10-K 1 oke10-k2017.htm OKE 10-K 2017 Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017.
OR
__ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.

Commission file number   001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1520922
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
 
100 West Fifth Street, Tulsa, OK
74103
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code   (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Common stock, par value of $0.01
New York Stock Exchange
(Title of each class)
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__.

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes X No __

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  (Check one)
Large accelerated filer X    Accelerated filer __    Non-accelerated filer __    Smaller reporting company __
Emerging growth company___

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.__

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

Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 30, 2017, was $19.5 billion.

On February 22, 2018, the Company had 410,634,227 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 23, 2018, are incorporated by reference in Part III.



ONEOK, Inc.
2017 ANNUAL REPORT

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

As used in this Annual Report, references to “we,” “our,” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries unless the context indicates otherwise.


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GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
$2.5 Billion Credit Agreement
ONEOK’s $2.5 billion revolving credit agreement, effective June 30, 2017
AFUDC
Allowance for funds used during construction
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2017
ASU
Accounting Standards Update
Bbl
Barrels, 1 barrel is equivalent to 42 United States gallons
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
CFTC
U.S. Commodity Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Act Amendments of 1972, as amended
DOT
United States Department of Transportation
EBITDA
Earnings before interest expense, income taxes, depreciation and amortization
EPA
United States Environmental Protection Agency
Exchange Act
Securities Exchange Act of 1934, as amended
FERC
Federal Energy Regulatory Commission
Foundation
ONEOK Foundation, Inc.
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
IRS
Internal Revenue Service
KCC
Kansas Corporation Commission
LIBOR
London Interbank Offered Rate
MBbl
Thousand barrels
MBbl/d
Thousand barrels per day
MDth/d
Thousand dekatherms per day
Merger Transaction
The transaction, effective June 30, 2017, in which ONEOK acquired all of ONEOK Partners’ outstanding common units not already directly or indirectly owned by ONEOK
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf/d
Million cubic feet per day
Moody’s
Moody’s Investors Service, Inc.
Natural Gas Act
Natural Gas Act of 1938, as amended
Natural Gas Policy Act
Natural Gas Policy Act of 1978, as amended
NGL(s)
Natural gas liquid(s)
NGL products
Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OCC
Oklahoma Corporation Commission
ONE Gas
ONE Gas, Inc.
ONEOK
ONEOK, Inc.
ONEOK Credit Agreement
ONEOK’s $300 million amended and restated revolving credit agreement, which terminated June 30, 2017
ONEOK Partners
ONEOK Partners, L.P.
ONEOK Partners Credit Agreement
ONEOK Partners’ $2.4 billion amended and restated revolving credit agreement, which terminated June 30, 2017
ONEOK Partners GP
ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole general partner of ONEOK Partners

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OPIS
Oil Price Information Service
OSHA
Occupational Safety and Health Administration
PHMSA
United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP
Percent of Proceeds
Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
Roadrunner
Roadrunner Gas Transmission, LLC, a 50 percent-owned joint venture
RRC
Railroad Commission of Texas
S&P
S&P Global Ratings
SCOOP
South Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Series E Preferred Stock
Series E Non-Voting, Perpetual Preferred Stock, par value $0.01 per share
STACK
Sooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in Oklahoma
Tax Cuts and Jobs Act
H.R. 1, the tax reform bill, signed into law on December 22, 2017
Term Loan Agreement
ONEOK Partners’ senior unsecured three-year $1.0 billion term loan agreement dated January 8, 2016, as amended
Topic 606
Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”
West Texas LPG
West Texas LPG Pipeline Limited Partnership and Mesquite Pipeline
WTI
West Texas Intermediate
WTLPG
West Texas LPG Pipeline Limited Partnership, an 80 percent-owned joint venture
XBRL
eXtensible Business Reporting Language

The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A, Risk Factors, and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and “Forward-Looking Statements,” in this Annual Report.


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PART I

ITEM 1.    BUSINESS

GENERAL

We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.” We are a leading midstream service provider and own one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent, Permian and Rocky Mountain regions with key market centers and an extensive network of natural gas gathering, processing, storage and transportation assets. We apply our core capabilities of gathering, processing, fractionating, transporting, storing and marketing natural gas and NGLs through vertical integration across the midstream value chain to provide our customers with premium services while generating consistent and sustainable earnings growth.

EXECUTIVE SUMMARY

Merger Transaction - On June 30, 2017, we completed the acquisition of all of the outstanding common units of ONEOK Partners that we did not already own at a fixed exchange ratio of 0.985 of a share of our common stock for each ONEOK Partners common unit. We issued 168.9 million shares of our common stock to third-party common unitholders of ONEOK Partners in exchange for all of the 171.5 million outstanding common units of ONEOK Partners that we previously did not own. As a result of the completion of the Merger Transaction, common units of ONEOK Partners are no longer publicly traded. The change in our ownership interest resulting from the Merger Transaction was accounted for as an equity transaction, and no gain or loss was recognized in our Consolidated Statement of Income.

Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable segments. Our consolidated earnings were approximately 90 percent fee-based in 2017, and we expect the same for 2018. In 2017, our Natural Gas Gathering and Processing segment’s fee revenues averaged 86 cents per MMBtu, compared with an average of 76 cents and 44 cents per MMBtu in 2016 and 2015, respectively, due to our contract restructuring efforts to mitigate commodity price risk and increasing volumes on those contracts with higher contracted fees. Volumes gathered and processed increased across our asset footprint in our Natural Gas Gathering and Processing segment in 2017, compared with 2016, as producers experienced improved drilling economics, continued improvements in production due to enhanced completion techniques and more efficient drilling rigs. We connected six third-party natural gas processing plants in our Natural Gas Liquids segment in 2017, which, along with increased supply and ethane recovery, contributed to higher gathered NGL volumes in 2017, compared with 2016. We expect additional NGL volume growth as these plants continue to increase production and recently announced plant connections come online. Our fee-based transportation services in our Natural Gas Pipelines segment increased in 2017, compared with 2016, due primarily to higher firm transportation capacity contracted from our WesTex pipeline expansion.

We continue to expect demand for our midstream services and infrastructure development to be primarily driven by producers who need to connect production with end-use markets where current infrastructure is insufficient. We are responding to this demand by constructing assets, such as our recently announced Elk Creek pipeline, Arbuckle II pipeline, MB-4 fractionator, Demicks Lake natural gas processing plant and other projects discussed below, to meet the needs of producers. We also expect additional demand for our services to support increased demand for NGL products from the petrochemical industry and NGL exporters, and increased demand for natural gas from exports and power plants, some of which were previously fueled by coal.

We are connected to supply in growing basins and have significant basin diversification across our asset footprint, including the Williston, Denver-Julesburg (DJ), Permian and Powder River Basins and the STACK and SCOOP areas. In addition, we are connected to major market centers for natural gas and NGL products. While our Natural Gas Gathering and Processing and Natural Gas Liquids segments generate primarily fee-based earnings, those segments’ results of operations are exposed to volumetric risk. Our exposure to volumetric risk can result from declining well productivity, reduced drilling activity, severe weather disruptions, operational outages and ethane rejection.

Rocky Mountain Region - We expect each of our business segments to benefit from increased production in this region, which includes the Williston, DJ and Powder River Basins, where there was an increase in producer activity in 2017, which we expect to continue throughout 2018. In our Natural Gas Gathering and Processing segment, our completed growth projects have increased our gathering and processing capacity to more than 1.0 Bcf/d and allow us to capture additional natural gas. We have available natural gas processing capacity in the Williston Basin of approximately 125 MMcf/d and approximately one million acres dedicated to us in the core of this basin. With continued volume growth expected due to improved drilling economics and producer efficiencies, we announced plans to construct the 200 MMcf/d Demicks Lake natural gas processing plant in the core

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of the Williston Basin. The Demicks Lake plant is expected to provide services necessary to help producers meet natural gas capture targets, while adding incremental NGLs to our NGL gathering system and supplying additional natural gas to our 50 percent owned Northern Border Pipeline. This project is supported by long-term primarily fee-based contracts and acreage dedications. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the Williston Basin with five connections to third-party natural gas processing plants in addition to our own. We connected one new third-party natural gas processing plant in the region in the first quarter 2017. The volume growth in this region has resulted in our existing Bakken NGL Pipeline and the Overland Pass Pipeline, of which we own 50 percent, operating at full capacity. In January 2018, we announced plans to construct the Elk Creek pipeline, which includes construction of an approximately 900-mile pipeline and related infrastructure to transport NGLs from the Rocky Mountain region to our existing Mid-Continent NGL facilities. This project, which is anchored by long-term contracts supported primarily by minimum volume commitments, will have an initial capacity of 240 MBbl/d, with the ability to be expanded to 400 MBbl/d with additional pump facilities. The Elk Creek pipeline project is expected to strengthen our position in the high-production areas of the Williston, Powder River and DJ Basins. In our Natural Gas Pipelines segment, our 50 percent-owned Northern Border Pipeline is well-positioned to transport natural gas from processing plants in the Williston Basin, including the recently announced Demicks Lake plant, to end-use markets and is substantially contracted through the fourth quarter 2020.

STACK and SCOOP - We expect each of our business segments to benefit from increased production in the Mid-Continent region from the highly productive STACK and SCOOP areas where there was an increase in producer activity in late 2016 and in 2017, which we expect to continue throughout 2018.

As producers continue to develop the STACK and SCOOP areas, we expect natural gas and NGL volumes on our systems to increase throughout 2018, compared with volumes for the same periods in 2016 and 2017, and expect increased demand for our services from producers that need incremental takeaway capacity for natural gas and NGLs out of the region. We anticipate NGL volume growth in the Mid-Continent region will also be driven by expected increases in ethane recovery as new world-scale ethylene production projects, petrochemical plant expansions and export facilities are completed.

In our Natural Gas Gathering and Processing segment, we have more than 300,000 acres dedicated to us in the STACK and SCOOP areas. In 2017, we announced plans to expand our Canadian Valley natural gas processing facility to 400 MMcf/d from 200 MMcf/d, which is expected to be completed by the end of 2018. The project is supported by long-term primarily fee-based contracts, minimum volume commitments and acreage dedications. In December 2017, we also completed a connection of our natural gas gathering systems in the STACK area to an existing third-party processing facility, accessing up to 200 MMcf/d of processing capacity by constructing a 30-mile natural gas gathering pipeline and related infrastructure. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the STACK and SCOOP areas. We have more than 110 connections to third-party natural gas processing plants in the Mid-Continent region, and in 2017, we connected three third-party natural gas processing plants. We announced plans to expand our natural gas liquids gathering system in the Mid-Continent region and our existing Sterling III pipeline, which are supported by long-term fee-based contracts and expected to be completed by the end of 2018. In February 2018, we announced plans to construct the Arbuckle II pipeline, which includes construction of an approximately 530-mile pipeline and related infrastructure to transport NGLs originating across our supply basins to Mont Belvieu, Texas. This pipeline project will have an initial capacity of 400 MBbl/d, with the ability to be expanded with additional pump facilities. This project is supported by long-term fee-based contracts. In our Natural Gas Pipelines segment, we are connected to more than 30 natural gas processing plants in Oklahoma, which have a total processing capacity of approximately 1.8 Bcf/d, and are expanding our ONEOK Gas Transportation pipeline by 100 MMcf/d to provide increased westbound transportation services from the STACK and SCOOP areas.

Permian Basin - We expect our Natural Gas Liquids and Natural Gas Pipelines business segments to benefit from increased production in the Permian Basin from the highly productive Delaware and Midland Basins, where there was an increase in producer drilling activity in late 2016 and in 2017, which we expect to continue throughout 2018.

In our Natural Gas Liquids segment, we are well-positioned in the Permian Basin with approximately 40 connections to third-party natural gas processing plants through our WTLPG joint venture, where we connected two third-party natural gas processing plants in 2017. In 2017, we announced that our WTLPG joint venture, in which we own an 80 percent interest, plans to extend its pipeline system into the core of the Delaware Basin, which includes construction of an approximately 120-mile pipeline lateral and related infrastructure to provide an initial incremental capacity of 110 MBbl/d. This project, which we expect to be completed in the third quarter 2018, is supported by long-term dedicated NGL production from two planned third-party natural gas processing plants and positions the West Texas LPG pipeline for significant future NGL volume growth. In our Natural Gas Pipelines segment, we believe that Roadrunner and our WesTex pipeline are well-positioned to serve growth in the Permian Basin. We are connected to more than 25 natural gas processing plants serving the Permian Basin, which have a total processing capacity of approximately 1.9 Bcf/d. The Roadrunner pipeline transports natural gas from the Permian Basin to the Mexican border near El Paso, Texas, and is fully subscribed with 25-year firm demand charge, fee-based agreements.

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The Roadrunner pipeline connects with our existing natural gas pipeline and storage infrastructure in Texas and, together with our completed WesTex intrastate natural gas pipeline expansion project, creates future opportunities for us to deliver natural gas supply to Mexico.

Gulf Coast - Demand for NGLs is expected to grow at the NGL market center in Mont Belvieu, Texas, as new world-scale ethylene production projects, petrochemical plant expansions and export facilities are completed. We expect increased NGL supply across our assets and construction of our Sterling III and WTLPG pipeline expansions, Elk Creek pipeline and Arbuckle II pipeline projects to result in higher NGL deliveries to this NGL market center. We have significant NGL fractionation and storage assets in this area, and additional capacity is needed to accommodate expected volume growth. In February 2018, we announced plans to construct the 125 MBbl/d MB-4 fractionator and related infrastructure in Mont Belvieu, Texas, which includes additional NGL storage capacity. This project is supported by long-term fee-based contracts and is fully contracted. Following the completion of MB-4, we expect our total NGL fractionation capacity to be 965 MBbl/d.

See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for more information on our growth projects, results of operations, liquidity and capital resources.

BUSINESS STRATEGY

Our primary business strategy is to maintain prudent financial strength and flexibility while growing our fee-based earnings and dividends per share with a focus on safe, reliable, environmentally responsible, legally compliant and sustainable operations for our customers, employees, contractors and the public through the following:
Operate in a safe, reliable, environmentally responsible and sustainable manner - environmental, safety and health issues continue to be a primary focus for us, and our emphasis on personal and process safety has produced improvements in the key indicators we track. We also continue to look for ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies;
Maintain prudent financial strength and flexibility while growing our fee-based earnings, dividends per share and cash flows from operations in excess of dividends paid - we operate primarily fee-based businesses in each of our three reportable segments. We continue to invest in organic growth projects to expand our existing asset footprint and provide a broad range of services to crude oil and natural gas producers and end-use markets. In February 2018, we paid a quarterly dividend of $0.77 per share ($3.08 per share on an annualized basis), an increase of 25 percent compared with the same quarter in the prior year. Our dividend increase and expected future dividend growth is due in part to the increase in cash flows resulting from the Merger Transaction and our growth projects. Since June 2017, we have announced organic growth projects totaling approximately $4.2 billion supported by a combination of long-term primarily fee-based contracts, minimum volume commitments and acreage dedications;
Manage our balance sheet and maintain investment-grade credit ratings - we seek to maintain investment-grade credit ratings. In January 2018, we completed an underwritten public offering of our common stock generating net proceeds of $1.2 billion, which we expect to satisfy our equity financing needs through 2018 and well into 2019. Following the equity offering, we had $2.5 billion of borrowing capacity available and expect to fund our growth projects through cash from operations and a combination of short- and long-term debt; and
Attract, select, develop and retain a diverse group of employees to support strategy execution - we continue to execute on our recruiting strategy that targets professional and field personnel in our operating areas. We also continue to focus on employee development efforts with our current employees and monitor our benefits and compensation package to remain competitive.

