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EX-32.01 - EXHIBIT 32.01 - OKLAHOMA GAS & ELECTRIC COa2017oge10-kxex3201.htm
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EX-10.10 - EXHIBIT 10.10 - OKLAHOMA GAS & ELECTRIC COa2017oge10-kxex1010.htm




 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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
o 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: 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma
 
73-0382390
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
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.
o  Yes   þ  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
o  Yes   þ  No
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.  þ  Yes   o  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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).  þ  Yes   o  No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation 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.    þ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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.
Large accelerated filer  o
Accelerated filer  o
  
Non-accelerated filer    þ (Do not check if a smaller reporting company)
Smaller reporting company  o
 
Emerging growth company o
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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o  Yes   þ  No
At June 30, 2017, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $0. As of such date, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp.
At January 31, 2018, there were 40,378,745 shares of common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp.  There were no other shares of capital stock of the registrant outstanding at such date.
DOCUMENTS INCORPORATED BY REFERENCE
None
Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
 



OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2017

TABLE OF CONTENTS

 
Page
 
 
 
 
 
 
 
 
 
 
 
 



i


GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations that are found throughout this Form 10-K.
Abbreviation
Definition
2017 Tax Act
Tax Cuts and Jobs Act of 2017
401(k) Plan
Qualified defined contribution retirement plan
ALJ
Administrative Law Judge
APSC
Arkansas Public Service Commission
ASC
FASB Accounting Standards Codification
ASU
FASB Accounting Standards Update
AVEC
Arkansas Valley Electric Cooperative Corporation
Bcf
Billion cubic feet
CSAPR
Cross-State Air Pollution Rule
Code
Internal Revenue Code of 1986
CO2
Carbon dioxide
Dry Scrubbers
Dry flue gas desulfurization units with spray dryer absorber
ECP
Environmental Compliance Plan
Enable
Enable Midstream Partners, LP, a midstream partnership formed between OGE Energy and CenterPoint Energy, Inc.
EPA
U.S. Environmental Protection Agency
FASB
Financial Accounting Standards Board
Federal Clean Water Act
Federal Water Pollution Control Act of 1972, as amended
FERC
Federal Energy Regulatory Commission
FIP
Federal Implementation Plan
GAAP
Accounting principles generally accepted in the U.S.
IRP
Integrated Resource Plan
kV
Kilovolt
MATS
Mercury and Air Toxics Standards
MMBtu
Million British thermal unit
Mustang Modernization Plan
The construction of seven new, efficient combustion turbines with generating capability of 462 MWs
MW
Megawatt
MWh
Megawatt-hour
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NOX
Nitrogen oxide
OCC
Oklahoma Corporation Commission
OG&E
Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Energy
OGE Energy Corp., parent company of OG&E
OSHA
Federal Occupational Safety and Health Act of 1970
Pension Plan
Qualified defined benefit retirement plan
Ppb
Parts per billion
QF
Qualified cogeneration facility
QF contracts
Contracts with QFs and small power production producers
Regional Haze Rule
The EPA's Regional Haze Rule
Restoration of Retirement Income Plan
Supplemental retirement plan to the Pension Plan
SIP
State Implementation Plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool
Stock Incentive Plan
2013 Stock Incentive Plan
System sales
Sales to OG&E's customers
U.S.
United States of America

ii


FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and similar expressions.  Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
the ability of OG&E and OGE Energy to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;
prices and availability of electricity, coal and natural gas;
business conditions in the energy industry;
competitive factors including the extent and timing of the entry of additional competition in the markets served by OG&E;
the impact on demand for our services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;
technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
availability and prices of raw materials for current and future construction projects;
the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery have an impact on rate structures or affect the speed and degree to which competition enters OG&E's markets;
environmental laws, safety laws or other regulations that may impact the cost of operations or restrict or change the way OG&E operates its facilities;
changes in accounting standards, rules or guidelines;
the discontinuance of accounting principles for certain types of rate-regulated activities;
the cost of protecting assets against, or damage due to, terrorism or cyberattacks and other catastrophic events;
creditworthiness of suppliers, customers and other contractual parties;
social attitudes regarding the utility industry;
identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;
increased pension and healthcare costs;
costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-K; and
other risk factors listed in the reports filed by OG&E with the Securities and Exchange Commission, including those listed in "Item 1A. Risk Factors."

OG&E undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.




1







PART I

Item 1. Business.

Introduction

OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations 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. 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. OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. OG&E's principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone 405-553-3000.

OG&E Mission and Focus

OGE Energy'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.

OG&E is focused on:

providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity;
providing safe, reliable energy to the communities and customers we serve, with a particular focus on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments;
having strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members;
continuing to grow a zero-injury culture and deliver top-quartile safety results;
complying with the EPA's Regional Haze Rule requirements;
ensuring we have the necessary mix of generation resources to meet the long-term needs of our customers; and
continuing focus on operational excellence and efficiencies in order to protect the customer bill.

General

OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. 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 91 percent of its total electric operating revenues in 2017 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 2017 was 6,456 MWs on July 21, 2017. OG&E's load responsibility peak demand was 5,752 MWs on July 21, 2017. The following table shows system sales and variations in system sales for 2017, 2016 and 2015.
Year Ended December 31 
2017
2017 vs. 2016
2016
2016 vs. 2015
2015
System sales - (Millions of MWh)
26.3
(2.2)%
26.9
(1.1)%
27.2

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.

2





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.

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
 
 
 
 
Year Ended December 31
2017
2016
2015
ELECTRIC ENERGY (Millions of MWh)
 
 
 
Generation (exclusive of station use)
18.5

21.4

20.9

Purchased
11.0

9.6

9.2

Total generated and purchased
29.5

31.0

30.1

OG&E use, free service and losses
(1.4
)
(1.1
)
(1.2
)
Electric energy sold
28.1

29.9

28.9

ELECTRIC ENERGY SOLD (Millions of MWh)
 
 
 
Residential
8.8

9.3

9.2

Commercial
7.6

7.6

7.4

Industrial
3.6

3.6

3.6

Oilfield
3.2

3.2

3.4

Public authorities and street light
3.1

3.2

3.1

Sales for resale


0.5

System sales
26.3

26.9

27.2

Integrated market
1.8

3.0

1.7

Total sales
28.1

29.9

28.9

ELECTRIC OPERATING REVENUES (In millions)
 
 
 
Residential
$
884.1

$
951.9

$
896.5

Commercial
588.3

573.7

535.0

Industrial
200.6

194.6

190.6

Oilfield
159.5

156.9

162.8

Public authorities and street light
208.0

204.3

194.2

Sales for resale
0.2

0.3

21.7

System sales revenues
2,040.7

2,081.7

2,000.8

Provision for rate refund
26.8

(33.6
)

Integrated market
23.5

49.3

48.6

Other
170.1

161.8

147.5

Total operating revenues
$
2,261.1

$
2,259.2

$
2,196.9

ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
 
 
 
Residential
719,441

712,467

705,294

Commercial
96,098

94,790

93,401

Industrial
2,795

2,831

2,872

Oilfield
6,415

6,469

6,328

Public authorities and street light
17,081

17,025

16,880

Sales for resale


1

Total customers
841,830

833,582

824,776

AVERAGE RESIDENTIAL CUSTOMER SALES
 
 
 
Average annual revenue
$
1,234.92

$
1,342.88

$
1,278.51

Average annual use (kilowatt-hour)
12,324

13,105

13,062

Average price per kilowatt-hour (cents)
10.02

10.25

9.79


3





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 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 2017, 85 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and seven percent to the FERC.

The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy.  The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy 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 OGE Energy 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

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 requested rate increase was based on a June 30, 2016 test year and included recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The requested increase also reflected increases in operation and maintenance expenses, including vegetation management and increased recovery of depreciation and dismantlement costs.

In May 2017, the APSC approved a settlement between OG&E and the staff of the APSC and other intervenors. The settlement provided for a $7.1 million annual rate increase and a 9.5 percent return on equity on a 50.0 percent equity capital structure.

The settlement also provided that OG&E will be regulated under a formula rate rider, which should result in a more efficient process as the return on equity, depreciation rates and capital structure should not change from what was approved by the APSC in this settlement. OG&E expects to make its first filing under the Arkansas Formula Rate Rider in October 2018.

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. On October 12, 2017, the OCC issued an order finding that, for the calendar year 2015, OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.

