Item 1. Business.

THE COMPANY

 

Introduction

 

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.   The Company was incorporated in August 1995 in the state of Oklahoma and its principal executive offices are located at 321 North Harvey , P.O. Box 321 , Oklahoma City, Oklahoma 73101-0321 ; telephone 405-553-3000 .

  

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas .  Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC.    OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries, and ultimately OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control , the Company began accounting for its interest in Enable using the equity method of accounting.

In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At December 31, 2016 , the Company owned 111.0 million common units, or 25.7 percent , of Enable's outstanding common units. Of the Company's 111.0 million common units, 68.2 million units were subordinated. The subordination period began on the closing date of Enable’s initial public offering and will extend until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. The Company anticipates that the subordination period will expire in August 2017 and will not impact future distributions that the Company receives from Enable. For additional information on the Company's equity investment in Enable and related party transactions, see Note 3.

Over the past two years, Enable has seen changes in producer activity due to the volatility of commodity prices. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. During 2016, those prices increased, and have stabilized, but have not rebounded to the pre-2015 levels. If commodity prices decline further, Enable's future operating results and cash flows could be negatively impacted. A portion of our earnings and operating cash flows depend on the performance of, and distributions from, Enable. As disclosed in this Form 10-K, Enable is subject to a number of risks. If any of those risks were to occur, the Company's business, financial condition, results of operations or cash flows could be materially adversely affected.

 

On February 10, 2017, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent , of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions."

Company Strategy

 

The Company's mission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management. The Company's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and interest in a publicly traded midstream company, while providing competitive energy products and services to customers, as well as seeking growth opportunities in both businesses.  

OG&E is focused on:

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders. The Company's financial objectives include a long-term annual earnings growth rate for OG&E of three to five percent on a weather-normalized basis, maintaining a strong credit rating as well as targeting dividend increases of approximately 10 percent annually through 2019. The targeted annual dividend increase has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets and the composition of the Company's assets and investment opportunities.    The Company also utilizes cash distributions from its investment in Enable to help fund its capital needs and support future dividend growth. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and having strong regulatory and legislative relationships.

 

ELECTRIC OPERATIONS - OG&E

General

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas . Its operations are conducted through OG&E . OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 267 communities that OG&E serves, 241 are located in Oklahoma and 26 are in Arkansas. OG&E derived 92 percent of its total electric operating revenues in 2016 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.

OG&E's system control area peak demand in 2016 was 6,538 MWs on August 11, 2016 . OG&E's load responsibility peak demand was 6,008 MWs on August 11, 2016 . As reflected in the table below and in the operating statistics that follow, there were 26.9 million MWh system sales in 2016 , 27.2 million MWh system sales in 2015 and 28.0 million MWh system sales in 2014 . Variations in system sales for the three years are reflected in the following table:

OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators as well as from consumers choosing appliances powered by other energy sources. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.

Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. It is possible that changes in regulatory policies or advances in technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production. Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinate of our competitiveness.

  

Regulation and Rates

OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas.  The issuance of certain securities by OG&E is also regulated by the OCC and the APSC.  OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC.  The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations.    In 2016 , 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.

The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of the Company.   The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E, (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions.  In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates .

Completed Regulatory Matters

FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation

On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.

Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities.

The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement.

On July 1, 2016, the Court upheld the FERC's decision requiring removal of the "right of first refusal" for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the "right of first refusal" in the SPP Membership Agreement to be anticompetitive.

The Company does not believe the Court’s ruling will have any impact on existing transmission projects for which the Company has already received a notice to construct from the SPP.   The Company intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.

Oklahoma Demand Program Rider Review - SmartHours Program

In July 2012, OG&E filed an application with the OCC to recover certain costs associated with demand programs through the Oklahoma Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off-peak hours during the months of May through October, by offering lower rates to those customers in the off-peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.

In December 2012, the OCC issued an order approving the recovery of costs associated with the demand programs, including the lost revenues associated with the SmartHours program, subject to the PUD Staff's review.

I n March 2014, the PUD Staff began their review of the demand program costs, including the lost revenues associated with the SmartHours program.

On August 9, 2016, OG&E entered into a settlement agreement with the PUD Staff to resolve the recoverable amount of lost revenues associated with the SmartHours program. The settlement provides for recovery of $10.1 million per year for 2013, 2014 and 2015, for a total of $30.3 million. OG&E had recorded $36.6 million of lost revenues for 2013, 2014 and 2015. On August 16, 2016, the OCC issued an order adopting the settlement agreement. Accordingly, OG&E reduced lost revenues and the Oklahoma Demand Program Rider regulatory asset by $6.3 million.

