# ONE Gas, Inc.: Form 10-K for the period ended Dec 31, 2017

- Company: [ONE Gas, Inc.](/companies/ogs.md) (CIK 1587732)
- Form: 10-K
- Filed: 2018-02-22
- Accepted by EDGAR: Feb 22, 2018, 14:05 ET
- Period: 2017-12-31
- Accession: 0001587732-18-000014
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1587732/000158773218000014/onegas10-k2017.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1587732/000158773218000014/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2017-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Gross profit | 12 months, 2017-01-01 to 2017-12-31 | $925.1m | us-gaap:GrossProfit |
| Operating income | 3 months, 2017-10-01 to 2017-12-31 | $89.5m | us-gaap:OperatingIncomeLoss |
| Operating income | 12 months, 2017-01-01 to 2017-12-31 | $299.5m | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2017-01-01 to 2017-12-31 | $46.1m | us-gaap:InterestExpense |
| Income tax | 12 months, 2017-01-01 to 2017-12-31 | $93.1m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2017-10-01 to 2017-12-31 | $47.1m | us-gaap:NetIncomeLoss |
| Net income | 12 months, 2017-01-01 to 2017-12-31 | $163.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2017-10-01 to 2017-12-31 | $0.89 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 12 months, 2017-01-01 to 2017-12-31 | $3.08 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2017-10-01 to 2017-12-31 | $0.90 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 12 months, 2017-01-01 to 2017-12-31 | $3.10 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2017-01-01 to 2017-12-31 | 52,979,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2017-01-01 to 2017-12-31 | $253.8m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2017-01-01 to 2017-12-31 | $356.4m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 12 months, 2017-01-01 to 2017-12-31 | $88.0m | us-gaap:PaymentsOfDividends |
| Share repurchases | 12 months, 2017-01-01 to 2017-12-31 | $17.5m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2017-12-31 | $14.4m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2017-12-31 | $589.0m | us-gaap:AssetsCurrent |
| Total assets | at 2017-12-31 | $5.21bn | us-gaap:Assets |
| Current liabilities | at 2017-12-31 | $673.3m | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2017-12-31 | $1.19bn | us-gaap:LongTermDebtNoncurrent |
| Short-term borrowings | at 2017-12-31 | $0 | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2017-12-31 | $1.96bn | us-gaap:StockholdersEquity |

## Business

As filed, 33,841 characters.

### OUR BUSINESS

ONE Gas, Inc. is incorporated under the laws of the state of Oklahoma. Our common stock is listed on the NYSE under the trading symbol “OGS,” and is included in the S&P MidCap 400 Index. We are a 100-percent regulated natural gas distribution utility, headquartered in Tulsa, Oklahoma. We are one of the largest publicly traded natural gas utilities in the United States, and successor to the company founded in 1906 as Oklahoma Natural Gas Company, which became ONEOK, Inc. (NYSE: OKE) in 1980. On January 31, 2014, ONE Gas officially separated from ONEOK.

We provide natural gas distribution services to more than 2 million customers, and are the largest natural gas distributor in Oklahoma and Kansas and the third largest in Texas, in terms of customers. 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 to approximately 88 percent, 72 percent and 13 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively.

### OUR STRATEGY

We operate with a mission to deliver natural gas for a better tomorrow. Our vision is to be a premier natural gas distribution company, creating exceptional value for all stakeholders. Our business strategy is focused on operating our systems in a safe, reliable and environmentally responsible manner and growing our business strategically, while delivering quality customer service. We believe this will enable us to generate a competitive total return for our shareholders and maintain our financial stability, leading to our strategic goals of zero harm, a fair return and satisfied customers.

We intend to accomplish our objectives by executing on the following strategies:

- Focus on Safety, Reliability and Compliance - We are committed, first and foremost, to pursuing a zero-incident safety and 100-percent compliance culture through programs, procedures, policies, guidelines and other internal controls designed to mitigate risk and incidents that may harm our employees, contractors, customers, the public or the environment. Additionally, a significant portion of our capital spending is focused on the safety, integrity, reliability and efficiency of our natural gas distribution system. We are committed to compliance with all federal, state and local laws and regulations.
- High-performing Workforce - The foundation of our company is our employees. Our success begins with our people and a commitment to attracting, selecting, retaining and developing a high-performing, ethical workforce where every employee understands that they can and do make a difference. We embrace and promote inclusion, diversity and collaboration. We expect a high standard of performance from our employees, and encourage our workforce to measure their productivity and be accountable for the best work possible. Each day that we do our best to safely, efficiently and ethically meet the needs of our customers is a day that leads to individual success and, ultimately, the success of the company.
- Increase Our Achieved ROE - We continually seek to increase our achieved ROE through improved operational performance, regulatory mechanisms and incremental transportation revenues. 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 continue to leverage technology to improve our operational performance. Ongoing initiatives to expand the use of technology in key areas of operations and customer service are expected to result in increased efficiency, thereby helping reduce the rate of increasing expenses.

Our focus on credit metrics and maintaining a balanced approach to capital management are significant objectives in providing reasonable rates to customers while also providing a fair return to shareholders. 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 customers, employees, investors, legislators and regulators. Our strategy includes meeting the needs of our customers through the delivery of safe and reliable natural gas service while seeking outcomes in future rate proceedings that provide recovery of our costs and a fair return on our infrastructure investments.
- Identify and Pursue Growth Opportunities - Our growth opportunities are a result of capital investments related to the safety and reliability of our existing system, as identified by our system integrity program, in addition to system expansion 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 we expect to further grow our rate base. In addition, as some of 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 seven major metropolitan areas we serve.

We believe the competitiveness of natural gas is increasing, creating new market opportunities for natural gas as an energy source within our existing service territories. Our emphasis on safety and a satisfying customer service experience makes our business an important part of the communities we serve. Natural gas remains positioned within the United States energy economy as the foundation fuel of scale, which we believe will support sustainable growth opportunities, energy independence and national security.

We remain committed to maintaining our status as a 100-percent regulated natural gas utility. We will, however, follow a disciplined financial and operational approach to evaluating both strategic acquisition opportunities and continued investments in our existing rate base.

### REGULATORY OVERVIEW

We are subject to the regulations and oversight of the state and local regulatory authorities 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 incorporated cities that it serves, which have primary jurisdiction for their respective service 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, our 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 we make investments or incur 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 allowed expenses. Under this mechanism, we have an allowed ROE of between 9 percent and 10 percent. If our achieved ROE is below 9 percent, our base rates are increased upon OCC approval to an amount necessary to restore the ROE to 9.5 percent. If our achieved ROE exceeds 10 percent, the portion of the earnings that resulted in an achieved ROE that exceeds 10 percent is shared with our customers, who receive the benefit of 75 percent of the portion of earnings that resulted in an achieved ROE that exceeds 10 percent. We receive the benefit of the remaining 25 percent. Oklahoma Natural Gas is required to file a rate case on or before June 30, 2021, based on a test year consisting of the twelve months ending December 31, 2020. Other regulatory mechanisms in Oklahoma include the following:

- Rate Design for Residential Customers - Oklahoma Natural Gas is authorized to utilize a rate structure providing customers with two rate choices. Rate Choice “A” is designed for customers whose annual normalized volume is less than 50 Dth. These customers pay 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 is $16.98, with a delivery fee of $4.1143 per Dth for these customers. Rate Choice “B” is designed for customers whose annual normalized volume is 50 Dth or greater. These customers pay only a fixed monthly service charge of $34.12. At December 31, 2017, 72 percent of Oklahoma Natural Gas’ residential customers were on Rate Choice “B.”