NARRATIVE DESCRIPTION OF BUSINESS

We report operations in the following business segments:
Natural Gas Gathering and Processing;
Natural Gas Liquids; and
Natural Gas Pipelines.

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides midstream services to contracted producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. In order for the natural gas to be accepted by the downstream market, it must have contaminants, such as water, nitrogen and carbon dioxide, removed and NGLs separated for further processing. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines,

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storage facilities and end users. The separated NGLs are sold and delivered through natural gas liquids pipelines to fractionation facilities for further separation.

Rocky Mountain region - The Williston Basin, which is located in portions of North Dakota and Montana, includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations, is an active drilling region. Our completed growth projects in the Williston Basin since 2016 have increased our gathering and processing capacity to more than 1.0 Bcf/d and allow us to capture increased natural gas production from new wells and previously flared natural gas production.

The Powder River Basin is primarily located in Wyoming, which includes the NGL-rich Niobrara Shale and Frontier, Turner and Sussex formations where we provide gathering and processing services to customers in the southeast portion of Wyoming.

Mid-Continent region - The Mid-Continent region is an active drilling region and includes the oil-producing, NGL-rich STACK and SCOOP areas and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations of Oklahoma and Kansas; and the Hugoton and Central Kansas Uplift Basins of Kansas.

Revenues - Revenues for this segment are derived primarily from commodity sales and the following types of services contracts:
POP with fee-based components - This type of contract includes contractual fees for gathering, treating, compressing and processing the producer’s natural gas. We also generally purchase the producer’s raw natural gas, which we process into residue natural gas and NGLs, then we sell these commodities and associated condensate to downstream customers. We remit sales proceeds to the producer according to the contractual terms and retain our portion. This type of contract represented approximately 96 percent and 94 percent of supply volumes in this segment for 2017 and 2016, respectively. There are a variety of factors that directly affect our POP with fee revenues, including:
the price of natural gas, crude oil and NGLs;
the composition of the natural gas and NGLs produced;
the fees we charge for our services; and
the volume produced.
Over time as our contracts are renewed or restructured, we have generally increased the fee components. In some POP with fee contracts, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of residue gas and/or NGLs to the producer (take-in-kind) and sell the volumes we retain to third parties. Additionally, under certain POP with fee contracts our contractual fees may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds.
Fee-only - Under this type of contract, we are paid a fee for the services we provide, based on volumes gathered, processed, treated and/or compressed. Our fee-only contracts represented approximately 4 percent and 6 percent of supply volumes in this segment for 2017 and 2016, respectively.

We contract to deliver residue natural gas, condensate and/or unfractionated NGLs to downstream customers at a specified delivery point. Our sales of NGLs are typically to our affiliate in the Natural Gas Liquids segment.

Upon adoption of Topic 606 in January 2018, the contractual fees we charge producers on the majority of our POP with fee contracts will be recorded as a reduction of the purchase price in cost of sales and fuel. In 2017 and prior periods, we recorded these fees as services revenue. The contractual fees on POP with fee contracts that include producer take-in-kind rights will continue to be recorded as services revenue, as we do not control the raw natural gas stream while we are providing midstream services. We do not expect adoption of the standard to be material to this segment’s operating income.

Property - Our Natural Gas Gathering and Processing segment owns the following assets:
approximately 11,400 miles and 7,700 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions, respectively;
nine natural gas processing plants with approximately 800 MMcf/d of processing capacity in the Mid-Continent region, and 11 natural gas processing plants with approximately 1,050 MMcf/d of processing capacity in the Rocky Mountain region; and
approximately 15 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Rocky Mountain region.

In addition, we have access to up to 200 MMcf/d of processing capacity in the Mid-Continent region through a long-term processing services agreement with an unaffiliated third party.


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Utilization - The utilization rates for our natural gas processing plants were approximately 79 percent and 76 percent for 2017 and 2016, respectively. We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service.

Unconsolidated Affiliates - Our Natural Gas Gathering and Processing segment includes the following unconsolidated affiliates:
49 percent ownership in Bighorn Gas Gathering, which gathers coal-bed methane produced in the Powder River Basin;
37 percent ownership in Fort Union Gas Gathering, which gathers coal-bed methane produced in the Powder River Basin and delivers it to the interstate pipeline system;
35 percent ownership interest in Lost Creek Gathering Company, which gathers natural gas produced from conventional dry natural gas wells in the Wind River Basin of central Wyoming and delivers it to the interstate pipeline system; and
10 percent ownership interest in Venice Energy Services Co., a natural gas processing facility near Venice, Louisiana.

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our unconsolidated affiliates.

Market Conditions and Seasonality - Supply - Our natural gas gathered and processed volumes increased in 2017, compared with 2016, due primarily to the following:
producers focusing their drilling and completion in the most productive areas with favorable economics where we have significant gathering and processing assets; and
continued producer improvements in production due to enhanced completion techniques and more efficient drilling rigs; offset partially by
natural production declines.

We expect our natural gas volumes to continue to grow in 2018 due to the production activities discussed above.

Rocky Mountain region - In the Williston Basin, we have significant natural gas gathering and processing assets and substantial acreage dedications. Natural gas volumes increased in 2017, compared with 2016, due primarily to new supply and completion of growth projects, offset partially by the impact of severe winter weather in the first quarter 2017.

Mid-Continent region - In the Mid-Continent region, we have significant natural gas gathering and processing assets in Oklahoma and Kansas. We had higher natural gas gathered and processed volumes in 2017, compared with 2016, due to increased producer activity in the STACK and SCOOP areas, where we have substantial acreage dedications.

Demand - Demand for gathering and processing services is dependent on natural gas production by producers, which is driven by the strength of the economy; producer firm commitments to transportation pipelines; natural gas, crude oil and NGL prices; and the demand for each of these products from end users. We generally contract with crude oil and natural gas producers who have proven reserves or are currently producing natural gas in areas within our existing infrastructure and need gathering and processing services. Additionally, demand is impacted by the weather, which is discussed below under “Seasonality.”

Rocky Mountain region - Demand for our gathering and processing services in the Williston Basin has remained strong in both high and low commodity price environments. Requirements in North Dakota for producers to reduce natural gas flaring have increased the need for our services to capture, gather and process natural gas, and we are responding by constructing assets, such as our recently announced Demicks Lake natural gas processing plant and related infrastructure. We have approximately 125 MMcf/d of available capacity from our more than 1.0 Bcf/d of processing assets. Upon completion of the Demicks Lake plant, we will have more than 1.2 Bcf/d of processing capacity in this region.

Mid-Continent region - As producers continue to develop the STACK and SCOOP areas, we expect increased demand for our services. We have approximately 100 MMcf/d of available processing capacity in Oklahoma. We are responding to producers’ needs by constructing assets, such as the 200 MMcf/d expansion of our Canadian Valley natural gas processing plant, which will increase our processing capacity to 1.2 Bcf/d in this region.

Commodity Prices - We have significantly reduced our direct exposure to commodity prices in this segment and our earnings are primarily fee-based.


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See discussion regarding our commodity price risk and related hedging activities under “Commodity Price Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Seasonality - Cold temperatures usually increase demand for natural gas and certain NGL products such as propane, the main heating fuels for homes and businesses. Warm temperatures usually increase demand for natural gas used in gas-fired electric generators for residential and commercial cooling, as well as agriculture-related equipment like irrigation pumps and crop dryers. During periods of peak demand for a certain commodity, prices for that product typically increase.

Extreme weather conditions and seasonal temperature changes impact the volumes and composition of natural gas gathered and processed. A freeze-off is a phenomenon where water produced with natural gas freezes at the wellhead or within the gathering system. This causes a temporary interruption in the flow of natural gas. Our operations may be affected by other weather conditions that may cause a loss of electricity at our facilities or prevent access to certain locations that affect a producer’s ability to produce oil and natural gas wells or our ability to connect new wells to our systems.

Competition - We compete for natural gas supply with other midstream gatherers and processors, major integrated oil companies, independent exploration and production companies that have gathering and processing assets, and pipeline companies and their affiliated marketing companies. The factors that typically affect our ability to compete for natural gas supply are:
quality of services provided;
producer drilling activity;
proceeds remitted and/or fees charged under our gathering and processing contracts;
location of our gathering systems relative to those of our competitors;
location of our gathering systems relative to drilling activity;
operating pressures maintained on our gathering systems;
efficiency and reliability of our operations;
delivery capabilities for natural gas and NGLs that exist in each system and plant location; and
cost of capital.

We continue to evaluate opportunities to increase earnings and cash flows, and reduce risk by:
improving natural gas processing efficiency;
constructing new assets;
reducing operating costs;
consolidating assets; and
decreasing commodity price exposure.

Customers - Our Natural Gas Gathering and Processing segment derives services revenue primarily from crude oil and natural gas producers, which include both large integrated and independent exploration and production companies. Our downstream commodity sales customers are primarily utilities, large industrial companies, marketing companies and our NGL affiliate. See discussion regarding our customer credit risk under “Counterparty Credit Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in extracting NGLs and, therefore, are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe our natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional natural gas gathering facility status. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We transport residue natural gas from certain of our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act. Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, to varying degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.


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Natural Gas Liquids

Overview - Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, DJ and Powder River Basins, where we provide midstream services to producers of NGLs and deliver those products to the two primary market centers, one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas Panhandle are connected to our natural gas liquids gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation and pipeline assets.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. The NGLs that are separated from the natural gas stream at natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products. These NGL products are then stored or distributed to our customers, such as petrochemical manufacturers, heating fuel users, ethanol producers, refineries, exporters and propane distributors.

Revenues - Revenues for our Natural Gas Liquids segment are derived primarily from commodity sales and fee-based services. We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment. Our fee-based services have increased due primarily to new supply connections, expansion of existing connections and the completion of capital-growth projects. Our business activities are categorized as exchange services, transportation and storage services, and optimization and marketing, which are defined as follows:
Exchange services - we utilize our assets to gather, fractionate and/or treat, and transport unfractionated NGLs, thereby converting them into marketable NGL products shipped to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of revenues regardless of volumetric throughput. Our exchange services activities are primarily fee-based and include some rate-regulated tariffs; however, we also capture certain product price differentials through the fractionation process.
Transportation and storage services - we transport NGL products and refined petroleum products, primarily under FERC-regulated tariffs. Tariffs specify the maximum rates we may charge our customers and the general terms and conditions for transportation service on our pipelines. Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.
Optimization and marketing - we utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through the purchase and sale of NGLs and NGL products. We primarily transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our marketing activities also include utilizing our natural gas liquids storage facilities to capture seasonal price differentials. A growing portion of our marketing activities serves truck and rail markets. Our isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.

In many of our exchange services contracts, we purchase the unfractionated NGLs at the tailgate of the processing plant and deduct contractual fees related to the transportation and fractionation services we must perform before we can sell them as NGL products. Upon adoption of Topic 606 in January 2018, these fees will be recorded as a reduction to the NGL purchase price in cost of sales and fuel. In 2017 and prior periods, we recorded these fees as exchange services revenue. We do not expect adoption of the standard to be material to this segment’s operating income.

Supply growth from the development of NGL-rich areas and capacity available on pipelines that connect the Mid-Continent and Gulf Coast resulted in NGL price differentials remaining narrow between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas. We expect relatively narrow price differentials to persist between these two market centers until demand for NGLs increases from petrochemical companies and exporters, which we expect as ethylene producers continue to complete their expansion projects and international demand for NGLs increases export volumes.


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Property - Our Natural Gas Liquids segment owns the following assets:
approximately 2,800 miles of non-FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 800 MBbl/d;
approximately 170 miles of non-FERC-regulated natural gas liquids distribution pipelines with peak transportation capacity of approximately 66 MBbl/d;
approximately 4,300 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 683 MBbl/d;
approximately 4,200 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with peak capacity of 993 MBbl/d;
one natural gas liquids fractionator in Oklahoma with operating capacity of approximately 210 MBbl/d, two natural gas liquids fractionators in Kansas with combined operating capacity of 280 MBbl/d and two natural gas liquids fractionators in Texas with combined operating capacity of 150 MBbl/d;
80 percent ownership interest in one natural gas liquids fractionator in Texas with our proportional share of operating capacity of approximately 128 MBbl/d;
interest in one natural gas liquids fractionator in Kansas with our proportional share of operating capacity of approximately 11 MBbl/d;
one isomerization unit in Kansas with operating capacity of 9 MBbl/d;
six natural gas liquids storage facilities in Oklahoma, Kansas and Texas with operating storage capacity of approximately 22.2 MMBbl;
eight natural gas liquids product terminals in Nebraska, Iowa and Illinois;
above- and below-ground storage facilities associated with our FERC-regulated natural gas liquids pipeline operations in Iowa, Illinois, Nebraska and Kansas with combined operating capacity of 978 MBbl; and
one ethane/propane splitter in Texas with operating capacity of 32 MBbl/d of purity ethane and 8 MBbl/d of propane.

In addition, we lease approximately 3.5 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas and have access to 60 MBbl/d of natural gas liquids fractionation capacity in Texas through a fractionation service agreement.

Utilization - The utilization rates for our various assets, including leased assets, have been impacted by ethane rejection. The utilization rates for 2017 and 2016, respectively, were as follows:
our non-FERC-regulated natural gas liquids gathering pipelines were approximately 73 percent and 66 percent;
our FERC-regulated natural gas liquids gathering pipelines were approximately 78 percent and 77 percent;
our FERC-regulated natural gas liquids distribution pipelines were approximately 57 percent and 56 percent; and
our natural gas liquids fractionators were approximately 74 percent and 70 percent.

We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service. Our fractionation utilization rate reflects approximate proportional capacity associated with our ownership interests.

Unconsolidated Affiliates - Our Natural Gas Liquids segment includes the following unconsolidated affiliates:
50 percent ownership interest in Overland Pass Pipeline Company, which operates an interstate natural gas liquids pipeline system extending approximately 760 miles, originating in Wyoming and Colorado and terminating in Kansas;
50 percent ownership interest in Chisholm Pipeline Company, which operates an interstate natural gas liquids pipeline system extending approximately 185 miles from origin points in Oklahoma and terminating in Kansas; and
50 percent ownership interest in Heartland Pipeline Company, which operates a terminal and pipeline system that transports refined petroleum products in Kansas, Nebraska and Iowa.

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Market Conditions and Seasonality - Supply - The unfractionated NGLs that we gather and transport originate primarily from natural gas processing plants connected to our natural gas liquids gathering systems in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region. Our Natural Gas Liquids segment is the largest NGL takeaway provider for the STACK and SCOOP areas and the Williston Basin. Our fractionation operations receive NGLs from a variety of processors and pipelines, including our affiliates, located in these regions. Supply for our Natural Gas Liquids segment depends on crude oil and natural gas drilling and production activities by producers, the decline rate of existing production, natural gas processing plant economics and capabilities, and the NGL content of the natural gas that is produced and processed in the areas in which we operate.


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Supply growth has resulted in available ethane supply that is greater than the petrochemical industry’s current demand. Low or unprofitable price differentials between ethane and natural gas have resulted in varied levels of ethane rejection at most of our and our customers’ natural gas processing plants connected to our NGL system in the Mid-Continent and Rocky Mountain regions. Ethane rejection levels across our system averaged more than 150 MBbl/d in 2017, which is slightly lower than 2016 despite an increase in overall supply volumes. We expect ethane rejection on our system to decrease to approximately 70 MBbl/d by the end of 2018, initially in regions closest to market centers such as the Permian Basin and Mid-Continent region, as ethylene producers continue to complete their expansion projects and NGL exporters increase their export volumes in 2018 and beyond.

