorem tax represents an increase or decrease in Kansas Gas Service’s taxes above or below the amount approved in a rate case. This amount is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.

Recovery through rates resulted in amortization of regulatory assets of approximately $6.4 million for the year ended December 31, 2014. Amortization of regulatory assets of approximately $32.0 million for the year ended December 31, 2013, included amounts recovered through rates totaling $21.8 million and $10.2 million related to certain transition costs as described above. Recovery through rates resulted in amortization of regulatory assets of approximately $18.3 million for the year ended December 31, 2012.

We collect, through our rates, the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs are nonlegal obligations; however, the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory liability. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions. We record the estimated nonlegal asset removal obligation in noncurrent liabilities in other deferred credits on our balance sheets.


10.	PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment by property type, for the periods indicated:



	December 31,			December 31,
	2014			2013
	(Thousands of dollars)
Natural gas distribution pipelines and related equipment	$	3,909,881		$	3,703,593
Natural gas transmission pipelines and related equipment	450,810			430,042
General plant and other	418,157			326,004
Construction work in process	71,353			74,435
Property, plant and equipment	4,850,201			4,534,074
Accumulated depreciation and amortization	(1,556,481		)	(1,489,216		)
Net property, plant and equipment	$	3,293,720		$	3,044,858

We compute depreciation expense for distribution operations by applying composite, straight-line rates approved by various regulatory agencies. The average depreciation rates for our property are set forth in the following table for the periods indicated:



Years Ended December 31,
2014	2013	2012
2.0% - 3.0%	2.0% - 3.0%	2.0% - 3.0%

We recorded capitalized interest of $2.5 million, $1.3 million and $1.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2014, 2013 and 2012 of $7.0 million, $10.5 million and $12.0 million, respectively. Such amounts are not included in capital expenditures on the Statements of Cash Flows.

Amounts recorded for regulatory accounting purposes that were not reflected in our financial statements were not material for the year ending December 31, 2014.


11.	SHARE-BASED PAYMENTS

The ONE Gas Equity Compensation Plan (ECP or ONE Gas Plan) provides for the granting of stock-based compensation, including incentive stock options, nonstatutory stock options, stock bonus awards, restricted stock awards, restricted stock unit awards, performance stock awards and performance unit awards to eligible employees and the granting of stock awards to nonemployee directors. We have reserved 2.8 million shares of common stock for issuance under the ECP. At December 31, 2014, we had approximately 1.3 million shares available for issuance under the ECP, which reflect shares issued and estimated

shares expected to be issued upon vesting of outstanding awards granted under the plan, less forfeitures. The plan allows for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements.

Prior to our separation, certain employees assigned to us in the separation participated in ONEOK’s share-based awards plans (ONEOK Plans). The ONEOK Plans provided for ONEOK common stock based awards to both employees and ONEOK’s nonmanagement directors. The plans permitted the granting of various types of awards including, but not limited to, performance stock units and restricted stock units. Awards could be granted for no consideration other than prior and future services or based on certain financial performance targets. In connection with the separation, awards granted by ONEOK in 2012 and 2013 were cancelled and replaced with awards of ONE Gas shares. The number of restricted stock units held by a ONE Gas participant was multiplied by a ratio of 2.04 which was determined by the ONEOK volume-weighted average share price of $68.22 on January 31, 2014, and the ONE Gas volume-weighted average share price of $33.50 on February 3, 2014, rounded to the nearest whole share.

The same ratio of 2.04 was used to convert the outstanding performance stock units awarded by ONEOK prior to the separation into awards for ONE Gas shares. A pre-distribution payout factor was applied to each grant based on ONEOK’s total shareholder return performance compared with its peer group for the number of days lapsed from the date of the grant to January 31, 2014, and these awards were frozen or “banked” and are not subject to an additional payout factor. The remaining units from each grant will continue to be at-risk based on our performance and the relative total shareholder return of our peer group.

No incremental cost was recorded in our financial statements upon cancellation and replacement of the 2012 and 2013 restricted stock units and performance stock units because the previous awards were cancelled and replaced pursuant to anti-dilution provisions of the ONEOK Plans and the fair value of the awards immediately following the cancellation and replacement was not higher than the fair value of the awards immediately before the cancellation and replacement.

We were charged by ONEOK for share-based compensation expense related to employees that directly supported our operations. ONEOK also charged us for the allocated costs of certain employees of ONEOK (including stock-based compensation) who provided general and administrative services on our behalf. Information included in this note is limited to share-based compensation associated with employees in 2014, and employees that directly supported our operations as part of ONEOK prior to our separation. See Note 2 for total costs charged to us by ONEOK.