- Rate Design for Commercial and Industrial Customers - Oklahoma Natural Gas is authorized to utilize a structure providing 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. These customers pay both a fixed monthly service charge of $20.81 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. These customers pay only a fixed monthly service charge of $36.01. All of Oklahoma Natural Gas’ Large Commercial and Industrial, or LCI, customers, whose annual volume is 150 Dth or greater, but less than 5,000 Dth, pay a fixed monthly service charge of $96.11. At December 31, 2017, 79 percent of Oklahoma Natural Gas’ commercial and industrial customers were on either SCI Rate Choice “B” or LCI.
- PGA Clause - Oklahoma Natural Gas’ commodity, transportation, storage and gas purchase operations and maintenance costs are passed through to its sales customers, without profit, 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.
- TAC - The TAC is a weather normalization mechanism designed to reduce the delivery charge component of customers’ bills for the additional volumes used when the actual HDDs exceed the normalized HDDs and to increase the delivery charge component of customers’ bills for volumes not used when actual HDDs are less than the normal HDDs. Normalized HDDs established through our most recent rate proceeding are based on 10-year weighted average HDDs as of December 31, 2014, for years 2005-2014, as calculated using 11 weather stations across Oklahoma and weighted on average customer count for Oklahoma. The TAC is in effect from November through April.
- Energy Efficiency Programs - Oklahoma Natural Gas has energy efficiency programs, available to all of its 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 $15.4 million each year from sales customers to fund the programs, which provides rebates for energy efficient natural gas appliances.
- CNG 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. Collections from the surcharge to fund the program were not material in 2017.

For the year ended December 31, 2017, approximately 88 percent of Oklahoma Natural Gas’ net margin from its sales customers was recovered from fixed charges.

**Kansas** - Kansas Gas Service files periodic rate cases with the KCC as needed to increase base rates to reflect Kansas Gas Service’s authorized revenue requirement. 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 - In 2016, the WNA Clause required Kansas Gas Service to accrue the variation in net margin resulting from actual weather differing from normal weather occurring from November through March. Beginning in April 2017, the WNA mechanism allows an accrual each month of the year. WNA is designed to reduce the delivery charge component of customers’ bills for the additional volumes used when the actual HDDs exceed the normalized HDDs and to increase the delivery charge component of customers’ bills for the reduction in volumes used when actual HDDs are less than the normal HDDs. Normal HDDs are established through rate proceedings and are based on a 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using 4 weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas. Annually, the amount of the adjustment is determined and is then applied to customers’ bills over the subsequent 12-month period. Prior to April 2017, Normal HDDs were based on a 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.

- ATSR - This rider requires Kansas Gas Service to recover the difference each year between the property tax costs included in its base rates and its actual property tax costs incurred 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 Postemployment Benefits Trackers - These trackers require Kansas Gas Service to track and defer for recovery in its next rate case the difference between the pension and other postemployment 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, such as expenditures necessary to meet state and federal pipeline safety requirements and government-required relocation projects, incurred between rate case filings. The filing cannot occur more often than once every 12 months and the rate adjustment cannot increase the monthly charge by more than $0.40 per residential customer compared with 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 was $16.70, and for the year ended December 31, 2017, approximately 54 percent of Kansas Gas Service’s net margin from its sales customers was recovered from fixed charges.

**Texas** - Texas Gas Service has grouped its customers into six service areas. These service areas are further divided into the incorporated cities and the unincorporated areas, referred to as the environs. The incorporated cities in the service areas have original jurisdiction, with the RRC having appellate authority, and the RRC has original jurisdiction for the environs. Periodic rate cases are filed with the cities or the RRC, as needed, to reflect Texas Gas Service’s authorized revenue requirement. Other regulatory mechanisms and constructs in Texas include the following:

- GRIP Statute - For the incorporated cities in three of the service areas and for the environs in five of the service areas, comprising 81 percent of Texas Gas Service’s customers, Texas Gas Service makes an annual filing under the GRIP statute, which allows it to recover taxes and depreciation and to earn a return on the annual net increase in investment for the service area. 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 three of the service areas, comprising 19 percent of its customers, Texas Gas Service makes an annual COSA filing for the incorporated cities. 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. The COSAs have a cap of 3.5 percent to 5 percent on the expense portion of the increase. A full rate case may be filed when desired by Texas Gas Service or the regulator, but is not required.
- WNA Clause - Texas Gas Service employs WNA clauses in all six service areas. The WNA clause is designed to reduce the delivery charge component of customers’ bills for the additional volumes used when the actual HDDs exceed the normalized HDDs and to increase the delivery charge component of customers’ bills for the reduction in volumes used when actual HDDs are less than the normal HDDs. Normal HDDs are established through rate proceedings in each of our service areas and are generally based on a 10-year average of HDDs in each service area. The WNA clause is in effect from September through May.
- COG Clause - In all service areas, Texas Gas Service recovers 100 percent of its natural gas costs, including transportation and storage costs, 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 natural gas costs recovered through the COG with the actual natural gas supply costs. Any over- or under-recovery is refunded or recovered, as applicable, in the subsequent year.
- Pension and Other Postemployment Benefits - Texas Gas Service is authorized by statute to defer pension and other postemployment 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 100 percent of its pipeline-integrity testing expenses via riders.
- Safety-Related Plant Replacements - Texas Gas Service is authorized by RRC rule to defer interest cost, 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 Programs - Texas Gas Service has energy conservation programs in the incorporated cities of our Central Texas and Rio Grande Valley service areas, comprising 46 percent of total customers. Texas Gas Service collects approximately $3.5 million per year from customers to fund the programs, which provide energy audits, weatherization and appliance rebates to promote energy conservation.

The average fixed monthly residential customer charge for Texas Gas Service is $16.19, and for the year ended December 31, 2017, approximately 66 percent of Texas Gas Service’s net margin from its sales customers was recovered from fixed charges.

### MARKET CONDITIONS AND SEASONALITY

Supply - We purchased 137 Bcf and 134 Bcf of natural gas supply in 2017 and 2016, respectively. 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, marketers and 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 provisions in our tariffs 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;
- more energy-efficient construction;
- fuel switching from natural gas to electricity; and
- customers improving the energy efficiency of existing homes by replacing doors and windows, adding insulation, and replacing appliances with more efficient appliances.

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

As of December 31, 2017, we had 50.4 Bcf of natural gas storage capacity under lease with remaining terms ranging from one to ten years and maximum allowable daily withdrawal capacity of approximately 1.3 Bcf. This storage capacity allows us to purchase natural gas during the off-peak season and store it for use in the winter periods. This storage is also needed to assure the reliability of gas deliveries during peak demands for natural gas. Approximately 27 percent of our winter natural gas supply needs for our sales customers is expected to be supplied from storage.

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 OCC, KCC and certain jurisdictions in Texas. We do not utilize financial derivatives for speculative purposes, nor do we have trading operations associated with our business.

Demand - See discussion below under Seasonality, Competition and CNG 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 TAC and 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 primarily to supply energy for space and water heating, cooking and clothes drying. 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 U.S. 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 table below contains data related to the cost of delivered gas relative to electricity based on current market conditions:

| Natural Gas vs. Electricity Average retail price of electricity / kWh(1) | Oklahoma 10.58¢ | Kansas 13.32¢ | Texas 11.18¢ |
| --- | ---: | ---: | ---: |
| Natural gas price equivalent of electricity / Dth(1) | $31.01 | $39.04 | $32.77 |
| ONE Gas delivered cost of natural gas / Dth(2) | $10.90 | $10.55 | $13.77 |
| Natural gas advantage ratio(3) | 2.8x | 3.7x | 2.4x |

(1) Source: United States Energy Information Agency, www.eia.gov, for the eleven-month period ended November 30, 2017.

(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, 2017.

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

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.

CNG - In meeting increased interest in CNG for motor vehicle transportation, particularly from fleet operators, we have continued to invest in our system to support the supply of natural gas to CNG fueling stations. As of December 31, 2017, we supply 147 fueling stations, 32 of which we operate. Of the 115 remaining stations, 65 are retail and 50 are private CNG stations. We transported 2.6 million Dth to CNG stations in 2017, which represents an increase of 5 percent compared with 2016.

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

See Note 13 of the Notes to Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for information regarding environmental and safety matters.