Oklahoma Rate Case Filing - 2015

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 53.0 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.

On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million, subject to refund for amounts in excess of the rates approved by the OCC.

In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations included, among other things, the use of OG&E's actual capital structure of 53.0 percent equity and 47.0 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.

During February and March 2017, the OCC held hearings and, on March 20, 2017, issued an order. The order resulted in an annual net increase of approximately $8.8 million in OG&E's rates to its Oklahoma retail customers. Although the order adopted certain recommendations set forth in the ALJ report, it differed in certain key respects.


4





The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent, (ii) depreciation expense is reduced by approximately $28.6 million from the ALJ report or $36.4 million from then current rates on an annual basis, (iii) recovery of 50.0 percent of short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause. The order maintained OG&E's existing capital structure of 53.0 percent equity and 47.0 percent long-term debt.

As a result of the March 2017 OCC rate order, OG&E recorded, in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates.

As of November 30, 2017, OG&E had completed the refund of $47.5 million collected in excess interim rates.

Mustang Modernization Plan - Arkansas

On August 15, 2017, OG&E filed for a determination with the APSC that the Mustang facility is in the public interest. The filing did not seek recovery for any costs associated with the Mustang Modernization Plan, as request for recovery of costs will take place with the first formula rate filing expected to be made in October 2018. On January 2, 2018, the APSC issued an order finding the Mustang Modernization Plan to be in the public interest.

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 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 a general rate case. On April 28, 2016, the OCC approved the Dry Scrubber project.

Two parties appealed the OCC's decision to the Oklahoma Supreme Court. OG&E 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 $542.4 million, including allowance for funds used during construction and capitalized ad valorem taxes and expects the project to be completed in mid to late 2018. As of December 31, 2017, OG&E had invested $401.3 million in the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $390.0 million, including allowance for funds used during construction and capitalized ad valorem taxes and expects the project to be completed in early 2018. As of December 31, 2017, OG&E had invested $348.4 million in the Mustang Modernization Plan.


5





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 Oklahoma by October 1, 2018 and in Arkansas by October 31, 2018.

Demand Program Rider - Energy Efficiency Lost Net Revenues

During the May 2017 implementation of new rates, OG&E reserved $5.6 million, pending resolution of a dispute with the OCC's Public Utility Division staff, regarding recovery of certain lost revenues associated with energy efficiency incurred prior to the March 2017 OCC rate order. These lost revenues are included within the total Demand Program Rider regulatory asset balance of $31.6 million as disclosed in Note 1 in "Item 8. Financial Statements and Supplementary Data."

Fuel Adjustment Clause Review for Calendar Year 2016

On August 3, 2017, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2016, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 7, 2018, an intervenor filed a recommendation to disallow the Oklahoma jurisdictional portion of $3.3 million related to wind sales in the SPP. A hearing is scheduled for March 29, 2018.

Oklahoma Rate Case Filing - 2018

On January 16, 2018, OG&E filed a general rate case in Oklahoma, requesting a rate increase of $1.9 million per year, assuming a 9.9 percent return on equity. The filing seeks recovery of the seven Mustang combustion turbines that are part of the Mustang Modernization Plan, requests an increase in depreciation rates to levels similar with rates in existence prior to the March 2017 OCC rate order and credits customers for the impacts of the 2017 Tax Act, enacted on December 22, 2017.

On December 22, 2017, the Attorney General of Oklahoma requested that the OCC reduce the rates and charges for electric service and provide for any refund due to the customers of OG&E resulting from the 2017 Tax Act. In response, on January 4, 2018, the OCC ordered OG&E to record a reserve, beginning on January 4, 2018, to reflect the reduced federal corporate tax rate of 21 percent and the amortization of excess accumulated deferred income tax and any other tax implications of the 2017 Tax Act on an interim basis, subject to refund until utility rates are adjusted to reflect the federal tax savings and a final order is issued in OG&E's pending rate case filed on January 16, 2018. Further, the OCC ordered the amounts of any refunds of such reserves owed to customers should accrue interest at a rate equivalent to OG&E's cost of capital as previously recognized in the March 2017 OCC rate order.

APSC Order - 2017 Tax Act

On January 12, 2018, as a result of the 2017 Tax Act, the APSC ordered OG&E to prepare and file an analysis, within 30 days of this order, of the ratemaking effects of the 2017 Tax Act on OG&E's revenue requirement and begin, effective January 1, 2018, to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act. The APSC will subsequently solicit comments or testimony regarding the extent of the impacts of the 2017 Tax Act and how any resulting benefits, including carrying charges, should be returned to customers.

FERC - Section 206 Filing

In January 2018, the Oklahoma Municipal Power Authority filed a complaint at the FERC stating that the base return on common equity used by OG&E in calculating formula transmission rates under the SPP Open Access Transmission Tariff is unjust and unreasonable and should be reduced from 10.60 percent to 7.85 percent, effective upon the date of the complaint. OG&E is analyzing the potential impact of the complaint but estimates that if the FERC ultimately orders a reduction, each 25 basis point reduction in the requested return on equity would reduce OG&E's SPP Open Access Transmission Tariff transmission revenues by approximately $1.5 million annually. In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act. Although the proceeding is in the early stages, OG&E expects to contest the reduction of its base return on equity. OG&E is unable to predict what action the FERC will take in response to the Oklahoma Municipal Power Authority's complaint or the timing of such action. However, if the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could have a material adverse effect on OG&E's financial position, results of operations and cash flows.


6





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, 2017 and 2016, OG&E had regulatory assets of $323.8 million and $526.6 million, respectively, and regulatory liabilities of $1,287.3 million and $312.0 million, respectively. These amounts include additional regulatory assets and liabilities for OG&E resulting from the reduction in the corporate federal tax rate enacted by the 2017 Tax Act. See Note 1 and Note 7 in "Item 8. Financial Statements and Supplementary Data" for 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 alternative 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 has 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.

7





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. In May 2017, the APSC approved a settlement requiring OG&E to be regulated under a formula rate rider. The formula rate rider provides for an adjustment to rates approved by the APSC in the May 2017 settlement if the earned rate of return falls outside of a plus or minus 50 basis point dead-band around the allowed return on equity. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC.

OG&E offers several alternative 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.

Fuel Supply and Generation
In 2017, 54.0 percent of OG&E-generated energy was produced by coal-fired units, 39.0 percent by natural gas-fired units and seven percent by wind-powered units. Of OG&E's 6,304 total MWs of generation capability reflected in the table in "Item 2. Properties," 3,304 MWs, or 52.4 percent, are from natural gas generation, 2,548 MWs, or 40.4 percent, are from coal generation, 449 MWs, or 7.1 percent, are from wind generation and 3 MWs, or 0.1 percent, are from solar generation. Over the last five years, the weighted average cost of fuel used, by type, was as follows:
Year Ended December 31 (In cents/Kilowatt-Hour) 
2017
2016
2015
2014
2013
Natural gas
2.821
2.488
2.529
4.506
3.905
Coal
2.069
2.213
2.187
2.152
2.273
Total fuel
2.211
2.199
2.196
2.752
2.784
The increase in the weighted average cost of fuel in 2017 compared to 2016 was primarily due to higher natural gas prices. 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. 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 to 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 2,548 MWs, are designed to burn low sulfur western sub-bituminous coal. The combination of all 2017 coal had a weighted average sulfur content of 0.23 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 SO2 per MMBtu.

8





For 2018, OG&E has acquired approximately half of its forecasted annual coal usage via existing inventory and purchase contracts that expire in December 2019. In 2017, OG&E purchased 6.7 million tons of coal from various Wyoming suppliers. See "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" 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 natural gas call 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 owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms. OG&E's current wind power portfolio also includes purchase power contracts with the following:
Company
Location
Term of Contract
Expiration of Contract
MWs
CPV Keenan
Woodward County, OK
20 years
2030
152.0
Edison Mission Energy
Dewey County, OK
20 years
2031
130.0
NextEra Energy
Blackwell, OK
20 years
2032
60.0
FPL Energy
Woodward, OK
15 years
2018
50.0

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 began construction on a new 10 MW solar farm in 2017. As of December 31, 2017, OG&E had invested $17.9 million and expects the Covington, Oklahoma solar farm to be placed in service during the first quarter of 2018. 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.

ENVIRONMENTAL MATTERS
 
General
 
The activities of OG&E 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, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions 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.
 
