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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported)
May 17, 2018
 
 
 
 
OGE ENERGY CORP.
(Exact Name of Registrant as Specified in Its Charter)
 
 
Oklahoma
(State or Other Jurisdiction of Incorporation)
 
 
1-12579
73-1481638
(Commission File Number)
(IRS Employer Identification No.)
 
 
321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma
73101-0321
(Address of Principal Executive Offices)
(Zip Code)
 
 
405-553-3000
(Registrant's Telephone Number, Including Area Code)
 
 
(Former Name or Former Address, if Changed Since Last Report)
 
 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
    
* Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
* Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
* Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
* Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR 240.12b-2).
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




Item 5.07. Submission of Matters to a Vote of Security Holders

OGE Energy Corp. (the "Company") is the parent company of Oklahoma Gas and Electric Company, a regulated electric utility with approximately 843,000 customers in Oklahoma and western Arkansas. In addition, the Company holds a 25.6 percent limited partner interest and a 50 percent general partner interest in Enable Midstream Partners, LP.
At the Annual Meeting of Shareholders of the Company held on May 17, 2018, the shareholders:

•
Elected 10 members of the Board of Directors;
•
Ratified the appointment of Ernst & Young LLP as the Company's principal independent accountants for 2018;
•
Approved, on an advisory basis, named executive officer compensation; and
•
Did not approve a shareholder proposal regarding allowing shareholders owning 10 percent of the Company's stock to call special meetings of shareholders.

The number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes as to each of such matters, were as stated below.
Proposal No. 1:
Votes For
Votes Against
Abstentions
Broker Non-Votes
Election of Directors
 
 
 
 
 
 
 
 
 
Terms Expiring in 2019
 
 
 
 
Frank A. Bozich
122,851,167

1,517,051

666,893

34,527,795

James H. Brandi
122,213,583

2,111,434

710,094

34,527,795

Peter D. Clarke
122,978,170

1,402,327

654,614

34,527,795

Luke R. Corbett
121,223,445

3,059,451

752,215

34,527,795

David L. Hauser
122,858,934

1,464,903

711,274

34,527,795

Robert O. Lorenz
121,670,236

2,638,184

726,691

34,527,795

Judy R. McReynolds
122,460,760

1,815,894

758,457

34,527,795

J. Michael Sanner
122,941,795

1,388,187

705,129

34,527,795

Sheila G. Talton
121,150,809

3,209,891

674,411

34,527,795

Sean Trauschke
120,180,192

4,215,780

639,139

34,527,795

 
 
 
 
 
Proposal No. 2:
Votes For
Votes Against
Abstentions
 
Ratification of the appointment of Ernst & Young LLP as the Company's principal independent accountants for 2018
156,430,169

2,306,520

826,217

 
 
 
 
 
 
Proposal No. 3:
Votes For
Votes Against
Abstentions
Broker Non-Votes
Advisory vote to approve named executive officer compensation
119,301,915

4,094,607

1,638,589

34,527,795

 
 
 
 
 
Proposal No. 4:
Votes For
Votes Against
Abstentions
Broker Non-Votes
Shareholder proposal regarding allowing shareholders owning 10 percent of the Company's stock to call special meetings of shareholders
50,847,063

72,683,092

1,504,956

34,527,795






Item 8.01. Other Events

As disclosed in the Company's Quarterly Report on Form 10-Q for the period ended March 31, 2018, effective January 1, 2018, the Company adopted Accounting Standards Update 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" ("ASU 2017-07"). ASU 2017-07 requires entities to bifurcate the components of net benefit expense between those that are attributed to compensation for service and those that are not. The service cost component of benefit expense continues to be presented within operating income, but entities are now required to present the other components of benefit expense as non-operating within the income statement. Additionally, ASU 2017-07 only permits the capitalization of the service cost component of net benefit expense. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs. The Company has presented the elements of net periodic benefit costs in the accompanying Consolidated Statements of Income in accordance with ASU 2017-07.

The following items of the Company's Annual Report on Form 10-K for the year ended December 31, 2017 have been recast to reflect the previously described implementation of ASU 2017-07 and are filed as exhibits to this Current Report on Form 8-K and incorporated herein by reference:

•
Exhibit 99.01
◦Item 6. Selected Financial Data
◦Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
◦Item 8. Financial Statements and Supplementary Data
•
Exhibit 101.INS - XBRL Instance Document
•
Exhibit 101.SCH - XBRL Taxonomy Schema Document
•
Exhibit 101.PRE - XBRL Taxonomy Presentation Linkbase Document
•
Exhibit 101.LAB - XBRL Taxonomy Label Linkable Document
•
Exhibit 101.CAL - XBRL Taxonomy Calculation Linkbase Document
•
Exhibit 101.DEF - XBRL Definition Linkbase Document

The implementation of ASU 2017-07 reflected in the recast financial statements had no effect on the Company's net income for any period. The recast items of the Form 10-K described above have been updated only for the aforementioned implementation of ASU 2017-07. The Company has not otherwise updated for activities or events occurring after the date these items were originally presented. This Current Report on Form 8-K should be read in conjunction with our Form 10-K (except for Items 6, 7 and 8, which are included in this Current Report on Form 8-K) and our other periodic reports on Form 10-Q and Form 8-K.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits
 
 
 
 
 
        Exhibit Number
 
                    Description
 
 
 
 
 
101.INS
 
XBRL Instance Document
101.SCH
 
XBRL Taxonomy Schema Document
101.CAL
 
XBRL Taxonomy Presentation Linkbase Document
101.DEF
 
XBRL Taxonomy Label Linkbase Document
101.LAB
 
XBRL Taxonomy Calculation Linkbase Document
101.PRE
 
XBRL Definition Linkbase Document




SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


 
OGE ENERGY CORP.
 