### EMPLOYEES

We employed approximately 3,500 people at February 1, 2018, 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, 2018:

| Union | Approximate Employees | Contract Expires |
| --- | ---: | --- |
| The United Steelworkers | 400 | October 31, 2019 |
| International Brotherhood of Electrical Workers (“IBEW”) | 300 | June 30, 2018 |

10

### EXECUTIVE OFFICERS OF THE REGISTRANT

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 | Age\* |  | Business Experience in Past Five Years |
| --- | ---: | --- | --- |
| **Pierce H. Norton II** | 57 | 2014 to present | President, Chief Executive Officer and Director |
|  |  | 2013 to 2014 | Executive Vice President, Commercial, ONEOK and ONEOK Partners |
| **Curtis L. Dinan** | 50 | 2014 to present | Senior Vice President, Chief Financial Officer and Treasurer |
|  |  | 2013 to 2014 | Senior Vice President, Natural Gas, ONEOK Partners |
| **Joseph L. McCormick** | 58 | 2014 to present | Senior Vice President, General Counsel and Assistant Secretary |
|  |  | 2013 to 2014 | Vice President and Associate General Counsel, ONEOK and ONEOK Partners |
| **Caron A. Lawhorn** | 56 | 2014 to present | Senior Vice President, Commercial |
|  |  | 2013 to 2014 | Senior Vice President, Commercial, Natural Gas Distribution, ONEOK |
| **Robert S. McAnnally** | 54 | 2015 to present | Senior Vice President, Operations |
|  |  | 2013 to 2015 | Senior Vice President, Marketing and Customer Service, Alabama Gas Corporation, a subsidiary of The Laclede Group, Inc. (now Spire Inc.) |
| **Mark A. Bender** | 53 | 2015 to present | Senior Vice President, Administration and Chief Information Officer |
|  |  | 2014 to 2015 | Vice President and Chief Information Officer |
|  |  | 2013 to 2014 | Vice President of Information Technology Operations, Chesapeake Energy Corporation |
| \* As of January 1, 2018 |  |  |  |

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, Corporate 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.

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

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

## Risk factors

As filed, 59,451 characters.

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 Part 2, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

### RISK FACTORS INHERENT IN OUR BUSINESS

***Regulatory actions could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover 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 authorities set the rates that we charge our customers for our services. Our ability to obtain timely future rate increases depends on regulatory discretion. As such, 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 adversely impacted. Regulatory proceedings also involve a risk of rate reduction, because once a proceeding has been filed, it is subject to challenge by various interveners. Risks and uncertainties relating to delays in obtaining, or failure to obtain, regulatory approvals, conditions imposed in regulatory approvals, and determinations in regulatory investigations can also impact financial performance. In particular, the timing and amount of rate relief can materially impact results of operations, financial condition and cash flows.

Further, accounting principles that govern our company permit certain assets that result from the regulatory process to be recorded on our Consolidated 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 by 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 adversely affect 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 adversely affected.

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 timely recover 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 give assurance that our regulators will continue to allow recovery of such expenditures in the future. Changes in the regulatory environment applicable to our business or the imposition of additional regulation could impair our ability to recover costs absorbed historically by our customers, and adversely impact our results of operations, 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, safety, financing, affiliate transactions, customer service and the terms of service to customers, including the rates that we can charge customers. Currently, there are regulatory efforts in Oklahoma, Kansas and Texas to adjust our rates to reflect lower federal corporate tax rates brought about by the enactment of the Tax Cuts and Jobs Act of 2017.

The profitability of our operations is dependent on our ability to pass through costs, including income taxes, 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. In addition, as the regulatory environment applicable to our operations increases in complexity, the risk of inadvertent noncompliance could also increase. Our failure to comply with applicable laws and regulations could result in the imposition of fines, penalties or other enforcement action by the authorities that regulate our operations.

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.

***We are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect our financial condition, results of operations and cash flows.***

In the normal course of business, we are involved in legal or administrative proceedings before various courts and governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require us to make payments in excess of amounts provided for in our consolidated financial statements, or to the extent they are not covered by insurance, could adversely affect our financial condition, results of operations and cash flows.

### Unfavorable economic and market conditions could adversely affect our earnings.

Weakening economic activity in our markets could result in a loss of existing customers, fewer new customers, especially in newly constructed homes and other buildings, or a decline in energy consumption, any of which could adversely affect 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. We cannot predict the timing, strength, or duration of any future economic slowdowns. Fluctuations and uncertainties in the economy make it challenging for us to accurately forecast and plan future business activities and to identify risks that may affect our business, financial condition, results of operations and cash flows. Changes in monetary or other policies of the federal or state governments may adversely affect the economic climate for the United States, the regions in which we operate or particular industries, such as ours or those of our customers. The foregoing could adversely affect our business, financial condition, results of operations and cash flows.

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

Changes in supply and demand within the natural gas markets, as well as other factors, could cause an increase in the price of natural gas. 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, other factors could put upward pressure on natural gas prices, including restrictions or regulations on shale natural gas production and waste water disposal, increased demand from natural gas fueled electric power generation and increases in natural gas exports. 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. Also, the threat of terrorist activities or heightened international tensions could lead to increased economic instability and volatility in the price of natural gas.

Natural gas costs are passed through to our customers based on the actual cost of the natural gas we purchase. However, 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. Costs are recovered through our collection on customer bills following consumption by our customers. The delay in recovery of our natural gas costs could adversely affect our financial condition and cash flows.

Further, higher and more volatile natural gas prices may adversely impact our customers’ perception of natural gas. 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 adversely impact our accounts receivable collections, resulting in higher bad debt expense. The occurrence of any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows, as well as our future growth opportunities.

***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-management 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.

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

The natural gas distribution business is competitive, and we face competition from other companies that supply energy, including electric companies, private generation, solar, 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 adversely impact 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 encourage decreases in natural gas consumption and allow competition from alternative energy sources for applications that have 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, environmental and other nonprice factors. Technological improvements in other energy sources, energy storage, conservation, efficiency 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 adversely affecting 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 adversely impact the growth opportunities available to us and the usage patterns and financial condition of our customers. This could adversely affect 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 rely on and must obtain sufficient natural gas supplies, pipeline transportation and storage capacity from third parties. We must contract for reliable and adequate delivery capacity for our distribution system, while considering the dynamics of the interstate and intrastate pipeline capacity markets, our own in-system resources, as well as the characteristics of our customer base. If we are unable to obtain these, our ability to meet our customers’ natural gas requirements could be impaired and our financial condition, cash flow 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 adversely affect our cost of and ability to access capital.***

Our ability to obtain adequate and cost-effective financing depends in part on our credit ratings. Our credit ratings are subject to change at any time in the discretion of the applicable rating agencies. Numerous factors, including many of which are not within our control, are considered by the rating agencies in connection with assigning credit ratings. For example, the Tax Cuts and Jobs Act of 2017 recently prompted one rating agency to adjust the credit outlook (but not the underlying credit ratings) of several regulated utilities, including us. A reduction in our ratings by our rating agencies could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit or delay 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 or delay our ability to obtain additional financing in the future for working capital, capital expenditures and acquisitions when necessary or desirable. In addition, our pool of investors and prospective creditors would likely decrease. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect our results of operations, financial condition 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, credit rating or reputation.

***We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect 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 adversely affect 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, or the discovery of presently unknown environmental conditions, 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 legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. A number of environmental issues may exist with respect to these former MGP sites. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation, changing technology and governmental regulations and could be material to our financial condition, results of operations and cash flows.

With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us that are subject to environmental regulation, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, which could adversely affect our financial condition, 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, and reputation.

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

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. 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 adversely impact 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 or cause fuel switching to other energy sources, and impact the competitive position of natural gas and the ability to serve new or existing customers, adversely affecting 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. To the extent climate change adversely impacts the economic health of our operating territory, it could adversely impact customer demand or our customers’ ability to pay. 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, our cost of providing service could increase. 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 adversely affect 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 adversely impact 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 for our sales to customers in Oklahoma, Kansas and portions of Texas, which are designed to limit our earnings sensitivity to weather. Weather normalization mechanisms require 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, financial condition and cash flows could vary and be impacted adversely.

***We may not be able to complete necessary or desirable 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 adversely impact 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 adversely impact 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 divestitures 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. These efforts may also distract our management and employees from day-to-day operations and require substantial commitments of time and resources. 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 adversely affect 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 successfully integrate businesses that we acquire.

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

At December 31, 2017, we had approximately $158 million of goodwill recorded on our Consolidated 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 adversely impact 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 adversely affect 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 adversely affect 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 significantly increase 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 adversely impact customer billings and customer growth. Changes in tax rates, including the effects of the Tax Cuts and Jobs Act of 2017, could adversely affect our cash flows and may increase the cash we pay for income taxes in the future. Any of these events may cause us to increase debt, conserve cash, adversely affect our ability to make capital expenditures to grow the business or other discretionary uses of cash, and could adversely affect 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, and in determining the amount of any reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by taxing authorities. 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 adversely affect 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 postemployment 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 and its potential revision, repeal and/or replacement 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 postemployment welfare plans for certain eligible employees. Our defined benefit plans are closed to new participants. Our other postemployment welfare plans only subsidize costs for providing postemployment medical benefits. 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 postemployment benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries, current and future legislative changes, changes in health care costs, and various actuarial calculations and assumptions.