In the past, environmental regulation caused OG&E to incur significant costs because the trend was to place more and more restrictions and limitations on OG&E activities. The Trump administration has delayed, reversed or proposed to repeal some

9





of these regulations and generally has not sought to adopt new, more stringent regulations. Nonetheless, OG&E continues to have obligations to take or complete action under previously adopted environmental rules, and OG&E 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 for environmental matters.  

It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2018 will be $189.2 million, of which $170.0 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2019 will be approximately $51.8 million, of which $35.2 million is for capital expenditures. The amounts above include capital expenditures for Dry Scrubbers and conversion of two coal-fueled units to natural gas. 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 OG&E, see "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

FINANCE AND CONSTRUCTION

Future Capital Requirements

Capital Requirements

OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities.  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.  OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. See "Liquidity and Capital Resources" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of OG&E's capital requirements.


10





Capital Expenditures

OG&E's estimates of capital expenditures for the years 2018 through 2022 are shown in the following table.  These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.
(In millions)
2018
2019
2020
2021
2022
Transmission (A)
$
90

$
50

$
50

$
50

$
50

Distribution:
 
 
 
 
 
Oklahoma
215

165

165

165

165

Arkansas
10

20

50

60

60

Generation
55

130

95

75

75

Other
50

25

25

25

25

Total Transmission, Distribution, Generation and Other
420

390

385

375

375

Projects:
 
 
 
 
 
Environmental - Dry Scrubbers (B)
95

20




Combustion turbines - Mustang
35





Environmental - natural gas conversion (B)
35

15




Allowance of funds used during construction and ad valorem taxes
40





Grid modernization, reliability, resiliency, technology and other

200

190

280

180

Total Projects
205

235

190

280

180

Total
$
625

$
625

$
575

$
655

$
555

(A)
Future transmission capital expenditures include the following:
Project Type
Project Description
Estimated Cost
(In millions)
Projected In-Service Date
Integrated Transmission Project
126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation and construction of the Mathewson substation on this transmission line. $150.0 million has been spent prior to 2018.
$158
First quarter 2018
(B)
Represent capital costs associated with OG&E’s ECP to comply with the EPA’s Regional Haze Rule. More detailed discussion regarding the Regional Haze Rule and OG&E’s ECP can be found in Note 12 in "Item 8. Financial Statements and Supplementary Data" and in "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

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 OG&E's financial objectives.

Pension and Postretirement Benefit Plans

OGE Energy made a $20.0 million contribution to its Pension Plan in both 2017 and 2016, of which four million is related to OG&E in 2017 compared to no contributions related to OG&E in 2016. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2018. See "Future Capital Requirements" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for further discussion of OGE Energy's pension and postretirement benefit plans.

Financing Activities and Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of OGE Energy's common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities.  OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.


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Short-Term Debt and Credit Facility

Short-term borrowings generally are used to meet working capital requirements. OG&E borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. At December 31, 2017, there were $112.5 million in advances to OGE Energy compared to $49.9 million in advances from OGE Energy at December 31, 2016. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $350.0 million of OGE Energy's revolving credit amount.  This agreement has a termination date of March 8, 2022.  On March 8, 2017, OG&E entered into a new $450.0 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility. There were no outstanding borrowings under this revolving credit agreement at December 31, 2017. At December 31, 2017, there was $0.3 million supporting letters of credit at a weighted-average interest rate of 0.95 percent. There were no outstanding commercial paper borrowings at December 31, 2017.  At December 31, 2017, OG&E had $449.7 million of net available liquidity under its revolving credit agreement. 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. See Note 10 in "Item 8. Financial Statements and Supplementary Data" for further discussion.

Issuance of Long-Term Debt

In March 2017, OG&E issued $300.0 million of 4.15 percent senior notes due April 1, 2047. The proceeds from the issuance were used for general corporate purposes, including to repay short-term debt, to repay borrowings under the revolving credit facility, to fund the payment of OG&E's $125.0 million of 6.5 percent senior notes that matured on July 15, 2017 and to fund ongoing capital expenditures and working capital.

In August 2017, OG&E issued $300.0 million of 3.85 percent senior notes due August 15, 2047. The proceeds from the issuance were used for general corporate purposes, including to repay short-term debt, to repay borrowings under the revolving credit facility and to fund ongoing capital expenditures and working capital.

EMPLOYEES
OG&E had 1,856 employees at December 31, 2017.

EXECUTIVE OFFICERS
The following persons were Executive Officers of the Registrant as of February 21, 2018:
Name
Age
Title
Sean Trauschke
50
Chairman of the Board, President and Chief Executive Officer
E. Keith Mitchell
55
Chief Operating Officer
Stephen E. Merrill
53
Chief Financial Officer
Scott Forbes (A)
60
Controller and Chief Accounting Officer
Patricia D. Horn
59
Vice President - Governance and Corporate Secretary
Jean C. Leger, Jr.
59
Vice President - Utility Operations
Kenneth R. Grant
51
Vice President- Sales and Marketing
Cristina F. McQuistion
53
Vice President - Chief Information Officer
Jerry A. Peace
55
Vice President - Integrated Resource Planning and Development
Sarah R. Stafford (A)
36
Accounting Research Officer
William H. Sultemeier
50
General Counsel
Charles B. Walworth
43
Treasurer
(A) Mr. Forbes is resigning as Controller and Chief Accounting Officer, effective as of February 28, 2018. Ms. Stafford will succeed Mr. Forbes as Controller and Chief Accounting Officer, effective March 1, 2018. Ms. Stafford was not an Executive Officer as of February 21, 2018.

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Trauschke, Merrill, Forbes, Sultemeier, Walworth and Ms. Horn are also officers of OGE Energy. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareholders of OGE Energy, currently scheduled for May 17, 2018.

Messrs. Trauschke and Merrill are members of the Board of Directors of Enable GP, LLC, the general partner of Enable.

12






The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
Name
Business Experience
Sean Trauschke
2015 - Present:
Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp.
 
2014 - 2015:
President of OGE Energy Corp.
 
2013 - 2014:
Vice President and Chief Financial Officer of OGE Energy Corp.
E. Keith Mitchell
2015 - Present:
Chief Operating Officer of OG&E
 
2013 - 2015:
Executive Vice President and Chief Operating Officer of Enable Midstream Partners, LP
 
2013:
President and Chief Operating Officer of Enogex Holdings; President of Enogex LLC
Stephen E. Merrill
2014 - Present:
Chief Financial Officer of OGE Energy Corp.
 
2013 - 2014:
Executive Vice President of Finance and Chief Administrative Officer of Enable Midstream Partners, LP
 
2013:
Chief Operating Officer of Enogex LLC
Scott Forbes
2013 - Present:
Controller and Chief Accounting Officer of OGE Energy Corp.
Patricia D. Horn
2014 - Present:
Vice President - Governance and Corporate Secretary of OGE Energy Corp.
 
2013 - 2014:
Vice President - Governance, Environmental and Corporate Secretary of OGE Energy Corp.
Jean C. Leger, Jr.
2013 - Present:
Vice President - Utility Operations of OG&E
Kenneth R. Grant
2016 - Present:
Vice President - Sales and Marketing of OG&E
 
2015:
Vice President Marketing and Product Development of OG&E
 
2013 - 2015:
Managing Director Tech Solutions & Ops of OG&E
 
2013:
Managing Director Customer Solutions of OG&E
Cristina F. McQuistion
2017 - Present:
Vice President - Chief Information Officer of OG&E
 
2016 - 2017:
Vice President - Chief Information Officer and Utility Strategy of OG&E

2014 - 2015:
Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OG&E

2013 - 2014:
Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OGE Energy Corp. and OG&E
Jerry A. Peace
2016 - Present:
Vice President - Integrated Resource Planning and Development of OG&E

2014 - 2015:
Chief Generation Planning and Procurement Officer of OG&E

2013 - 2014:
Chief Risk Officer of OGE Energy Corp.
Sarah R. Stafford (A)
2016 - Present:
Accounting Research Officer of OGE Energy Corp.
 
2013 - 2016:
Senior Manager - Ernst & Young, LLP
William H. Sultemeier
2017 - Present:
General Counsel of OGE Energy Corp.
 
2016:
Partner - Jones Day
 
2013-2015:
Shareholder - Greenberg Traurig, LLP
Charles B. Walworth
2014 - Present:
Treasurer of OGE Energy Corp.
 