Compensation cost expensed for our share-based payment plans was $7.0 million, net of tax benefits of $4.4 million, for 2014. Compensation cost charged to us for employees directly supporting our operations by ONEOK for 2013 and 2012 totaled $9.7 million and $4.8 million, respectively, which is net of $6.1 million and $3.0 million of tax benefits, respectively. Compensation costs capitalized for employees were not material for 2014, 2013 and 2012.

Restricted Stock Unit Awards - We have granted restricted stock unit awards to key employees that vest over a service period of generally three years and entitle the grantee to receive shares of our common stock. The awards granted that replaced awards granted by ONEOK in 2012 vested, and 2013 will vest, consistent with their original vesting dates in 2015 and 2016, respectively. No dividends accrue prior to vesting on the restricted stock units granted that replaced the awards granted by ONEOK in 2012. Restricted stock unit awards granted in 2014 and that replaced awards granted by ONEOK in 2013 accrue dividend equivalents in the form of additional restricted stock units prior to vesting. Restricted stock unit awards are measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments for awards that do not accrue dividends and adjusted for estimated forfeitures. Compensation expense is recognized on a straight-line basis over the vesting period of the award. A forfeiture rate of 3 percent per year based on historical forfeitures under our share-based payment plans is used.

Performance Stock Unit Awards - We have granted performance stock unit awards to key employees. The shares of common stock underlying the performance stock units vest at the expiration of a service period of generally three years if certain performance criteria are met by us as determined by the Executive Compensation Committee of the Board of Directors. The awards granted that replaced awards granted by ONEOK in 2012 vested, and 2013 will vest, consistent with their original vesting dates in 2015 and 2016, respectively, if certain performance criteria are met by us for the at-risk portion of the awards as described above. Upon vesting, a holder of performance stock units is entitled to receive a number of shares of common stock equal to a percentage (0 percent to 200 percent) of the performance stock units granted, based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of other utilities over the same period.

If paid, the outstanding performance stock unit awards entitle the grantee to receive shares of our common stock. The outstanding performance stock unit awards are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled,

regardless of when, if ever, the market condition is satisfied. No dividends accrue prior to vesting on performance stock units granted to replace awards granted by ONEOK in 2012. The new performance stock unit awards granted in 2014 and the grants that replaced awards granted by ONEOK in 2013 accrue dividend equivalents in the form of additional performance stock units prior to vesting. The fair value of these performance stock units was estimated on the grant date based on a Monte Carlo model. A forfeiture rate of 3 percent per year based on historical forfeitures under our and, prior to the separation, ONEOK’s share-based payment plans was used. Compensation expense is recognized on a straight-line basis over the period of the award. The compensation expense on these awards will only be adjusted for changes in forfeitures.

Restricted Stock Unit Award Activity

As of December 31, 2014, there was $2.8 million of total unrecognized compensation costs related to the nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 1.8 years. The following tables set forth activity and various statistics for restricted stock unit awards outstanding under the respective plans for the period indicated:



	ONE Gas Plan				ONEOK Plans
	Number of Shares		Weighted- Average Price		Number of Shares		Weighted- Average Price
Nonvested December 31, 2013	—		$	—	137,670		$	34.57
Released to participants prior to separation	—		$	—	(66,960	)	$	28.50
Cancelled and replaced upon separation	246,683		$	19.71	(70,710	)	$	40.31
Granted	94,865		$	33.19	—		$	—
Released to participants	(7,217	)	$	19.85	—		$	—
Forfeited	(8,601	)	$	25.76	—		$	—
Nonvested December 31, 2014	325,730		$	23.47	—		$	—



	2014		2013		2012
Weighted-average grant date fair value (per share)	$	33.19	$	47.36	$	36.60
Fair value of shares granted (thousands of dollars)	$	3,149	$	1,323	$	2,046

Performance Stock Unit Award Activity

As of December 31, 2014, there was $4.9 million of total unrecognized compensation cost related to the nonvested performance stock unit awards, which is expected to be recognized over a weighted-average period of 1.7 years. The following tables set forth activity and various statistics related to our performance stock unit awards and the assumptions used by us, and ONEOK prior to 2014, in the valuations of the 2014, 2013 and 2012 grants at the grant date:



	ONE Gas Plan				ONEOK Plans
	Number of Units		Weighted- Average Price		Number of Units		Weighted- Average Price
Nonvested December 31, 2013	—		$	—	264,537		$	40.45
Released to participants prior to separation	—		$	—	(128,458	)	$	34.68
Cancelled and replaced upon separation	739,521		$	14.57	(136,079	)	$	45.90
Granted	124,015		$	35.98	—		$	—
Forfeited	(15,585	)	$	19.15	—		$	—
Nonvested December 31, 2014	847,951		$	17.62	—		$	—



	2014		2013		2012
Volatility	18.40%	(a)	22.27%	(b)	27.00%	(b)
Dividend yield	3.37%		3.04%		2.86%
Risk-free interest rate	0.67%		0.42%		0.38%
(a) - Volatility based on historical volatility over three years using daily stock price observations of our peer utilities.
(b) - Volatility based on historical volatility over three years using daily ONEOK stock price observations.