Mustang Modernization Plan - Arkansas

On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility.  Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas.  The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings.  In July 2016, OG&E filed a motion to dismiss this proceeding and in August, the APSC approved the dismissal. OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service.

Pending Regulatory Matters

Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 400 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs.

On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. On April 28, 2016, the OCC approved the Dry Scrubber project.

Two parties appealed the OCC's decision to the Oklahoma Supreme Court. The Company is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.

OG&E anticipates the total cost of Dry Scrubbers will be $547.5 million , including allowance for funds used during construction and capitalized ad valorem taxes. As of December 31, 2016 , OG&E had invested $208.7 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $424.9 million and expects the project to be completed in late 2017. As of December 31, 2016 , OG&E had invested $187.8 million on the Mustang Modernization Plan.

Integrated Resource Plans

In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Arkansas by October 1, 2017 and in Oklahoma by October 1, 2018.

Oklahoma Rate Case Filing

On December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53 percent . The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million . Each 0.25 percent change in the requested return on equity affects the requested rate increase by approximately $9.0 million .

In late March 2016, the PUD Staff and other intervenors filed testimony in the case.  The PUD Staff recommended a $6.1 million annual rate increase based on a return on equity of 9.25 percent and a common equity percentage of 53.0 percent .  Included in the PUD Staff's recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement.

The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent , as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent .  Included in the Oklahoma Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement.

The Oklahoma Industrial Energy Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent .  Included in the Oklahoma Industrial Energy Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement.

On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million , which is subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case. As of December 31, 2016 , the Company has recorded $39.0 million of revenues from the interim rate increase and has reserved $33.7 million of that revenue.

In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations include, among other things, the use of OG&E's actual capital structure of 53 percent equity and 47 percent long-term debt and a return on equity of 9.87 percent resulting in an annual increase in OG&E's revenues of $40.7 million . The parties provided comments on the ALJ's report in early January 2017, and the OCC held hearings in early February 2017. The Company is unable to predict what action the OCC will take, or the timing of such action.

Arkansas Rate Case Filing

On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management costs, and increased recovery of depreciation and dismantlement costs. A hearing in this matter is scheduled for the second quarter of 2017.

Fuel Adjustment Clause Review for Calendar Year 2015

On September 8, 2016, the OCC Staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. A hearing in this Cause will be held on March 30, 2017.

Regulatory Assets and Liabilities

OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates.  Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates.  Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.

At December 31, 2016 and 2015 , OG&E had regulatory assets of $526.6 million and $448.7 million , respectively, and regulatory liabilities of $312.0 million and $342.4 million , respectively. See Note 1 for a further discussion.

Management continuously monitors the future recoverability of regulatory assets.    When, in management's judgment, future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate.    If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.

Rate Structures

Oklahoma

OG&E's standard tariff rates include a cost-of-service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power.

OG&E offers several alternate customer programs and rate options.  Under OG&E's Smart Grid enabled SmartHours programs, "time-of-use" and "variable peak pricing" rates offer customers the ability to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity and costs are at their lowest. The guaranteed flat bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year. Another tariff rate option provides a "renewable energy" resource to OG&E's Oklahoma retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. Another program being offered to OG&E's commercial and industrial customers is a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required. OG&E also offers certain qualifying customers "day-ahead price" and "flex price" rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price" and "flex price" rate options are based on OG&E's projected next day hourly operating costs.

OG&E also has the Public Schools-Demand and Public Schools Non-Demand rate classes that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service.  Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to our military partners.

The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers.  The revenue impacts associated with these options are not determinable in future years because

customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices.  Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.

Arkansas

OG&E's standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. OG&E offers several alternate customer programs and rate options. The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest. A second tariff rate option provides a "renewable energy" resource to OG&E's Arkansas retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Arkansas retail customers.  OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. OG&E offers its commercial and industrial customers a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action. OG&E offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The day-ahead price is based on OG&E's projected next day hourly operating costs.