(Registrant)
 
 
By:
/s/ Sarah R. Stafford
 
Sarah R. Stafford
 
 Controller and Chief Accounting Officer
 
 

May 17, 2018



Exhibit



Exhibit 23.01

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-92423) pertaining to the deferred compensation plan, the Registration Statement (Form S-8 No. 333-104497) pertaining to the employees' stock ownership and retirement savings plan, Registration Statement (Form S-8 No. 333-190406) pertaining to the employees' stock ownership and retirement savings plan, Registration Statement (Form S-8 No. 333-190405) pertaining to the 2013 stock incentive plan, the Registration Statement (Form S-3ASR No. 333-221303) pertaining to the dividend reinvestment and stock purchase plan and the Registration Statement (Form S-3ASR No. 333-213005) pertaining to the common stock and debt securities of our report dated February 21, 2018, except as it relates to the changes due to the application of Accounting Standards Update 2017-07 described in Note 2, as to which the date is May 17, 2018, with respect to the consolidated financial statements and schedule of OGE Energy Corp., and our report dated February 21, 2018, with respect to the effectiveness of internal control over financial reporting of OGE Energy Corp., included in this Current Report on Form 8-K, filed with the Securities and Exchange Commission.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma
May 17, 2018



Exhibit
Exhibit 99.01


OGE Energy Corp.'s (the "Company") audited consolidated financial statements for the years ended December 31, 2015, 2016 and 2017, selected financial data and related Management's Discussion and Analysis of Financial Condition and Results of Operations have been recast to reflect the implementation of Accounting Standards Update 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" ("ASU 2017-07") as discussed in Note 11 in "Item 8. Financial Statements and Supplementary Data." These new presentations have no effect on the Company's reported net income for any period. The revised sections of the Form 10-K included have not otherwise been updated for events occurring after the date of the consolidated financial statements, which were originally presented in the Form 10-K. This Exhibit 99.01 to Form 8-K should be read in conjunction with the Form 10-K (except for Items 6, 7 and 8, which are included) and the Company's other periodic reports on Form 10-Q and Form 8-K. Capitalized words not defined below are defined in the Glossary in the Form 10-K.

Item 6. Selected Financial Data.

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

$
2,259.2

$
2,196.9

$
2,453.1

$
2,867.7

Cost of sales
897.6

880.1

865.0

1,106.6

1,428.9

Operating expenses
832.5

866.1

825.8

805.3

842.3

Operating income
531.0

513.0

506.1

541.2

596.5

Equity in earnings of unconsolidated affiliates
131.2

101.8

15.5

172.6

101.9

Allowance for equity funds used during construction
39.7

14.2

8.3

4.2

6.6

Other net periodic pension and postretirement (cost) benefit
(20.7
)
(9.7
)
(24.9
)
(4.4
)
(43.0
)
Other income
46.4

26.0

27.0

17.8

31.8

Other expense
14.1

16.9

14.3

14.4

22.2

Interest expense
143.8

142.1

149.0

148.4

147.5

Income tax (benefit) expense
(49.3
)
148.1

97.4

172.8

130.3

Net income
619.0

338.2

271.3

395.8

393.8

Less: Net income attributable to noncontrolling interests
—

—

—

—

6.2

Net income attributable to OGE Energy
$
619.0

$
338.2

$
271.3

$
395.8

$
387.6

Basic earnings per average common share attributable to OGE Energy common shareholders
$
3.10

$
1.69

$
1.36

$
1.99

$
1.96

Diluted earnings per average common share attributable to OGE Energy common shareholders
$
3.10

$
1.69

$
1.36

$
1.98

$
1.94

Dividends declared per common share
$
1.27000

$
1.15500

$
1.05000

$
0.95000

$
0.85125

Balance Sheet Data (at period end)
 
 
 
 
 
Property, plant and equipment, net
$
8,339.9

$
7,696.2

$
7,322.4

$
6,979.9

$
6,672.8

Total assets
$
10,412.7

$
9,939.6

$
9,580.6

$
9,509.9

$
9,120.5

Long-term debt
$
2,999.4

$
2,630.5

$
2,738.8

$
2,737.4

$
2,385.9

Total stockholders' equity
$
3,851.1

$
3,443.8

$
3,326.0

$
3,244.4

$
3,037.1

Capitalization Ratios (B)
 
 
 
 
 
Stockholders' equity
56.2
%
56.7
%
54.7
%
54.1
%
55.9
%
Long-term debt
43.8
%
43.3
%
45.3
%
45.9
%
44.1
%
Ratio of Earnings to Fixed Charges (C)
 
 
 
 
 
Ratio of earnings to fixed charges
4.42

4.41

4.12

4.49

3.98


1
Exhibit 99.01

(A)
In May 2013, Enable was formed to own and operate the midstream businesses of OGE Energy and CenterPoint. OGE Energy accounts for its interest in Enable using the equity method of accounting subsequent to the formation of Enable. Prior to May 1, 2013, OGE Energy consolidated the results of Enogex LLC.
(B)
Capitalization ratios = [Total stockholders' equity / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)].
(C)
For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of income from continuing operations before income taxes and equity in earnings of unconsolidated affiliates, plus distributed equity income plus fixed charges, less allowance for borrowed funds used during construction and other capitalized interest 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.


2
Exhibit 99.01

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations.
 