Demand - Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations affect the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, fractionation and transportation services. Natural gas and propane are subject to weather-related seasonal demand. Other NGL products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as butanes and natural gasoline used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane, propane, normal butane and natural gasoline are used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fibers. Several petrochemical companies are constructing new plants, plant expansions, additions or enhancements that improve the light-NGL feed capability of their facilities due primarily to the increased supply and attractive price of ethane, compared with crude oil-based alternatives, as a petrochemical feedstock in the United States. The demand for NGLs is expected to continue to increase from petrochemical companies and exporters in the coming months as ethylene producers complete their expansion projects and international demand for NGLs increases export volumes. Increasing producer activity in high-production areas is driving the need for additional gathering and fractionation services, such as our recently announced Sterling III and WTLPG pipeline expansions, Elk Creek pipeline, Arbuckle II pipeline and MB-4 projects.

Commodity Prices - Our Natural Gas Liquids segment provides primarily fee-based services. However, we are exposed to market risk associated with changes in the price of NGLs; the location differential between the Mid-Continent, Chicago, Illinois, and Gulf Coast regions; and the relative price differential between natural gas, NGLs and individual NGL products, which affect our NGL purchases and sales, and our exchange services, transportation and storage services, and optimization and marketing financial results. Supply growth from the development of NGL-rich areas and capacity available on pipelines that connect the Mid-Continent and Gulf Coast resulted in 2017 NGL price differentials remaining narrow between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas. However, location price differentials for the fourth quarter 2017 were some of the widest that we have experienced since 2012. NGL storage revenue may be affected by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market.

Seasonality - Our natural gas liquids fractionation and pipeline operations typically experience some seasonal variation. Some NGL products stored and transported through our assets are subject to weather-related seasonal demand, such as propane, which can be used for heating during the winter and for agricultural purposes such as crop drying in the fall. Demand for butanes and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, may also be subject to some variability during seasonal periods when certain government restrictions on motor fuel blending products change. The ability of natural gas processors to produce NGLs also is affected by weather. Extreme weather conditions and ground temperature changes impact the volumes of natural gas gathered and processed and NGL volumes gathered, transported and fractionated. Power interruptions, inaccessible well sites as a result of severe storms or freeze-offs, a phenomenon where water produced from natural gas freezes at the wellhead or within the gathering system, cause a temporary interruption in the flow of natural gas and NGLs.

Competition - Our Natural Gas Liquids segment competes with other fractionators, intrastate and interstate pipeline companies, storage providers, and gatherers and transporters for NGL supply in the Permian Basin and Rocky Mountain, Mid-Continent and Gulf Coast regions. The factors that typically affect our ability to compete for NGL supply are:
quality of services provided;
producer drilling activity;
the petrochemical industry’s level of capacity utilization and feedstock requirements;
fees charged under our contracts;
current and forward NGL prices;
location of our gathering systems relative to our competitors;
location of our gathering systems relative to drilling activity;
proximity to NGL supply areas and markets;
efficiency and reliability of our operations;
receipt and delivery capabilities that exist in each pipeline system, plant, fractionator and storage location; and

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cost of capital.

We have responded to these factors by making capital investments to access new supplies; increasing gathering, fractionation and distribution capacity; increasing storage, withdrawal and injection capabilities; and reducing operating costs so that we may compete effectively. Our competitors continue to invest in natural gas liquids pipeline and fractionation infrastructure to address the growing NGL supply and petrochemical demand. As our growth projects and those of our competitors have alleviated constraints between the Mid-Continent and Gulf Coast NGL market centers, we expect relatively narrow price differentials between these two market centers to persist until demand for NGLs increases from petrochemical companies and exporters. In addition, our and our competitors’ natural gas liquids infrastructure projects provide NGL supply from the Rocky Mountain region, Marcellus and Utica basins into the Gulf Coast market center, which affects NGL prices and competes with and could displace NGL supply volumes from the Mid-Continent and Rocky Mountain regions where our assets are located. We believe our natural gas liquids fractionation, pipelines and storage assets are located strategically, connecting diverse supply areas to market centers.

Customers - Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies; major and independent crude oil and natural gas production companies; propane distributors; ethanol producers; and petrochemical, refining and NGL marketing companies. See discussion regarding our customer credit risk under “Counterparty Credit Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Government Regulation - The operations and revenues of our natural gas liquids pipelines are regulated by various state and federal government agencies. Our interstate natural gas liquids pipelines are regulated by the FERC, which has authority over the terms and conditions of service; rates, including depreciation and amortization policies; and initiation of service. In Oklahoma, Kansas and Texas, certain aspects of our intrastate natural gas liquids pipelines that provide common carrier service are subject to the jurisdiction of the OCC, KCC and RRC, respectively.

PHMSA has asserted jurisdiction over certain portions of our fractionation facilities in Bushton, Kansas, that it believes are subject to its jurisdiction. We have objected to the scope of PHMSA’s jurisdiction and are seeking resolution of this matter. We do not anticipate that the cost of compliance will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment provides transportation and storage services to end users through its wholly owned assets and its 50 percent ownership interests in Northern Border Pipeline and Roadrunner.

Interstate Pipelines - Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include:
Midwestern Gas Transmission, which is a bidirectional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines that have access to both the Utica Shale and the Marcellus Shale at the Chicago Hub near Joliet, Illinois;
Viking Gas Transmission, which is a bidirectional system that interconnects with a TransCanada Corporation pipeline at the United States border near Emerson, Canada, and ANR Pipeline Company near Marshfield, Wisconsin;
Guardian Pipeline, which interconnects with several pipelines at the Chicago Hub near Joliet, Illinois, and with local natural gas distribution companies in Wisconsin; and
OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico.

Intrastate Pipelines - Our intrastate natural gas pipeline assets in Oklahoma transport natural gas through the state and have access to the major natural gas production areas in the Mid-Continent region, which include the STACK and SCOOP areas and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations. Our intrastate natural gas pipeline assets in Oklahoma serve end-use markets, such as local distribution companies and power generation companies. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing formations in the Texas Panhandle, including the Granite Wash formation and Delaware, Cline and Midland producing formations in the Permian Basin. These pipelines are capable of transporting natural gas throughout the western portion of Texas, including the Waha Hub where other pipelines may be accessed for transportation to western markets, exports to

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Mexico, the Houston Ship Channel market to the east and the Mid-Continent market to the north. Our intrastate natural gas pipeline assets also have access to the Hugoton and Central Kansas Uplift Basins in Kansas.

Revenues - Revenues in this segment are derived primarily from transportation and storage services.

Our transportation revenues are primarily fee-based from the following types of services:
Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve.
Interruptible service - Under interruptible service transportation agreements, the customer may utilize available capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess capacity is available.

Our regulated natural gas transportation services contracts are based upon rates stated in the respective tariffs, which have generally been established through shipper specific negotiation, discounts and negotiated settlements. The rates are filed with FERC or the appropriate state jurisdictional agencies. In addition, customers typically are assessed fees, such as a commodity charge, and we may retain a percentage or specified volume of natural gas in-kind based on the natural gas volumes transported.

Our storage revenues are primarily fee-based from the following types of services:
Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically have terms longer than one year.
Park-and-loan service - An interruptible service offered to customers providing the ability to park (inject) or loan (withdraw) natural gas into or out of our storage, typically for monthly or seasonal terms. Customers reserve the right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

We own natural gas storage facilities located in Texas and Oklahoma that are connected to our intrastate natural gas pipelines. We also have underground natural gas storage facilities in Kansas. In Texas and Kansas, natural gas storage operations may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas storage operations are not subject to rate regulation by the state, and we have market-based rate authority from the FERC for certain types of services.

Property - Our Natural Gas Pipelines segment owns the following assets:
approximately 1,500 miles of FERC-regulated interstate natural gas pipelines with approximately 3.5 Bcf/d of peak transportation capacity;
approximately 5,200 miles of state-regulated intrastate transmission pipelines with peak transportation capacity of approximately 3.5 Bcf/d; and
approximately 52.2 Bcf of total active working natural gas storage capacity.

Our storage includes two underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities in Kansas and two underground natural gas storage facilities in Texas.

Utilization - Our natural gas pipelines were approximately 94 percent and 92 percent subscribed in 2017 and 2016, respectively, and our natural gas storage facilities were 64 percent and 65 percent subscribed in 2017 and 2016, respectively.

Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes the following unconsolidated affiliates:
50 percent interest in Northern Border Pipeline, which owns a FERC-regulated interstate pipeline that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, and the Williston Basin in North Dakota to a terminus near North Hayden, Indiana.
50 percent interest in Roadrunner, which has the capacity to transport approximately 570 MMcf/d of natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. We are the operator of Roadrunner.

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

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Market Conditions and Seasonality - Supply - The development of shale and other resource areas has continued to increase available natural gas supply across North America and has caused location and seasonal price differentials to narrow in the regions where we operate.

Interstate - Guardian Pipeline, Midwestern Gas Transmission and Viking Gas Transmission access supply from the major producing regions of the Mid-Continent, Rocky Mountains, Canada, Gulf Coast and the Northeast. The current supply of natural gas for Northern Border Pipeline is primarily sourced from Canada; however, as the Williston Basin supply area has developed, more natural gas supply from this area is being transported on Northern Border Pipeline to markets near Chicago. In addition, supply volumes from nontraditional natural gas production areas, such as the Marcellus and Utica shale areas in the Northeast, may compete with and displace volumes from the Mid-Continent, Rocky Mountain and Canadian supply sources in our markets. Factors that may impact the supply of Canadian natural gas transported by our pipelines are primarily the availability of United States supply, Canadian natural gas available for export, Canadian storage capacity, government regulation and demand for Canadian natural gas in Canada and United States consumer markets.

Intrastate and Storage - Our intrastate pipelines and storage assets may be impacted by the pace of drilling activity by crude oil and natural gas producers and the decline rate of existing production in the major natural gas production areas in the Permian Basin and the Mid-Continent region.

Demand - Demand for our services is related directly to our access to supply and the demand for natural gas by the markets that our natural gas pipelines and storage facilities serve. Demand is also affected by weather, the economy, natural gas price volatility and regulatory changes.
Weather - The effect of weather on our natural gas pipelines operations is discussed below under “Seasonality.”
Economy - The strength of the economy directly impacts manufacturing and industrial companies that consume natural gas.
Price volatility - Commodity price volatility can influence producers’ decisions related to the production of natural gas. Our pipeline customers, primarily natural gas and electric utilities, require natural gas to operate their businesses and generally are not impacted by location price differentials. However, narrower location price differentials may impact demand for our services from natural gas marketers as discussed below under “Commodity Prices.”
Regulatory - Demand for our services is also affected as coal-fired electric generators are retired and replaced with power generation from natural gas. EPA regulations on emissions from coal-fired electric-generation plants have increased the demand for natural gas as a fuel for electric generation, as well as related transportation and storage services. The demand for natural gas and related transportation and storage services is expected to increase over the next several years as regulations continue to be implemented.

Commodity Prices - Although our revenues are primarily fee-based, commodity prices can affect our results of operations.
Transportation - We are exposed to market risk through interruptible contracts or when existing firm contracts expire and are subject to renegotiation with customers that have competitive alternatives.
Storage - Natural gas storage revenue is impacted by the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market.
Fuel - Our fuel costs and the value of the retained fuel in-kind received for our services also are impacted by changes in the price of natural gas.

Seasonality - Demand for natural gas is seasonal. Weather conditions throughout North America may significantly impact regional natural gas supply and demand. High temperatures may increase demand for gas-fired electric generation needed to meet the electricity demand required to cool residential and commercial properties. Cold temperatures may lead to greater demand for our transportation services due to increased demand for natural gas to heat residential and commercial properties. Low precipitation levels may impact the demand for natural gas that is used to fuel irrigation activity in the Mid-Continent region.

To the extent that pipeline capacity is contracted under firm-service transportation agreements, revenue, which is generated primarily from fixed-fee charges, is not significantly impacted by seasonal throughput variations.

Natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of residential, commercial and electric-generation users. The majority of our storage capacity is either contracted under firm-service agreements or is used for park-and-loan services. We retain a portion of our storage capacity for operational purposes.


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Competition - Our natural gas pipelines and storage facilities compete directly with other intrastate and interstate pipeline companies and other storage facilities. Competition among pipelines and natural gas storage facilities is based primarily on fees for services, quality and reliability of services provided, current and forward natural gas prices, proximity to natural gas supply areas and markets, and access to capital. Competition for natural gas transportation services continues to increase as new infrastructure projects are completed and the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Regulatory bodies also are encouraging the use of natural gas for electric generation that has traditionally been fueled by coal. The combined cost of coal and the associated rail transportation continues to be competitive with the cost of natural gas; however, the clean-burning aspects of natural gas and abundance of supply make it an economically competitive and environmentally advantaged alternative. We believe that our pipelines and storage assets compete effectively due to their strategic locations connecting supply areas to market centers and other pipelines.

Customers - Our natural gas pipeline assets primarily serve local natural gas distribution companies, electric-generation facilities, large industrial companies, municipalities, producers and marketing companies. Our utility customers generally require our services regardless of commodity prices. See discussion regarding our customer credit risk under “Counterparty Credit Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Government Regulation - Interstate - Our interstate natural gas pipelines are regulated under the Natural Gas Act, which gives the FERC jurisdiction to regulate virtually all aspects of this business, such as transportation of natural gas, rates and charges for services, construction of new facilities, depreciation and amortization policies, acquisition and disposition of facilities, and the initiation and discontinuation of services.

Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively, and by the FERC under the Natural Gas Policy Act for certain services where we deliver natural gas into FERC regulated natural gas pipelines. While we have flexibility in establishing natural gas transportation rates with customers, there is a maximum rate that we can charge our customers in Oklahoma and Kansas and for the services regulated by the FERC. In Texas and Kansas, natural gas storage may be regulated by the state and by the FERC for certain types of services. In Oklahoma, natural gas storage operations are not subject to rate regulation by the state, and we have market-based rate authority from the FERC for certain types of services.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

SEGMENT FINANCIAL INFORMATION

Segment Adjusted EBITDA, Customers and Total Assets - See Note P of the Notes to Consolidated Financial Statements in this Annual Report for disclosure by segment of our adjusted EBITDA and total assets and for a discussion of revenues from external customers.

Other

Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own a 17-story office building (ONEOK Plaza) with approximately 505,000 square feet of net rentable space and a parking garage in downtown Tulsa, Oklahoma, where our headquarters are located. ONEOK Leasing Company, L.L.C. leases excess office space to others and operates our headquarters office building. ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to multiple federal, state, local and/or tribal historical preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands and waterways preservation, cultural resources protection, 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. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows. In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing

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environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us.

There is a belief that emissions of GHGs is linked to global climate change. GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of GHGs.

Our environmental and climate change actions focus on minimizing the impact of our operations on the environment. These actions include: (i) developing and maintaining an accurate GHG emissions inventory according to current rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emissions control and the capture of carbon dioxide to keep it from reaching the atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities.

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

We believe it is likely that future governmental legislation and/or regulation may require us either to limit GHG emissions from our operations or to purchase allowances for such emissions. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations or when they will become effective. In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted.

For additional information regarding the potential impact of laws and regulations on our operations see Item 1A “Risk Factors.”