The increase in the weighted average cost of fuel in 2016 as compared to 2015 was primarily due to higher coal prices. The decrease in the weighted average cost of fuel in 2015 as compared to 2014 was primarily due to lower natural gas prices. The decrease in the weighted average cost of fuel in 2014 as compared to 2013 was primarily due to less natural gas used, partially offset by higher natural gas prices. The increase in the weighted average cost of fuel in 2013 as compared to 2012 was primarily due to higher gas prices. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.

OG&E participates in the SPP Integrated Marketplace. As part of the Integrated Marketplace, the SPP has balancing authority responsibilities for its market participants.  The SPP Integrated Marketplace functions as a centralized dispatch, where market participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers.  The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations, and determine which generating units will run at any given time for maximum cost-effectiveness.  As a result, OG&E's generating units produce output that is different from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.

Coal

OG&E's coal-fired units, with an aggregate capability of 2,568 MWs, are designed to burn low sulfur western sub-bituminous coal. The combination of all coal has a weighted average sulfur content of 0.24 percent . Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.5 lbs of SO ₂ per MMBtu.

For 2017, OG&E has acquired 100 percent of its forecasted annual coal usage via existing inventory and purchase contracts that expire in December 2017 . In 2016 , OG&E purchased 5.5 million tons of coal from various Wyoming suppliers. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.

Natural Gas

As a participant in the SPP Integrated Marketplace, OG&E now purchases a relatively small percentage of its natural gas supply through long-term agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.

Wind

OG&E's current wind power portfolio includes the following, in addition to the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms owned by OG&E: (i) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (ii) access to up to 152 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to 130 MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2031 and (iv) access to up to 60 MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032.

Solar

In 2015, OG&E placed its first solar plant in service. The plant consists of two separate solar farms and is located in Oklahoma City, on the site of the Mustang generating facility. The Mustang solar plant has a maximum capacity of 2.5 MWs and consists of almost 10,000 photovoltaic panels.

OG&E expects to begin construction on 10 MWs of new solar farms in 2017. OG&E will evaluate the need to build additional solar plants, based on customer demand, cost, and reliability.

Safety and Health Regulation

 

OG&E is subject to a number of Federal and state laws and regulations, including OSHA, the EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.

In addition, the OSHA Hazard Communication Standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

NATURAL GAS MIDSTREAM OPERATIONS - ENABLE MIDSTREAM PARTNERS

Overview

 

Enable is a publicly traded Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. Enable serves current and emerging production areas in the United States, including several unconventional shale resource plays and local and regional end-user markets in the United States. Enable's assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Enable's gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to its producer customers. Enable's transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to its producer, power plant, LDC and industrial end-user customers.

Enable's natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable's crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. Enable's natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma and an investment in SESH, a pipeline extending from Louisiana to Alabama.

Enable was formed on May 1, 2013, to own and operate the midstream businesses of the Company and CenterPoint. As of December 31, 2016 , Enable's portfolio of energy infrastructure assets included approximately 12,900 miles of gathering pipelines, 14 major processing plants with approximately 2.5 Bcf/d of processing capacity, approximately 7,800 miles of interstate pipelines (including SESH), approximately 2,200 miles of intrastate pipelines and eight natural gas storage facilities providing approximately 85.0 Bcf of storage capacity.

The following table shows the components of Enable's gross margin for the year ended December 31, 2016 .

Gathering and Processing

Enable owns and operates substantial natural gas and crude oil gathering and natural gas processing assets in five states. Enable's gathering and processing operations consist primarily of natural gas gathering and processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins and crude oil gathering assets serving the Williston Basin. Enable provides a variety of services to the active producers in its operating areas, including gathering, compressing, treating, and processing natural gas, fractionating NGLs, and gathering crude oil and produced water.

Natural Gas Gathering and Processing. The following table sets forth certain information regarding Enable's gathering and processing assets as of or for the year ended December 31, 2016 :

Enable's gathering assets include more than 12,600 miles of natural gas gathering pipelines as of December 31, 2016 . Enable's natural gas gathering systems consist of networks of pipelines that collect natural gas from points at or near its customers' wells for delivery to plants for processing or pipelines for transportation. Natural gas is moved from the receipt points to the delivery points on Enable's gathering systems by the use of compression.

Enable's natural gas processing assets included 14 natural gas processing plants with 2,450 MMcf/d of inlet capacity as of December 31, 2016. Natural gas is comprised primarily of methane, but at the wellhead, natural gas may contain varying amounts of NGLs. Enable's processing plants recover NGLs from natural gas and primarily deliver NGLs and natural gas to pipelines for transportation.