2013 - 2014:
Assistant Treasurer of OGE Energy Corp.
(A) Ms. Stafford was not an Executive Officer as of February 21, 2018.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

OGE Energy's website address is www.oge.com. Through OGE Energy's website under the heading "Investors," "Investor Relations," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's 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.


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Item 1A.  Risk Factors.
 
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to OG&E. In addition to the other information in this Form 10-K and other documents filed by us with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OG&E.  Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us.  Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

REGULATORY RISKS
 
OG&E's profitability depends to a large extent on the ability to fully recover its costs from its customers in a timely manner, and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.

OG&E is subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk.  The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers in a timely manner. Any failure to obtain utility commission approval to increase rates to fully recover costs, or a delay in the receipt of such approval, could have an adverse impact on OG&E's results of operations. In addition, OG&E's jurisdictions have fuel adjustment clauses that permit OG&E to recover fuel costs through rates without a general rate case, subject to a later determination that such fuel costs were prudently incurred. If the state regulatory commissions determine that the fuel costs were not prudently incurred, recovery could be disallowed.
 
In recent years, the regulatory environments in which OG&E operates have received an increased amount of attention.  It is possible that there could be changes in the regulatory environment that would impair OG&E's ability to fully recover costs historically paid by OG&E's customers.  State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met.  OG&E cannot assure that the OCC, APSC and the FERC will grant rate increases in the future or in the amounts requested, and they could instead lower OG&E's rates.
 
OG&E is unable to predict the impact on its operating results from future regulatory activities of any of the agencies that regulate OG&E.  Changes in regulations or the imposition of additional regulations could have an adverse impact on OG&E's results of operations.

OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a federal agency, whose regulatory paradigms and goals may not be consistent.
 
OG&E is currently a vertically integrated electric utility. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission.
 
OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to FERC regulation of its transmission activities and any wholesale sales.  Exposure to inconsistent state and federal regulatory standards may limit our ability to operate profitably.  Further alteration of the regulatory landscape in which we operate, including a change in our authorized return on equity, may harm our financial position and results of operations.

Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position or liquidity.

We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs.  There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.  

In response to recent regulatory and judicial decisions and international accords, emissions of greenhouse gases including, most significantly, CO2 could be restricted in the future as a result of federal or state legal requirements or litigation relating to greenhouse gas emissions. No rules are currently in effect that require us to reduce our greenhouse gas emissions, but if such

14


rules were to become effective, they could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry operations practices. These activities are subject to stringent and complex federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way OG&E can handle or dispose of its wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. OG&E may be unable to recover these costs from insurance or other regulatory mechanisms.  Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
 
For further discussion of environmental matters that may affect OG&E, see "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
 
OG&E's business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives.  Significant portions of OG&E's facilities were constructed many years ago.  Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment.  This could adversely affect OG&E's financial position and results of operations.  While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.  

As of December 31, 2017, OG&E had invested $401.3 million in the Dry Scrubbers and $348.4 million in the Mustang Modernization Plan.

The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.  

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. The SPP has implemented regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights.  Collectively the three markets operate together under the global name, SPP Integrated Marketplace.  OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers.  OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities.  OG&E records the SPP Integrated Marketplace transactions as sales or purchases with results reported as Operating Revenues or Cost of Sales in its Financial Statements. OG&E's revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP. 

Increased competition resulting from restructuring efforts could have a significant financial impact on OG&E and consequently decrease our revenue.
 
We have been and will continue to be affected by competitive changes to the utility and energy industries.  Significant changes have occurred and additional changes have been proposed to the wholesale electric market.  Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, lower profit margins and/or increased costs of capital.  Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows.


15


Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry.  Governmental and market reactions to these events may have negative impacts on our business, financial position, results of operations, cash flows and access to capital.
 
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion.  The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors.  The capital markets and rating agencies also have increased their level of scrutiny.  We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, financial position, cash flows or access to the capital markets.  It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically.  Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity.  These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our financial position, results of operations and cash flows.
 
We are subject to substantial utility and energy regulation by governmental agencies.  Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
 
We are subject to substantial regulation from federal, state and local regulatory agencies.  We are required to comply with numerous laws and regulations and to obtain permits, approvals and certifications from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities.  We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
 
In compliance with the Energy Policy Act of 2005, the FERC approved the NERC as the national energy reliability organization. The NERC is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur.  One of OG&E's regulators, NERC, has comprehensive regulations and standards related to the reliability and security of our operating systems, and is continuously developing additional mandatory compliance requirements for the utility industry. The increasing development of NERC rules and standards will increase compliance costs and our exposure for potential violations of these standards.

OPERATIONAL RISKS
 
Our results of operations may be impacted by disruptions beyond our control.
 
We are exposed to risks related to performance of contractual obligations by our suppliers.  We are dependent on coal and natural gas for much of our electric generating capacity.  We rely on suppliers to deliver coal and natural gas in accordance with short and long-term contracts.  We have certain supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal and natural gas to us.  The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us.  In addition, the suppliers under these agreements may not be required to supply coal and natural gas to us under certain circumstances, such as in the event of a natural disaster.  Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment.  Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
 
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm or generator or transmission facility outage on a neighboring system or the actions of a neighboring utility.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position, results of operations and cash flows.


16


OG&E's electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power costs.  

OG&E owns and operates coal-fired, natural gas-fired, wind-powered and solar-powered generating facilities.  Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels.  Included among these risks are:

increased prices for fuel and fuel transportation as existing contracts expire;
facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
operator error or safety related stoppages;
disruptions in the delivery of electricity; and
catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.

When unplanned maintenance work is required on power plants or other equipment, OG&E will not only incur unexpected maintenance expenses, but it may also have to make spot market purchases of replacement electricity that could exceed OG&E's costs of generation or be forced to retire a generation unit if the cost or timing of the maintenance is not reasonable and prudent. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.

Changes in technology, regulatory policies and customer electricity consumption may cause our generating facilities to be less competitive and impact our results of operations.

OG&E primarily generates electricity at large central facilities. This method typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations. OG&E's widespread use of Smart Grid technology allowing for two-way communications between the utility and its customers could enable the entry of technology companies into the interface between OG&E and its customers, resulting in unpredictable effects on our current business.

Reductions in customer electricity consumption, thereby reducing utility electric sales, could result from increased deployment of renewable energy technologies as well as increased efficiency of household appliances, among other general efficiency gains in technology. However, this potential reduction in load would not reduce our need for ongoing investments in our infrastructure to reliably serve our customers. Continued utility infrastructure investment without increased electricity sales could cause increased rates for customers, potentially resulting in further reductions in electricity sales and reduced profitability.

Economic conditions could negatively impact our business and our results of operations.
 
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets.  A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.
 
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt.  If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
 
In addition, economic conditions, particularly budget shortfalls, could increase the pressure on federal, state and local governments to raise additional funds by increasing corporate tax rates and/or delaying, reducing or eliminating tax credits, grants or other incentives that could have a material adverse impact on our results of operations and cash flows.
 

17


We are subject to financial risks associated with climate change.

Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to OG&E. In addition, to the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory imposed costs, CO2 taxes or costs associated with additional regulatory requirements, OG&E may be adversely impacted. A declining economy could adversely impact the overall financial health of OG&E due to a lack of load growth and decreased sales opportunities. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

We are subject to cybersecurity risks and increased reliance on processes automated by technology.

In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems which may result in a loss of service to customers and also subjects OG&E to financial harm due to the significant expense to repair security breaches or system damage. The implementation of OG&E's Smart Grid program further increases potential risks associated with cybersecurity attacks. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on its financial position, results of operations and cash flows.
Our security procedures, which include among others, virus protection software, cybersecurity and our business continuity planning, including disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse effect of cybersecurity attacks on our systems, which could adversely impact our operations.
We maintain property, casualty and cybersecurity insurance that may cover certain resultant physical damage or third-party injuries caused by potential cyber events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities or sustained military campaigns may adversely impact our financial position, results of operations and cash flows.
 
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities or sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain.  Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.


18


Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, earthquakes and prolonged droughts, as well as seasonal temperature variations may adversely affect our financial position, results of operations and cash flows.
 