Pipeline Safety - We are subject to PHMSA safety regulations, including pipeline asset integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) increased maximum penalties for violating federal pipeline safety regulations, directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us and may result in the imposition of more stringent regulations.

Since 2015, PHMSA has issued notices of proposed rule-making for hazardous liquid pipeline safety regulations, natural gas transmission and gathering lines and underground natural gas storage facilities, none of which have become final. The potential capital and operating expenditures related to the proposed regulations are unknown, but we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations.

Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations 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. 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 control or limit GHG emissions, including initiatives directed at issues associated with climate change. We monitor all relevant legislation and regulatory initiatives to assess the potential impact on our operations and otherwise take efforts to limit GHG emissions from our facilities, including methane. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us and the emission equivalents for all NGLs produced by us as if all of these products were combusted, even if they are used otherwise.

Our 2016 total reported emissions were approximately 50 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon

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dioxide equivalents from natural gas and NGL products delivered to customers and produced as if all such fuel and NGL products were combusted. 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 GHG emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rule-making associated with GHG emissions from the oil and natural gas industry. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

We closely monitor proposed and final rule-makings. At this time we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations and EPA actions. However, the EPA may issue additional regulations, responses, amendments and/or policy guidance, which could alter our present expectations. Generally, EPA rule-makings require expenditures for updated emissions controls, monitoring and recordkeeping requirements at affected facilities.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released the Chemical Facility Anti-Terrorism Standards in 2007, and the new final rule associated with these regulations was issued in December 2014. We provided information regarding our chemicals via Top-Screens submitted to Homeland Security, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, one of our facilities has been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and possible security enhancement costs to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

EMPLOYEES

At January 31, 2018, we employed 2,470 people.


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EXECUTIVE OFFICERS

All executive officers are elected annually by our Board of Directors. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.
Name and Position
 
Age
 
Business Experience in Past Five Years
John W. Gibson
 
65

 
2014 to present
 
Chairman of the Board, ONEOK
Chairman of the Board
 
 
 
2014 to 2017
 
Chairman of the Board, ONEOK Partners
 
 
 
 
2011 to 2014
 
Chairman and Chief Executive Officer, ONEOK and ONEOK Partners
Terry K. Spencer
 
58

 
2014 to present
 
President and Chief Executive Officer, ONEOK
President and Chief Executive Officer
 
 
 
2014 to 2017
 
President and Chief Executive Officer, ONEOK Partners
 
 
 
 
2014 to present
 
Member of the Board of Directors, ONEOK
 
 
 
 
2014 to 2017
 
Member of the Board of Directors, ONEOK Partners
 
 
 
 
2012 to 2014
 
President, ONEOK and ONEOK Partners
Robert F. Martinovich
 
60

 
2015 to present
 
Executive Vice President and Chief Administrative Officer, ONEOK
Executive Vice President and Chief Administrative Officer
 
 
 
2015 to 2017
 
Executive Vice President and Chief Administrative Officer, ONEOK Partners
 
 
 
 
2014 to 2015
 
Executive Vice President, Commercial, ONEOK and ONEOK Partners
 
 
 
 
2013 to 2014
 
Executive Vice President, Operations, ONEOK and ONEOK Partners
 
 
 
 
2012
 
Executive Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
 
 
 
 
2011 to 2012
 
Member of the Board of Directors, ONEOK Partners
Walter S. Hulse III
 
54

 
2017 to present
 
Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK
Chief Financial Officer, Executive Vice President, Strategic Planning and Corporate Affairs
 
 
 
2015 to 2017
 
Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK and ONEOK Partners
 
 
 
 
2012 to 2015
 
Managing Member, Spinnaker Strategic Advisory Services, LLC
Kevin L. Burdick
 
53

 
2017 to present
 
Executive Vice President and Chief Operating Officer, ONEOK
Executive Vice President and Chief Operating Officer
 
 
 
2017
 
Executive Vice President and Chief Commercial Officer, ONEOK and ONEOK Partners
 
 
 
 
2016 to 2017
 
Senior Vice President, Natural Gas Gathering and Processing, ONEOK Partners
 
 
 
 
2013 to 2016
 
Vice President, Natural Gas Gathering and Processing, ONEOK Partners
 
 
 
 
2009 to 2013
 
Vice President and Chief Information Officer, ONEOK and ONEOK Partners
Wesley J. Christensen
 
64

 
2014 to present
 
Senior Vice President, Operations, ONEOK
Senior Vice President, Operations
 
 
 
2011 to 2017
 
Senior Vice President, Operations, ONEOK Partners
Stephen B. Allen
 
44

 
2017 to present
 
Senior Vice President, General Counsel and Assistant Secretary, ONEOK
Senior Vice President, General Counsel
and Assistant Secretary
 
 
 
2008 to 2017
 
Vice President and Associate General Counsel, ONEOK and ONEOK Partners
Derek S. Reiners
 
46

 
2017 to present
 
Senior Vice President, Finance and Treasurer, ONEOK
Senior Vice President, Finance and Treasurer
 
 
 
2013 to 2017
 
Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
 
 
 
 
2009 to 2012
 
Senior Vice President and Chief Accounting Officer, ONEOK and ONEOK Partners
Sheppard F. Miers III
 
49

 
2013 to present
 
Vice President and Chief Accounting Officer, ONEOK
Vice President and Chief Accounting Officer
 
 
 
2013 to 2017
 
Vice President and Chief Accounting Officer, ONEOK Partners
 
 
 
 
2009 to 2012
 
Vice President and Controller, ONEOK Partners

No family relationships exist 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.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Bylaws and the written charter of our Audit Committee also are 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 social media accounts, and any corresponding applications, are not incorporated by reference into this report.

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

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ITEM 1A.    RISK FACTORS

Our investors should consider the following risks that could affect us and our business. Although we have tried to identify 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 consider carefully 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 II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

RISKS INHERENT IN OUR BUSINESS

If the level of drilling in the regions in which we operate declines substantially near our assets, our volumes and revenues could decline.

Our gathering and transportation pipeline systems are connected to, and dependent on the level of production from, natural gas and crude oil wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our processing and fractionation plants, we must continually obtain new supplies. Our ability to maintain or expand our businesses depends largely on the level of drilling and production by third parties in the regions in which we operate. Our natural gas and NGL supply volumes may be impacted if producers curtail or redirect drilling and production activities. Drilling and production are impacted by factors beyond our control, including:
demand and prices for natural gas, NGLs and crude oil;
producers’ access to capital;
producers’ finding and development costs of reserves;
producers’ desire and ability to obtain necessary permits in a timely and economic manner;
natural gas field characteristics and production performance;
surface access and infrastructure issues; and
capacity constraints on natural gas, crude oil and natural gas liquids infrastructure from the producing areas and our facilities.

Commodity prices have experienced significant volatility. Drilling and production activity levels may vary across our geographic areas; however, a prolonged period of low commodity prices may reduce drilling and production activities across all areas. If we are not able to obtain new supplies to replace the natural decline in volumes from existing wells or because of competition, throughput on our gathering and transportation pipeline systems and the utilization rates of our processing and fractionation facilities would decline, which could have a material adverse effect on our business, results of operations, financial position and cash flows, and our ability to pay cash dividends.

Continued development of new supply sources could impact demand for our services.

The discovery of nonconventional natural gas production areas near certain market areas that we serve may compete with natural gas originating in production areas connected to our systems. For example, the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio may cause natural gas in supply areas connected to our systems to be diverted to markets other than our traditional market areas and may affect capacity utilization adversely on our pipeline systems and our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows. In addition, supply volumes from these nonconventional natural gas production areas may compete with and displace volumes from the Mid-Continent, Permian, Rocky Mountains and Canadian supply sources in certain of our markets. In our Natural Gas Gathering and Processing segment, the development of these new nonconventional reserves could move drilling rigs from our current service areas to other areas, which may reduce demand for our services. In our Natural Gas Pipelines segment, the displacement of natural gas originating in supply areas connected to our pipeline systems by these new supply sources that are closer to the end-use markets could result in lower transportation revenues, which could have a material adverse impact on our business, financial condition, results of operations and cash flows.


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The volatility of natural gas, crude oil and NGL prices could affect adversely our earnings and cash flows.

A significant portion of our revenues are derived from the sale of commodities that are received in conjunction with natural gas gathering and processing services, the transportation and storage of natural gas, and from the purchase and sale of NGLs and NGL products. Commodity prices have been volatile and are likely to continue to be so in the future. The prices we receive for our commodities are subject to wide fluctuations in response to a variety of factors beyond our control, including, but not limited to, the following:
overall domestic and global economic conditions;
relatively minor changes in the supply of, and demand for, domestic and foreign energy;
market uncertainty;
the availability and cost of third-party transportation, natural gas processing and fractionation capacity;
the level of consumer product demand and storage inventory levels;
ethane rejection;
geopolitical conditions impacting supply and demand for natural gas, NGLs and crude oil;
weather conditions;
domestic and foreign governmental regulations and taxes;
the price and availability of alternative fuels;
speculation in the commodity futures markets;
the effects of imports and exports on the price of natural gas, crude oil, NGL and liquefied natural gas;
the effect of worldwide energy-conservation measures;
the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials; and
technology and improved efficiency impacting supply and demand for natural gas, NGLs and crude oil.

These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services, which could have a material adverse effect on our earnings and cash flows. As commodity prices decline, we could be paid less for our commodities, thereby reducing our cash flows. In addition, crude oil, natural gas and NGL production could also decline due to lower prices.

Market volatility and capital availability could affect adversely our business.

The capital and global credit markets have experienced volatility and disruption in the past. In many cases during these periods, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for certain companies. Much of our business is capital intensive, and our ability to grow is dependent, in part, upon our ability to access capital at rates and on terms we determine to be attractive. Similar or more severe levels of global market disruption and volatility may have an adverse effect on us resulting from, but not limited to, disruption of our access to capital and credit markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing costs and increasingly restrictive covenants. If we are unable to access capital at competitive rates, our strategy of enhancing the earnings potential of our existing assets, including through capital-growth projects and acquisitions of complementary assets or businesses, may be affected adversely. A number of factors could affect adversely our ability to access capital, including: (i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other hydrocarbons; (iv) the overall health of the energy and related industries; (v) ability to maintain investment-grade credit ratings; (vi) share price and (vii) capital structure. If our ability to access capital becomes constrained significantly, our interest costs and cost of equity will likely increase and could affect adversely our financial condition and future results of operations.

Our operating results may be affected materially and adversely by unfavorable economic and market conditions.

Economic conditions worldwide have from time to time contributed to slowdowns in the crude oil and natural gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices may have an impact on many of our customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. If global economic and market conditions (including volatility in commodity markets) or economic conditions in the United States or other key markets remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition, results of operations and liquidity.


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Increased competition could have a significant adverse financial impact on our business.

The natural gas and natural gas liquids industries are expected to remain highly competitive. The demand for natural gas and NGLs is primarily a function of commodity prices, including prices for alternative energy sources, customer usage rates, weather, economic conditions and service costs. Our ability to compete also depends on a number of other factors, including competition from other companies for our existing customers; the efficiency, quality and reliability of the services we provide; and competition for throughput at our gathering systems, pipelines, processing plants, fractionators and storage facilities.

Increased regulation of exploration and production activities, including hydraulic fracturing and disposal of waste water, could result in reductions or delays in drilling and completing new crude oil and natural gas wells, which could impact adversely our earnings by decreasing the volumes of natural gas and NGLs transported on our or our joint ventures’ natural gas and natural gas liquids pipelines.

The natural gas industry is relying increasingly on natural gas supplies from nonconventional sources, such as shale and tight sands. Natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized injection of water, sand and chemicals into a geologic formation to stimulate natural gas production. Legislation or regulations placing restrictions on hydraulic fracturing activities, including waste-water disposal, could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of unprocessed natural gas and, in turn, affect adversely our revenues and results of operations by decreasing the volumes of unprocessed natural gas and NGLs gathered, treated, processed, fractionated and transported on our or our joint ventures’ natural gas and natural gas liquids pipelines, several of which gather unprocessed natural gas from areas where the use of hydraulic fracturing is prevalent.

In the competition for supply, we may have significant levels of excess capacity on our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets.

Our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage facilities for natural gas and NGL supply delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our pipelines, processing, fractionation and in our storage assets, which could have a material adverse impact on our results of operations and cash flows.

We may not be able to replace, extend or add additional contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends and our ability to grow.

Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers and suppliers or otherwise increase the contracted volumes of natural gas and NGLs provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans and the amount of cash available to pay dividends could be affected adversely. Our ability to replace, extend or add additional customer or supplier contracts, or increase contracted volumes of natural gas and NGLs from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:
the level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils or nuclear energy;
natural gas and NGL prices, demand, availability; and
margins in our markets.

We may face opposition to the construction or operation of our pipelines and facilities from various groups.

We may face opposition to the construction or operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our construction activities or operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that delays or interrupts the construction of assets or

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revenues generated by our existing operations, or which causes us to make significant expenditures not covered by insurance, could affect adversely our financial condition, results of operations, cash flows and our share price.

Growing our business by constructing new pipelines and plants or making modifications to our existing facilities subjects us to construction risk and supply risks, should adequate natural gas or NGL supply be unavailable upon completion of the facilities.

One of the ways we may grow our businesses is through the construction of new pipelines and new gathering, processing, storage and fractionation facilities and through modifications to our existing pipelines and existing gathering, processing, storage and fractionation facilities. The construction and modification of pipelines and gathering, processing, storage and fractionation facilities may face the following risks:
projects may require significant capital expenditures, which may exceed our estimates, and involves numerous regulatory, environmental, political, legal and weather-related uncertainties;
projects may increase demand for labor, materials and rights of way, which may, in turn, affect our costs and schedule;
we may be unable to obtain new rights of way to connect new natural gas or NGL supplies to our existing gathering or transportation pipelines;
if we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost;
our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project;
we may have only limited natural gas or NGL supply committed to these facilities prior to their construction;
we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize;
we may rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves; and
we may be required to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas or NGLs, which may not yet be operational.
As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve our expected investment return, which could affect materially and adversely our results of operations, financial condition and cash flows.

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

Our operations are subject to all of the risks and hazards typically associated with the operation of natural gas and natural gas liquids gathering, transportation and distribution pipelines, storage facilities and processing and fractionation plants. Operating risks include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes and the performance of pipeline facilities below expected levels of capacity and efficiency. 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. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred and interruptions to the operations of our pipeline or other facilities caused by such an event could reduce revenues generated by us and increase expenses, thereby impairing our ability to meet our obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and we are not fully insured against all risks inherent to 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. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, cash flows and results of operations. Further, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.


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We may not be able to develop and execute growth projects and acquire new assets, which could result in reduced dividends to our shareholders.

Our ability to maintain and grow our dividends paid to our shareholders depends on the growth of our existing businesses and strategic acquisitions. Our ability to make strategic acquisitions and investments will depend on:
the extent to which acquisitions and investment opportunities become available;
our success in bidding for the opportunities that do become available;
regulatory approval, if required, of the acquisitions or investments on favorable terms; and
our access to capital, including our ability to use our equity in acquisitions or investments, and the terms upon which we obtain capital.

Our ability to develop and execute growth projects will depend on our ability to implement business development opportunities and finance such activities on economically acceptable terms.

If we are unable to make strategic acquisitions and investments, integrate successfully businesses that we acquire with our existing business, or develop and execute our growth projects, our future growth will be limited, which could impact adversely our results of operations and cash flows and, accordingly, result in reduced cash dividends over time.

Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per-share basis.