Crude Oil Gathering. As of December 31, 2016 , Enable had approximately 175 miles of crude oil gathering pipelines and approximately 160 miles of produced water gathering pipelines in the Bakken Shale of the Williston Basin. Enable's crude oil gathering systems have a combined design capacity of 49.5 MBbl/d and as of December 31, 2016 , Enable had 0.2 million gross acres dedicated under a crude oil gathering agreement. For the year ended December 31, 2016, Enable had an average daily throughput of 25.0 MBbl/d of crude oil and an average daily throughput of 6.0 MBbl/d of produced water on Enable's Bakken Shale gathering system.

Enable's Bakken Shale crude oil gathering assets are located in Dunn, McKenzie, Williams and Mountrail Counties in North Dakota. These systems were designed and built to serve the crude oil production of XTO Energy, Inc. in the area that they serve. On Enable's systems, crude oil is received on crude oil gathering pipelines near its customer’s wells for delivery to third party transportation pipelines, and produced water is received by produced water gathering pipelines for delivery to third party disposal wells. Enable does not take title to crude oil or produced water gathered and it does not own or operate produced water disposal wells.

Delivery Points. Natural gas that is gathered, and when applicable, processed, is typically redelivered to Enable's customers at interconnections with transportation pipelines. Enable's gathering lines interconnect with both its interstate and intrastate pipelines, as well as other interstate and intrastate pipelines, including the Acadian, ANR, ETC Tiger, Gulf Crossing, Gulf South, NGPL, Northern Natural, Panhandle Eastern, Regency, Southern Natural Gas, Tennessee Gas and Texas Eastern Transmission pipelines. These connections provide producers with access to a variety of natural gas market hubs.

Crude oil gathered on Enable's Bakken Shale gathering systems in Dunn and McKenzie Counties is redelivered to its customers on the BakkenLink Pipeline, which provides access to rail transportation. Crude oil gathered on Enable's Bakken Shale gathering systems in Williams and Mountrail Counties is redelivered to its customers on the Enbridge North Dakota Pipeline, which provides interstate transportation from North Dakota to Minnesota. Enable anticipates constructing interconnections between its gathering systems and other pipelines that will provide access to the Dakota Access Pipeline during 2017.

Enable typically purchases the NGLs produced at its processing plants and most of the NGLs are delivered into third-party pipelines and transported to Conway, Kansas, or Mont Belvieu, Texas, where the NGLs are sold under contract or on the spot market. At Enable's Cox City, Calumet and Wetumka plants, it operates depropanizers that allow Enable to extract propane from the NGL stream and sell propane to local markets. Additionally, Enable operates a fractionator at its Waskom plant and sells ethane, propane, butane and natural gasoline to local markets.

Customers. Enable generates revenues from producers in the basins in which it operates. For the year ended December 31, 2016, Enable's top natural gas gathering and processing customers by gathered volumes were Continental Resources, Inc., Vine Oil and Gas, GeoSouthern Energy Corporation, XTO Energy Inc., Apache Corporation, Tapstone Energy LLC , affiliates of Chesapeake Energy Corporation, BP America Production Company, Covey Park Energy LLC and Marathon Oil Company. For the year ended December 31, 2016 , Enable's top ten natural gas producer customers accounted for approximately 66 percent of its gathered natural gas volumes.

Enable's Bakken Shale gathering systems serve XTO Energy Inc. The rates and terms of service on Enable's Bakken Shale crude oil gathering systems are regulated by the FERC under the Interstate Commerce Act, but Enable's Bakken Shale produced water gathering systems are not FERC regulated. As of December 31, 2016 , XTO Energy Inc. was Enable's only customer on these systems.

Contracts. Enable's contracts typically provide for natural gas and crude oil gathering services that are fee-based and for natural gas processing arrangements that are fee-based, or percent-of-liquids, percent-of-proceeds or keep-whole based. For the year ended December 31, 2016 , 46 percent, 46 percent and eight percent of Enable's inlet volumes were under processing arrangements that were fee-based, percent-of-proceeds or percent-of-liquids, and keep-whole, respectively. For the year ended December 31, 2016 , 78 percent of Enable's gathering and processing gross margin was fee-based, and the remaining 22 percent of its gathering and processing gross margin was primarily from sales of commodities, including natural gas, NGLs, and condensate received under percent-of-proceeds, percent-of-liquids and keep-whole arrangements.