	2014		2013		2012
Weighted-average grant date fair value (per share)	$	35.98	$	52.30	$	42.39
Fair value of shares granted (thousands of dollars)	$	4,462	$	2,926	$	4,286

Employee Stock Purchase Plan

We have reserved a total of 0.7 million shares of common stock for issuance under our Employee Stock Purchase Plan (the ESPP). Subject to certain exclusions, all employees who work at least 20 hours per week are eligible to participate in the ESPP. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan. The purchase price of the stock is 85 percent of the lower of the average market price of our common stock on the grant date or exercise date. Approximately 36 percent of employees participated in the plan in 2014 and purchased 51,418 shares at $32.29. Compensation expense, before taxes, was $0.4 million in 2014. All eligible employees of ONEOK were eligible to participate in a similar ESPP plan, but enrollment of our employees in that plan was terminated upon the separation. Compensation expense, before tax, charged to us by ONEOK for employees who directly supported our operations was $2.7 million and $0.8 million for 2013 and 2012, respectively.

Employee Stock Award Program

Under the program, each time the per-share closing price of our common stock on the NYSE closed for the first time at or above each $1.00 increment above its previous historical high closing price, we issued, for no monetary consideration, one share of our common stock to all eligible employees. Shares issued to employees under this program during 2014 totaled 35,324, and compensation expense, before taxes, related to the Employee Stock Award Program was $2.5 million. Compensation expense, before taxes, charged to us by ONEOK related to a similar program to ours that was administered by ONEOK for employees who directly supported our operations was $4.2 million and $1.2 million for 2013 and 2012, respectively.


12.	EMPLOYEE BENEFIT PLANS

Retirement and Other Postretirement Benefit Plans

Prior to separation, certain employees participated in the Plans sponsored by ONEOK. We accounted for the Plans as multiemployer benefit plans. Accordingly, we did not record an asset or liability to recognize the funded status of the Plans. We recognized a liability only for any required contributions to the Plans that were accrued and unpaid at the balance sheet date. These defined benefit pension and other postretirement benefit costs included amounts associated with vested participants who are no longer employees. As described in Note 2, prior to 2014, ONEOK also charged us for the allocated cost of certain employees of ONEOK who provided general and administrative services on our behalf. ONEOK included an allocation of the benefit costs associated with these ONEOK employees based upon its allocation methodology, not necessarily specific to the employees providing general and administrative services on our behalf.

Retirement Plans - We have a defined benefit pension plan covering nonbargaining-unit employees hired before January 1, 2005, and certain bargaining-unit employees hired before December 15, 2011. Nonbargaining unit employees hired after December 31, 2004; employees represented by Local No. 304 of the International Brotherhood of Electrical Workers (IBEW) hired on or after July 1, 2010; employees represented by the United Steelworkers hired on or after December 15, 2011; and employees who accepted a one-time opportunity to opt out of the defined benefit pension plan are covered by a profit-sharing plan. Certain employees of the Texas Gas Services division were entitled to benefits under a frozen cash-balance pension plan. In addition, we have a supplemental executive retirement plan for the benefit of certain officers. No new participants in the supplemental executive retirement plan have been approved since 2005, and it was formally closed to new participants as of January 1, 2014. We fund our defined benefit pension costs at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended, and the Pension Protection Act of 2006. Pension expense in 2014 was $27.1 million. Pension expense charged to us by ONEOK for employees directly supporting our operations totaled $35.0 million and $22.8 million for 2013 and 2012, respectively.

Other Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. The postretirement medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance. Other postretirement benefit expense in 2014 was $5.9 million. Other postretirement benefit expense charged to us by ONEOK for employees directly supporting our operations totaled $12.3 million and $16.6 million for 2013 and 2012, respectively.