Any acquisition involves potential risks that may include, among other things:
inaccurate assumptions about volumes, revenues and costs, including potential synergies;
an inability to integrate successfully the businesses we acquire;
decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;
a significant increase in our interest expense and/or financial leverage if we incur additional debt to finance the acquisition;
the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance policies may exclude from coverage;
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets;
limitations on rights to indemnity from the seller;
inaccurate assumptions about the overall costs of equity or debt;
the diversion of management’s and employees’ attention from other business concerns;
unforeseen difficulties operating in new product areas or new geographic areas;
increased regulatory burdens;
customer or key employee losses at an acquired business; and
increased regulatory requirements.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.

Mergers between our customers, suppliers and competitors could result in lower volumes being gathered, processed, fractionated, transported or stored on our assets, thereby reducing the amount of cash we generate.

Mergers between our existing customers, suppliers and our competitors could provide strong economic incentives for the combined entities to utilize their existing gathering, processing, fractionation and/or transportation systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these counterparties, and we could experience difficulty in replacing those lost volumes. Because most of our operating costs are fixed, a reduction in volumes could result not only in lower net income but also in a decline in cash flows, which would reduce our ability to pay cash dividends to our shareholders.

We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which could disrupt our operations.

We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these

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rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.

Terrorist attacks directed at our facilities could affect adversely our business.

The United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments may subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

Any reduction in our credit ratings could affect materially and adversely our business, financial condition, liquidity and results of operations.

Our long-term debt and our commercial paper program have been assigned an investment-grade credit rating of “Baa3” and Prime-3, respectively, by Moody’s and “BBB” and A-2, respectively, by S&P. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Specifically, if Moody’s or S&P were to downgrade our long-term debt or our commercial paper rating, particularly below investment grade, our borrowing costs would increase, which would affect adversely our financial results, and our potential pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.

Holders of our common stock may not receive dividends in the amount identified in guidance, or any dividends at all.

We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we pay in the form of dividends may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including our working capital needs, our ability to borrow, the restrictions contained in our indentures and credit facility, our debt service requirements and the cost of acquisitions, if any. A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our stock price.

Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates.

Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates, as discussed in Note N of the Notes to Consolidated Financial Statements. The amount of cash that our unconsolidated affiliates can distribute principally depends upon the amount of cash flows these affiliates generate from their respective operations, which may fluctuate from quarter to quarter. We do not have any direct control over the cash distribution policies of our unconsolidated affiliates. This lack of control may contribute to us not having sufficient available cash each quarter to continue paying dividends at the current levels.

Additionally, the amount of cash that we have available for cash dividends depends primarily upon our cash flows, including cash flows from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by noncash items such as depreciation, amortization and provisions for asset impairments. As a result, we may be able to pay cash dividends during periods when we record losses and may not be able to pay cash dividends during periods when we record net income.

We are exposed to the credit risk of our customers or counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We assess the creditworthiness of our customers and counterparties and obtain collateral or contractual terms as we deem appropriate. We cannot, however, predict to what extent our business may be impacted by deteriorating market or financial conditions, including possible declines in our customers’ and counterparties’ creditworthiness. Our customers and counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent our customers and counterparties are in financial distress or commence bankruptcy proceedings, contracts with them may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If we fail to assess adequately the creditworthiness of existing or future customers and counterparties any material nonpayment or nonperformance by our

26


customers and counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on our business, results of operations, financial condition and ability to pay cash dividends to our shareholders.

Our primary market areas are located in the Mid-Continent, Rocky Mountain, Permian Basin and Gulf Coast regions of the U.S. Our counterparties are primarily major integrated and independent exploration and production, pipeline, marketing and petrochemical companies. Therefore our customers and counterparties may be similarly affected by changes in economic, regulatory or other factors that may affect our overall credit risk.

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

We have developed and implemented a comprehensive set of policies and procedures that involve both our senior management and our Audit Committee to assist us in managing risks associated with, among other things, the marketing, trading and risk-management activities associated with our business segments. Our 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. 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 position or cash flows.

Our businesses are subject to market and credit risks.

We are exposed to market and credit risks in all of our operations. To reduce the impact of commodity price fluctuations, we may use derivative instruments, such as swaps, puts, futures and forwards, to hedge anticipated purchases and sales of natural gas, NGLs, crude oil and firm transportation commitments. Interest-rate swaps are also used to manage interest-rate risk. However, derivative instruments do not eliminate the risks. Specifically, such risks include commodity price changes, market supply shortages, interest-rate changes and counterparty default. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts, or increased interest expense.

We do not hedge fully against commodity price changes, seasonal price differentials, product price differentials or location price differentials. This could result in decreased revenues, increased costs and lower margins, affecting adversely our results of operations.

Certain of our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs and crude oil prices. Market risk refers to the risk of loss of cash flows and future earnings arising from adverse changes in commodity prices. Our primary commodity price exposures arise from:
the value of the commodities sold under POP with fee contracts of which we retain a portion of the sales proceeds;
the price differentials between the individual NGL products with respect to our NGL transportation and fractionation agreements;
the location price differentials in the price of natural gas and NGLs with respect to our natural gas and NGL transportation businesses;
the seasonal price differentials in natural gas and NGLs related to our storage operations; and
the fuel costs and the value of the retained fuel in-kind in our natural gas pipelines and storage operations.

To manage the risk from market price fluctuations in natural gas, NGLs and crude oil prices, we may use derivative instruments such as swaps, puts, futures, forwards and options. However, we do not hedge fully against commodity price changes, and we therefore retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased costs.

Our use of financial instruments and physical forward transactions to hedge market-risk exposure to commodity price and interest-rate fluctuations may result in reduced income.

We utilize financial instruments and physical forward transactions to mitigate our exposure to interest rate and commodity price fluctuations. Hedging instruments that are used to reduce our exposure to interest-rate fluctuations could expose us to risk of

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financial loss where we may contract for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate. In addition, these hedging arrangements may limit the benefit we would otherwise receive if we had contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate. Hedging arrangements for forecasted sales are used to reduce our exposure to commodity price fluctuations and limit the benefit we would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the stated price in the hedge instrument for these commodities.

Changes in interest rates could affect adversely our business.

We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our short-term borrowings. From time to time we use interest-rate derivatives to hedge interest obligations on specific debt issuances, including anticipated debt issuances. These hedges may be ineffective, and our results of operations, cash flows and financial position could be affected adversely by significant fluctuations in interest rates from current levels.

Demand for natural gas and for certain of our NGL products and services is highly weather sensitive and seasonal.

The demand for natural gas and for certain of our NGL products, such as propane, is weather sensitive and seasonal, with a portion of revenues derived from sales for heating during the winter months. Weather conditions influence directly the volume of, among other things, natural gas and propane delivered to customers. Deviations in weather from normal levels and the seasonal nature of certain of our segments can create variations in earnings and short-term cash requirements.

Energy efficiency and technological advances may affect the demand for natural gas and NGLs and affect adversely our operating results.

More strict local, state and federal energy-conservation measures in the future or technological advances in heating, including installation of improved insulation and the development of more efficient furnaces, energy generation or other devices could affect the demand for natural gas and NGLs and affect adversely our results of operations and cash flows.

A breach of information security, including a cybersecurity attack, or failure of one or more key information technology or operational systems, or those of third parties, may affect adversely our operations, financial results or reputation.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. The various uses of these IT systems, networks and services include, but are not limited to:
controlling our plants and pipelines with industrial control systems including Supervisory Control and Data Acquisition (SCADA);
collecting and storing customer, employee, investor and other stakeholder information and data;
processing transactions;
summarizing and reporting results of operations;
hosting, processing and sharing confidential and proprietary research, business plans and financial information;
complying with regulatory, legal or tax requirements;
providing data security; and
handling other processing necessary to manage our business.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could affect adversely our business and results of operations. Our financial results could also be affected adversely if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our businesses. We use software to help manage and operate our businesses, and this may subject us to increased risks. In recent years, there has been a rise in the number of cyberattacks on companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. If any such failure, interruption or similar event results in the improper disclosure of information maintained in our information systems and networks or those of our vendors,

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including personnel, customer and vendor information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Efforts by us and our vendors to develop, implement and maintain security measures may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. Although we believe that we have robust information security procedures and other safeguards in place, as cyberthreats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

Cyberattacks against us or others in our industry could result in additional regulations. Current efforts by the federal government, such as the Improving Critical Infrastructure Cybersecurity executive order, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial results or prevent fraud. As a result, current and potential holders of our equity and debt securities could lose confidence in our financial reporting, which would harm our business and cost of capital.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our equity interests.

Pipeline safety laws and regulations may impose significant costs and liabilities.

Pipeline safety legislation that was signed into law in 2012, the 2011 Pipeline Safety Act, directed the Secretary of Transportation to promulgate new safety regulations for natural gas and hazardous liquids pipelines, including expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the maximum allowable pressure of certain gas transmission pipelines. The 2011 Pipeline Safety Act also increased the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations.

The 2011 Pipeline Safety Act, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act or rules implementing such acts could cause us to incur capital and operating expenditures for pipeline replacements or repairs, additional monitoring equipment or more frequent inspections or testing of our pipeline facilities, preventive or mitigating measures and other tasks that could result in higher operating costs or capital expenditures as necessary to comply with such standards, which costs could be significant.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Compliance with environmental regulations that we are subject to may be difficult and costly.

We are subject to multiple federal, state, local and/or tribal historical preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands and waterways preservation, cultural resources protection, 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. For example, if a leak or spill of hazardous substances or petroleum products occurs from our pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and clean-up costs, which could affect materially our results of operations and cash flows. In addition, emissions controls and/or other regulatory or permitting mandates under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to

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us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.

The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment. Examples of these laws include:
the Clean Air Act and analogous state laws that impose obligations related to air emissions;
the Clean Water Act and analogous state laws that regulate discharge of wastewater from our facilities to state and federal waters;
the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal; and
the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

Various federal and state governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.

There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we gather, transport, process and store, air emissions related to our operations, past industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could increase significantly our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Additional information is included under Item 1, Business, under “Regulatory, Environmental and Safety Matters” and in Note O of the Notes to Consolidated Financial Statements in this Annual Report.

Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be affected materially and adversely by increased costs due to stricter pollution-control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. New or revised environmental regulations might also affect materially and adversely our products and activities, and federal and state agencies could impose additional safety requirements, all of which could affect materially our profitability.

We may face significant costs to comply with the regulation of GHG emissions.

GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of GHGs.

We believe it is likely that future governmental legislation and/or regulation may require us either to limit GHG emissions associated with our operations or to purchase allowances for such emissions. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations or when they will become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions, even though the technology is not currently available for efficient reduction, or to purchase allowances for such emissions. Emissions also could be taxed independently of limits.

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In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted.

Future legislation and/or regulation designed to reduce GHG emissions could make some of our activities uneconomic to maintain or operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with GHG regulatory requirements. Our future results of operations, cash flows or financial condition could be affected adversely if such costs are not recovered through regulated rates or otherwise passed on to our customers.

We continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit GHG emissions from our facilities, including methane. Although the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.

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

There is a belief that emissions of GHGs is 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. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition, through decreased revenues. 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. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornados and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could affect negatively 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 against GHG emitters, based on links drawn between GHG emissions and climate change.

If production from the Western Canada Sedimentary Basin remains flat or declines and demand for natural gas from the Western Canada Sedimentary Basin is greater in market areas other than the Midwestern United States, demand for our interstate transportation services could decrease significantly.

We depend on a portion of natural gas supply from the Western Canada Sedimentary Basin for some of our interstate pipelines, primarily Viking Gas Transmission and our investment in Northern Border Pipeline, that transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern United States market area. If demand for natural gas increases in Canada or other markets not served by our pipelines and/or production remains flat or declines, demand for transportation service on our interstate natural gas pipelines could decrease significantly, which could impact adversely our business, financial condition, results of operations and cash flows.

Our business is subject to regulatory oversight and potential penalties.

The natural gas industry historically has been subject to heavy state and federal regulation that extends to many aspects of our businesses and operations, including:
rates, operating terms and conditions of service;
the types of services we may offer our counterparties;
construction of new facilities;
the integrity, safety and security of facilities and operations;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
maintenance of accounts and records; and
relationships with affiliate companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of operations.

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We cannot guarantee that state or federal regulators will authorize any projects or acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions.

Failure to comply with all applicable state or federal statutes, rules and regulations and orders could bring substantial penalties and fines. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation.

Finally, we cannot give any assurance regarding future state or federal regulations under which we will operate or the effect such regulations could have on our business, financial condition, results of operations and cash flows.

Our regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.

Under the Natural Gas Act, which is applicable to interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to crude oil and natural gas liquids pipelines, our interstate transportation rates, which are regulated by the FERC, must be just and reasonable and not unduly discriminatory.

Under current policy, the FERC permits interstate pipelines that are subject to cost of service regulation to include an income tax allowance when calculating their regulated rates. The FERC’s income tax allowance policy has been the subject of challenge, and we cannot predict whether the FERC or a reviewing court will alter the existing policy. For example, on July 1, 2016, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision that calls into question a decade of FERC policy and precedent permitting regulated companies organized as pass-through entities for income tax purposes to include an allowance for income taxes in their rates. The court has remanded the case to the FERC to allow it to have an opportunity to provide a reasoned basis for its decision on income tax allowances for partnership pipelines. The FERC has issued a Notice of Inquiry seeking comments on proposed methods to adjust FERC’s income tax policy. Comments were due in March 2017, but additional comments continue to be filed. If the FERC’s policy were to change and if the FERC were to disallow a substantial portion of our pipelines’ income tax allowance, our regulated rates, and therefore our revenues and ability to make quarterly cash dividends to our shareholders, could be affected adversely.

The Tax Cuts and Jobs Act may reduce future tariff rates charged on our regulated pipelines. If in the future the FERC or other regulatory bodies were to require a refund of previously collected amounts on our regulated pipelines related to this tax legislation, then we may be required to record a regulatory liability through a one-time charge to expense, which could be material.

If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may affect adversely the rates charged for our services.

Finally, shippers may protest our pipeline tariff filings, and the FERC and or state regulatory agency may investigate tariff rates. Further, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to be in excess of a just and reasonable level. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. The FERC and/or state regulatory agencies also may investigate tariff rates absent shipper complaint. Any finding that approved rates exceed a just and reasonable level on the natural gas pipelines would take effect prospectively. In a complaint proceeding challenging natural gas liquids pipeline rates, if the FERC determines existing rates exceed a just and reasonable level, it could require the payment of reparations to complaining shippers for up to two years prior to the complaint. Any such action by the FERC or a comparable action by a state regulatory agency could affect adversely our pipeline businesses’ ability to charge rates that would cover future increases in costs, or even to continue to collect rates that cover current costs, and provide for a reasonable return. We can provide no assurance that our pipeline systems will be able to recover all of their costs through existing or future rates.

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

Federal, state and local agencies have jurisdiction over many of our activities, including regulation by the FERC of our interstate pipeline assets. The profitability of our regulated operations is dependent on our ability to pass through costs related

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to providing energy and other commodities to our customers by filing periodic rate cases. The regulatory environment applicable to our regulated businesses could impair our ability to recover costs historically absorbed by our customers.

We are unable to predict the impact that the future regulatory activities of these agencies will have on our operating results. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition, cash flows and results of operations.

Our regulated pipeline companies have recorded certain assets that may not be recoverable from our customers.

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated rate-making process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition 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.