In lean gas areas, such as the lean gas areas of the eastern Arkoma Basin and the Haynesville Shale of the Ark-La-Tex Basin, some of Enable's natural gas gathering contracts contain minimum volume commitments from Enable's customers. In addition, a portion of the crude oil gathered by Enable's crude oil gathering system is under a contract with a minimum volume commitment. Under a minimum volume commitment a customer agrees to either deliver a minimum volume of natural gas or crude oil to Enable's system for service or pay the service fees for the minimum volume of natural gas or crude oil regardless of whether or not the minimum volume of natural gas or crude oil is delivered. Enable calls any payment for the difference between the volume gathered and the minimum volume committed a shortfall payment. Some of Enable's contracts provide its customers the option to elect to pay a higher gathering fee over the remaining term of the contract in lieu of making a shortfall payment. For the year ended December 31, 2016 , 31 percent of Enable's gathering and processing gross margin was attributable to natural gas gathering contracts with minimum volume commitments, which as of December 31, 2016 had volume commitment-weighted average remaining terms of 4.6 years. Of this gross margin, 62 percent was attributable to shortfall payments. For the year ended December 31, 2016 , three percent of Enable's gathering and processing gross margin was attributable to a crude oil gathering contract with a minimum volume commitment and a remaining term of 12.2 years; however, if the customer ships in excess of

the minimum volume, this volume commitment could end before the expiration of the contract term. Of this gross margin, none was attributable to shortfall payments.

For Enable's gathering and processing contracts that do not have minimum volume commitments, it strives to obtain acreage dedications. Under an acreage dedication, a customer agrees to deliver all of the natural gas or crude oil produced from a given area to Enable's system for gathering, and, if applicable, processing. As of December 31, 2016 , Enable had 6.9 million gross acres dedicated under natural gas gathering agreements with a volume-weighted average remaining term of 5.9 years and 0.2 million gross acres dedicated under a crude oil gathering agreement with a remaining term of 14.2 years.

Competition. Competition to gather and process natural gas is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Enable's gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable's primary competitors are other midstream companies who are active in the regions where it operates.

Competition to gather crude oil and produced water is primarily a function of rates, terms of service, system reliability, construction cycle time and prices at the wellhead. The rates and terms of service of Enable's crude oil gathering, but not its produced water gathering, are FERC regulated. Enable's Bakken gathering systems compete with other gatherers, including those affiliated with producers and other midstream companies.

Seasonality. While the results of Enable's gathering and processing segment are not materially affected by seasonality, from time to time its operations and construction of assets can be impacted by inclement weather.

Transportation and Storage

Enable owns and operates interstate and intrastate transportation and storage systems across nine states. Enable's transportation and storage systems consist primarily of its interstate systems, EGT and MRT, its intrastate system, EOIT and its investment in SESH. Enable's transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, LDCs and industrial end users as well as interconnected pipelines for delivery to additional markets. Enable's transportation and storage assets also provide facilities where natural gas can be stored by customers.

The following table sets forth certain information regarding Enable's transportation and storage assets as of December 31, 2016 :

 Enable's transportation and storage assets were designed and built to serve large natural gas and electric utilities in its areas of operation. In addition, Enable's transportation and storage assets serve natural gas producers, industrial end users and natural gas marketers. For the year ended December 31, 2016 , Enable's top transportation and storage customers by revenue were

affiliates of CenterPoint, Spire Inc., XTO Energy Inc., American Electric Power Co., the Company, Continental Resources, Inc, Chesapeake Energy Corporation, Midcontinent Express Pipeline LLC, EOG Resources, Inc. and Entergy Corporation.

Enable's transportation assets include approximately 10,000 miles of transportation pipelines in Texas, Oklahoma, Arkansas, Louisiana, Kansas and Missouri, providing access to natural gas supplies from the Anadarko, Arkoma and Ark-La-Tex Basins to natural gas consuming markets in the Southeastern, Northeastern and Midwestern United States. Enable's storage assets, as of December 31, 2016 , provide a combined capacity of 85.0 Bcf with 2.0 Bcf/d of aggregate maximum withdrawal capacity from seven storage facilities in Oklahoma, Louisiana, Illinois and from its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana. Gulf South owns an undivided 9/12th interest in, and operates, the Bistineau Storage Facility. In addition, Enable has contracted for 3.3 Bcf of firm storage capacity in Cardinal’s Perryville and Arcadia salt cavern storage facilities.