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used by us, and ONEOK prior to 2014, to determine the periodic benefit costs for the periods indicated:



	Years Ended December 31,
	2014	2013	2012
Discount rate - pension plans	5.25%	4.25%	5.00%
Discount rate - other postretirement plans	5.00%	4.00%	5.00%
Expected long-term return on plan assets	7.75%	8.25%	8.25%
Compensation increase rate	3.35% - 3.50%	3.45% - 3.50%	3.20% - 3.80%

We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models. As of December 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014.

We determine our discount rates annually. We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our defined benefit pension and other postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows. Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds. Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and other postretirement benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for defined benefit pension and other postretirement costs. Differences, if any, between the expense and the amount recovered through rates would be reflected in earnings, net of authorized deferrals. The KCC has authorized Kansas Gas Service’s recovery of defined benefit pension and other postretirement benefit costs in excess of the amounts included in rates over a period of 5 years.

We historically have recovered defined benefit pension and other postretirement benefit costs through rates. We believe it is probable that regulators will continue to include the net periodic pension and other postretirement benefit costs in our cost of service.

Obligations and Funded Status - In connection with the separation from ONEOK, we entered into an Employee Matters Agreement with ONEOK, which provides that our employees no longer participate in benefit plans sponsored or maintained by ONEOK as of the separation date. Effective January 1, 2014, the ONEOK defined benefit pension plans and other postretirement benefit plans transferred assets and obligations related to those employees transferring to ONE Gas and vested participants who are no longer employees to the new ONE Gas plans. As a result, we recorded sponsored pension and other postretirement plan obligations of approximately $1.1 billion, and sponsored defined benefit pension and other postretirement plan assets of approximately $1.0 billion, which are reflected below as our balances at the beginning of the period. Additionally, as a result of the transfer of unrecognized losses from ONEOK, our regulatory assets and deferred income taxes increased $331 million and $86 million, respectively.

The following table sets forth our defined benefit pension and other postretirement benefit plans, benefit obligations and fair value of plan assets for the periods indicated:



	Pension Benefits			Other Postretirement Benefits
	Year Ended December 31, 2014
Changes in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period	$	863,620		$	239,171
Service cost	11,620			3,468
Interest cost	43,791			11,605
Plan participants’ contributions	—			2,642
Actuarial loss	159,275			14,998
Benefits paid	(50,135		)	(14,196		)
Benefit obligation, end of period	1,028,171			257,688

Change in Plan Assets
Fair value of plan assets, beginning of period	840,699			147,237
Actual return on plan assets	53,907			6,912
Employer contributions	925			9,182
Plan participants’ contributions	—			2,642
Benefits paid	(50,135		)	(14,196		)
Fair value of assets, end of period	845,396			151,777
Balance at December 31	$	(182,775	)	$	(105,911	)

Current liabilities	$	(907	)	$	—
Noncurrent liabilities	(181,868		)	(105,911		)
Balance at December 31	$	(182,775	)	$	(105,911	)

The accumulated benefit obligation for our defined benefit pension plans was $970.7 million at December 31, 2014.

There are no plan assets expected to be withdrawn and returned to us in 2015.

Components of Net Periodic Benefit Cost - The following table sets forth the components of net periodic benefit cost for our defined benefit pension and other postretirement benefit plans for the period indicated:



	Pension Benefits			Other Postretirement Benefits
	Year Ended December 31, 2014
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	11,620		$	3,468
Interest cost	43,791			11,605
Expected return on assets	(59,862		)	(11,393		)
Amortization of unrecognized prior service cost	549			(1,760		)
Amortization of net loss	30,200			3,969
Settlements	773			—
Net periodic benefit cost	$	27,071		$	5,889

Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income (loss) related to our defined benefit pension benefits and other postretirement benefits for the period indicated:



	Pension Benefits			Other Postretirement Benefits
	Year Ended December 31, 2014
	(Thousands of dollars)
Net loss arising during the period	$	(3,543	)	$	—
Amortization of loss	518			—
Deferred income taxes	1,244			—
Total recognized in other comprehensive income (loss)	$	(1,781	)	$	—

The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense for the period indicated:



	Pension Benefits			Other Postretirement Benefits
	December 31, 2014
	(Thousands of dollars)
Prior service credit (cost)	$	(266	)	$	4,337
Accumulated loss	(426,862		)	(64,861		)
Accumulated other comprehensive loss before regulatory assets	(427,128		)	(60,524		)
Regulatory asset for regulated entities	418,699			60,524
Accumulated other comprehensive loss after regulatory assets	(8,429		)	—
Deferred income taxes	3,255			—
Accumulated other comprehensive loss, net of tax	$	(5,174	)	$	—

The following tables set forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year:



	Pension Benefits		Other Postretirement Benefits
Amounts to be recognized in 2015	(Thousands of dollars)
Prior service credit (cost)	$	266	$	(1,760	)
Actuarial net loss	$	44,219	$	6,040

Health Care Cost Trend Rates - The following table sets forth the assumed health care cost-trend rates for the periods indicated:



	2014
Health care cost-trend rate assumed for next year	4.00% - 7.75%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate)	4.00% - 5.00%
Year that the rate reaches the ultimate trend rate	2022

Assumed health care cost-trend rates have a significant effect on the amounts reported for our health care plans. A one percentage point change in assumed health care cost-trend rates would have the following effects:



	One Percentage		One Percentage
	Point Increase		Point Decrease
	(Thousands of dollars)
Effect on total of service and interest cost	$	484	$	(463	)
Effect on other postretirement benefit obligation	$	6,903	$	(6,675	)

Plan Assets - Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. To achieve this strategy, we have established a liability-driven investment strategy to change the allocations as the plan reaches certain funded status. The plan’s investments include a diverse blend of various domestic and international equities, investment-grade debt securities which mirror the cash flows of our liability, insurance contracts and alternative investments. The current target allocation for the assets of our defined benefit pension plan is as follows:



U.S. large-cap equities	37.4	%
Investment-grade bonds	30.0	%
Developed foreign large-cap equities	10.6	%
Alternative investments	7.7	%
Mid-cap equities	5.6	%
Emerging markets equities	5.0	%
Small-cap equities	3.7	%
Total	100	%

As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.

The following tables set forth our pension benefits and other postretirement benefits plan assets by fair value category as of the measurement date:



	Pension Benefits
	December 31, 2014
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity Securities (a)	$	439,165	$	66,766	$	—	$	505,931
Government obligations	—		47,769		—		47,769
Corporate obligations (b)	—		153,412		—		153,412
Cash and money market funds (c)	4,152		16,341		—		20,493
Insurance contracts and group annuity contracts	—		—		59,877		59,877
Other investments (d)	—		—		57,914		57,914
Total assets	$	443,317	$	284,288	$	117,791	$	845,396

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(d) - This category represents alternative investments such as hedge funds.



	Other Postretirement Benefits
	December 31, 2014
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity Securities (a)	$	49,553	$	12,589	$	—	$	62,142
Government obligations	—		78		—		78
Corporate obligations (b)	—		251		—		251
Cash and money market funds (c)	964		5,894		—		6,858
Insurance contracts and group annuity contracts	—		82,353		—		82,353
Other investments (d)	—		—		95		95
Total assets	$	50,517	$	101,165	$	95	$	151,777

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(d) - This category represents alternative investments such as hedge funds.

The following table sets forth the reconciliation of Level 3 fair value measurements of our pension plans:



	Pension Benefits
	December 31, 2014
	Insurance Contracts			Other Investments			Total
	(Thousands of dollars)
January 1, 2014	$	63,454		$	73,590		$	137,044
Net realized and unrealized gains (losses)	3,446			(15,676		)	(12,230		)
Settlements	(7,023		)	—			(7,023		)
December 31, 2014	$	59,877		$	57,914		$	117,791

Contributions - During 2014, we contributed $0.9 million to our defined benefit pension plans and we contributed $9.2 million to our other postretirement benefit plans. In 2015, we expect to contribute $0.9 million to our defined benefit pension plans and expect to contribute $3.9 million to our other postretirement benefit plans.

Pension and Other Postretirement Benefit Payments - Benefit payments for our defined benefit pension and other postretirement benefit plans for the period ended December 31, 2014 were $50.1 million and $14.2 million, respectively. The following table sets forth the pension benefits and other postretirement benefits payments expected to be paid in 2015-2024:



	Pension Benefits		Other Postretirement Benefits
Benefits to be paid in:	(Thousands of dollars)
2015	$	51,253	$	13,611
2016	$	52,366	$	14,283
2017	$	53,622	$	15,084
2018	$	55,068	$	15,776
2019	$	56,236	$	16,398
2020 through 2024	$	301,502	$	88,596

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2014, and include estimated future employee service.

Other Employee Benefit Plans

401(k) Plan - We have a 401(k) Plan which covers all full-time employees, and employee contributions are discretionary. We match 100 percent of each participant’s eligible contribution up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our contributions made to the plan were $9.7 million in 2014. Prior to our separation, ONEOK maintained a similar 401(k) Plan and compensation expense charged to us for employees who directly supported our operations by ONEOK totaled $8.3 million and $8.4 million in 2013 and 2012, respectively for ONEOK’s matching contributions to this plan.