Weather conditions directly influence the demand for electric power.  In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time.  As a result, overall operating results may fluctuate on a seasonal and quarterly basis.  In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder.  Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability.  Severe weather, such as tornadoes, thunderstorms, ice storms, wind storms, earthquakes and prolonged droughts may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers.  The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period. In addition, prolonged droughts could cause a lack of sufficient water for use in cooling during the electricity generating process. Additionally, if climate change exacerbates physical changes in weather, operations may be impacted as discussed above.

FINANCIAL RISKS
 
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our financial position, results of operations or cash flows.
 
OGE Energy has a Pension Plan that covers a significant amount of our employees hired before December 1, 2009.  OGE Energy also has defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1, 2000.  Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements.  Based on our assumptions at December 31, 2017, OGE Energy expects to make future contributions to maintain required funding levels.  It has been OGE Energy's practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. OGE Energy may continue to make voluntary contributions in the future.  These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
 
If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates.  In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our financial position and results of operations.  Those factors are outside of our control.
 
In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years.  We believe that our employee benefit costs, including costs related to health care plans for our employees, will continue to rise.  The increasing costs and funding requirements with our Pension Plan, health care plans and other employee benefits may adversely affect our financial position, results of operations or liquidity.

We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
 
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average.  Over the next three years, 35 percent of our current employees will meet the eligibility requirements to retire.  Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.

We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
 
The terms of the indentures governing our debt securities do not fully prohibit us from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreement and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we now face may intensify.


19


Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
 
We cannot assure you that any of our current credit 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 so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
 
We have a revolving credit agreement for working capital, capital expenditures, acquisitions and other corporate purposes.  The levels of our debt could have important consequences, including the following:

the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
our debt levels may limit our flexibility in responding to changing business and economic conditions.

We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
 
We are exposed to credit risks in our generation and retail distribution operations.  Credit risk includes the risk that counterparties who owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
  
Item 1B.  Unresolved Staff Comments.
 
None.


20





Item 2.  Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 10 generating stations with an aggregate capability of 6,304 MWs at December 31, 2017. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
 
 
 
 
 
2017 Capacity Factor (A)
 
Unit Capability (MW)
Station Capability (MW)
 
 
Year Installed
 
Fuel Capability
 
Station & Unit
 
Unit Design Type
 
Seminole
1
1971
Steam-Turbine
Gas
6.0
%
 
434

 
 
2
1973
Steam-Turbine
Gas
8.0
%
 
430

 
 
3
1975
Steam-Turbine
Gas/Oil
8.5
%
 
456

1,320

Muskogee
4
1977
Steam-Turbine
Coal
49.2
%
 
493

 
 
5
1978
Steam-Turbine
Coal
36.8
%
 
498

 
 
6
1984
Steam-Turbine
Coal
55.5
%
 
518

1,509

Sooner
1
1979
Steam-Turbine
Coal
39.0
%
 
520

 
 
2
1980
Steam-Turbine
Coal
38.2
%
 
519

1,039

Horseshoe Lake
6
1958
Steam-Turbine
Gas/Oil
4.1
%
 
167

 
 
7
1963
Combined Cycle
Gas/Oil
4.5
%
 
214

 
 
8
1969
Steam-Turbine
Gas
3.5
%
 
397

 
 
9
2000
Combustion-Turbine
Gas
9.7
%

45

 
 
10
2000
Combustion-Turbine
Gas
9.6
%

43

866

Redbud (B)
1
2003
Combined Cycle
Gas
51.0
%
 
153

 
 
2
2003
Combined Cycle
Gas
45.1
%
 
153

 
 
3
2003
Combined Cycle
Gas
48.5
%
 
154

 
 
4
2003
Combined Cycle
Gas
42.9
%
 
153

613

Mustang (C)
5A
1971
Combustion-Turbine
Gas/Jet Fuel
0.5
%
 
33

 
 
5B
1971
Combustion-Turbine
Gas/Jet Fuel
0.5
%
 
32

 
 
8
2017
Combustion-Turbine
Gas
%

60

125

McClain (D)
1
2001
Combined Cycle
Gas
80.5
%
 
380

380

Total Generating Capability (all stations, excluding renewable)
5,852

 
 
 
 
 
 
 
 
 
Renewable
 
 
 
 
 
2017 Capacity Factor (A)
Unit Capability (MW)
Station Capability (MW)
 
 
Year Installed
 
Number of Units
Fuel Capability
Station
 
Location
Crossroads
 
2011
Canton, OK
98
Wind
40.9
%
2.3

228

Centennial
 
2007
Laverne, OK
80
Wind
23.3
%
1.5

120

OU Spirit
 
2009
Woodward, OK
44
Wind
34.8
%
2.3

101

Mustang
 
2015
Oklahoma City, OK
90
Solar
22.5
%

3

Total Generating Capability (renewable)
452

(A)
 2017 Capacity Factor = 2017 Net Actual Generation / (2017 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours))
(B)
Represents OG&E's 51 percent ownership interest in the Redbud Plant.
(C)
On December 31, 2017, Mustang units 3 and 4 were retired. On December 30, 2017, Mustang unit 8, the first of seven efficient combustion turbines installed as part of the Mustang Modernization Plan, was placed in service. OG&E expects units 6, 7, 9, 10, 11 and 12 to be placed in service at various times during the first quarter of 2018.
(D)
Represents OG&E's 77 percent ownership interest in the McClain Plant.

At December 31, 2017, OG&E's transmission system included: (i) 52 substations with a total capacity of 13.3 million kV-amps and 4,949 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.9 million kV-amps and 277 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 346 substations with a total capacity of 9.7 million kV-amps, 29,317 structure miles of overhead lines, 2,824 miles of underground conduit and 10,875 miles of underground conductors in Oklahoma and (ii) 30 substations with a total capacity of 0.9 million kV-amps, 2,785 structure miles of overhead lines, 282 miles of underground conduit and 689 miles of underground conductors in Arkansas.


21


OG&E owns 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73102. In addition to its executive offices, OG&E owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, service centers, fleet and equipment service facilities, operation support and other properties.

During the three years ended December 31, 2017, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $1.4 billion, and gross retirements were $290.3 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to 12.5 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2017.

Item 3.  Legal Proceedings.
 
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability.  These generally relate to lawsuits or claims made by third parties, including governmental agencies.  When appropriate, management consults with legal counsel and other experts to assess the claim.  If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.

Item 4.  Mine Safety Disclosures.

Not Applicable.

PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.
In 2017, 2016 and 2015, OG&E declared dividends to OGE Energy of $105.0 million, $190.0 million and $120.0 million, respectively.

22


Item 6. Selected Financial Data.

HISTORICAL DATA

Year Ended December 31 (In millions)
2017
2016
2015
2014
2013
SELECTED FINANCIAL DATA
 
 
 
 
 
Results of Operations Data
 
 
 
 
 
Operating revenues
$
2,261.1

$
2,259.2

$
2,196.9

$
2,453.1

$
2,262.2

Cost of sales
897.6

880.1

865.0

1,106.6

965.9

Operating expenses
851.8

870.2

831.5

808.5

771.0

Operating income
511.7

508.9

500.4

538.0

525.3

Allowance for equity funds used during construction
39.7

14.2

8.3

4.2

6.6

Other income
36.6

16.4

13.3

4.8

8.1

Other expense
2.3

2.9

1.6

1.9

4.6

Interest expense
138.4

138.1

146.7

141.5

129.3

Income tax expense
141.8

114.4

104.8

111.6

113.5

Net income
$
305.5

$
284.1

$
268.9

$
292.0

$
292.6

Balance Sheet Data (at period end)
 
 
 
 
 
Property, plant and equipment, net
$
8,333.8

$
7,681.8

$
7,296.1

$
6,941.5

$
6,634.6

Total assets
$
9,255.6

$
8,669.4

$
8,525.5

$
8,248.9

$
7,680.7

Long-term debt
$
2,999.4

$
2,530.8

$
2,639.3

$
2,638.0

$
2,286.0

Total stockholder's equity
$
3,455.7

$
3,252.1

$
3,155.7

$
3,004.2

$
2,829.3

Capitalization Ratios (A)
 
 
 
 
 
Stockholder's equity
53.5
%
56.2
%
54.3
%
53.1
%
55.2
%
Long-term debt
46.5
%
43.8
%
45.7
%
46.9
%
44.8
%
Ratio of Earnings to Fixed Charges (B)
 
 
 
 
 
Ratio of earnings to fixed charges
3.71

3.64

3.40

3.73

3.96

(A)
Capitalization ratios = [Total stockholder's equity / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)].
(B)
For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction and (ii) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.