Some of our nonregulated businesses have a higher level of risk than our regulated businesses.

Some of our nonregulated operations, which include our Natural Gas Gathering and Processing segment, much of our Natural Gas Liquids segment and a portion of our Natural Gas Pipelines segment, have a higher level of risk than our regulated operations, which includes a portion of our Natural Gas Pipelines segment and a portion of our Natural Gas Liquids segment. We expect to continue investing in natural gas and natural gas liquids projects and other related projects, some or all of which may involve nonregulated businesses or assets. These projects could involve risks associated with operational factors, such as competition and dependence on certain suppliers and customers; and financial, economic and political factors, such as rapid and significant changes in commodity prices, the cost and availability of capital and counterparty risk, including the inability of a counterparty, customer or supplier to fulfill a contractual obligation.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could affect operations and cash flows available for dividends to our shareholders.

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 midstream energy 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 midstream energy 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 our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could affect adversely our operations and cash flows available for dividends to our shareholders.

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

The workplaces associated with our facilities are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. The failure to comply with OSHA requirements or general industry standards, including keeping adequate records or monitoring 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 position, results of operations and cash flows.

Measurement adjustments on our pipeline system may be impacted materially by changes in estimation, type of commodity and other factors.

Natural gas and natural gas liquids measurement adjustments occur as part of the normal operating conditions associated with our assets. The quantification and resolution of measurement adjustments are complicated by several factors including: (1) the significant quantities (i.e., thousands) of measurement equipment that we use throughout our natural gas and natural gas liquids systems, primarily around our gathering and processing assets; (2) varying qualities of natural gas in the streams gathered and processed through our systems and the mixed nature of NGLs gathered and fractionated; and (3) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that can occur on our systems, which could negatively affect our business, financial position, results of operations and cash flows.


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Many of our pipeline and storage assets have been in service for several decades.

Many of our pipeline and storage assets are designed as long-lived assets. Over time the age of these assets could result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant increase in these expenditures, costs or liabilities could affect materially and adversely our results of operations, financial position or cash flows, as well as our ability to pay cash dividends.

We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint-venture participants agree.

We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets that may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100 percent) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint-venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

Moreover, any joint-venture owner generally may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners. Any such transaction could result in us being required to partner with different or additional parties.

We do not operate all of our joint-venture assets nor do we employ directly all of the persons responsible for providing us with administrative, operating and management services. This reliance on others to operate joint-venture assets and to provide other services could affect adversely our business and operating results.

We rely on others to provide administrative, operating and management services for certain of our joint-venture assets. We have a limited ability to control the operations and the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the provider. Some or all of these services may be outsourced to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. We may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our contracts and negatively affect our business and operating results. Our reliance on others to operate joint-venture assets, together with our limited ability to control certain costs, could harm our business and results of operations.

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.

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, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if a low commodity price environment persisted for a prolonged period, it could result in lower volumes delivered to our systems and impairments of our assets or equity-method investments. If we determine that an impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by consolidated debt to total capitalization.


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Our indebtedness and guarantee obligations could impair our financial condition and our ability to fulfill our obligations.

As of December 31, 2017, we had total indebtedness of $9.2 billion. Our indebtedness and guarantee obligations could have significant consequences. For example, they could:
make it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the senior notes;
impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
diminish our ability to withstand a downturn in our business or the economy;
require us to dedicate a substantial portion of our cash flows from operations to debt-service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, dividends or general corporate purposes;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
place us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer guarantee obligations.

We are not prohibited under the indentures governing the senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations summarized in the next paragraph. If we incur significant additional indebtedness, it could worsen the negative consequences mentioned above and could affect adversely our ability to repay our other indebtedness.

Our revolving debt agreements with banks contain provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, certain of these agreements contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Certain agreements also require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in the “Liquidity and Capital Resources” section of Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants.

If we are unable to meet our debt-service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the senior notes.

Our debt securities are effectively subordinated to claims of our secured creditors, and the guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although many of our operating subsidiaries have guaranteed such debt securities, the guarantees are subject to release under certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities effectively would be subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.

An event of default may require us to offer to repurchase certain of our and ONEOK Partners’ senior notes or may impair our ability to access capital.

The indentures governing certain of our and ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $15 million or more for certain of our senior notes or $100 million or more for certain of our senior notes and ONEOK Partners’ senior notes. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facility or seek alternative financing sources to finance the repurchases and repayment. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.

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A court may use fraudulent conveyance considerations to avoid or subordinate the cross guarantees of our and ONEOK Partners’ indebtedness.

Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. In connection with the closing of the Merger Transaction, ONEOK, ONEOK Partners and the Intermediate Partnership issued cross guarantees for our and ONEOK Partners’ senior notes, borrowings under the $2.5 Billion Credit Agreement and the Term Loan Agreement and our commercial paper. A court may use fraudulent conveyance laws to subordinate or avoid the cross guarantees of certain of our and ONEOK Partners’ indebtedness. It is also possible that under certain circumstances, a court could hold that the direct obligations of the guarantor could be superior to the obligations under that cross guarantee.

A court could avoid or subordinate the guarantor’s guarantee of our and ONEOK Partners’ indebtedness in favor of the guarantor’s other debts or liabilities to the extent that the court determined either of the following were true at the time the guarantor issued the guarantee:
the guarantor incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the guarantor contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or
the guarantor did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the guarantor:
–     was insolvent or rendered insolvent by reason of the issuance of the guarantee;
was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or
–     intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if:
the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation;
the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
it could not pay its debts as they become due.

Among other things, a legal challenge of the cross guarantees of our and ONEOK Partners’ indebtedness on fraudulent conveyance grounds may focus on the benefits, if any, realized by the guarantor as a result of our and ONEOK Partners’ issuance of such debt. To the extent the guarantor’s guarantee of our and ONEOK Partners’ indebtedness is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such debt would cease to have any claim in respect of the guarantee.

The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase.

We have a defined benefit pension plan for certain employees and postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries and changes in health care costs. For further discussion of our defined benefit pension plan, see Note L of the Notes to Consolidated Financial Statements in this Annual Report.

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

TAX RISKS

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

The positions taken in our federal and state tax return filings require significant judgments, use of estimates and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts

36


of deductible and taxable items. Despite management’s belief that our tax return positions are fully supportable, certain positions may be successfully challenged by federal, state and local jurisdictions.

The separation of ONE Gas could result in substantial tax liability.

We have received a private letter ruling from the IRS substantially to the effect that, for U.S. federal income tax purposes, the separation and certain related transactions qualify under Sections 355 and/or 368 of the U.S. Internal Revenue Code of 1986, as amended. If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution such as the separation satisfies certain requirements necessary to obtain tax-free treatment under section 355 of the Code. The private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the separation, we obtained an opinion of outside legal and tax counsel, substantially to the effect that, for U.S. federal income tax purposes, the separation and certain related transactions qualify under Sections 355 and 368 of the Code. The opinion relies on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion will not be binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.    PROPERTIES

A description of our properties is included in Item 1, Business.

ITEM 3.    LEGAL PROCEEDINGS

Information about our legal proceedings is included in Note O of the Notes to Consolidated Financial Statements in this Annual Report.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.


37


PART II

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

MARKET INFORMATION AND HOLDERS

Our common stock is listed on the NYSE under the trading symbol “OKE.” The corporate name ONEOK is used in newspaper stock listings. The following table sets forth the high and low closing prices of our common stock for the periods indicated:
 
 
Year Ended
December 31, 2017
 
Year Ended
December 31, 2016
 
 
High
 
Low
 
High
 
Low
First Quarter
 
$
58.83

 
$
52.20

 
$
30.82

 
$
19.62

Second Quarter
 
$
56.33

 
$
47.41

 
$
47.45

 
$
28.37

Third Quarter
 
$
56.88

 
$
50.36

 
$
51.39

 
$
42.99

Fourth Quarter
 
$
56.70

 
$
50.02

 
$
59.03

 
$
46.44


At February 22, 2018, there were 13,480 holders of record of our 410,634,227 outstanding shares of common stock.

DIVIDENDS

The following table sets forth the quarterly dividends per share paid on our common stock in the periods indicated:
 
 
Years Ended December 31,
 
 
2017
 
2016
 
2015
First Quarter
 
$
0.615

 
$
0.615

 
$
0.605

Second Quarter
 
0.615

 
0.615

 
0.605

Third Quarter
 
0.745

 
0.615

 
0.605

Fourth Quarter
 
0.745

 
0.615

 
0.615

Total
 
$
2.72

 
$
2.46

 
$
2.43


In February 2018, we paid a quarterly dividend of $0.77 per share ($3.08 per share on an annualized basis) to shareholders of record as of January 29, 2018.

EMPLOYEE STOCK AWARD PROGRAM

Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share, and one additional share of common stock when the per-share closing price of our common stock on the NYSE was at or above each one dollar increment above $13. No shares were issued to employees under this program during 2017, 2016 or 2015.

The total number of shares of our common stock available for issuance under this program is 900,000. The shares issued under this program have not been registered under the Securities Act, in reliance upon the position taken by the SEC (see Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not require registration under the Securities Act. See Note K of the Notes to Consolidated Financial Statements in this Annual Report for additional information about the employee stock award program and other equity compensation plans.


38


PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock with the S&P 500 Index, the Alerian Energy Infrastructure Index, the Alerian MLP Index and a ONEOK Peer Group during the period beginning on December 31, 2012, and ending on December 31, 2017.

The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.

Value of $100 Investment, Assuming Reinvestment of Distributions/Dividends,
at December 31, 2012, and at the End of Every Year Through December 31, 2017.

a2017performancechartrevised.jpg
 
 
Cumulative Total Return
 
 
Years Ended December 31,
 
 
2013
 
2014
 
2015
 
2016
 
2017
 
 
 
 
 
 
 
 
 
 
 
ONEOK, Inc.
 
$
149.68

 
$
141.70

 
$
74.52

 
$
185.49

 
$
181.67

S&P 500 Index
 
$
132.36

 
$
150.43

 
$
152.51

 
$
170.70

 
$
207.92

ONEOK Peer Group (a)
 
$
140.73

 
$
167.47

 
$
104.89

 
$
132.17

 
$
116.57

Alerian Energy Infrastructure Index (b)
 
$
130.12

 
$
148.17

 
$
93.19

 
$
133.34

 
$
133.99

Alerian MLP Index
 
$
127.60

 
$
133.68

 
$
90.21

 
$
106.55

 
$
99.72

(a) - The ONEOK Peer Group is comprised of the following companies: Boardwalk Pipeline Partners, LP; Buckeye Partners, L.P.; DCP Midstream, LP; Enbridge Energy Partners, L.P.; Energy Transfer Partners, L.P.; EnLink Midstream Partners, LP; Enterprise Products Partners L.P.; Kinder Morgan, Inc.; Magellan Midstream Partners, L.P.; MPLX LP; NuStar Energy L.P.; Plains All American Pipeline, L.P.; Targa Resources Corp.; and The Williams Companies, Inc.
(b) - The Alerian Energy Infrastructure Index measures the composite performance of more than 30 North American energy infrastructure companies who are engaged in midstream activities involving energy commodities. Following the Merger Transaction, we believe this index is a better benchmark for comparison than the Alerian MLP Index. We have included both indices in this transition year.


39


ITEM 6.    SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for the periods indicated:
 
 
Years Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(Millions of dollars, except per share data)
Revenues
 
$
12,173.9

 
$
8,920.9

 
$
7,763.2

 
$
12,195.1

 
$
11,871.9

Income from continuing operations
 
$
593.5

 
$
745.6

 
$
385.3

 
$
668.7

 
$
589.1

Income from continuing operations attributable to ONEOK
 
$
387.8

 
$
354.1

 
$
251.1

 
$
319.7

 
$
278.7

Net income attributable to ONEOK
 
$
387.8

 
$
352.0

 
$
245.0

 
$
314.1

 
$
266.5

Total assets
 
$
16,845.9

 
$
16,138.8

 
$
15,446.1

 
$
15,261.8

 
$
17,692.2

Long-term debt, including current maturities
 
$
8,524.3

 
$
8,330.6

 
$
8,434.2

 
$
7,160.8

 
$
7,715.0

Earnings per share - continuing operations
 
 
 
 

 
 

 
 

 
 

Basic
 
$
1.30

 
$
1.68

 
$
1.19

 
$
1.53

 
$
1.35

Diluted
 
$
1.29

 
$
1.67

 
$
1.19

 
$
1.52

 
$
1.33

Earnings per share - total
 
 
 
 

 
 

 
 

 
 

Basic
 
$
1.30

 
$
1.67

 
$
1.17

 
$
1.50

 
$
1.29

Diluted
 
$
1.29

 
$
1.66

 
$
1.16

 
$
1.49

 
$
1.27

Dividends declared per share of common stock
 
$
2.72

 
$
2.46

 
$
2.43

 
$
2.125

 
$
1.48


In the fourth quarter 2017, we recorded a one-time noncash charge to net income through income tax expense of $141.3 million, related to revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act. For more information, see Note M in the Notes to the Consolidated Financial Statements.

Also in 2017, we incurred a $20.0 million noncash expense related to our Series E Preferred Stock contribution to the Foundation and operating costs related to the Merger Transaction of $30.0 million.

We recorded noncash impairment charges of $20.2 million, $264.3 million and $76.4 million in 2017, 2015 and 2014, respectively.

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

The following discussion and analysis should be read in conjunction with Part I, Item 1, Business, our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.

RECENT DEVELOPMENTS

Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for additional information.

Merger Transaction - On June 30, 2017, we completed the acquisition of all of the outstanding common units of ONEOK Partners that we did not already own at a fixed exchange ratio of 0.985 of a share of our common stock for each ONEOK Partners common unit. We issued 168.9 million shares of our common stock to third-party common unitholders of ONEOK Partners in exchange for all of the 171.5 million outstanding common units of ONEOK Partners that we previously did not own. As a result of the completion of the Merger Transaction, common units of ONEOK Partners are no longer publicly traded. The change in our ownership interest resulting from the Merger Transaction was accounted for as an equity transaction, and no gain or loss was recognized in our Consolidated Statement of Income.

Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable segments. Our consolidated earnings were approximately 90 percent fee-based in 2017, and we expect the same for 2018. In 2017, our Natural Gas Gathering and Processing segment’s fee revenues averaged 86 cents per MMBtu, compared with an average of 76 cents and 44 cents per MMBtu in the same periods in 2016 and 2015, respectively, due to our contract restructuring efforts to mitigate commodity price risk and increasing volumes on those contracts with higher contracted fees.

40


Volumes gathered and processed increased across our asset footprint in our Natural Gas Gathering and Processing segment in 2017, compared with 2016, as producers experienced improved drilling economics, continued improvements in production due to enhanced completion techniques and more efficient drilling rigs. We connected six third-party natural gas processing plants in our Natural Gas Liquids segment in 2017, which, along with increased supply and ethane recovery, contributed to higher gathered NGL volumes in 2017, compared with 2016. We expect additional NGL volume growth as these plants continue to increase production and recently announced plant connections come online. Our fee-based transportation services in our Natural Gas Pipelines segment increased in 2017, compared with 2016, due primarily to higher firm transportation capacity contracted from our WesTex pipeline expansion.