Profit-Sharing Plan - We have a profit-sharing plan for all nonbargaining unit employees hired after December 31, 2004, and employees covered by the IBEW collective bargaining agreement hired after June 30, 2010, and employees covered by USW collective bargaining agreement hired after December 15, 2011. Nonbargaining unit employees who were employed prior to January 1, 2005, employees covered by the IBEW collective bargaining agreement employed prior to July 1, 2010, and employees covered by the United Steelworker collective bargaining agreement employed prior to December 16, 2011, were given a one-time opportunity to make an irrevocable election to participate in the profit-sharing plan and not accrue any additional benefits under ONEOK’s defined benefit pension plan after December 31, 2004, and June 30, 2010, respectively. We plan to make a contribution to the profit-sharing plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan. Our contributions made to the plan were $4.0 million in 2014. ONEOK maintained a similar Profit-Sharing Plan and compensation expense associated with ONEOK’s contributions made to the plan for employees who directly supported our operations prior to the separation were $1.6 million and $2.1 million in 2013 and 2012, respectively.

Employee Deferred Compensation Plan - Our Nonqualified Deferred Compensation Plan provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Contributions made to the plan were not material in 2014. ONEOK maintained a similar plan and contributions made to the plan for employees who directly supported our operations prior to the separation were not material in 2013 and 2012.


13.	INCOME TAXES

The following table sets forth our provision for income taxes for the periods indicated:



	Years Ended December 31,
	2014		2013		2012
	(Thousands of dollars)
Current income tax provision
Federal	$	17,006	$	—	$	—
State	1,397		67		360
Total current income tax provision	18,403		67		360
Deferred income tax provision
Federal	42,024		53,562		51,481
State	7,911		8,643		8,010
Total deferred income tax provision	49,935		62,205		59,491
Total provision for income taxes	$	68,338	$	62,272	$	59,851

The following table is a reconciliation of our income tax provision for the periods indicated:



	Years Ended December 31,
	2014			2013			2012
	(Thousands of dollars)
Income before income taxes	$	178,128		$	161,467		$	156,360
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	62,345			56,513			54,726
State income taxes, net of federal tax benefit	6,051			5,661			5,423
Other, net	(58		)	98			(298		)
Total provision for income taxes	$	68,338		$	62,272		$	59,851

Prior to separation, our operations were included in the consolidated federal and state income tax returns of ONEOK. Our income tax provision was calculated on a separate return basis. Accordingly, we recognized deferred tax assets and liabilities for the difference between the financial statement and income tax basis of assets and liabilities and carry-forward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse as if we had been a corporation for federal and state income tax purposes. In addition, ONEOK managed its tax position based upon the tax attributes of the consolidated group. Certain attributes may not be available to use if we had been operating as an independent company.

The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated:



	December 31,
	2014		2013
	(Thousands of dollars)
Deferred tax assets
Employee benefits and other accrued liabilities	$	128,715	$	—
Net operating loss	8,144		40,125
Other	5,655		8,249
Total deferred tax assets	142,514		48,374
Deferred tax liabilities
Excess of tax over book depreciation	820,853		750,305
Purchased-gas cost adjustment	16,177		4,695
Other regulatory assets and liabilities, net	193,159		2,563
Total deferred tax liabilities	1,030,189		757,563
Net deferred tax liabilities	$	887,675	$	709,189

At December 31, 2014, we had income taxes receivable of $43.8 million. We had no income taxes payable or receivable at December 31, 2013.

In accordance with the Tax Matters Agreement, a cash settlement of $3.8 million is expected from ONEOK related to both the filing of ONEOK’s income tax return for the calendar year ended December 31, 2013 and for the January 1, 2014, through January 31, 2014 period. Our net deferred tax liabilities were adjusted to reflect this settlement.

The net operating loss of $8.1 million expires in 2035. We expect to utilize all of the net operating loss prior to its expiration date.


14.	COMMITMENTS AND CONTINGENCIES

Commitments - Operating leases represent future minimum lease payments under noncancelable leases covering office space, facilities and information technology hardware and software. Rental expense was $5.0 million in 2014 and $4.8 million in each of 2013 and 2012. The following table sets forth our operating lease payments for the periods indicated:



Operating Leases
(Millions of dollars)
2015	$	4.7
2016	4.5
2017	4.3
2018	4.0
2019	3.4
Thereafter	10.4
Total	$	31.3

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 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, results of operations and cash flows.


•	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.