23





Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations.

Introduction
 
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western ArkansasIts operations 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. 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. OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S.

Overview
 
OG&E Mission and Focus

OGE Energy'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.

OG&E is focused on:

providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity;
providing safe, reliable energy to the communities and customers we serve, with a particular focus on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments;
having strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members;
continuing to grow a zero-injury culture and deliver top-quartile safety results;
complying with the EPA's Regional Haze Rule requirements;
ensuring we have the necessary mix of generation resources to meet the long-term needs of our customers; and
continuing focus on operational excellence and efficiencies in order to protect the customer bill.

Summary of Operating Results

2017 compared to 2016. OG&E reported net income of $305.5 million and $284.1 million, respectively, in 2017 and 2016, an increase of $21.4 million, or 7.5 percent, primarily due to higher net other income and lower depreciation and amortization expense as a result of the March 2017 OCC rate order mandating a reduction in depreciation rates, partially offset by higher income tax expense, higher operation and maintenance expense and lower gross margin primarily due to milder weather.

2016 compared to 2015. OG&E reported net income of $284.1 million and $268.9 million, respectively, in 2016 and 2015, an increase of $15.2 million, or 5.7 percent, primarily due to an increase in gross margin related to warmer summer weather and increased wholesale transmission revenues and an increase in other income. Partially offsetting these items was an increase in other operation and maintenance expense, an increase in depreciation expense due to additional assets being placed in service and an increase in income tax expense.

2018 Outlook

OG&E projects to earn approximately $286 million to $306 million or $1.43 to $1.53 per average diluted share in 2018 and is based on the following assumptions:

normal weather patterns are experienced for the remainder of the year;
gross margin on revenues of approximately $1.380 billion to $1.390 billion based on sales growth of approximately one percent on a weather-adjusted basis;
operating expenses of approximately $927 million to $937 million, with operation and maintenance expenses comprising approximately 53 percent of the total;
interest expense of approximately $152 million to $155 million which assumes an $11 million allowance for borrowed funds used during construction reduction to interest expense and assumes a debt refinancing of $250 million in the second half of 2018;

24





other income of approximately $33 million including approximately $21 million of allowance for equity funds used during construction;
assumes a regulatory asset for the Dry Scrubbers for approximately $9 million, or $0.03 per share;
an effective tax rate of approximately 10.9 percent;
new rates take effect in Oklahoma by August 1, 2018; and
every 25 basis point change in the allowed Oklahoma return on equity equates to a change of approximately $8 million in revenue.

OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

Non-GAAP Financial Measures

Gross margin is defined by OG&E as operating revenues less fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies. For a reconciliation of gross margin to revenue for the years ended December 31, 2017, 2016 and 2015, see OG&E (Electric Utility) Results of Operations below.

Detailed below is a reconciliation of gross margin to revenue included in the 2018 Outlook.

Reconciliation of Gross Margin to Revenue

(In millions)
Twelve Months Ended December 31, 2018
(A)
Operating revenues
$
1,932

Cost of sales
547

Gross margin
$
1,385

(A)
Based on the midpoint of OG&E earnings guidance for 2018.

Results of Operations
 
The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 2017, 2016 and 2015 and OG&E's financial position at December 31, 2017 and 2016.  The following information should be read in conjunction with the Financial Statements and Notes thereto.  Known trends and contingencies of a material nature are discussed to the extent considered relevant.




25





Year Ended December 31 (Dollars in millions)
2017
2016
2015
Operating revenues
$
2,261.1

$
2,259.2

$
2,196.9

Cost of sales
897.6

880.1

865.0

Other operation and maintenance
486.1

469.8

444.5

Depreciation and amortization
280.9

316.4

299.9

Taxes other than income
84.8

84.0

87.1

Operating income
511.7

508.9

500.4

Allowance for equity funds used during construction
39.7

14.2

8.3

Other income
36.6

16.4

13.3

Other expense
2.3

2.9

1.6

Interest expense
138.4

138.1

146.7

Income tax expense
141.8

114.4

104.8

Net income
$
305.5

$
284.1

$
268.9

Operating revenues by classification:
 
 
 
Residential
$
884.1

$
951.9

$
896.5

Commercial
588.3

573.7

535.0

Industrial
200.6

194.6

190.6

Oilfield
159.5

156.9

162.8

Public authorities and street light
208.0

204.3

194.2

Sales for resale
0.2

0.3

21.7

System sales revenues
2,040.7

2,081.7

2,000.8

Provision for rate refund
26.8

(33.6
)

Integrated market
23.5

49.3

48.6

Other
170.1

161.8

147.5

Total operating revenues
$
2,261.1

$
2,259.2

$
2,196.9

Reconciliation of gross margin to revenue
 
 
 
Operating revenues
$
2,261.1

$
2,259.2

$
2,196.9

Cost of sales
897.6

880.1

865.0

Gross margin
$
1,363.5

$
1,379.1

$
1,331.9

MWh sales by classification (In millions)
 
 
 
Residential
8.8

9.3

9.2

Commercial
7.6

7.6

7.4

Industrial
3.6

3.6

3.6

Oilfield
3.2

3.2

3.4

Public authorities and street light
3.1

3.2

3.1

Sales for resale


0.5

System sales
26.3

26.9

27.2

Integrated market
1.8

3.0

1.7

Total sales
28.1

29.9

28.9

Number of customers
841,830

833,582

824,776

Weighted-average cost of energy per kilowatt-hour (In cents)
 
 
 
Natural gas
2.821

2.488

2.529

Coal
2.069

2.213

2.187

Total fuel
2.211

2.199

2.196

Total fuel and purchased power
3.049

2.842

2.874

Degree days (A)
 
 
 
Heating - Actual
2,877

2,800

3,038

Heating - Normal
3,349

3,349

3,349

Cooling - Actual
1,944

2,247

2,071

Cooling - Normal
2,092

2,092

2,092

(A)
Degree days are calculated as follows:  The high and low degrees of a particular day are added together and then averaged.  If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day.  If the calculated average is below 65 degrees, then the difference between the

26





calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day.  The daily calculations are then totaled for the particular reporting period.

2017 compared to 2016. OG&E's net income increased $21.4 million, or 7.5 percent, in 2017 as compared to 2016 primarily due to lower depreciation and amortization expense as a result of the March 2017 OCC rate order mandating a reduction in depreciation rates, higher allowance for equity funds used during construction, higher other income and higher allowance for borrowed funds used during construction, partially offset by higher income tax expense, higher operation and maintenance expense, lower gross margin and higher interest on long-term debt.
Gross margin was $1,363.5 million in 2017 as compared to $1,379.1 million in 2016, a decrease of $15.6 million, or 1.1 percent. The below factors contributed to the change in gross margin:
(In millions)
Change
Weather (price and quantity) (A)
$
(15.1
)
Price variance (B)
(13.9
)
Wholesale transmission revenue
(8.1
)
New customer growth
14.2

Non-residential demand and related revenues
5.0

Industrial and oilfield sales
2.2

Other
0.1

Change in gross margin
$
(15.6
)
(A)
Cooling degree days decreased approximately 13 percent in 2017.
(B)
Decreased primarily due to additional reserves for rate refunds in both Oklahoma and Arkansas, as well as riders moving to base rates in the March 2017 OCC rate order.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. OG&E's cost of sales increased $17.5 million, or 2.0 percent, in 2017 as compared to 2016. The changes are detailed in the table below.
(In millions)
Change
Fuel expense (A)
$
(61.5
)
Purchased power costs:
 
Purchases from SPP (B)
74.4

Wind
0.2

Cogeneration
(9.5
)
Transmission expense (C)
13.9

Change in cost of sales
$
17.5

(A)
Decrease in fuel expense was primarily due to decreased utilization of company-owned generation.
(B)
Increase in the cost of purchases from the SPP was due to an increase of 26.8 percent in MWh purchased and an increase of 16.2 percent in cost per MWhs purchased. The increase in cost per MWh purchased was due to an increase in fuel prices and higher grid congestion costs during 2017.
(C)
Increase in transmission-related charges was primarily due to higher SPP charges for the base plan projects of other utilities.