Introduction
 
The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

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

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

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

In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At December 31, 2017, the Company owned 111.0 million common units, or 25.7 percent, of Enable's outstanding common units. For additional information on the Company's equity investment in Enable and related party transactions, see Note 3 in "Item 8. Financial Statements and Supplementary Data."

Over the course of 2015 and continuing into early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. During 2016 and 2017, those prices increased, and have stabilized, but have not rebounded to the pre-2015 levels. Based on these recent commodity prices, Enable has seen changes in producer activity that have negatively impacted Enable's operations and financial position and could see additional changes in producer activity that may negatively impact Enable's operations and affect its future distribution rates. If commodity prices decline further, Enable's future operating results and cash flows could be negatively impacted. A portion of our earnings and operating cash flows depend on the performance of, and distributions from, Enable. As disclosed in this Form 10-K, Enable is subject to a number of risks, including contract renewal risk, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGL and crude oil prices. If any of those risks were to occur, the Company's business, financial condition, results of operations or cash flows could be materially adversely affected.

On February 9, 2018, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions."

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

3
Exhibit 99.01

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.

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

•
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.

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

Summary of Operating Results
2017 compared to 2016. Net income was $619.0 million, or $3.10 per diluted share, in 2017 as compared to $338.2 million, or $1.69 per diluted share, in 2016. The increase in net income of $280.8 million, or 83.0 percent, or $1.41 per diluted share, in 2017 as compared to 2016 was primarily due to:
    
•
an increase in net income at OGE Holdings of $271.5 million, or $1.36 per diluted share of the Company's common stock, primarily due to an income tax benefit of $245.2 million as a result of the 2017 Tax Act and an increase of equity in earnings of Enable; and
•
an increase in net income at OG&E of $21.4 million, or $0.11 per diluted share of the Company's common stock, 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 pension cost and lower gross margin primarily due to milder weather; partially offset by
•
an increase in net loss of other operations of $12.1 million, or $0.06 per diluted share of the Company's common stock, primarily due to income tax expense of $10.5 million as a result of the 2017 Tax Act.


4
Exhibit 99.01

2016 compared to 2015. Net income was $338.2 million, or $1.69 per diluted share, in 2016 as compared to $271.3 million, or $1.36 per diluted share, in 2015. The increase in net income of $66.9 million, or 24.7 percent, or $0.33 per diluted share, in 2016 as compared to 2015 was primarily due to:
    
•
an increase in net income at OGE Holdings of $44.3 million, or $0.22 per diluted share of the Company's common stock, primarily due to the goodwill impairment adjustment at Enable in September 2015, partially offset by higher income tax expense due to higher pre-tax operating income and a change in state tax rates;
•
an increase in net income at OG&E of $15.2 million, or $0.07 per diluted share of the Company's common stock, 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; and
•
an increase in net income of other operations of $7.4 million, or $0.04 per diluted share of the Company's common stock, primarily due to charges in 2015 associated with pre-construction expenditures for cancelled new office space to consolidate Oklahoma City personnel and a decrease in depreciation, partially offset by an increase in interest expense.

A more detailed discussion regarding the financial performance of OG&E and the Natural Gas Midstream Operations can be found under "Results of Operations" below.

OG&E's 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.

Enable's Non-GAAP Financial Measures

Gross margin is defined by Enable as total revenues minus costs of natural gas and NGLs, excluding depreciation and amortization. Total revenues consist of the fees that they charge their customers and the sales price of natural gas and NGLs that they sell. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that they purchase. Enable deducts the cost of natural gas and NGLs from total revenue to arrive at a measure of the core profitability of their mix of fee-based and commodity-based customer arrangements. Gross margin allows for meaningful comparison of the operating results between Enable's fee-based revenues and Enable's commodity-based contracts which involve the purchase or sale of natural gas, NGLs and/or crude oil. In addition, the Company believes gross margin allows for a meaningful comparison of the results of Enable's commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold.


5
Exhibit 99.01

Results of Operations
 
The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the years ended December 31, 2017, 2016 and 2015 and the Company's consolidated financial position at December 31, 2017 and 2016.  The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto.  Known trends and contingencies of a material nature are discussed to the extent considered relevant.
 
Year Ended December 31,
(In millions except per share data)
2017
2016
2015
Net income
$
619.0

$
338.2

$
271.3

Basic average common shares outstanding
199.7

199.7

199.6

Diluted average common shares outstanding
200.0

199.9

199.6

Basic earnings per average common share
$
3.10

$
1.69

$
1.36

Diluted earnings per average common share
$
3.10

$
1.69

$
1.36

Dividends declared per common share
$
1.27000

$
1.15500

$
1.05000

 
Results by Business Segment
 
Year Ended December 31,
(In millions)
2017
2016
2015
Net income (loss):
 
 
 
OG&E (Electric Utility)
$
305.5

$
284.1

$
268.9

OGE Holdings (Natural Gas Midstream Operations) (A)
325.2

53.7

9.4

Other operations (B)
(11.7
)
0.4

(7.0
)
Consolidated net income
$
619.0

$
338.2

$
271.3

(A)
The Company recorded an income tax benefit of $245.2 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes at OGE Holdings, as a result of the 2017 Tax Act. See Note 7 in "Item 8. Financial Statements and Supplementary Data" for further discussion of the effects of the 2017 Tax Act. The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 in "Item 8. Financial Statements and Supplementary Data" for further discussion of the goodwill impairment.
(B)
The Company recorded an income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes at OGE Energy (holding company), as a result of the 2017 Tax Act. Other operations primarily includes the operations of the holding company and consolidating eliminations.