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


15.	QUARTERLY FINANCIAL DATA (UNAUDITED)



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2014	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Thousands of dollars)
Revenues	$	766,178	$	296,838	$	241,522	$	514,368
Net margin	$	259,836	$	176,493	$	166,452	$	224,176
Operating income	$	109,353	$	26,812	$	19,119	$	70,010
Net income	$	59,076	$	9,454	$	4,653	$	36,607
Earnings per share
Basic	$	1.13	$	0.18	$	0.09	$	0.70
Diluted	$	1.13	$	0.18	$	0.09	$	0.69



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2013	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Thousands of dollars)
Revenues	$	635,933	$	311,608	$	219,725	$	522,686
Net margin	$	251,674	$	178,447	$	159,233	$	223,654
Operating income	$	101,838	$	39,307	$	14,189	$	65,014
Net income	$	53,492	$	14,951	$	434	$	30,318
Earnings per share
Basic and diluted	$	1.02	$	0.29	$	0.01	$	0.58


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of our internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their reports which are included herein (Item 8).

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors of the Registrant

Information concerning our directors is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

Executive Officers of the Registrant

Information concerning our executive officers is included in Part I, Item 1, Business, of this Annual Report.

Compliance with Section 16(a) of the Exchange Act

Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

Nominating Procedures

Information concerning the nominating procedures is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

The Audit Committee

Information concerning the Audit Committee is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

The Audit Committee Financial Experts

Information concerning the Audit Committee Financial Experts is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

The Executive Compensation Committee

Information concerning the Executive Compensation Committee is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

The Corporate Governance Committee

Information concerning the Corporate Governance Committee is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

The Executive Committee

Information concerning the Executive Committee is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

Committee Charters

The full text of our Audit Committee charter, Executive Compensation Committee charter, Corporate Governance Committee charter and Executive Committee charter are published on and may be printed from our website at www.onegas.com and are also available from our corporate secretary upon request.

ITEM 11. EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

Information concerning the ownership of certain beneficial owners is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

Security Ownership of Management

Information on security ownership of directors and officers is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

Equity Compensation Plan Information

The following table sets forth certain information concerning our equity compensation plans as of December 31, 2014:



	Number of Securities Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities in Column (a))
Plan Category	(a)	(b)			(c)
Equity compensation plans approved by security holders	—	$	—		—
Equity compensation plans not approved by security holders (1)	—	$	—	(2)	3,474,486
Total	—	$	—		3,474,486

(1) Includes shares granted under our Employee Stock Purchase Plan and Employee Stock Award Program, restricted stock incentive units and performance-unit awards granted under our Equity Compensation Plan and our Nonqualified Deferred Compensation Plan for Nonemployee Directors. For a brief description of the material features of these plans, see Note 12 of the Notes to Financial Statements in this Annual Report. Column (c) includes 648,391, 89,681 and 2,736,414 shares available for future issuance under our Employee Stock Purchase Plan, Employee Stock Award Program and Equity Compensation Plan, respectively.

(2) Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for Nonemployee Directors is distributed to participants at fair market value on the date of distribution. The price used for these plans to calculate the weighted-average exercise price in the table is $41.22, which represents the year-end closing price of our common stock on the NYSE.


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information on certain relationships and related transactions and director independence is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.


ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

Information on the principal accountant’s fees and services is set forth in our 2015 definitive Proxy Statement and is incorporated herein by this reference.

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(1) Financial Statements			Page No.

	(a)	Report of Independent Registered Public Accounting Firm	45

	(b)	Statements of Income for the years ended December 31, 2014, 2013 and 2012	46

	(c)	Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	47

	(d)	Balance Sheets as of December 31, 2014 and 2013	48-49

	(e)	Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	50

	(f)	Statements of Equity for the years ended December 31, 2014, 2013 and 2012	51-52

	(g)	Notes to Financial Statements	53-78

(2) Financial Statements Schedules

	All schedules have been omitted because of the absence of conditions under which they are required.



(3) Exhibits

	2.1	Separation and Distribution Agreement, dated as of January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 2.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-36108)).

	3.1	Amended and Restated Certificate of Incorporation of ONE Gas, Inc., dated January 31, 2014 (incorporated by reference to Exhibit 4.5 to ONE Gas, Inc.’s Registration Statement on Form S-8 filed on January 31, 2014 (File No. 333-193690)).

	3.2	Amended and Restated By-Laws of ONE Gas, Inc. (incorporated by reference to Exhibit 4.6 to ONE Gas, Inc.’s Registration Statement on Form S-8 filed on January 31, 2014 (File No. 333-193690)).

	4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	4.2	Indenture, dated January 27, 2014, between ONE Gas, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 30, 2014 (File No. 1-36108)).