Enable's transportation and storage assets are comprised of three categories: (1) interstate transportation and storage, (2) intrastate transportation and storage and (3) Enable's investment in SESH.

Interstate Transportation and Storage

Enable's interstate transportation and storage business consists of EGT and MRT. As interstate pipelines, EGT and MRT are subject to regulation as natural gas companies by FERC under the Natural Gas Act of 1938.

EGT

EGT provides natural gas transportation and storage services primarily to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. In addition to 5,900 miles of interstate pipelines with capacity of 6.5 Bcf/d, EGT has two underground natural gas storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana, which, as of December 31, 2016, operate at a combined capacity of 29.5 Bcf with 739 MMcf/d of aggregate maximum withdrawal capacity.

Customers. EGT primarily serves LDCs owned by CenterPoint, producers in key plays in the Mid-continent, power plants, other LDCs and industrial end-users. EGT’s customer are primarily located in Arkansas, Louisiana, Oklahoma and Texas. For the year ended December 31, 2016, approximately 25 percent of EGT's service revenue was attributable to contracts with LDCs owned by CenterPoint with a volume-weighted average contract life of 4.1 years. In addition to the CenterPoint LDCs, EGT’s other major customers include XTO Energy Inc., Continental Resources, Inc. and American Electric Power Co.

Contracts. Although EGT has established maximum rates for interstate transportation and storage services as required by the FERC, EGT is authorized to enter into negotiated rate and discounted rate agreements with its customers. EGT’s services are typically provided under firm, fee-based, transportation and storage agreements. For the year ended December 31, 2016, approximately 59 percent of Enable's transportation and storage gross margin was derived from EGT’s firm contracts, 83 percent of EGT’s transportation capacity was under firm contracts with a volume-weighted average remaining contract life of 2.8 years, and 78 percent of EGT’s storage capacity was under firm contracts with a volume-weighted average remaining contract life of 4.2 years. The primary terms of EGT’s firm transportation and storage contracts with the CenterPoint LDCs will begin to expire in 2018, with the majority of the contracts expiring in 2021.

Seasonality. EGT provides gas transmission delivery services to LDCs owned by CenterPoint in Arkansas, Louisiana, Oklahoma and Texas. Customer demand for natural gas on EGT is usually greater during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. In addition, EGT experiences seasonal impacts associated with storage spreads and basis spreads on interconnected pipelines, as well as power plant demand.

Competition. EGT competes with a variety of other interstate and intrastate pipelines across Texas, Oklahoma, Arkansas and Louisiana. Enable's management views the principal elements of competition among pipelines as rates and terms, flexibility and reliability of service. EGT provides both flexibility and reliability of service with access to multiple sources of supply in the Anadarko, Arkoma and Ark-La-Tex Basins and access to multiple markets in the Midwest, Northeast and Southeast through interconnections with other pipelines. EGT’s interconnections with other pipelines are primarily at Enable's Perryville Hub.

MRT

MRT provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois. In addition to 1,600-miles of interstate pipelines with capacity of 1.7 Bcf/d, MRT has one underground natural gas storage facility in Louisiana and one underground natural gas storage facility in Illinois, which, as of December 31, 2016, operate at a combined capacity of 31.5 Bcf with 620 MMcf/d of aggregate maximum withdrawal capacity.

Customers. MRT primarily serves Laclede Gas Company, the St. Louis LDC owned by Spire Inc. For the year ended December 31, 2016, 59 percent of MRT's service revenue was attributable to Spire Inc. under contracts with a volume-weighted average contract life of 2.3 years. MRT’s other customers include utilities and industrial end users. MRT’s customers are primarily located in Arkansas, Missouri and Illinois.

Contracts. MRT’s services are typically provided under firm, fee-based transportation and storage agreements, with rates and terms of service regulated by the FERC. For the year ended December 31, 2016, approximately 14 percent of Enable's transportation and storage gross margin was derived from MRT’s firm contracts, 95 percent of MRT’s transportation capacity was under firm contracts with a volume-weighted average remaining contract life of 2.5 years and 91 percent of MRT’s storage capacity was under firm contracts with a volume-weighted average remaining contract life of 1.4 years. MRT’s firm transportation and storage contracts with Spire Inc. are scheduled to expire in 2018 and 2020.