Any sustained declines in equity markets and reductions in bond values may have a material adverse effect on the value of our pension and other postemployment benefit plan assets. In these circumstances, additional cash contributions to our pension and other postemployment 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, and its potential revision, repeal and/or replacement. The future costs of compliance with the provisions are difficult to measure at this time. Also, our costs of providing such benefits and related funding requirements could also materially increase in the future, depending on the timing of the recovery, if any, of such costs through our rates, which could adversely impact our financial condition and cash flows.

***Our business is subject to operational hazards and unforeseen interruptions that could materially and adversely affect 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 adversely affect our earnings and cash flows.

Unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate response to events may have an adverse impact on our financial condition, results of operations 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.

***Our business increasingly relies on technology, the failure of which, or the occurrence of cyber or physical security attacks thereon, or those of third parties, may adversely affect our financial results.***

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, including an enterprise resource planning system that integrates data and reporting activities across our company. The failure of these or other similarly important technologies, the lack of alternative technologies, or our inability to have these technologies supported, updated, expanded or integrated into other technologies, could hinder our operations and adversely impact our financial condition and results of operations. The use of technological programs, systems and tools may subject our business to increased risks.

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 or third party 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 or third party tampering or manipulation of those systems will result in losses that are difficult to detect or mitigate.

There is no guarantee that the precautions we take to protect against unauthorized access to secured data on our systems are adequate to safeguard against all security breaches. Any future cyber or physical security attacks, or threats of such attacks, that affect our distribution facilities, our customers, our suppliers and third-party service providers or any financial data could have a material adverse effect on our businesses. As potential cyber or physical security attacks become more common and sophisticated, we could be required to incur increased costs to strengthen our systems or to obtain additional insurance coverage against potential losses. In addition, cyber or physical attacks or threats on our company, customer and employee data may result in a financial loss and may adversely impact our reputation. Third-party systems on which we rely could also suffer operational system failure.

The foregoing events could adversely affect 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 adversely affected by strikes or work stoppages by our unionized employees.***

At February 1, 2018, approximately 700 of our estimated 3,500 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, results of operations and cash flows.

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

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

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

We are subject to additional changes in GAAP, SEC regulations and other interpretations of financial reporting requirements for public utilities. We neither have control over the impact these changes may have on our financial condition or results of operations nor the timing of such changes.

***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, results of operations and cash flows.

***Some of our debt, including borrowings under our ONE Gas Credit Agreement and our commercial paper program, 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 and commercial paper program are based on variable rates of interest. 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 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 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.

***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 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, results of operations and cash flows.

### 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 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.

## Properties

As filed, 667 characters.

The following table sets forth the approximate miles of distribution mains and transmission pipeline as of December 31, 2017:

| Properties (miles) | OK | KS | TX | Total |
| --- | ---: | ---: | ---: | ---: |
| Distribution | **18,500** | **11,400** | **10,300** | **40,200** |
| Transmission | **700** | **1,600** | **300** | **2,600** |
| Total properties | **19,200** | **13,000** | **10,600** | **42,800** |

We lease approximately 400 thousand square feet of office space and other facilities for our operations. In addition, we have 50.4 Bcf of natural gas storage capacity under lease, with maximum allowable daily withdrawal capacity of approximately 1.3 Bcf.

## Legal proceedings

As filed, 128 characters.

See Note 13 of the Notes to Consolidated Financial Statements in this Annual Report for information regarding legal proceedings.

## Management's discussion and analysis

As filed, 90,506 characters.

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

### EXECUTIVE SUMMARY

We are a 100-percent regulated natural gas distribution company. 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 of our natural gas sales net margin in 2017 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 that adjust customers’ bills when the actual HDDs differ from normalized HDDs, 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, therefore, is contingent on a number of factors, including: (1) regulatory outcomes, which determine the returns we are authorized to earn and the rates we are allowed to charge for our service; (2) the consumption of natural gas, which impacts the amount of our net margin derived from the variable component of our rates; (3) our operating performance, which impacts our operating expenses; and (4) 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 integrity 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, because integrity and environmental regulation is changing constantly, our capital and operating expenditures to comply will change, as well. Although we believe our regulators will continue to allow recovery of such expenditures in the future, we will continue to make these expenditures with no assurance about if, or over what period, we will be permitted to recover them.

### RECENT DEVELOPMENTS

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

As a result of the enactment of the Tax Cuts and Jobs Act of 2017, we remeasured our deferred income taxes based upon the new tax rate enacted in 2017. As a regulated entity, the change in deferred income taxes is recorded as an offset to a regulatory liability and may be subject to refund to customers. The effect on the net deferred income tax liability for the enacted decrease in the federal tax rate was $517.2 million, of which $519.4 million was recorded as a reduction to the deferred income tax liabilities and deferred as a regulatory liability for ratemaking purposes and offset by $2.2 million recorded as an increase in deferred income tax expense attributable to the remeasured deferred income taxes associated with certain expenses not currently recovered in our rates. These adjustments had no impact on our 2017 cash flows.

See Regulatory Activities below for a discussion of the impact of tax reform on our rates in each state.

Dividend - In January 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of February 23, 2018, payable on March 9, 2018.

### REGULATORY ACTIVITIES

Oklahoma - In March 2017, Oklahoma Natural Gas filed its first annual PBRC following the general rate case that was approved in January 2016. This filing was based on a calendar test year of 2016. The PBRC filing demonstrated that Oklahoma Natural Gas was earning within the allowed return on equity range of 9.0 to 10.0 percent. Therefore, Oklahoma Natural Gas did not seek a modification to base rates. The filing also requested an energy efficiency program true-up and utility incentive adjustment of approximately $1.9 million. A joint stipulation and settlement agreement was approved by the OCC in August 2017. As required, PBRC filings are made annually on March 15, until the next general rate case, which is currently required to be filed on or before June 30, 2021, based on a calendar test year of 2020.

In March 2016, Oklahoma Natural Gas filed its energy efficiency program true-up application for its 2015 program year, requesting a utility incentive of $1.9 million and a program true-up adjustment of $3.1 million. This filing also sought approval for the demand portfolio of conservation and energy efficiency programs for calendar years 2017 through 2019. In October 2016, the OCC approved the joint stipulation and settlement agreement.

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

In March 2015, Oklahoma Natural Gas filed its energy efficiency program true-up application for its 2014 program year, requesting a utility incentive of $1.2 million. In December 2015, the OCC approved the joint stipulation and settlement agreement which was filed in July 2015.

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

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

In May 2016, Kansas Gas Service filed a request with the KCC for an increase in base rates, reflecting system investments and operating costs necessary to maintain the safety and reliability of its natural gas distribution system. In October 2016, Kansas Gas Service reached a unanimous settlement agreement with all parties for a net increase in base rates of approximately $8.1 million. Including the GSRS of approximately $7.4 million, the total base rate increase was $15.5 million. The agreement was a “black-box settlement,” meaning the parties agreed to a specific revenue number but no specific return on equity or determination with respect to other contested issues. Additionally, the agreement modified the weather normalization clause to accrue the variation in net margin resulting from the difference in actual weather relative to normal weather over 12 months, rather than five months. The KCC approved the new rates effective January 1, 2017.

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

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

In November 2015, Texas Gas Service notified the EPSA that it would be filing a full rate case in 2016 in lieu of the previously agreed to annual rate review mechanism called EPARR. In March 2016, Texas Gas Service filed a rate case for its El Paso, Dell City and Permian service areas, as well as consolidation of these three areas. In September 2016, the RRC approved the consolidation and a base rate increase of $8.8 million, which was based on a 9.5 percent return on equity and a 60.1 percent common equity ratio. In October 2016, new rates went into effect for all customers, except for those in the cities of the former Permian service area. Texas Gas Service filed for these new rates for customers in the cities of the former Permian service area in October 2016, and the rates became effective in December 2016.