Growth Projects - Increased producer activity and volume growth across our assets have increased demand for midstream infrastructure. We are responding to this growing demand by constructing assets to meet the needs of natural gas processors and producers across our asset footprint, including the Williston, DJ, Permian and Powder River Basins and the STACK and SCOOP areas. Since June 2017, we have announced approximately $4.2 billion of additional growth projects supported by long-term primarily fee-based contracts, minimum volume commitments and acreage dedications to serve the expected growth and needs of natural gas processors and producers. These projects are outlined in the table below:
Project
Scope
Approximate Costs (a)
Completion Date
 
 
(in millions)
 
Additional STACK processing capacity
200 MMcf/d processing capacity through long-term processing services agreement

$40
December 2017
 
30-mile natural gas gathering pipeline
 
 
WTLPG pipeline expansion
120-mile pipeline lateral extension with capacity of 110 MBbl/d in the Permian Basin
$160 (b)
Third Quarter 2018
 
Supported by long-term dedicated NGL production from two planned third-party natural gas processing plants
 
 
Sterling III pipeline expansion and Arbuckle connection
60 MBbl/d NGL pipeline expansion
$130
Fourth Quarter 2018
Increases capacity to 250 MBbl/d
 
 
 
Includes additional NGL gathering system expansions
 
 
 
Supported by long-term third-party contract
 
 
Canadian Valley expansion
200 MMcf/d processing plant expansion in the STACK area and related gathering infrastructure
$160
Fourth Quarter 2018
 
Increases capacity to 400 MMcf/d
 
 
 
20 MBbl/d additional NGL volume
 
 
 
Supported by acreage dedications, long-term primarily fee-based contracts and minimum volume commitments
 
 
Elk Creek pipeline and related infrastructure
900-mile NGL pipeline from the Williston Basin to the Mid-Continent region with initial capacity of 240 MBbl/d, and related infrastructure
$1,400
Fourth Quarter 2019
 
Anchored by by long-term contracts supported primarily by minimum volume commitments
 
 
 
Expansion capability up to 400 MBbl/d with additional pump facilities
 
 
Arbuckle II pipeline
530-mile NGL pipeline from the STACK area to Mont Belvieu, Texas, with initial capacity up to 400 MBbl/d, and related infrastructure
$1,360
First Quarter 2020
 
Supported by long-term contracts

 
 
 
Expansion capability up to 1,000 MBbl/d
 
 
MB-4 fractionator and related infrastructure
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu
$575
First Quarter 2020
 
Fully contracted with long-term contracts
 
 
Demicks Lake plant and related infrastructure
200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin
$400
Fourth Quarter 2019
 
Supported by acreage dedications with long-term primarily fee-based contracts
 
 
Total
 
$4,225
 
(a) Excludes capitalized interest/AFUDC.
(b) Represents our portion of the total project cost of $200 million.

41



Ethane Opportunity - Ethane rejection levels across our system averaged more than 150 MBbl/d in 2017, which is slightly lower than 2016 despite an increase in overall NGL supply volumes. We expect ethane rejection on our system to decrease to approximately 70 MBbl/d by the end of 2018, initially in regions closest to market centers such as the Permian Basin and Mid-Continent region, as ethylene producers complete their expansion projects and NGL exporters increase their export volumes. We expect this increase in ethane recovery to have a favorable impact on our financial results.

Income Taxes - The Tax Cuts and Jobs Act makes extensive changes to the U.S. tax laws and includes provisions that, beginning in 2018, reduce the U.S. corporate tax rate to 21 percent from 35 percent, increase expensing for capital investment, limit the interest deduction, and limit the use of net operating losses to offset future taxable income. We consider the aggregate of these changes as positive to our business and continue to expect that we will not pay federal cash income taxes through at least 2021. As a result of the enactment of the Tax Cuts and Jobs Act, we recorded a one-time noncash charge to net income through income tax expense of $141.3 million in the fourth quarter 2017, related to revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards.

The Tax Cuts and Jobs Act may also impact future tariff rates charged on our regulated pipelines. The tariff rates charged on substantially all of our regulated pipelines have been established through shipper specific negotiation, discounts and negotiated settlements with rate moratoriums, which do not ascribe any specific cost of service elements, including income taxes. As such, we expect future tariff rate changes, if any, related to the change in U.S. corporate tax rate to be established prospectively over time on a similar negotiated basis. If in the future the FERC or other regulatory bodies were to require a refund of previously collected amounts on our regulated pipelines, then we may record a regulatory liability through a one-time charge to expense. For more information, see Note M in the Notes to the Consolidated Financial Statements.

Equity Issuances - In January 2018, we completed an underwritten public offering of 21.9 million shares of our common stock at a public offering price of $54.50 per share, generating net proceeds of $1.2 billion. We used the net proceeds from this offering to fund capital expenditures and for general corporate purposes, which included repaying a portion of our outstanding indebtedness. We have satisfied our expected equity financing needs through 2018 and well into 2019.

In July 2017, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate amount of $1 billion. The program allows us to offer and sell our common stock at prices we deem appropriate through a sales agent. Sales of our common stock may be made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. During the year ended December 31, 2017, we sold 8.4 million shares of common stock through our “at-the-market” equity program that resulted in net proceeds of $448.3 million.

Dividends - During 2017, we paid dividends totaling $2.72 per share, an increase of 11 percent from the $2.46 per share paid in 2016. In February 2018, we paid a quarterly dividend of $0.77 per share ($3.08 per share on an annualized basis), an increase of 25 percent compared with the same period in the prior year. We expect 85 to 95 percent of our 2018 dividend payments to investors to be a return of capital. Our dividend growth is due to the increase in cash flows resulting from the Merger Transaction and the continued growth of our operations.


42


FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:
 
 
 
 
 
 
 
 
Variances
 
Variances
 
 
Years Ended December 31,
 
2017 vs. 2016
 
2016 vs. 2015
Financial Results
 
2017
 
2016
 
2015
 
Increase (Decrease)
 
Increase (Decrease)
 
 
(Millions of dollars)
Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity sales
 
$
9,862.7

 
$
6,858.5

 
$
6,098.3

 
$
3,004.2

 
44
 %
 
$
760.2

 
12
 %
Services
 
2,311.2

 
2,062.4

 
1,665.0

 
248.8

 
12
 %
 
397.4

 
24
 %
Total revenues
 
12,173.9

 
8,920.9

 
7,763.3

 
3,253.0

 
36
 %
 
1,157.6

 
15
 %
Cost of sales and fuel (exclusive of items shown separately below)
 
9,538.0

 
6,496.1

 
5,641.1

 
3,041.9

 
47
 %
 
855.0

 
15
 %
Operating costs
 
833.6

 
757.1

 
693.3

 
76.5

 
10
 %
 
63.8

 
9
 %
Depreciation and amortization
 
406.3

 
391.6

 
354.6

 
14.7

 
4
 %
 
37.0

 
10
 %
Impairment of long-lived assets
 
16.0

 

 
83.7

 
16.0

 
*

 
(83.7
)
 
(100
)%
Gain on sale of assets
 
(0.9
)
 
(9.6
)
 
(5.6
)
 
(8.7
)
 
(91
)%
 
4.0

 
71
 %
Operating income
 
$
1,380.9

 
$
1,285.7

 
$
996.2

 
$
95.2

 
7
 %
 
$
289.5

 
29
 %
Equity in net earnings from investments
 
$
159.3

 
$
139.7

 
$
125.3

 
$
19.6

 
14
 %
 
$
14.4

 
11
 %
Impairment of equity investments
 
$
(4.3
)
 
$

 
$
(180.6
)
 
$
4.3

 
*

 
$
(180.6
)
 
(100
)%
Interest expense, net of capitalized interest
 
$
(485.7
)
 
$
(469.7
)
 
$
(416.8
)
 
$
16.0

 
3
 %
 
$
52.9

 
13
 %
Net income
 
$
593.5

 
$
743.5

 
$
379.2

 
$
(150.0
)
 
(20
)%
 
$
364.3

 
96
 %
Net income attributable to noncontrolling interests
 
$
205.7

 
$
391.5

 
$
134.2

 
$
(185.8
)
 
(47
)%
 
$
257.3

 
*

Net income attributable to ONEOK
 
$
387.8

 
$
352.0

 
$
245.0

 
$
35.8

 
10
 %
 
$
107.0

 
44
 %
Adjusted EBITDA
 
$
1,986.9

 
$
1,849.9

 
$
1,579.5

 
$
137.0

 
7
 %
 
$
270.4

 
17
 %
Capital expenditures
 
$
512.4

 
$
624.6

 
$
1,188.3

 
$
(112.2
)
 
(18
)%
 
$
(563.7
)
 
(47
)%
* Percentage change is greater than 100 percent or is not meaningful.
See reconciliation of income from continuing operations to adjusted EBITDA in the “Adjusted EBITDA” section.

Due to the nature of our contracts, changes in commodity prices and sales volumes affect both commodity sales and cost of sales and fuel in our Consolidated Statements of Income and, therefore, the impact is largely offset between the two line items.

2017 vs. 2016 - Operating income and adjusted EBITDA increased primarily as a result of the following:
Natural gas and NGL volume growth in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments;
Restructured contracts resulting in higher fee revenues from increased average fee rates and a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts in our Natural Gas Gathering and Processing segment;
Higher optimization and marketing earnings due to higher optimization volumes and wider location price differentials in our Natural Gas Liquids segment; and
Higher firm demand charge contracted capacity in our Natural Gas Pipelines segment; offset partially by
Higher labor and employee-related costs associated with benefit plans across all three of our segments, labor costs associated with the growth of operations in our Natural Gas Gathering and Processing segment, routine maintenance projects in our Natural Gas Liquids and Natural Gas Pipelines segments and higher ad valorem taxes in our Natural Gas Liquids segment;
Merger Transaction costs in 2017 of $30.0 million; and
Lower net realized natural gas prices and condensate prices in our Natural Gas Gathering and Processing segment.

Operating income was also impacted in 2017 by $16.0 million of noncash impairment charges related to nonstrategic long-lived assets in our Natural Gas Gathering and Processing segment.


43


Net income was further impacted by a one-time noncash charge through income tax expense of $141.3 million, related to revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act and $20.0 million of noncash expenses related to our Series E Preferred Stock contribution to the Foundation.

Equity in net earnings from investments increased due primarily to higher firm transportation revenues related to Roadrunner’s Phase II capacity, which was placed in service in October 2016. Roadrunner is fully subscribed under long-term firm demand charge contracts.

In 2017, we recorded $4.3 million of noncash impairment charges related to a nonstrategic equity investment in our Natural Gas Gathering and Processing segment.

Net income attributable to noncontrolling interests decreased as a result of the Merger Transaction. Prior to June 30, 2017, we and our subsidiaries owned all of the general partner interest, which included incentive distribution rights, and a portion of the limited partner interest, which together represented a 41.2 percent ownership interest in ONEOK Partners. The earnings of ONEOK Partners that are attributed to its units held by the public prior to the Merger Transaction are reported as “Net income attributable to noncontrolling interest” in our accompanying Consolidated Statements of Income until June 30, 2017.

Capital expenditures decreased due primarily to growth projects placed in service in 2016 in our Natural Gas Gathering and Processing segment.

2016 vs. 2015 - Operating income and adjusted EBITDA increased due primarily as a result of the following:
Higher natural gas and NGL volumes from our completed capital-growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and from new plant connections and increased ethane recovery in our Natural Gas Liquids segment;
Higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment; and
Higher firm demand charge volumes contracted in our Natural Gas Pipelines segment; offset partially by
Lower net realized NGL and natural gas prices in our Natural Gas Gathering and Processing segment; and
Higher labor costs associated with the growth of our operations in our Natural Gas Gathering and Processing segment and higher employee-related costs associated with incentive and medical benefit plans in all three of our segments.

Operating income was also impacted by higher depreciation expense due to projects completed in 2016 and 2015 and noncash expenses of a share-based deferred compensation plan due primarily to the increase of ONEOK’s share price in 2016.

Equity in net earnings from investments increased due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline and higher firm transportation revenues on Northern Border Pipeline and Roadrunner, offset partially by lower equity earnings from our Powder River Basin equity investments.

Interest expense increased primarily as a result of higher interest costs incurred associated with our $500 million debt issuance in August 2015 and lower capitalized interest due to lower spending on capital-growth projects.

Net income attributable to noncontrolling interests, which reflects primarily the portion of ONEOK Partners that we did not own, increased in 2016, compared with 2015, due primarily to higher earnings at ONEOK Partners, including noncash impairment charges in 2015.

Capital expenditures decreased due to projects placed in service in 2016 and 2015, spending reductions to align with customer needs and lower well connect activities in our Natural Gas Gathering and Processing segment due to a reduction in drilling and completion activity.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.

Natural Gas Gathering and Processing

Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas, including the Bakken Shale and Three Forks formations in the Williston Basin and the STACK and SCOOP areas, that we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. Nearly all of the new natural gas production is from horizontally drilled wells in nonconventional resource areas. These wells tend to produce volumes at higher

44


initial production rates resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. These wells are expected to have long productive lives.

In 2017, we announced plans to expand our Canadian Valley natural gas processing facility to 400 MMcf/d from 200 MMcf/d and related gathering infrastructure in the STACK area. This project is expected to be complete by the end of 2018 at a cost of approximately $160 million, excluding capitalized interest, and is supported by long-term primarily fee-based contracts, minimum volume commitments and acreage dedications.

In February 2018, we announced plans to construct the 200 MMcf/d Demicks Lake natural gas processing plant and related infrastructure in the core of the Williston Basin. This project is expected to be complete in the fourth quarter 2019 at a cost of $400 million, excluding capitalized interest, and is supported by long-term primarily fee-based contracts and acreage dedications.

In 2015, 2016 and 2017 we completed the following projects:
Completed Projects
Location
Capacity
Approximate
Costs (a)
Completion Date
 
 
 
(In millions)
 
Lonesome Creek processing plant and infrastructure
Williston Basin
200 MMcf/d
$600
November 2015
Sage Creek infrastructure
Powder River Basin
Various
$35
December 2015
Natural gas compression
Williston Basin
100 MMcf/d
$75
December 2015
Bear Creek processing plant and infrastructure
Williston Basin
80 MMcf/d
$240
August 2016
Stateline de-ethanizers
Williston Basin
26 MBbl/d
$85
September 2016
Natural gas gathering pipeline and infrastructure
STACK
200 MMcf/d
$40
December 2017
(a) Excludes capitalized interest.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated.
 
 
 
 
 
 
 
 
Variances
 
Variances
 
 
Years Ended December 31,
 
2017 vs. 2016
 
2016 vs. 2015
Financial Results
 
2017
 
2016
 
2015
 
Increase (Decrease)
 
Increase (Decrease)
 
 
(Millions of dollars)
NGL sales
 
$
1,208.0

 
$
586.0

 
$
554.3

 
$
622.0

 
*

 
$
31.7

 
6
 %
Condensate sales
 
103.2

 
58.3

 
55.1

 
44.9

 
77
 %
 
3.2

 
6
 %
Residue natural gas sales
 
856.3

 
690.6

 
839.5

 
165.7

 
24
 %
 
(148.9
)
 
(18
)%
Gathering, compression, dehydration and processing fees and other revenue
 
859.1

 
716.7

 
388.2

 
142.4

 
20
 %
 
328.5

 
85
 %
Cost of sales and fuel (exclusive of depreciation and items shown separately below)
 
(2,216.4
)
 
(1,331.5
)
 
(1,265.6
)
 
884.9

 
66
 %
 
65.9

 
5
 %
Operating costs
 
(309.5
)
 
(285.6
)
 
(272.4
)
 
23.9

 
8
 %
 
13.2

 
5
 %
Equity in net earnings from investments, excluding noncash impairment charges
 
12.1

 
10.7

 
17.9

 
1.4

 
13
 %
 
(7.2
)
 
(40
)%
Other
 
5.7

 
1.6

 
1.6

 
4.1

 
*

 

 
 %
Adjusted EBITDA
 
$
518.5

 
$
446.8

 
$
318.6

 
$
71.7

 
16
 %
 
$
128.2

 
40
 %
Impairment of equity investments
 
$
(4.3
)
 
$

 
$
(180.6
)
 
$
4.3

 
*

 
$
(180.6
)
 
(100
)%
Capital expenditures
 
$
284.2

 
$
410.5

 
$
887.9

 
$
(126.3
)
 
(31
)%
 
$
(477.4
)
 
(54
)%
* Percentage change is greater than 100 percent or is not meaningful.
See reconciliation of income from continuing operations to adjusted EBITDA in the “Adjusted EBITDA” section.