Seasonality. Customer demand for natural gas on MRT is usually greater during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. In addition, MRT experiences seasonal impacts associated with storage spreads and basis spreads on market-based pipelines.

Competition. MRT competes with various intrastate pipelines providing natural gas to the St. Louis market. In addition, MRT, from time-to-time, competes with potential projects to connect one or more third party interstate pipelines to the St. Louis market, such as the proposed Spire Inc. STL Pipeline for which a notice of application was filed on February 6, 2017 with the FERC. Enable's management views the principal elements of competition among pipelines as rates, terms of service, flexibility and reliability of service. MRT, through its interconnections with a variety of interstate and intrastate pipelines and its access to supply from a variety of producing basins, provides its customers with access to a variety of natural gas supply sources.

Intrastate Transportation and Storage

Enable's intrastate transportation and storage assets consist primarily of EOIT. EOIT provides transportation and storage services in Oklahoma. Enable's EOIT system delivers natural gas from the Arkoma and Anadarko Basins, including growth areas in the Cana Woodford, Granite Wash, Cleveland, Tonkawa, South Central Oklahoma Oil Province, Sooner Trend Anadarko Basin Canadian and Kingfisher Counties, and Mississippi Lime Shale plays in western Oklahoma and the Texas Panhandle, to utilities and industrial end users connected to EOIT and to interstate and intrastate pipelines interconnected with EOIT. EOIT had 1.72 TBtu/d of average daily throughput for the year ended December 31, 2016. In addition to the 2,200 miles of intrastate pipelines, EOIT has two underground natural gas storage facilities in Oklahoma, which, as of December 31, 2016 operate at a combined capacity of 24 Bcf with 605 MMcf/d of aggregate maximum withdrawal capacity. Enable's intrastate transportation also includes a 20-mile intrastate pipeline in Illinois.

Customers. EOIT’s customers include Oklahoma’s two largest electric utilities, OG&E and Public Service Company of Oklahoma, an affiliate of American Electric Power Co. For the year ended December 31, 2016, approximately seven percent of Enable's total transportation and storage gross margin was attributable to a firm contract with its affiliate OG&E, and approximately three percent of Enable's transportation and storage gross margin was attributable to a firm contract with Public Service Company of Oklahoma. Enable's transportation agreement with OG&E extends through April 30, 2019, and will remain in effect year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. Enable's transportation agreement with Public Service Company of Oklahoma is on a one-year renewal term and has been extended through December 31, 2017. EOIT’s customers also include other electric generators, LDCs, Arkoma and Anadarko Basin producers and industrial end users.

Contracts. EOIT provides fee-based firm and interruptible transportation and storage services on both an intrastate basis and, pursuant to Section 311 of the Natural Gas Policy Act of 1978, on an interstate basis. For the year ended December 31, 2016, approximately 20 percent of Enable's transportation and storage gross margin was derived from EOIT’s firm contracts, with a volume-weighted average remaining contract life of 4.9 years.

Seasonality. EOIT provides gas transmission delivery services to the majority of OG&E’s and all of PSO’s natural gas-fired electric generation facilities in Oklahoma. Customer demand for natural gas transportation and storage services on EOIT is usually greater during the summer, primarily due to demand by natural gas-fired power plants to serve residential and commercial electricity requirements.

Competition. EOIT competes with a variety of interstate and intrastate pipelines in providing transportation and storage services in Oklahoma, including competing against several pipelines with which EOIT interconnects. Enable's management views competition in the transportation and storage market as primarily a function of rates, terms of services, flexibility and reliability of service. EOIT’s integrated transportation and storage system allows Enable to provide load following service to natural gas-

fired power plants to allow the power plants the ability to regulate generation and meet the instantaneous changes in customer demand for electricity.

Enable's Investment in SESH

SESH is an approximately 290-mile interstate pipeline that provides transportation services in Louisiana, Mississippi, and Alabama. Enable owns a 50 percent interest in SESH and provides field operations for the pipeline. Spectra Energy Partners, LP owns the remaining 50 percent interest in SESH and provides gas control and commercial operations for the pipeline. As of December 31, 2016, SESH had 1.09 Bcf/d of transportation capacity from Perryville, Louisiana to its endpoint in Mobile County, Alabama.