*Rio Grande Valley Service Area -* In January 2018, Texas Gas Service reached a settlement with the RRC Staff in the unincorporated areas of the Rio Grande Valley service area. This settlement, if approved by the RRC, will result in an increase in revenues of $0.5 million with new rates expected to be effective by April 2018. This settlement reflects a corporate income tax rate of 21 percent associated with the Tax Cuts and Jobs Act of 2017 and requires Texas Gas Service to calculate, defer and begin refunding to customers the rate reductions resulting from changes to the corporate tax rate made in the Tax Cuts and Jobs Act of 2017 that would have occurred between January 1, 2018 and the effective date of the new rates.

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

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

In June 2016, Texas Gas Service filed a rate case for its Central Texas and South Texas service areas. The filing included a request to consolidate the South Texas service area with the Central Texas service area. Texas Gas Service filed this rate case directly with the cities of the Central Texas service area, which includes the city of Austin, and the RRC for the unincorporated areas. In October 2016, all parties to the filing reached a unanimous settlement agreement for an increase in revenues of $6.8 million for the new consolidated service area. New rates were effective in November 2016, for customers in the cities of the former Central Texas service area. RRC approval was received in November 2016 and new rates became effective for customers in the unincorporated areas of the new consolidated Central Texas service area the same month. Texas Gas Service received approval for the same rates in the incorporated areas of the former South Texas service area, with new rates effective in January 2017.

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

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

*El Paso Service Area* - In March 2015, Texas Gas Service filed under the EPARR, requesting an increase in revenues totaling $11.2 million in the city of El Paso and surrounding incorporated cities in the EPSA. In August 2015, Texas Gas Service and the incorporated cities in the EPSA reached an agreement on a rate increase of $8.0 million to take effect in August 2015. In April 2015, Texas Gas Service filed with the RRC under the GRIP statute, requesting an increase of $0.4 million in revenues for the unincorporated areas of the EPSA. The RRC approved the filing in July 2015.

*Other Texas Service Areas -* In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate increases associated with these filings that were approved totaled $1.4 million, $2.0 million and $4.8 million in 2017, 2016 and 2015, respectively.

Tax Reform - We are working with our regulators in each of the states that we operate to address the impact of the Tax Cuts and Jobs Act of 2017 on our rates. In each state, we have received or expect to receive accounting orders requiring us to establish a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35 percent statutory income tax rate and the new 21 percent statutory income tax rate beginning in January 2018. The establishment of this regulatory liability will result in a reduction to our revenues beginning in the first quarter of fiscal 2018. The amount, period and timing of the return of these liabilities to our customers will be determined by our regulators in each of our jurisdictions.

The following regulatory activities relate to the enactment of the Tax Cuts and Jobs Act of 2017:

*Oklahoma* - In December 2017, the Oklahoma Attorney General filed a motion on behalf of customers in Oklahoma requesting that the OCC take action for an immediate reduction in rates and protection of rate payers’ interests. On January 9, 2018, the Commissioners approved an order directing Oklahoma Natural Gas to record a deferred liability beginning on the effective date of the order to reflect the reduced federal corporate tax rate of 21 percent and the associated savings in excess ADIT and any other tax implications of the Tax Cuts and Jobs Act of 2017 on an interim basis, subject to refund, until utility rates are adjusted to reflect the federal tax savings and a final order is issued in Oklahoma Natural Gas’ next scheduled PBRC proceeding. The order also directs Oklahoma Natural Gas, to the extent not already accounted for in Oklahoma Natural Gas’ current PBRC tariff, to accrue interest at a rate equivalent to Oklahoma Natural Gas’ cost of capital as recognized in the most recent PBRC filing on the amounts of any refunds determined to be owed to customers until issuance of a final order in the upcoming PBRC proceeding.

*Kansas* - On January 18, 2018, the KCC opened a general investigation for the purposes of examining the financial impact of the Tax Cuts and Jobs Act of 2017 on regulated public utilities operating in Kansas. The KCC also granted a KCC Staff recommendation: (1) to issue an AAO requiring utilities to track and accumulate, in a deferred revenue account, the portion of their revenue that results from the use of a 35 percent federal corporate tax rate for its last KCC-approved revenue determination instead of the new lower federal corporate tax rate; (2) that the deferrals commence on the effective date of the new federal corporate tax rate; (3) that the KCC express its intent to capture excess ADIT in a manner consistent with tax normalization rules; and (4) that the portion of current rates affected by the Tax Cuts and Jobs Act of 2017 should be considered interim and subject to refund, with interest compounded monthly at the rate for customer deposits, until the KCC has an opportunity to evaluate the reasonableness of those rates with new lower federal tax rates.

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

*Texas -* The RRC is in the process of determining how the impact of the Tax Cuts and Jobs Act of 2017 will be reflected in gas utility rates in Texas. On January 23, 2018, the RRC directed the Commission’s gas services division to analyze the impact of the Tax Cuts and Jobs Act of 2017 on current gas utility rates and to develop recommendations to ensure that, beginning January 1, 2018, all gas utility customers in Texas receive the full benefit of the Tax Cuts and Jobs Act of 2017.

See Liquidity and Capital Resources - Tax Reform and Note 12 of the Notes to Consolidated Financial Statements for additional discussion of the Tax Cuts and Jobs Act of 2017.

### OTHER

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. There were no writeoffs of regulatory assets resulting from the failure to meet the criteria for capitalization during 2017, 2016 and 2015.

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

**Selected Financial Results -** Net income was $163.0 million, or $3.08 per diluted share, $140.1 million, or $2.65 per diluted share, and $119.0 million, or $2.24 per diluted share, for the years ended December 31, 2017, 2016 and 2015, respectively. Our prospective adoption of ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” resulted in favorable impacts to income tax expense and our net income from recording $5.2 million of excess tax benefits as a reduction to income tax expense in the first quarter 2017. As a result of the Tax Cuts and Jobs Act of 2017, we recorded deferred income tax expense of $2.2 million attributable to the remeasurement of ADIT associated with portions of our operating expenses not previously recovered in our rates.

We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. We evaluate our financial performance principally on operating income. The following table sets forth certain selected financial results for our operations for the periods indicated:

*(Millions of dollars, except percentages)*

| Financial Results | Years Ended December 31, 2017 | 2016 | 2015 | Variances 2017 vs. 2016 Increase (Decrease) |  | Variances 2016 vs. 2015 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Natural gas sales | **$1,409.1** | $1,300.1 | $1,417.9 | **$109.0** | **8%** | $(117.8) | (8)% |
| Transportation revenues | **100.9** | 98.1 | 98.8 | **2.8** | **3%** | (0.7) | (1)% |
| Cost of natural gas | **614.5** | 541.8 | 706.0 | **72.7** | **13%** | (164.2) | (23)% |
| Net margin, excluding other revenues | **895.5** | 856.4 | 810.7 | **39.1** | **5%** | 45.7 | 6% |
| Other revenues | **29.6** | 29.0 | 31.0 | **0.6** | **2%** | (2.0) | (6)% |
| Net margin | **925.1** | 885.4 | 841.7 | **39.7** | **4%** | 43.7 | 5% |
| Operating costs | **473.7** | 472.5 | 469.6 | **1.2** | **—%** | 2.9 | 1% |
| Depreciation and amortization | **151.9** | 143.8 | 133.0 | **8.1** | **6%** | 10.8 | 8% |
| Operating income | **$299.5** | $269.1 | $239.1 | **$30.4** | **11%** | $30.0 | 13% |
| Capital expenditures | **$356.4** | $309.0 | $294.3 | **$47.4** | **15%** | $14.7 | 5% |

30

Net margin is comprised of total revenues less cost of natural gas. Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. In addition, our cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of gas that we purchase, net margin is not affected by fluctuations in the cost of natural gas.