The following operating results analysis by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements. 


6
Exhibit 99.01

OG&E (Electric Utility)
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
470.7

469.0

428.5

Depreciation and amortization
280.9

316.4

299.9

Taxes other than income
84.8

84.0

87.1

Operating income
527.1

509.7

516.4

Allowance for equity funds used during construction
39.7

14.2

8.3

Other net periodic pension and postretirement (cost) benefit
(15.4
)
(0.8
)
(16.0
)
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 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.


7
Exhibit 99.01

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 pension cost, 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.

Other operation and maintenance expense increased $1.7 million, or 0.4 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

Capitalized labor (A)
(7.4
)
Other
(5.4
)
Change in other operation and maintenance expense
$
1.7

(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.


8
Exhibit 99.01

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 14 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 net periodic pension and postretirement cost increased $14.6 million, primarily due to higher settlement charges resulting from an increase in the dollar value of lump sum pension payments requested by retirees.

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.
  
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 14 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.
 

9
Exhibit 99.01

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.

Other operation and maintenance expense increased $40.5 million, or 9.5 percent, in 2016 as compared to 2015. The below factors contributed to the change in other operation and maintenance expense:

(In millions)
Change
Payroll and benefits (A)
$
25.6

Contract professional services (B)
8.7

Corporate allocations and overheads (C)
8.1

Other
(1.9
)
Change in other operation and maintenance expense
$
40.5

(A)
Increased primarily due to increases in pension expense, which increased in order to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, incentive compensation, 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 net periodic pension and postretirement cost decreased $15.2 million, or 95 percent, primarily due to lower settlement charges resulting from a decrease in the dollar value of lump sum pension payments requested by retirees.

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.


10
Exhibit 99.01

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.

OGE Holdings (Natural Gas Midstream Operations)
 
Year Ended December 31,
(In millions)
2017
2016
2015
Operating revenues
$
—

$
—

$
—

Cost of sales
—

—

—

Other operation and maintenance
(0.3
)
(0.2
)
2.5

Depreciation and amortization
—

—

—

Taxes other than income
1.0

—

—

Operating loss
(0.7
)
0.2

(2.5
)
Equity in earnings of unconsolidated affiliates (A)
131.2

101.8

15.5

Other (expense) income
(0.5
)
(7.8
)
(4.6
)
Income before taxes
130.0

94.2

8.4

Income tax (benefit) expense (B)
(195.2
)
40.5

(1.0
)
Net income attributable to OGE Holdings
$
325.2

$
53.7

$
9.4

(A)
The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of Enable's goodwill impairment, as adjusted for the basis difference. See Note 3 in "Item 8. Financial Statements and Supplementary Data" for further discussion of the goodwill impairment.
(B)
Includes an income tax benefit of $245.2 million due to the remeasurement of deferred taxes, as a result of the 2017 Tax Act.

Reconciliation of Equity in Earnings of Unconsolidated Affiliates

The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for the years ended December 31, 2017 and 2016.
 
Year Ended December 31,
(In millions)
2017
2016
2015
Enable net income (loss)
$
400.3

$
289.5

$
(752.0
)
Distributions senior to limited partners
—

(9.1
)
—

Differences due to timing of OGE Energy and Enable accounting close
—

(12.2
)
12.1

Enable net income (loss) used to calculate OGE Energy's equity in earnings
$
400.3

$
268.2

$
(739.9
)
OGE Energy's percent ownership at period end
25.7
%
25.7
%
26.3
%
OGE Energy's portion of Enable net income (loss)
$
102.7

$
70.7

$
(194.4
)
Impairments recognized by Enable associated with OGE Energy's basis differences
—

2.6

178.4

OGE Energy's share of Enable net income (loss)
102.7

73.3

(16.0
)
Amortization of basis difference
11.3

11.6

13.5

Elimination of Enable fair value step up
17.2

16.9

18.0

Equity in earnings of unconsolidated affiliates
$
131.2

$
101.8

$
15.5


Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's investment in Enogex LLC and its underlying equity in the net assets of Enable and is also adjusted for the elimination of the Enogex Holdings fair value adjustments.

11
Exhibit 99.01

The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $714.2 million as of December 31, 2017. The basis difference is being amortized over approximately 30 years, beginning in May 2013. The following table reconciles the basis difference in Enable from December 31, 2016 to December 31, 2017.

(In millions)
 
Basis difference as of December 31, 2016
$
743.7

Change in Enable basis difference
(1.0
)
Amortization of basis difference
(11.3
)
Elimination of Enable fair value step up
(17.2
)
Basis difference as of December 31, 2017
$
714.2


Enable Results of Operations

The following tables represents summarized financial information of Enable for 2017, 2016 and 2015:
 
Year Ended December 31,
(In millions)
2017
2016
2015
Operating revenues
$
2,803

$
2,272

$
2,418

Cost of natural gas and NGLs
1,381

1,017

1,097

Operating income (loss)
528

385

(712
)
Net income (loss)
400

290

(752
)

 
Year Ended December 31,
 
2017
2016
2015
Gathered volumes - TBtu/d
3.56

3.13

3.14

Transportation volumes - TBtu/d
5.04

4.88

4.97

Natural gas processed volumes - TBtu/d
1.96

1.80

1.78

NGLs sold - MBbl/d (A)(B)
92.21

78.16

75.55

(A) Excludes condensate.
(B) NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

Year Ended December 31, 2017 as compared to Year Ended December 31, 2016

OGE Holdings' earnings before taxes increased $35.8 million for the year ended December 31, 2017 as compared to the same period in 2016, primarily due to an increase in equity in earnings of Enable of $29.4 million and a decrease in pension settlement expense of $6.8 million. The increase in the Company's equity in earnings of Enable was primarily attributable to a $143.0 million increase in Enable's operating income. Enable's operating income increased primarily due to an increase in gross margin of $167.0 million and a decrease in impairments of $9.0 million that increased the Company's equity in earnings of Enable by $42.9 million and $2.3 million, respectively, partially offset by an increase in depreciation and amortization expense of $28.0 million, an increase in interest expense of $21.0 million and an increase in preferred distributions of $14.0 million that decreased the Company's equity in earnings of Enable by $7.2 million, $5.4 million and $3.6 million, respectively.