 

Customers and Contracts. SESH’s customers are companies that generate electricity for the Florida power market. The rates charged by SESH for interstate transportation services are regulated by the FERC. SESH’s transportation services are typically provided under firm, fee-based negotiated rate agreements. SESH's transportation contracts have a volume-weighted average remaining contract life of 5.4 years.

Seasonality. SESH is generally not impacted by seasonality, SESH's load factor generally remains constant throughout the year.

Competition. SESH competes with other interstate and intrastate pipelines providing access to the Southeast power generation market. Enable's management views the principal elements of competition among pipelines as rates and terms, flexibility and reliability of service.

ENVIRONMENTAL MATTERS

 

General

 

The activities of the Company are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.

  

Under the Obama administration, the trend in environmental regulation was to place more restrictions and limitations on activities that may affect the environment. The Company is unable to predict what changes the Trump administration may have on proposed or existing environmental regulations. The Company cannot assure that future events, such as changes in existing laws, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause it to incur significant costs.

It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2017 will be $241.3 million , of which $221.9 million is for capital expenditures.    It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2018 will be approximately $180.8 million , of which $161.6 million is for capital expenditures. The amounts for OG&E above include capital expenditures for low NO _X burners, Dry Scrubbers and gas conversions. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.

For a further discussion of environmental matters that may affect the Company, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations" in this Form 10-K.

FINANCE AND CONSTRUCTION

Future Capital Requirements and Financing Activities

Capital Requirements

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E.    Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes.    The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper ) and permanent financings. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for a discussion of the Company's capital requirements.

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets , will be evaluated based upon their impact upon achieving the Company's financial objectives.   

Pension and Postretirement Benefit Plans

During 2016 , the Company made a $20.0 million contribution to its Pension Plan . During 2015 , the Company did not make any contributions to its Pension Plan. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2017 . See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a discussion of the Company's pension and postretirement benefit plans.

Common Stock Dividends

At the Company's September 2016 board meeting, the Board of Directors approved management's recommendation of a 10 percent increase in the quarterly dividend rate to $0.30250 per share from $0.27500 per share effective in October 2016. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a further discussion.

Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt , proceeds from offerings and distributions from Enable will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities.    The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper ) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-Term Debt and Credit Facilities

Short-term borrowings generally are used to meet working capital requirements.  The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement.   The Company has revolving credit facilities totaling in the aggregate $1,150.0 million . These bank facilities can also be used as letter of credit facilities .   As of December 31, 2016 , the Company had $236.2 million in short-term debt compared to no balance at December 31, 2015 . The average balance of short-term debt in 2016 was $216.7 million at a weighted-average interest rate of 0.79 percent . The maximum month-end balance of short-term debt in 2016 was $355.6 million .    At December 31, 2016 , the Company had $912.0 million of net available liquidity under its revolving credit agreements.    OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2017 and ending December 31, 2018.    At December 31, 2016 , the Company had $0.3 million in cash and cash equivalents.  See Note 10 for a discussion of the Company's short-term debt activity.

In December 2011, the Company and OG&E entered into unsecured revolving credit agreement s in the aggregate of $1,150.0 million ( $750.0 million for the Company and $400.0 million for OG&E ) which expire in December 2018. The Company and OG&E expect to replace the existing agreements with new revolving credit agreements during 2017, under terms and conditions generally similar to the existing agreements.

Expected Issuance of Long-Term Debt

OG&E expects to issue $300.0 million of long-term debt during the first half of 2017 , depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.

Common Stock

The Company does not expect to issue any common stock in 2017 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 8 for a discussion of the Company's common stock activity.

Distributions by Enable

 

Pursuant to the Enable Limited Partnership Agreement, Enable made distributions of $141.2 million , $139.3 million and $143.7 million during the years ended December 31, 2016 , 2015 and 2014 .

EMPLOYEES

The Company had 2,453 employees at December 31, 2016 , of which 158 are seconded to Enable.

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Trauschke, Merrill, Forbes, Renfrow, Sultemeier, Walworth and Ms. Horn are also officers of OG&E.   Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareholders , currently scheduled for May 18, 2017 .

Mr. Trauschke is a member of the Board of Directors of Enable GP, LLC, the general partner of Enable. Mr. Merrill will become a member of the Board of Directors of Enable GP, LLC on March 1, 2017.

The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

The Company's website address is www.oge.com. Through the Company's website under the heading "Investors," "Investor Relations," "SEC Filings," the Company makes available, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed

with or furnished to the Securities and Exchange Commission . Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K.