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

*(Millions of dollars, except percentages)*

| Net Margin, Excluding Other Revenues Natural gas sales | Years Ended December 31, 2017 | 2016 | 2015 | Variances 2017 vs. 2016 Increase (Decrease) |  | Variances 2016 vs. 2015 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Residential | **$663.8** | $629.8 | $589.8 | **$34.0** | **5%** | $40.0 | 7% |
| Commercial and industrial | **124.2** | 121.7 | 115.6 | **2.5** | **2%** | 6.1 | 5% |
| Wholesale and public authority | **6.6** | 6.8 | 6.5 | **(0.2)** | **(3)%** | 0.3 | 5% |
| Net margin on natural gas sales | **794.6** | 758.3 | 711.9 | **36.3** | **5%** | 46.4 | 7% |
| Transportation revenues | **100.9** | 98.1 | 98.8 | **2.8** | **3%** | (0.7) | (1)% |
| Net margin, excluding other revenues | **$895.5** | $856.4 | $810.7 | **$39.1** | **5%** | $45.7 | 6% |

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:

*(Millions of dollars, except percentages)*

| Net Margin on Natural Gas Sales Net margin on natural gas sales | Years Ended December 31, 2017 | 2016 | 2015 | Variances 2017 vs. 2016 Increase (Decrease) |  | Variances 2016 vs. 2015 Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Fixed margin | **$567.1** | $557.5 | $519.2 | **$9.6** | **2%** | $38.3 | 7% |
| Variable margin | **227.5** | 200.8 | 192.7 | **26.7** | **13%** | 8.1 | 4% |
| Net margin on natural gas sales | **$794.6** | $758.3 | $711.9 | **$36.3** | **5%** | $46.4 | 7% |

2017 vs. 2016 - Net margin increased $39.7 million due primarily to the following:

- an increase of $26.7 million from new rates primarily in Texas and Kansas;
- an increase of $5.3 million from the impact of weather normalization mechanisms, which offset warmer than normal weather in 2017;
- an increase of $3.8 million due primarily to higher transportation volumes from customers in Kansas and Oklahoma; and
- an increase of $3.4 million in residential sales due primarily to net customer growth in Oklahoma and Texas.

Operating costs increased $1.2 million due primarily to the following:

- an increase of $8.4 million in employee-related costs resulting from higher labor and compensation costs;
- an increase of $2.9 million from the deferral in the first quarter of 2016 of certain information technology costs incurred as a result of our separation from ONEOK in 2014, which was approved in Oklahoma as a regulatory asset, and a deferral of regulatory expenses incurred previously in the fourth quarter of 2016, which was approved in the West Texas rate case as a regulatory asset;
- an increase of $1.9 million in bad debt expense; and
- an increase of $1.2 million in information technology costs; offset by
- a decrease of $5.9 million from the deferral of MGP costs previously accrued, as discussed further in our Environmental, Safety and Regulatory Matters, which was approved in Kansas as a regulatory asset;
- a decrease of $4.0 million related to the higher environmental remediation costs in 2016 discussed further in our Environmental, Safety and Regulatory Matters; and
- a decrease of $3.4 million in legal-related costs.

Depreciation and amortization expense increased $8.1 million due primarily to an $11.0 million increase in depreciation from our capital expenditures being placed into service, offset partially by a decrease in the amortization of other postemployment benefit deferrals in Kansas.

2016 vs. 2015 - Net margin increased $43.7 million due primarily to the following:

- an increase of $44.0 million from new rates primarily in Oklahoma and Texas;
- an increase of $3.8 million in residential sales due primarily to customer growth in Oklahoma and Texas; and
- an increase of $1.3 million in ad-valorem recoveries in Kansas, which is offset with higher regulatory amortization expense in depreciation and amortization expense; offset partially by
- a decrease of $1.8 million due to lower sales volumes, net of weather normalization, primarily from warmer weather in 2016 compared to 2015;
- a decrease of $1.7 million due primarily to lower transportation volumes from weather-sensitive customers in Kansas and Oklahoma; and
- a decrease of $1.1 million in CNG revenues in Oklahoma.

Operating costs increased $2.9 million due primarily to the following:

- an increase of $4.0 million in environmental remediation costs discussed further below in our Environmental, Safety and Regulatory Matters;
- an increase of $2.7 million in legal-related costs; and
- an increase of $0.9 million in employee-related costs; offset partially by
- a decrease of $2.9 million from the deferral of certain information technology costs incurred as a result of our separation from ONEOK in 2014, which was approved in Oklahoma as a regulatory asset, and a deferral of regulatory expenses incurred previously, which was approved in the West Texas rate case as a regulatory asset; and
- a decrease of $1.5 million in information technology costs.

Depreciation and amortization expense increased $10.8 million due primarily to an increase in depreciation from our capital expenditures being placed into service.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities and information technology assets. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations.

Capital expenditures increased $47.4 million for 2017, compared with 2016, due primarily to increased system integrity activities and extending service to new areas. Capital expenditures increased $14.7 million for 2016, compared with 2015, due primarily to increased system integrity activities and extending service to new areas. Our capital expenditures are expected to be approximately $375.0 million for 2018.

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

*(in thousands)*

| Average Number of Customers | Years Ended December 31, 2017 OK | KS | TX | Total | 2016 OK | KS | TX | Total | Variances 2017 vs. 2016 Increase (Decrease) OK | KS | TX | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Residential | **793** | **582** | **618** | **1,993** | 787 | 581 | 612 | 1,980 | **6** | **1** | **6** | **13** |
| Commercial and industrial | **73** | **50** | **35** | **158** | 73 | 50 | 34 | 157 | **—** | **—** | **1** | **1** |
| Wholesale and public authority | **—** | **—** | **3** | **3** | — | — | 3 | 3 | **—** | **—** | **—** | **—** |
| Transportation | **5** | **6** | **1** | **12** | 5 | 6 | 1 | 12 | **—** | **—** | **—** | **—** |
| Total customers | **871** | **638** | **657** | **2,166** | 865 | 637 | 650 | 2,152 | **6** | **1** | **7** | **14** |

*(in thousands)*

| Average Number of Customers | Years Ended December 31, 2016 OK | KS | TX | Total | 2015 OK | KS | TX | Total | Variances 2016 vs. 2015 Increase (Decrease) OK | KS | TX | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Residential | 787 | 581 | 612 | 1,980 | 783 | 579 | 606 | 1,968 | 4 | 2 | 6 | 12 |
| Commercial and industrial | 73 | 50 | 34 | 157 | 73 | 50 | 34 | 157 | — | — | — | — |
| Wholesale and public authority | — | — | 3 | 3 | — | — | 3 | 3 | — | — | — | — |
| Transportation | 5 | 6 | 1 | 12 | 5 | 6 | 1 | 12 | — | — | — | — |
| Total customers | 865 | 637 | 650 | 2,152 | 861 | 635 | 644 | 2,140 | 4 | 2 | 6 | 12 |

The following table reflects the total volumes delivered, excluding the effects of weather normalization mechanisms on sales volumes. On an ongoing basis we will report volumes delivered to show the relationship between our volumes delivered and actual HDDs for the periods presented.

| Volumes (MMcf) Natural gas sales | Years Ended December 31, 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Residential | **99,940** | 101,956 | 114,303 |
| Commercial and industrial | **32,242** | 32,276 | 35,518 |
| Wholesale and public authority | **1,933** | 2,414 | 2,624 |
| Total sales volumes delivered | **134,115** | 136,646 | 152,445 |
| Transportation | **209,551** | 208,141 | 204,762 |
| Total volumes delivered | **343,666** | 344,787 | 357,207 |

Total sales volumes delivered decreased for 2017, compared with 2016, due primarily to warmer temperatures in our Texas services areas. Total sales volumes delivered decreased for 2016, compared with 2015, due primarily to warmer temperatures in 2016. The impact of weather on residential and commercial net margin is mitigated by weather normalization mechanisms in all jurisdictions. Transportation volumes increased slightly for 2017 compared with 2016 due to higher consumption by our transportation customers in Oklahoma. Transportation volumes increased for 2016 compared with 2015, due to a large industrial customer’s facility undergoing maintenance in 2015, offset partially by a decrease in transportation volumes associated with smaller weather-sensitive customers.

The following table reflects the total volumes sold:

| Volumes (MMcf) Natural gas sales | Years Ended December 31, 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Residential | **106,805** | 105,494 | 115,477 |
| Commercial and industrial | **33,811** | 33,084 | 35,943 |
| Wholesale and public authority | **1,925** | 2,406 | 2,615 |
| Total sales volumes sold | **142,541** | 140,984 | 154,035 |
| Transportation | **209,551** | 208,141 | 204,763 |
| Total volumes sold | **352,092** | 349,125 | 358,798 |

Total sales volumes sold increased for 2017, compared with 2016, due primarily to colder temperatures in the fourth quarter of 2017. Total sales volumes sold decreased for 2016, compared with 2015, due primarily to warmer temperatures in 2016. Transportation volumes increased slightly for 2016 compared with 2015, due to a large industrial customer’s facility undergoing maintenance in 2015, offset partially by a decrease in transportation volumes associated with smaller weather-sensitive customers.