Enable's gathering and processing business segment reported an increase in operating income of $131.0 million. The increase in operating income was primarily due to an increase in gross margin of $160.0 million that increased the Company's equity in earnings of Enable by $41.1 million. The increase in gross margin was partially offset by an increase in depreciation and amortization expense of $20.0 million and an increase in operations and maintenance and general and administrative expenses of $13.0 million that decreased the Company's equity in earnings of Enable by $5.1 million and $3.3 million, respectively. Gathering and processing gross margin increased primarily due to an increase in gross margin from natural gas sales due to higher average natural gas prices and higher gathering volumes in the Anadarko and Ark-La-Tex Basins, an increase in processing margins resulting from higher average NGL prices and higher processed volumes in the Anadarko Basin, an increase in gathering margin due to increased gathering volumes in the Anadarko and Ark-La-Tex Basins and increased billings under minimum volume commitments in the Arkoma Basin and an increase in gross margin from changes in the fair value of condensate and NGL derivatives.


12
Exhibit 99.01

Enable's transportation and storage business segment reported an increase in operating income of $13.0 million. The increase in operating income was primarily due to a decrease in operations and maintenance and general and administrative expenses of $12.0 million and an increase in gross margin of $10.0 million that increased the Company's equity in earnings of Enable by $3.1 million and $2.6 million, respectively. These increases were partially offset by an increase of depreciation and amortization expense of $8.0 million that decreased the Company's equity in earnings of Enable by $2.1 million. Transportation and storage gross margin increased primarily due to an increase in gross margin from changes in the fair value of natural gas derivatives, an increase in NGL sales due to an increase in transported volumes and NGL prices and an increase in off-system transportation margins. These increases were partially offset by a decrease in system management activities, a decrease in firm transportation services between Carthage, Texas and Perryville, Louisiana and a decrease in realized gains on natural gas derivatives.

Income tax benefit was $195.2 million during the year ended December 31, 2017 as compared to income tax expense of $40.5 million during the same period in 2016. The change is primarily due to a remeasurement of federal deferred taxes related to the 2017 Tax Act, a remeasurement of state deferred taxes and return to provision adjustments related to the Company's investment in Enable during the year ended December 31, 2016, offset by higher pre-tax operating income.

Year Ended December 31, 2016 as compared to Year Ended December 31, 2015

OGE Holdings' earnings before taxes increased $85.8 million for the year ended December 31, 2016 as compared to the same period of 2015, primarily due to an increase in equity in earnings of Enable of $86.3 million. The increase in the Company's equity in earnings of Enable was primarily attributable to an increase of $1.097 billion in Enable's operating income during the year ended December 31, 2016 as compared to 2015. This increase was primarily due to goodwill and asset impairments recorded by Enable in 2015 of $1.125 billion, which resulted in the Company recognizing a $108.4 million goodwill impairment during 2015, as adjusted for basis differences. In addition, a decrease in operation and maintenance expense that includes administrative expense of $56.0 million increased the Company's equity in earnings of Enable by approximately $15.0 million and was partially offset by a decrease in Enable's gross margin of $66.0 million that decreased the Company's equity in earnings of Enable by $17.0 million.

Enable's gathering and processing business segment reported an increase in operating income of $499 million. Goodwill and asset impairments recorded in 2015 positively impacted operating income by $534 million in 2016. Absent the impact of such impairment, operating income decreased $35 million primarily due to a reduction in gross margin of $33 million and an increase in depreciation and amortization expense of $17 million that decreased the Company's equity in earnings of Enable by $9 million and $4 million, respectively. These changes were partially offset by a decrease of $17 million in operation and maintenance expenses that increased the Company's equity in earnings of Enable by $4 million. Gathering and processing gross margin decreased primarily due to lower commodity prices and a decrease due to one-time project reimbursements partially offset by increased volumes in the Williston Basin, increased billings under minimum volume commitments, higher rates on fee-based gathering services and an increase in the imbalance receivable associated with the annual fuel rate determination.

Enable's transportation and storage segment reported an increase in operating income of $601 million. Goodwill and asset impairments recorded in 2015 represented $591 million of this increase; further, a decrease of $39 million in operation and maintenance expense increased the Company's equity in earnings of Enable by $10 million. These increases were partially offset by a decrease in gross margin of $29 million that decreased the Company's equity in earnings of Enable by $8 million, primarily due to lower margin on unrealized natural gas derivatives, lower system management activities and lower firm transportation revenues partially offset by an increase in gross margin from transportation services for local distribution companies.

Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years. Should lower commodity prices persist, or should commodity prices decline further, Enable's future operating results and cash flows could be negatively impacted.

Income tax expense was $40.5 million in 2016 as compared to a benefit of $1.0 million in 2015, an increase in expense of $41.5 million primarily due to higher pre-tax operating income and a state deferred tax revaluation resulting from a change in state tax rates.