27





Other operation and maintenance expense increased $16.3 million, or 3.5 percent, in 2017 as compared to 2016. The below factors contributed to the change in other operation and maintenance expense:
(In millions)
Change
Vegetation management
$
14.5

Other
9.2

Capitalized labor (A)
(7.4
)
Change in other operation and maintenance expense
$
16.3

(A)
Increased during 2017 primarily due to more storm costs exceeding the $2.7 million OCC-allowed threshold, which were moved to a regulatory asset, as well as mutual assistance, which was provided in the aftermath of Hurricanes Harvey and Irma.

Depreciation and amortization expense decreased $35.5 million, or 11.2 percent, primarily due to lower depreciation expense related to the reduction in depreciation rates approved in the March 2017 OCC rate order as discussed in Note 13 in "Item 8. Financial Statements and Supplementary Data," partially offset by additional assets being placed into service.
 
Allowance for equity funds used during construction increased $25.5 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other income increased $20.2 million, primarily due to an increase in the tax gross-up related to higher allowance for funds used during construction and an increase in gains on guaranteed flat bill margins.

Allowance for borrowed funds used during construction increased $10.5 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Income tax expense increased $27.4 million, or 24.0 percent, primarily due to higher pre-tax operating income and lower tax credits generated.
2016 compared to 2015.  OG&E's net income increased $15.2 million, or 5.7 percent, in 2016 as compared to 2015, primarily due to an increase in gross margin related to warmer summer weather and increased transmission revenues and an increase in other income, partially offset by increases in other operation and maintenance expense, depreciation expense and income tax expense. 


28






Gross margin was $1,379.1 million in 2016 as compared to $1,331.9 million in 2015, an increase of $47.2 million, or 3.5 percent. The below factors contributed to the change in gross margin:
(In millions)
Change
Interim rate increase - Oklahoma (A)
$
39.0

Reserve for rate refund (A)
(33.7
)
Wholesale transmission revenue (B)
20.3

Price variance (C)
18.1

Quantity variance (primarily weather)
13.1

New customer growth
3.2

Non-residential demand and related revenues
0.6

Expiration of AVEC contract (D)
(9.7
)
Other
(3.7
)
Change in gross margin
$
47.2

(A)
As discussed in Note 13 in "Item 8. Financial Statements and Supplementary Data," on July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million. Interim rates are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the general rate case.
(B)
Increased primarily due to the SPP's settlement of revenue credits related to the Windspeed Transmission line for the years 2008 through August 2016. Other increases include a recovery of the base plan projects in the SPP formula rate for 2015 and 2016.
(C)
Increased primarily due to the reversal of a reserve for gas transportation charges in addition to the pricing impact of weather related sales.
(D)
On June 30, 2015, the wholesale power contract with AVEC expired.

OG&E's cost of sales increased $15.1 million, or 1.7 percent, in 2016 as compared to 2015. The changes are detailed in the table below.
(In millions)
Change
Fuel expense (A)
$
12.2

Purchased power costs:
 
Purchases from SPP (B)
(12.3
)
Wind

Cogeneration

Transmission expense (C)
15.2

Change in cost of sales
$
15.1

(A)
Increased primarily due to higher volumes of natural gas used partially offset by lower natural gas prices. In 2016, OG&E's fuel mix was 48.0 percent coal, 45.3 percent natural gas and 6.7 percent wind. In 2015, OG&E's fuel mix was 49.0 percent coal, 44.0 percent natural gas and seven percent wind.
(B)
Decreased primarily due to a decrease in purchases from the SPP.
(C)
Increased primarily due to higher SPP charges for the base plan projects of other utilities and SPP charges for the Windspeed Transmission line for the years 2008 through August 2016.
 

29





Other operation and maintenance expense increased $25.3 million, or 5.7 percent, in 2016 as compared to 2015. The below factors contributed to the change in other operation and maintenance expense:
(In millions)
Change
Salaries and wages (A)
$
10.4

Contract professional services (B)
8.7

Corporate allocations and overheads (C)
8.1

Other
(1.9
)
Change in other operation and maintenance expense
$
25.3

(A)
Increased primarily due to increases in incentive compensation, pension expense, annual salaries and medical/dental expense, partially offset by a decrease in overtime.
(B)
Increased primarily due to increased consulting costs associated with demand side management programs.
(C)
Increased primarily due to additional direct support in information technology, facility direct support, strategy and marketing support.

Depreciation and amortization expense increased $16.5 million, or 5.5 percent, primarily due to additional assets being placed in service and amortization of deferred storm costs.

Taxes other than income taxes decreased $3.1 million, or 3.6 percent, due to increased capitalization of ad valorem taxes primarily associated with environmental projects.

Allowance for equity funds used during construction increased $5.9 million, or 71.1 percent, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other income increased $3.1 million, or 23.3 percent, primarily due to an increase in the tax gross-up related to higher allowance for equity funds used during construction and an increase in interest income related to riders, partially offset by decreased guaranteed flat bill margins.

Other expense increased $1.3 million, or 81.3 percent, primarily due to increased other miscellaneous expenses, increased charitable donations during 2016 and an increase in consulting services.

Interest expense decreased $8.6 million, or 5.9 percent, primarily due to the retirement of senior notes in January 2016, partially offset by increased allowance for borrowed funds used during construction primarily associated with environmental projects.

Income tax expense increased $9.6 million, or 9.2 percent, primarily due to higher pre-tax operating income in addition to lower renewable energy credits.

Off-Balance Sheet Arrangement

Railcar Lease Agreement
 
OG&E has a noncancellable operating lease with a purchase option, covering 1,243 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units.  Rental payments are charged to fuel expense and are recovered through OG&E's tariffs and fuel adjustment clauses.
 
On December 17, 2015, OG&E renewed the lease agreement effective February 1, 2016.  At the end of the new lease term, which is February 1, 2019, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease.  If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $18.2 million. OG&E is also required to maintain all of the railcars it has under the operating lease.


30





Liquidity and Capital Resources

Working Capital
 
Working capital is defined as the difference in current assets and current liabilities. OG&E's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to and the timing of collections from customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.

Accounts Receivable and Accrued Unbilled Revenues. The balance of Accounts Receivable and Accrued Unbilled Revenues was $255.0 million and $232.7 million at December 31, 2017 and 2016, respectively, an increase of $22.3 million, or 9.6 percent, primarily due to an increase in billings to OG&E's retail customers.

Advances to Parent/Advances from Parent. The balance in Advances to Parent was $112.5 million at December 31, 2017 compared to an Advances from Parent balance of $49.9 million at December 31, 2016. The change in Advances with Parent is primarily due to an increase of cash from customers due to increased rates and long-term debt issued in 2017, partially offset by daily operational expenses and capital expenditures.

Other Current Assets. The balance of Other Current Assets was $48.6 million and $78.3 million at December 31, 2017 and 2016, respectively, a decrease of $29.7 million, or 37.9 percent, primarily due to increased revenue collections from customers associated with various rate riders.

Accounts Payable. The balance of Accounts Payable was $216.8 million and $196.4 million at December 31, 2017 and 2016, respectively, an increase of $20.4 million, or 10.4 percent, primarily due to the timing of vendor payments and accruals, partially offset by a decrease in fuel and purchased power payables.

Accrued Compensation. The balance of Accrued Compensation was $25.6 million and $31.3 million at December 31, 2017 and 2016, respectively, a decrease of $5.7 million, or 18.2 percent, primarily due to lower accruals for incentive compensation payouts.

Long-Term Debt Due Within One Year. The balance of Long-Term Debt Due Within One Year was $249.8 million and $125.0 million at December 31, 2017 and 2016, respectively, an increase of $124.8 million, or 99.8 percent, primarily due to the reclassification of long-term debt that will mature on September 1, 2018, partially offset by debt that matured July 15, 2017.

Fuel Clause Recoveries. The balance of Fuel Clause Over Recoveries was $1.7 million at December 31, 2017 compared to a Fuel Clause Under Recoveries balance of $51.3 million at December 31, 2016. The change is primarily due to higher recoveries from OG&E retail customers as compared to the actual cost of fuel and purchased power.

Other Current Liabilities. The balance of Other Current Liabilities was $28.5 million and $95.8 million at December 31, 2017 and 2016, respectively, a decrease of $67.3 million, or 70.3 percent, primarily due to amounts refunded to customers in 2017.