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

| HDDs | Years Ended December 31, 2017 Actual | Normal | 2016 Actual | Normal | 2017 vs. 2016 Actual Variance | 2017 Actual as a percent of Normal | 2016 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Oklahoma | 2,849 | 3,264 | 2,843 | 3,264 | **—%** | **87%** | 87% |
| Kansas | 4,088 | 4,889 | 4,016 | 4,860 | **2%** | **84%** | 83% |
| Texas | 1,247 | 1,785 | 1,455 | 1,785 | **(14)%** | **70%** | 82% |

| HDDs | Years Ended December 31, 2016 Actual | Normal | 2015 Actual | Normal | 2016 vs. 2015 Actual Variance | 2016 Actual as a percent of Normal | 2015 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Oklahoma | 2,843 | 3,264 | 3,135 | 3,317 | (9)% | 87% | 95% |
| Kansas | 4,016 | 4,860 | 4,264 | 4,860 | (6)% | 83% | 88% |
| Texas | 1,455 | 1,785 | 1,715 | 1,785 | (15)% | 82% | 96% |

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:

- *Oklahoma* - For 2017 and 2016, 10-year weighted average HDDs as of December 31, 2014, for years 2005-2014, as calculated using 11 weather stations across Oklahoma and weighted on average customer count, and for 2015, 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.
- *Kansas* - For 2017, 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using 4 weather stations across Kansas and weighted on HDDs by weather station and customers, and for 2016 and 2015, 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.
- *Texas* - An average of HDDs authorized in our most recent rate proceeding in each jurisdiction, and weighted using a rolling 10-year average of actual natural gas distribution sales volumes by jurisdiction.

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

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

Through March 31, 2017, Kansas Gas Services’ WNA clause required it to accrue the variation in net margin resulting from actual weather differing from normal weather occurring from November through March. Beginning in April 2017, Kansas Gas Services’ WNA clause requires an accrual each month of the year.

### CONTINGENCIES

We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows. See Note 13 of the Notes to Consolidated Financial Statements in this Annual Report for information with respect to legal proceedings.

### LIQUIDITY AND CAPITAL RESOURCES

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

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales 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 favorable rates in order to finance our infrastructure investments.

**Tax Reform -** The Tax Cuts and Jobs Act of 2017 will have an overall negative impact on our operating cash flow due to several dynamics. The reduction in the tax rate will result in less revenue collected from customers related to the recovery of tax expense included in our rates. Although this revenue is ultimately paid out as an expense, under the new law, we will lose the timing benefit, thereby reducing cash that may have been carried over many years. Under the new tax law, natural gas utilities are not eligible to take bonus depreciation, but they are also not subject to the new limitations on the deduction of interest expense. The loss of bonus depreciation will result in earlier cash tax payments, as compared to the previous tax law, once accumulated NOLs are fully extinguished. The lowering of the tax rate effectively resulted in an over-collection of tax expenses, as customers’ rates include tax expenses based on the statutory tax rate. Future cash flows will be reduced as we refund the excess ADIT collection to customers.

The timing of these changes in our cash flows and the degree to which it impacts us will not be known until we make future regulatory filings, new rates are approved by our regulators and the manner and timing in which we refund previously collected taxes are determined. We believe that our capital structure and available liquidity resources will be adequate to adjust for these changes. See additional discussion under Regulatory Activities - Tax Reform and Note 12 of Notes to Consolidated Financial Statements of this Annual Report.

**Short-term Financing -** In October 2017, we amended and restated our revolving credit agreement. The ONE Gas Credit Agreement remains a $700.0 million revolving unsecured credit facility, and includes a $20.0 million letter of credit subfacility and a $60.0 million swingline subfacility. We will also be able to request an increase in commitments of up to an additional $500.0 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022, and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. 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, 2017, our total debt-to-capital ratio was 44 percent, and we were in compliance with all covenants under the ONE Gas Credit Agreement.

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.

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

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

At December 31, 2017, we had issued $357.2 million in the form of commercial paper, $2.1 million in letters of credit outstanding and had approximately $14.4 million of cash and cash equivalents. At December 31, 2017, we had no borrowings and $340.7 million of credit available under the ONE Gas Credit Agreement. The weighted-average interest rate on our commercial paper was 1.55 percent at December 31, 2017.

**Long-Term Debt -** The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full. At December 31, 2017, our long-term debt-to-capital ratio was 38 percent.

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.

**Credit Ratings -** Our credit ratings as of December 31, 2017, were:

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

On January 19, 2018, Moody’s changed our outlook to negative from stable based on the potential impacts of the Tax Cuts and Jobs Act of 2017.

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

**Pension and Other Postemployment Benefit Plans -** During 2017, we contributed $111.9 million to our defined benefit pension plan and $6.2 million to our other postemployment benefit plans. Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 11 of the Notes to Consolidated Financial Statements in this Annual Report.

### CASH FLOW ANALYSIS

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

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

| Total cash provided by (used in): | Years Ended December 31, 2017 (Millions of dollars) | 2016 | 2015 | Variances 2017 vs. 2016 | 2016 vs. 2015 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Operating activities | **$253.8** | $290.6 | $407.9 | **$(36.8)** | $(117.3) |
| Investing activities | **(355.8)** | (308.5) | (294.3) | **(47.3)** | (14.2) |
| Financing activities | **101.7** | 30.2 | (123.1) | **71.5** | 153.3 |
| Change in cash and cash equivalents | **(0.3)** | 12.3 | (9.5) | **(12.6)** | 21.8 |
| Cash and cash equivalents at beginning of period | **14.7** | 2.4 | 11.9 | **12.3** | (9.5) |
| Cash and cash equivalents at end of period | **$14.4** | $14.7 | $2.4 | **$(0.3)** | $12.3 |

**Operating Cash Flows -** Changes in cash flows from operating activities are due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information. 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.

2017 vs. 2016 - Cash flows from operating activities were lower in 2017 compared with 2016. Before considering the impacts of operating asset and liability changes, cash flows were higher in 2017 compared with 2016 due primarily to an increase in net income, higher noncash expenses for depreciation and amortization and deferred income taxes. The increase in operating asset and liability changes more than offset these increases. The largest decrease in working capital relates to a decrease in employee benefit obligation attributed to the $111.9 million contribution to our defined benefit pension plan and $6.2 million contribution to our other postemployment benefit plans in 2017.

2016 vs. 2015 - Cash flows from operating activities were lower in 2016 compared with 2015. Before considering the impacts of operating asset and liability changes, cash flows were higher in 2016 compared with 2015 due primarily to an increase in net income, higher noncash expenses for depreciation and amortization and deferred income taxes. The increase in operating asset and liability changes more than offset these increases. The largest increase in working capital relates to an increase in accounts receivable caused by higher costs of natural gas delivered to customers in the fourth quarter of 2016 compared with 2015, when accounts receivable declined. Additionally, through 2016, our net over-recovered purchased gas costs decreased by $29.3 million. Through 2015, our net over-recovered purchased gas costs increased by $25.3 million. The change in the natural gas cost recoveries between periods also contributed to the decrease in cash flows from operating assets and liabilities.

**Investing Cash Flows -** 2017 vs. 2016 - Cash used in investing activities increased for 2017, compared to 2016, due primarily to capital expenditures for increased system integrity activities and extending service to new areas.

2016 vs. 2015 - Cash used in investing activities increased for 2016, compared to 2015, due primarily to capital expenditures for increased system integrity activities and extending service to new areas.

**Financing Cash Flows -** 2017 vs. 2016 - Cash provided by financing activities for 2017 increased, compared with 2016, due primarily to net borrowings on our notes payable to fund working capital and capital investments, offset partially by the 28 cent per share increase in annual dividends.

2016 vs. 2015 - Cash provided by financing activities for 2016 increased, compared with 2015, due primarily to net borrowings on our notes payable to fund working capital and capital investments, offset partially by the 20 cent per share increase in annual dividends.

### ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

**Environmental Matters** - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2017, 2016 or 2015.

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

We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred. We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.

With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development continued in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016.