Due to the nature of our contracts, changes in commodity prices and sales volumes affect commodity sales and cost of sales and fuel and, therefore, the impact is largely offset between these line items.


45


2017 vs. 2016 - Adjusted EBITDA increased $71.7 million, primarily as a result of the following:
an increase of $66.0 million due primarily to natural gas volume growth in the Williston Basin and the STACK and SCOOP areas, offset partially by natural production declines and the impact of severe winter weather in the first quarter 2017; and
an increase of $44.0 million due primarily to restructured contracts resulting in higher fee revenues from increased average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts; offset partially by
an increase of $23.9 million in operating costs due primarily to increased labor and employee-related costs associated with our benefit plans and the growth of our operations;
a decrease of $11.9 million due primarily to lower realized natural gas and condensate prices; and
a decrease of $8.0 million due to contract settlements in 2016.

Capital expenditures decreased due to growth projects placed in service in 2016.

See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.

2016 vs. 2015 - Adjusted EBITDA increased $128.2 million, primarily as a result of the following:
an increase of $144.3 million due primarily to restructured contracts resulting in higher fee revenues from increased average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts;
an increase of $92.2 million due primarily to natural gas volume growth in the Rocky Mountain region, offset partially by volume declines in the Mid-Continent region and the impact of weather in the Williston Basin in December 2016; and
an increase of $8.0 million due to contract settlements; offset partially by
a decrease of $91.9 million due primarily to lower net realized NGL and natural gas prices;
an increase of $13.2 million in operating costs due primarily to increased labor related to the growth of our operations resulting from completed capital-growth projects and higher employee-related costs associated with incentive and medical benefit plans;
a decrease of $7.2 million due to lower equity earnings primarily related to our Powder River Basin equity investments; and
a decrease of $4.0 million due primarily to increased ethane recovery to maintain downstream NGL product specifications.

Capital expenditures decreased due to projects placed in service, spending reductions to align with customer needs and lower well connect activities due to a reduction in drilling and completion activity.
 
 
Years Ended December 31,
Operating Information (a)
 
2017
 
2016
 
2015
Natural gas gathered (BBtu/d)
 
2,211

 
2,034

 
1,932

Natural gas processed (BBtu/d) (b)
 
2,056

 
1,882

 
1,687

NGL sales (MBbl/d)
 
187

 
156

 
129

Residue natural gas sales (BBtu/d)
 
896

 
865

 
853

Realized composite NGL net sales price ($/gallon) (c) (d)
 
$
0.22

 
$
0.23

 
$
0.34

Realized condensate net sales price ($/Bbl) (c) (e)
 
$
35.22

 
$
38.31

 
$
37.81

Realized residue natural gas net sales price ($/MMBtu) (c) (e)
 
$
2.48

 
$
2.80

 
$
3.64

Average fee rate ($MMBtu)
 
$
0.86

 
$
0.76

 
$
0.44

(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.
(c) - Includes the impact of hedging activities on our equity volumes.
(d) - Net of transportation and fractionation costs.
(e) - Net of transportation costs.

Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales increased in 2017, compared with 2016, due to the completion of growth projects and new supply in the Williston Basin and the STACK and SCOOP areas, offset partially by natural production declines on existing wells and the impact of severe winter weather in the first quarter 2017.


46


Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales increased in 2016, compared with 2015, due to the completion of capital-growth projects in the Williston Basin, offset partially by natural gas volume declines in the Mid-Continent region.

The quantity and composition of NGLs and natural gas are expected to continue to change with anticipated production increases across our supply basins, new processing plants placed in service and increased ethane recovery.

Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Impairment Charges - In the third quarter 2017, following a review of nonstrategic assets for potential divestiture, we recorded $16.0 million of noncash impairment charges related to certain nonstrategic gathering and processing assets located in North Dakota and $4.3 million of noncash impairment charges related to a nonstrategic equity investment located in Oklahoma.

In 2015, due to the continued and greater than expected decline in volumes gathered in the dry natural gas area of the Powder River Basin, we evaluated our investments in this area. We recorded a $63.5 million noncash impairment charge to long-lived assets for our coal-bed methane natural gas gathering system, which we shut down in 2016. We reviewed our Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek Gathering Company equity investments and recorded noncash impairment charges of $180.6 million in 2015.

In 2015, we also recorded a noncash impairment charge of $10.2 million related to a previously idled asset, as our expectation for future use of the asset changed.

Natural Gas Liquids

Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region into the Permian Basin. Crude oil, natural gas and NGL production from this activity; higher petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital investments to expand our infrastructure to bring these commodities from supply basins to market.

Our Natural Gas Liquids segment invests in NGL-related projects to accommodate the transportation, fractionation and storage of NGL supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers and to meet increasing petrochemical industry and NGL export demand in the Gulf Coast.

We have the following projects announced or under construction:
Project in Progress
Location
Capacity
Approximate
Costs (a)
Completion Date
 
 
 
(In millions)
 
WTLPG pipeline expansion (b)
Permian Basin
110 MBbl/d
$200
Third Quarter 2018
Sterling III pipeline expansion and Arbuckle
connection
STACK and SCOOP
60 MBbl/d
$130
Fourth Quarter 2018
Elk Creek pipeline and related infrastructure
Rocky Mountain Region
240 MBbl/d
$1,400
Fourth Quarter 2019
Arbuckle II pipeline and related infrastructure
STACK and SCOOP
400 MBbl/d
$1,360
First Quarter 2020
MB-4 fractionator and related infrastructure
Gulf Coast
125 MBbl/d
$575
First Quarter 2020
Total
 
 
$3,665
 
(a) Excludes capitalized interest/AFUDC.
(b) A joint venture, in which we own an 80 percent interest. Approximate costs represent total project costs.

In January 2018, we announced plans to construct the new Elk Creek pipeline and related infrastructure to transport NGLs from the Rocky Mountain region, which includes the Williston, DJ and Powder River Basins, to our existing Mid-Continent NGL facilities. The project includes construction of an approximately 900-mile, 20-inch diameter pipeline that is expected to be completed by the end of 2019 and will have the capacity to transport up to 240 MBbl/d of unfractionated NGLs to Bushton, Kansas. The pipeline will have the capability to be expanded to 400 MBbl/d with additional pump facilities. This project is

47


anchored by long-term contracts with terms ranging between 10 to 15 years totaling approximately 100 MBbl/d, which is supported primarily by minimum volume commitments.

In February 2018, we announced plans to construct the new Arbuckle II pipeline and related infrastructure project, with initial capacity to transport 400 MBbl/d of NGLs originating across our supply basins to our storage and fractionation facilities in Mont Belvieu, Texas. The approximately 530-mile pipeline is expandable to 1,000 MBbl/d with additional pump facilities. This project is anchored by long-term contracts with terms ranging from 10 to 20 years and is more than 50 percent contracted.

In February 2018, we announced plans to construct the new MB-4 fractionation facility and related infrastructure, which includes additional NGL storage capacity in Mont Belvieu, Texas. Our current available fractionation capacity in the Gulf Coast region is not sufficient for the expected increase in NGL volumes from supply growth and our pipeline projects discussed above. The fractionator will have a capacity of 125 MBbl/d, is anchored by long-term contracts with terms ranging from 10 to 20 years and is fully contracted.

In 2015 and 2016 we completed the following projects:
Completed Projects
Location
Capacity
Approximate
Costs (a)
Completion Date
 
 
 
(In millions)
 
NGL Pipeline and Hutchinson Fractionator
infrastructure
Mid-Continent Region
95 miles
$120
April 2015
Bear Creek NGL infrastructure
Williston Basin
40 miles
$45
August 2016
(a) Excludes capitalized interest/AFUDC.

We continue to evaluate opportunities to increase the capacity of our gathering and fractionation assets or construct new assets to connect supply growth from the Williston Basin, Mid-Continent and Permian Basin with end-use markets. The Elk Creek pipeline project replaces our previously announced expansion of the Bakken NGL Pipeline.

In 2017, we connected one third-party natural gas processing plant to our NGL system in the Rocky Mountain region, two in the Permian Basin and three in the STACK and SCOOP areas of the Mid-Continent region.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated.
 
 
 
 
 
 
 
 
Variances
 
Variances
 
 
Years Ended December 31,
 
2017 vs. 2016
 
2016 vs. 2015
Financial Results
 
2017
 
2016
 
2015
 
Increase (Decrease)
 
Increase (Decrease)
 
 
(Millions of dollars)
NGL and condensate sales
 
$
8,998.9

 
$
6,152.5

 
$
5,200.8

 
$
2,846.4

 
46
%
 
$
951.7

 
18
 %
Exchange service revenues
 
1,430.3

 
1,327.5

 
1,196.9

 
102.8

 
8
%
 
130.6

 
11
 %
Transportation and storage revenues
 
197.0

 
195.7

 
182.0

 
1.3

 
1
%
 
13.7

 
8
 %
Cost of sales and fuel (exclusive of depreciation and items shown separately below)
 
(9,176.5
)
 
(6,321.4
)
 
(5,328.3
)
 
2,855.1

 
45
%
 
993.1

 
19
 %
Operating costs
 
(359.8
)
 
(327.6
)
 
(314.5
)
 
32.2

 
10
%
 
13.1

 
4
 %
Equity in net earnings from investments
 
59.9

 
54.5

 
38.7

 
5.4

 
10
%
 
15.8

 
41
 %
Other
 
5.1

 
(1.6
)
 
(3.3
)
 
6.7

 
*

 
1.7

 
52
 %
Adjusted EBITDA
 
$
1,154.9

 
$
1,079.6

 
$
972.3

 
$
75.3

 
7
%
 
$
107.3

 
11
 %
Capital expenditures
 
$
114.3

 
$
105.9

 
$
226.1

 
$
8.4

 
8
%
 
$
(120.2
)
 
(53
)%
* Percentage change is greater than 100 percent.
See reconciliation of income from continuing operations to adjusted EBITDA in the “Adjusted EBITDA” section.

Due to the nature of our contracts, changes in commodity prices and sales volumes affect commodity sales and cost of sales and fuel, and therefore the impact is largely offset between these line items.


48


2017 vs. 2016 - Adjusted EBITDA increased $75.3 million, primarily as a result of the following:
an increase of $81.5 million in exchange services due primarily to increased supply volumes in the Williston Basin, the STACK and SCOOP areas and the Powder River Basin and ethane recovery; offset partially by lower volumes in the Granite Wash and Barnett Shale and reduced volumes related to Hurricane Harvey;
an increase of $13.5 million in our optimization and marketing activities due primarily to higher optimization volumes and wider location price differentials; and
an increase of $5.4 million in equity in net earnings from investments due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline and higher volumes and increased ethane recovery from plants connected to Overland Pass Pipeline; offset partially by
an increase of $32.2 million in operating costs due primarily to routine maintenance projects, higher ad valorem taxes, higher labor and employee-related costs associated with our benefit plans and additional operating costs related to Hurricane Harvey.

Capital expenditures increased due primarily to increased routine growth and maintenance projects.

2016 vs. 2015 - Adjusted EBITDA increased $107.3 million, primarily as a result of the following:
an increase of $90.0 million in exchange services due to increased exchange services volumes from recently connected natural gas processing plants primarily in the Williston Basin, increased Mid-Continent volumes gathered in the STACK and SCOOP areas and increased volumes resulting from increased ethane recovery primarily from the Williston Basin to maintain downstream NGL product specifications; offset partially by lower volumes and rates on the West Texas LPG system and the impact of weather on our system in December 2016;
an increase of $15.8 million in equity in net earnings from investments due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline;
an increase of $13.8 million in transportation and storage services due to higher storage and terminaling revenue in the Gulf Coast and revenues from minimum volume obligations on our distribution pipelines;
an increase of $8.4 million related to higher isomerization volumes resulting from wider NGL price differentials between normal butane and iso-butane; and
an increase of $4.3 million due to the impact of operational measurement gains in 2016 and operational measurement losses in 2015; offset partially by
a decrease of $13.8 million in our optimization and marketing activities, which resulted from a $20.0 million decrease due primarily to narrower product price differentials, offset partially by a $6.2 million increase due primarily to higher optimization volumes; and
an increase of $13.1 million in operating costs due primarily to higher employee-related costs associated with incentive and medical benefit plans.

Capital expenditures decreased due primarily to spending reductions for growth capital to align with customer needs.

In 2015, we recorded a noncash impairment charge of $10.0 million related to a previously idled asset, as our expectation for future use of the asset changed.
 
 
Years Ended December 31,
Operating Information
 
2017
 
2016
 
2015
NGLs transported - gathering lines (MBbl/d) (a)
 
812

 
770

 
769

NGLs fractionated (MBbl/d) (b)
 
621

 
586

 
552

NGLs transported - distribution lines (MBbl/d) (a)
 
567

 
508

 
428

Average Conway-to-Mont Belvieu OPIS price differential -
ethane in ethane/propane mix ($/gallon)
 
$
0.05

 
$
0.03

 
$
0.02

(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.

2017 vs. 2016 - NGLs transported on gathering lines and NGLs fractionated increased due to higher volumes primarily from the STACK and SCOOP areas and Williston Basin resulting from recent plant connections, increased supply and increased ethane recovery, which was offset partially by decreased volumes from the Barnett Shale and Granite Wash. NGLs transported on gathering lines also increased due to higher volumes from the Permian Basin.

While overall NGL supply volumes and ethane recovery increased, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.


49


NGLs transported on distribution lines increased due primarily to higher transported volumes for optimization activities.

2016 vs. 2015 - NGLs transported on gathering lines remained relatively unchanged due to increased volumes from new plant connections in the Williston Basin, increased ethane recovery and increased Mid-Continent volumes gathered in the STACK and SCOOP areas, offset by decreased volumes on the West Texas LPG system, decreased Mid-Continent volumes gathered from the Barnett Shale, lower short-term contracted volumes and the impact of weather on gathered volumes across our system in December 2016.

NGLs fractionated increased due to increased volumes from new plant connections in the Williston Basin, increased ethane recovery and increased Mid-Continent volumes gathered in the STACK and SCOOP areas, offset partially by decreased volumes gathered from the Barnett Shale and lower short-term contracted volumes and the impact of weather on gathered volumes across our system in December 2016.

While the volume of ethane recovered increased, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.

NGLs transported on distribution lines increased due primarily to higher gathered and fractionated volumes as discussed above and due to increased volumes transported for our optimization business.

Natural Gas Pipelines

Growth Projects - The development of shale and other resource areas has continued to increase available natural gas supply, and we expect producers to require incremental transportation services in the future as additional supply is developed. The abundance of natural gas supply and regulations on emissions from coal-fired electric-generation plants may also increase the demand for our services from electric-generation companies if they convert to a natural gas fuel source.