	4.3	Supplemental Indenture No. 1, dated January 27, 2014, between ONE Gas, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 30, 2014 (File No. 1-36108)).



	4.4	Registration Rights Agreement, dated January 27, 2014, among Morgan Stanley & Co. LLC, J.P. Morgan Securities LLC and RBS Securities Inc., as representatives of the several initial purchasers named therein (incorporated by reference to Exhibit 10.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 30, 2014 (File No. 1-36108)).

	10.1	Tax Matters Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-36108)).

	10.2	Transition Services Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 10.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-36108)).

	10.3	Employee Matters Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 10.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-36108)).

	10.4	Form of ONE Gas, Inc. Indemnification Agreement between ONE Gas, Inc. and ONE Gas, Inc. officers and directors (incorporated by reference to Exhibit 10.5 to ONE Gas, Inc.’s Registration Statement on Form 10 filed on October 1, 2013 (File No. 1-36108)).

	10.5	ONE Gas, Inc. Annual Officer Incentive Plan (incorporated by reference to Exhibit 10.6 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.6	ONE Gas, Inc. Pre-2005 Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.7 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.7	ONE Gas, Inc. Employee Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.8 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.8	ONE Gas, Inc. Pre-2005 Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.9 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.9	ONE Gas, Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.10 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.10	Credit Agreement, dated as of December 20, 2013, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swingline lender and a letter of credit issuer, and the other lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Current Report on Form 8-K filed on December 23, 2013 (File No. 1-13643)).

	10.11	ONE Gas, Inc. Officer Change in Control Severance Plan (incorporated by reference to Exhibit 10.12 to ONE Gas, Inc.’s Registration Statement filed on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.12	ONE Gas, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.13 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.13	Form of 2014 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.13 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).




	10.14	Form of 2014 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.14 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).

	10.15	Form of 2013 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.15 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).

	10.16	Form of 2013 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.16 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).

	10.17	Form of 2012 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.17 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).

	10.18	Form of 2012 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.18 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).

	10.19	ONE Gas, Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.16 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	10.20	ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc. Current Report on Form 8-K filed on February 24, 2014 (File No. 1-36108)).

	10.21	ONE Gas, Inc. 401(k) Plan of ONE Gas Employees and Former ONE Gas Employees effective as of January 1, 2014 (incorporated by reference to Exhibit 4.4 to ONE Gas, Inc.’s Registration Statement on Form S-8 filed on January 31, 2014 (File No. 333-193690)).

	10.22	Form of Commercial Paper Dealer Agreement (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on September 10, 2014 (File No. 1-36108)).

	10.23	Form of 2015 Performance Unit Award Agreement.

	10.24	Form of 2015 Restricted Unit Award Agreement.

	12.1	Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2014, 2013, 2012, 2011 and 2010.

	21.1	Subsidiaries of ONE Gas, Inc.

	23.1	Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.

	31.1	Certification of Pierce H. Norton II pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification of Pierce H. Norton II pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

	32.2	Certification of Curtis L. Dinan pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).



	101.INS	XBRL Instance Document.

	101.SCH	XBRL Schema Document.

	101.CAL	XBRL Calculation Linkbase Document.

	101.LAB	XBRL Label Linkbase Document.

	101. PRE	XBRL Presentation Linkbase Document.

	101.DEF	XBRL Extension Definition Linkbase Document.

Attached as Exhibit 101 to this Annual Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Statements of Income for the years ended December 31, 2014, 2013 and 2012; (iii) Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012; (iv) Balance Sheets for the years ended December 31, 2014 and 2013; (v) Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012; (vi) Statements of Equity for the years ended December 31, 2014, 2013 and 2012; and (vii) Notes to Financial Statements.

We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



Date: February 19, 2015		ONE Gas, Inc.
		Registrant

	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan
		Senior Vice President,
		Chief Financial Officer and Treasurer

Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 19th day of February 2015.



	/s/ John W. Gibson		/s/ Pierce H. Norton II
	John W. Gibson		Pierce H. Norton II
	Chairman of the Board		President, Chief Executive Officer and
			Director

	/s/ Curtis L. Dinan		/s/ Robert B. Evans
	Curtis L. Dinan		Robert B. Evans
	Senior Vice President,		Director
	Chief Financial Officer and Treasurer
	(Principal Accounting Officer)

	/s/ Michael G. Hutchinson		/s/ Pattye L. Moore
	Michael G. Hutchinson		Pattye L. Moore
	Director		Director

	/s/ Eduardo A. Rodriguez		/s/ Douglas H. Yaeger
	Eduardo A. Rodriguez		Douglas H. Yaeger
	Director		Director