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

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2017, 2016 or 2015. A number of environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

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

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

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

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The potential capital and operating expenditures associated with compliance with the proposed rule are currently being evaluated and could be significant depending on the final regulations.

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

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

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

**Pipeline Security -** The U.S. Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in 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 integrity 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. Additionally, in March 2016, we were one of 40 founding partners to launch the EPA’s Natural Gas STAR Methane Challenge Program, whereby oil and natural gas companies agree to promote and track commitments to reduce methane emissions beyond what is federally required. Our Methane Challenge Program commitment to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe aligns with our planned system integrity expenditures for infrastructure replacements. We anticipate reporting in 2018 our calendar year 2017 performance relative to our commitment.

Additional information about our environmental matters is included in the section entitled Environmental Matters in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report. 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 investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2017, 2016 or 2015.

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

### IMPACT OF NEW ACCOUNTING STANDARDS

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

### ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities; and also requires the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates. See our Risk Factors and/or Forward-Looking Statements for factors which could impact our estimates.

The following summary sets forth what we consider to be our most critical estimates and 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 consolidated 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 8 of the Notes to Consolidated Financial Statements 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 2017 and 2016, utilized a qualitative assessment and did not result in any impairment indicators. Subsequent to July 1, 2017, 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.

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.

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 Consolidated Financial Statements in this Annual Report for further discussion of goodwill.

**Pension and Other Postemployment Benefits -** We have defined benefit retirement plans covering eligible retirees and full-time employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible retirees and employees who retire with at least five years of service.

To calculate the expense and liabilities related to our plans, we utilize an outside actuarial consultant, which uses statistical and other factors to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. We use tables issued by the Society of Actuaries to estimate mortality rates. In determining the projected benefit costs, assumptions can change from period to period and may result in material changes in the costs and liabilities we recognize.

During 2017, we contributed approximately $111.9 million to our defined benefit pension plan and $6.2 million to our other postemployment benefit plans. In 2018, we expect to contribute approximately $1.0 million to our defined benefit pension plan and $3.0 million to our other postemployment benefit plans. In September 2017, we purchased group annuity contracts and transferred approximately $46.7 million of the assets and liabilities related to certain participants in our defined benefit pension plan to a third-party insurance company.

During 2017, we recorded net periodic benefit costs of $30.2 million and $1.7 million related to our pension plans and other postemployment benefit plans, respectively, prior to regulatory deferrals. We estimate that in 2018, we will record expense of $29.0 million and a credit of $3.5 million related to pension plans and other postemployment benefit plans, respectively, prior to regulatory deferrals.

The following table sets forth the significant assumptions used to determine our estimated 2018 net periodic benefit cost related to our defined pension and other postemployment benefit plans, and sensitivity to changes with respect to these assumptions:

|  | Rate Used | Cost Sensitivity (a) (Millions of dollars) | Obligation Sensitivity (b) |
| --- | ---: | ---: | ---: |
| Discount rate for pension | **3.80%** | **$3.4** | **$32.8** |
| Discount rate for other postemployment benefits | **3.70%** | **$0.7** | **$6.7** |
| Expected long-term return on plan assets (c) | **7.25%/7.60%** | **$2.6** | **$—** |

(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.

(c) Expected long-term return on plan assets for pension and other postemployment benefits are 7.25 percent and 7.60 percent, respectively.

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

|  | One Percentage Point Increase (Millions of dollars) | One Percentage Point Decrease |
| --- | ---: | ---: |
| Effect on total of service and interest cost | **$0.6** | **$(0.6)** |
| Effect on other postemployment benefit obligation | **$2.9** | **$(3.0)** |

**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. 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.

We will adopt the FASB’s ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards, for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. We have evaluated all of our sources of revenue to determine the potential effect of the new standard on our financial position, results of operations, cash flows and the related accounting policies and business processes. Upon adoption, there will not be a cumulative adjustment to our opening retained earnings. The only impact of adopting ASC 606 is that we expect to reclassify certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we reflect variations in weather in our rates billed to customers.

We have determined the majority of our natural gas sales and transportation tariffs to be implied contracts with customers, which are settled over time, where our performance obligation is settled with our customer when natural gas is delivered and simultaneously consumed by the customer. For our other utility revenue, which are primarily one-time service fees that meet the requirements under ASC 606, the performance obligation is satisfied at a point in time when services are rendered to the customer. In addition, we will use the invoice method practical expedient, where we will recognize revenue for volumes delivered for which we have a right to invoice. As a result, we will estimate unbilled revenues at the end of each accounting period consistent with past practice. Our disclosures will reflect our sources of revenue disaggregated among natural gas sales including sales to residential, commercial, industrial, wholesale and public authority customers, transportation revenue, and other utility revenues. The reclassification of certain revenues that do not meet the requirements under ASC 606 will be classified as other revenues on the Consolidated Income Statement and in our Notes to Consolidated Financial Statements.

**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. In 2017, we recorded a regulatory asset of approximately $5.9 million for estimated costs incurred at, and nearby, our 12 former MGP sites that was accrued at January 1, 2017. In 2016, we recorded a reserve of $4.0 million for potential costs associated with further investigation and remediation at one of the former MGP sites. 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 2017, 2016 or 2015. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

See Note 13 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.

### CONTRACTUAL OBLIGATIONS

The following table sets forth our contractual obligations at December 31, 2017:

|  | Contractual Obligations (Millions of dollars) 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Long-term debt, including current maturities | $— | $300.0 | $— | $— | $— | $901.3 | $1,201.3 |
| Commercial paper | 357.2 | — | — | — | — | — | 357.2 |
| Interest payments on debt | 45.1 | 39.4 | 38.9 | 38.9 | 38.9 | 602.7 | 803.9 |
| Firm transportation and storage capacity contracts | 190.2 | 175.7 | 164.5 | 144.7 | 117.5 | 102.1 | 894.7 |
| Natural gas purchase commitments | 140.5 | 0.6 | 0.1 | 0.1 | 0.1 | 0.1 | 141.5 |
| Employee benefit plans | 4.0 | 0.1 | 0.1 | 0.1 | 0.1 | — | 4.4 |
| Operating leases | 4.7 | 3.9 | 3.7 | 3.3 | 3.3 | 3.2 | 22.1 |
| Total | $741.7 | $519.7 | $207.3 | $187.1 | $159.9 | $1,609.4 | $3,425.1 |

Long-term debt, commercial paper borrowings 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 postemployment benefit plans. See Note 11 of the Notes to Consolidated 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,” “likely,” and other words and terms of similar meaning. One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this 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 of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
- the economic climate and, particularly, its effect on the natural gas requirements of our residential and

commercial industrial customers;

- competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power, geothermal energy and biofuels;
- conservation and energy storage efforts of our customers;
- variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate change;
- indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors;
- our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of existing supply, and transportation and storage arrangements that are not replaced with contracts with similar terms and pricing;
- 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, which may be affected by risks beyond our control such as commodity price volatility and counterparty creditworthiness;
- our ability to generate sufficient cash flows to meet all our liquidity 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 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 existing or the addition of new environmental, safety, tax and other laws to which we and our subsidiaries are subject;
- the uncertainty of estimates, including accruals and costs of environmental remediation;
- 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 or breaches of technology systems 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 and the requirements of our regulators as a result of the Tax Cuts and Jobs Act of 2017;
- changes in accounting standards;
- changes in corporate governance standards;
- discovery of material weaknesses in our internal controls;
- our ability to attract and retain talented employees, management and directors;
- declines in the discount rates on, declines in the market value of the debt and equity securities of, and increases in funding requirements for, our defined benefit plans, as well as increased costs of providing health care benefits;
- 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 with ONEOK; 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 Part 1, 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.

## Market risk

As filed, 2,542 characters.

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 commodity prices or interest rates 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 Oklahoma, Kansas and most jurisdictions we serve in Texas, we are able to recover natural gas costs related to uncollectible accounts through our purchased-gas cost adjustment mechanisms.

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## Controls and procedures

As filed, 2,116 characters.

### 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, 2017.

The effectiveness of our internal control over financial reporting as of December 31, 2017, 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, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Filed Feb 22, 2018.
Source: SEC EDGAR, the filing index for accession 0001587732-18-000014. Last ingested by Listed: Nov 3, 2026, 18:56 ET. No prices; not investment advice.