13
Exhibit 99.01

Off-Balance Sheet Arrangement 

OG&E 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.

Liquidity and Capital Resources

Working Capital
 
Working capital is defined as the difference in current assets and current liabilities. The Company'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 $257.1 million and $235.2 million at December 31, 2017 and 2016, respectively, an increase of $21.9 million, or 9.3 percent, primarily due to an increase in billings to OG&E's retail customers.

Other Current Assets. The balance of Other Current Assets was $54.6 million and $81.8 million at December 31, 2017 and 2016, respectively, a decrease of $27.2 million, or 33.3 percent, primarily due to increased revenue collections from customers associated with various rate riders.
   
Short-Term Debt. The balance of Short-term Debt was $168.4 million and $236.2 million at December 31, 2017 and 2016, respectively, a decrease of $67.8 million, or 28.7 percent. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The decrease in 2017 compared to 2016 was primarily due to the repayment of short-term debt from the proceeds of the senior notes issuance in both March and August 2017.

Accounts Payable. The balance of Accounts Payable was $230.4 million and $205.4 million at December 31, 2017 and 2016, respectively, an increase of $25.0 million, or 12.2 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 $35.9 million and $45.1 million at December 31, 2017 and 2016, respectively, a decrease of $9.2 million, or 20.4 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 $224.7 million at December 31, 2017 and 2016, respectively, an increase of $25.1 million, or 11.2 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 and November 24, 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 $28.7 million and $96.0 million at December 31, 2017 and 2016, respectively, a decrease of $67.3 million, or 70.1 percent, primarily due to amounts refunded to customers in 2017.


14
Exhibit 99.01

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
$
784.5

$
644.7

$
867.1

$
139.8

21.7
%
$
(222.4
)
(25.6
)%
Net cash used in investing activities
(821.9
)
(620.4
)
(500.1
)
(201.5
)
32.5
%
(120.3
)
24.1
 %
Net cash provided from (used in) financing activities
51.5

(99.2
)
(297.3
)
150.7

*

198.1

(66.6
)%
* Greater than a 100 percent variance.

Operating Activities

The increase of $139.8 million, or 21.7 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, and increased equity in earnings of Enable, partially offset by an increase in vendor payments.  Cash distributions from Enable did not change compared to prior year; however, the increase in equity in earnings of Enable resulted in an increased portion of the cash distributions being classified as a return on investment in operating activities as opposed to the prior year classification as a return of investment in investing activities.
  
The decrease of $222.4 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 at OG&E.

Investing Activities

The increase of $201.5 million, or 32.5 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 at OG&E and a decrease in return of investment. An increase in equity in earnings of Enable resulted in an increased portion of cash distributions from Enable being classified as a return on investment in operating activities as opposed to the prior year classification as a return of investment in investing activities.

The increase of $120.3 million, or 24.1 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 at OG&E.

Financing Activities

The increase of $150.7 million in net cash provided from financing activities in 2017 as compared to 2016 was primarily due to the issuance by OG&E of $300.0 million in long-term debt in each of March 2017 and August 2017, partially offset by a decrease in short-term debt and the payment of $100.0 million in long-term debt in November 2017.

The decrease of $198.1 million, or 66.6 percent, in net cash used in financing activities in 2016 as compared to 2015 was primarily due to an increase in short-term debt, partially offset by the payment of $110.0 million in long-term debt during the first quarter of 2016.

2017 Capital Requirements, Sources of Financing and Financing Activities
 
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $1,049.2 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $78.8 million, resulting in total net capital requirements and contractual obligations of $1,128.0 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 $82.6 million totaling $852.9 million in 2016, of which $135.8 million was to comply with environmental regulations.
 
In 2017, the Company's primary sources of capital were cash generated from operations, proceeds from the issuance of short-term debt and distributions from Enable. Changes in working capital reflect the seasonal nature of the Company'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.


15
Exhibit 99.01

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

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

Capital Expenditures
 
The Company's consolidated 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 the Company's businesses) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included in the table below.
(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 14 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."
 

16
Exhibit 99.01

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

Contractual Obligations
 
The following table summarizes the Company's contractual obligations at December 31, 2017.  See the Company's Consolidated Statements of Capitalization and Note 13 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

Noncancellable operating lease
0.6

—

—

—

0.6

Total operating lease obligations
4.8

26.3

5.8

40.6

77.5

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
657.7

694.1

345.4

3,583.5

5,280.7

Amounts recoverable through fuel adjustment clause (B)
(235.9
)
(266.6
)
(239.7
)
(888.6
)
(1,630.8
)
Total contractual obligations, net
$
421.8

$
427.5

$
105.7

$
2,694.9

$
3,649.9

(A)
Maturities of the Company'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.


17
Exhibit 99.01

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 $84.4 million, compared to expected return on plan assets of $42.6 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. The Company made a $20.0 million contribution to its Pension Plan in both 2017 and 2016. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2018. The Company 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.