Cash Flows
 
 
 
 
2017 vs. 2016
2016 vs. 2015
Year Ended December 31 (In millions)
2017
2016
2015
$
Change
%
Change
$
Change
%
Change
Net cash provided from operating activities
$
715.7

$
572.9

$
770.5

$
142.8

24.9
%
$
(197.6
)
(25.6
)%
Net cash used in investing activities
(823.4
)
(659.2
)
(549.0
)
(164.2
)
24.9
%
(110.2
)
20.1
 %
Net cash provided from (used in) financing activities
107.7

86.3

(221.5
)
21.4

24.8
%
307.8

*

* Greater than a 100 percent variance.

Operating Activities

The increase of $142.8 million, or 24.9 percent, in net cash provided from operating activities in 2017 as compared to 2016 was primarily due to increased amounts received from customers, primarily due to recovery of fuel costs, partially offset by an increase in vendor payments.


31





The decrease of $197.6 million, or 25.6 percent, in net cash provided from operating activities in 2016 as compared to 2015 was primarily due to a return of cash from fuel over recoveries to customers.

Investing Activities

The increase of $164.2 million, or 24.9 percent, in net cash used in investing activities in 2017 as compared to 2016 was primarily due to an increase in capital expenditures related to environmental projects.

The increase of $110.2 million, or 20.1 percent, in net cash used in investing activities in 2016 as compared to 2015 was primarily due to an increase in capital expenditures related to environmental projects.
 
Financing Activities

The increase of $21.4 million, or 24.8 percent, in net cash provided from financing activities in 2017 as compared to 2016 was primarily due to the issuance of $300.0 million in long-term debt in each of March 2017 and August 2017, partially offset by changes in cash advances with parent.

The increase of $307.8 million in net cash provided from financing activities in 2016 as compared to 2015 was primarily due to an increase in net advances with OGE Energy partially offset by the payment of $110.0 million in long-term debt during the first quarter of 2016 and an increase in dividend payments.

2017 Capital Requirements, Sources of Financing and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $949.2 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $78.0 million, resulting in total net capital requirements and contractual obligations of $1,027.2 million in 2017, of which $213.9 million was to comply with environmental regulations. This compares to net capital requirements of $770.3 million and net contractual obligations of $81.8 million totaling $852.1 million in 2016, of which $137.9 million was to comply with environmental regulations.
In 2017, OG&E's primary sources of capital were cash generated from operations and proceeds from the issuance of short-term debt. Changes in working capital reflect the seasonal nature of OG&E's business, the revenue lag between billing and collection from customers and fuel inventories.  See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

The Dodd-Frank Act

Derivative instruments have been used at times in managing OG&E's commodity price exposure. The Dodd-Frank Act, among other things, provides for regulation by the Commodity Futures Trading Commission of certain commodity-related contracts. Although OG&E qualifies for an end-user exception from mandatory clearing of commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and could add additional regulatory oversight over its contracting activities.

Future Capital Requirements
 
OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities.  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.  OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings.


32





Capital Expenditures

OG&E's estimates of capital expenditures for the years 2018 through 2022 are shown in the following table.  These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.
(In millions)
2018
2019
2020
2021
2022
Transmission (A)
$
90

$
50

$
50

$
50

$
50

Distribution:
 
 
 
 
 
Oklahoma
215

165

165

165

165

Arkansas
10

20

50

60

60

Generation
55

130

95

75

75

Other
50

25

25

25

25

Total Transmission, Distribution, Generation and Other
420

390

385

375

375

Projects:
 
 
 
 
 
Environmental - Dry Scrubbers (B)
95

20




Combustion turbines - Mustang
35





Environmental - natural gas conversion (B)
35

15




Allowance of funds used during construction and ad valorem taxes
40





Grid modernization, reliability, resiliency, technology and other

200

190

280

180

Total Projects
205

235

190

280

180

Total
$
625

$
625

$
575

$
655

$
555

(A)
Future transmission capital expenditures include the following:
Project Type
Project Description
Estimated Cost
(In millions)
Projected In-Service Date
Integrated Transmission Project
126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation and construction of the Mathewson substation on this transmission line. $150.0 million has been spent prior to 2018.
$158
First quarter 2018
(B)
Represent capital costs associated with OG&E’s ECP to comply with the EPA’s Regional Haze Rule. More detailed discussion regarding the Regional Haze Rule and OG&E’s ECP can be found in Note 12 in "Item 8. Financial Statements and Supplementary Data" and in "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

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 OG&E's financial objectives. 


33





Contractual Obligations
 
The following table summarizes OG&E's contractual obligations at December 31, 2017.  See OG&E's Statements of Capitalization and Note 12 in "Item 8. Financial Statements and Supplementary Data" for additional information.
(In millions)
2018
2019-2020
2021-2022
After 2022
Total
Maturities of long-term debt (A)
$
250.1

$
250.2

$
0.2

$
2,529.6

$
3,030.1

Operating lease obligations:
 
 
 
 
 
Railcars
1.7

20.9



22.6

Wind farm land leases
2.5

5.4

5.8

40.6

54.3

Total operating lease obligations
4.2

26.3

5.8

40.6

76.9

Other purchase obligations and commitments:
 
 
 
 
 
Cogeneration capacity and fixed operation and maintenance payments
72.8

118.5

94.9

1.6

287.8

Expected cogeneration energy payments
35.7

71.5

75.4

0.9

183.5

Minimum fuel purchase commitments
139.8

60.8

49.2

382.7

632.5

Expected wind purchase commitments
58.7

113.4

115.1

505.0

792.2

Long-term service agreement commitments
7.9

44.3

4.8

123.1

180.1

Mustang Modernization expenditures
24.9




24.9

Environmental compliance plan expenditures
63.0

9.1



72.1

Total other purchase obligations and commitments
402.8

417.6

339.4

1,013.3

2,173.1

Total contractual obligations
657.1

694.1

345.4

3,583.5

5,280.1

Amounts recoverable through fuel adjustment clause (B)
(235.9
)
(266.6
)
(239.7
)
(888.6
)
(1,630.8
)
Total contractual obligations, net
$
421.2

$
427.5

$
105.7

$
2,694.9

$
3,649.3

(A)
Maturities of OG&E's long-term debt during the next five years consist of $250.1 million, $250.1 million, $0.1 million, $0.1 million and $0.1 million in 2018, 2019, 2020, 2021 and 2022, respectively.  
(B)
Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's expected cogeneration energy payments, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.

OG&E also has 440 MWs of QF contracts to meet its current and future expected customer needs.  OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.
 
The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses.  Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations.  The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.

Pension and Postretirement Benefit Plans
 
At December 31, 2017, 35.6 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income, other securities and U.S. Treasury notes and bonds as presented in Note 11 in "Item 8. Financial Statements and Supplementary Data."  During 2017, actual returns on the Pension Plan were $64.2 million, compared to expected return on plan assets of $32.8 million.  During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, decreased.  Funding levels are dependent on returns on plan assets and future discount rates. OGE Energy made a $20.0 million contribution to its Pension Plan in both 2017 and 2016, of which four million is related to OG&E in 2017 compared to no contributions related to OG&E in 2016. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2018. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.


34





The following table presents the status of OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2017 and 2016. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheets as discussed in Note 1 in "Item 8. Financial Statements and Supplementary Data." The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
 
Pension Plan
Restoration of Retirement
Income Plan
Postretirement
Benefit Plans
December 31 (In millions)
2017
2016
2017
2016
2017
2016
Benefit obligations
$
510.6

$
500.5

$
4.2

$
4.0

$
115.8

$
166.4

Fair value of plan assets
477.2

457.3



45.2

47.8

Funded status at end of year
$
(33.4
)
$
(43.2
)
$
(4.2
)
$
(4.0
)
$
(70.6
)
$
(118.6
)

Financing Activities and Future Sources of Financing
 
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of OGE Energy's common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities.  OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) 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 Facility
 
At December 31, 2017, there were $112.5 million in advances to OGE Energy compared to $49.9 million in advances from OGE Energy at December 31, 2016. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $350.0 million of OGE Energy's revolving credit amount.  This agreement has a termination date of March 8, 2022.   On March 8, 2017, OG&E entered into a new $450.0 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility. There were no outstanding borrowings under this revolving credit agreement at December 31, 2017. At December 31, 2017, there was $0.3 million supporting letters of credit at a weighted-average interest rate of 0.95 percent.  There were no outstanding commercial paper borrowings at December 31, 2017.  At December 31, 2017, OG&E had $449.7 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to