The following table presents the status of the Company'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 in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1 in "Item 8. Financial Statements and Supplementary Data") in the Company's Consolidated Balance Sheets.  The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated 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
$
687.5

$
672.2

$
8.1

$
7.0

$
149.4

$
215.9

Fair value of plan assets
635.3

595.9

—

—

50.2

53.1

Funded status at end of year
$
(52.2
)
$
(76.3
)
$
(8.1
)
$
(7.0
)
$
(99.2
)
$
(162.8
)

Common Stock Dividends
The Company's dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management's estimation of the long-term earnings power of its businesses. The Company's financial objective includes dividend increases of approximately 10 percent annually through 2019. The targeted annual dividend increase has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets and the composition of the Company's assets and investment opportunities. At the Company's September 2017 board meeting, the Board of Directors approved management's recommendation of a 10 percent increase in the quarterly dividend rate to $0.3325 per share from $0.3025 per share effective in October 2017.
Financing Activities and Future Sources of Financing

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

Short-Term Debt and Credit Facilities
 
Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. In March 2017, the Company and OG&E each entered into new $450.0 million unsecured revolving credit agreements which expire March 2022. These bank facilities can also be used as letter of credit facilities.  As of December 31, 2017, the Company had $168.4 million of short-term debt compared to $236.2 million at December 31, 2016. The average balance of short-term debt in 2017 was $175.7 million at a weighted-average interest rate of 1.30 percent. The maximum month-end balance of short-term debt in 2017 was $260.1 million. At December 31, 2017, the Company had $731.3 million of net available liquidity under its revolving credit agreements.  OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2017 and ending December 31, 2018.  At December 31, 2017, the Company had $14.4 million in cash and cash equivalents. See Note 10 in "Item 8. Financial Statements and Supplementary Data" for further discussion.

18
Exhibit 99.01

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.

Security Ratings
 
Moody’s Investors Services
Standard & Poor's Ratings Services
Fitch Ratings
OG&E Senior Notes
A1
A-
A+
OGE Energy Senior Notes
A3
BBB+
A-
OGE Energy Commercial Paper
P2
A2
F2

Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. Pricing grids associated with the Company'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 the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.
 
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency, and each rating should be evaluated independently of any other rating.

On June 29, 2017, Moody's Investors Service revised the rating outlooks on the Company and OG&E from stable to negative. Moody's Investors Service indicated that the revised outlooks reflect the potential for a decline in financial metrics amidst some uncertainty over cost recovery and earned returns in Oklahoma. The revised outlooks did not trigger any collateral requirements or change fees under the revolving credit agreements.

Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

Common Stock
The Company does not expect to issue any common stock in 2018 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 8 in "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's common stock activity.

Distributions by Enable
 
Pursuant to the Enable Limited Partnership Agreement, Enable made distributions of $141.2 million, $141.2 million and $139.3 million to the Company during the years ended December 31, 2017, 2016 and 2015, respectively. On June 22, 2016, Enable's Limited Partnership Agreement was amended to change the last permitted distribution date from 45 days to 60 days after the close of each quarter. Enable's General Partner Agreement was amended to change the distribution deadline from 50 days after the close of each quarter to five days following distributions by Enable.
     
Critical Accounting Policies and Estimates
 
The Consolidated Financial Statements and Notes to Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis.  In preparing the Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets

19
Exhibit 99.01

and contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could have a material effect on the Company's Consolidated Financial Statements.  However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.  In management's opinion, the areas of the Company where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment. For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company's Audit Committee. The Company discusses its significant accounting policies, including those that do not require management to make difficult, subjective or complex judgments or estimates, in Note 1 in "Item 8. Financial Statements and Supplementary Data."

Pension and Postretirement Benefit Plans
 
The Company has a Pension Plan that covers a significant amount of the Company's employees hired before December 1, 2009. Effective December 1, 2009, the Company's Pension Plan is no longer being offered to employees hired on or after December 1, 2009.  The Company also has defined benefit postretirement plans that cover a significant amount of its employees.  Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding.  Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized.  The Pension Plan rate assumptions are shown in Note 11 in "Item 8. Financial Statements and Supplementary Data."  The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio.  The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid.  Funding levels are dependent on returns on plan assets and future discount rates.  Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan.  The following table indicates the sensitivity of the Pension Plan funded status to these variables.
 
Change
Impact on Funded Status
Actual plan asset returns
+/- 1 percent
+/- $6.4 million
Discount rate
+/- 0.25 percent
+/- $12.9 million
Contributions
+/- $10 million
+/- $10.0 million
 
Income Taxes

The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Accordingly, it is necessary to make judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts the Company recognized in its consolidated financial statements. Tax positions taken by the Company on its income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.
On December 22, 2017, President Trump signed the 2017 Tax Act into law, significantly changing U.S. corporate income tax laws. The 2017 Tax Act reduces the corporate federal tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017. See Note 7 in "Item 8. Financial Statements and Supplementary Data" for further discussion of the effects of the 2017 Tax Act.


20
Exhibit 99.01

Asset Retirement Obligations
 
The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from three to 74 years. The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.

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. The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost.

See Note 1 and Note 7 in "Item 8. Financial Statements and Supplementary Data" for further discussion of the 2017 Tax Act's impact on OG&E's regulatory assets and liabilities as of December 31, 2017.
 
Unbilled Revenues
 
OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month.  As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month.  OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period. At December 31, 2017, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of $0.5 million.  At December 31, 2017 and 2016, Accrued Unbilled Revenues were $66.5 million and $59.7 million, respectively.  The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
 
Allowance for Uncollectible Accounts Receivable
 
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off.  To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized.  Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 2017, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.1 million.  The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in the Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million at both December 31, 2017 and 2016.

Accounting Pronouncements
See Note 2 in "Item 8. Financial Statements and Supplementary Data" for discussion of current accounting pronouncements that are applicable to the Company.
Commitments and Contingencies
 
In the normal course of business, the Company 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, the Company has

21
Exhibit 99.01

incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the Company's Consolidated Financial Statements. At the present time, based on available information, the Company 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 the Company's consolidated financial position, results of operations or cash flows.  See Note 13 in "Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" for a discussion of the Company's commitments and contingencies.
 
Environmental Laws and Regulations
 
The activities of the Company are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, 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.
 
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. OG&E is managing several potentially material uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
 
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 for OG&E above include capital expenditures for Dry Scrubbers and conversion of two coal-fueled units to natural gas. 
 
Air
 
Federal Clean Air Act Overview

OG&E’s operations are subject to the Federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.

Regional Haze Control Measures

The EPA's 2005 Regional Haze Rule is intended to protect visibility in certain national parks and wilderness areas throughout the U.S. that may be impacted by air pollutant emissions. On December 28, 2011, the EPA issued a final Regional Haze Rule for Oklahoma which adopted a FIP for SO2 emissions at Sooner Units 1 and 2 and Muskogee Units 4 and 5. The FIP compliance date is January 4, 2019 as a result of an appeal filed by OG&E and others.  

OG&E's strategy for satisfying the FIP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. As described in Note 14 in "Item 8. Financial Statements and Supplementary Data," the OCC has approved the Company's decision to install Dry Scrubbers at the Sooner units. As of December 31, 2017, OG&E has invested $401.3 million in the Dry Scrubbers and $13.0 million in the Muskogee gas conversion.

Cross-State Air Pollution Rule

In August 2011, the EPA finalized its CSAPR that required 27 states in the eastern half of the U.S. (including Oklahoma) to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. Litigation challenging the

22
Exhibit 99.01

rule prevented it from entering into effect until 2014. Several parties to that litigation, including OG&E, have petitions for review that remain pending although the rule is now effective. Compliance with the CSAPR began in 2015 using the amount of allowances originally scheduled to be available in 2012. As of December 31, 2017, OG&E has installed seven low NOX burner systems on two Muskogee units, two Sooner units and three Seminole units and is in compliance.

On September 7, 2016, the EPA finalized an update to the 2011 CSAPR. The new rule applies to ozone-season NOX in 22 eastern states (including Oklahoma), utilizes a cap and trade program for NOX emissions and took effect on May 1, 2017. The rule reduces the 2016 CSAPR emissions cap for all seven of OG&E’s coal and gas facilities by 47 percent combined. OG&E and numerous other parties filed petitions for judicial and administrative review of the 2016 rule. Those petitions all are pending without any relevant substantive decisions by the authorities.

Due to the pending litigation and administrative proceedings, the ultimate timing and impact of the 2016 CSAPR update rule on our operations cannot be determined with certainty at this time. However, the Company does not anticipate additional capital expenditures beyond what has already been disclosed and does not expect that the reduced emissions cap, if upheld, will have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Hazardous Air Pollutants Emission Standards

On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units, which became effective April 16, 2012. The Company believes that it complied with the MATS rule by the April 16, 2016 deadline that applied to OG&E. Nonetheless, there is continuing litigation, to which the Company is not a party, challenging whether the EPA had statutory authority to issue the MATS rule. The Company cannot predict the outcome of this litigation or how it will affect the Company.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, the Company could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of the end of 2017, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect the Company's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS.

The EPA proposed to designate part of Muskogee County in which OG&E's Muskogee Power Plant is located as non-attainment for the 2010 SO2 NAAQS on March 1, 2016, even though nearby monitors indicate compliance with the NAAQS. The proposed designation is based on modeling that does not reflect the planned conversion of two of the coal units at Muskogee to natural gas. OG&E commented that the EPA should defer a designation of the area to allow time for additional monitoring. The State of Oklahoma's revised monitoring plan was approved by the EPA, and the required monitoring commenced at the beginning of 2017 and will continue through the end of 2019. Nonetheless, the EPA has a deadline for making a decision on the designation pursuant to a consent decree entered by the U.S. District Court for the Northern District of California to resolve a citizen suit. The deadline has been extended several times, with the current deadline being August 26, 2017, but a decision has yet to be reached. It is unclear what impact, if any, the consent decree deadline will have on the monitoring plan. At this time, OG&E cannot determine with any certainty whether the proposed designation of Muskogee County will cause a material impact to OG&E's financial results. The EPA has published final decisions on all other areas of Oklahoma. In this decision, Noble County, in which the Sooner plant is located, was deemed to be in attainment with the 2010 standard.

On September 30, 2015, the EPA finalized a NAAQS for ozone at 70 ppb, which is more stringent than the previous standard of 75 ppb, set in 2008. In September 2016, Governor Mary Fallin submitted to the EPA the recommendation of "attainment/unclassifiable" for all 77 counties in Oklahoma. This recommendation is subject to approval by the EPA. In a letter to Oklahoma dated December 20, 2017, the EPA proposed to approve this recommendation.

The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.


23
Exhibit 99.01

Climate Change and Greenhouse Gas Emissions
There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including CO2, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the earth's atmosphere.  On June 1, 2017, President Trump announced that the U.S. will withdraw from the Paris Climate Accord and begin negotiations to re-enter the agreement with different terms. A new agreement may result in future additional emissions reductions in the U.S.; however, it is not possible to determine what the international legal standards for greenhouse gas emissions will be in the future and the extent to which these commitments will be implemented through the Clean Air Act or any other existing statutes and new legislation.

If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of CO2 and other greenhouse gases on the Company's facilities, this could result in significant additional compliance costs that would affect the Company’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Several states outside the area where the Company operates have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO2 emissions from existing fossil-fuel-fired power plants along with state-specific CO2 reduction standards expressed as both rate-based (lbs./MWh) and mass-based (tons/yr.) goals. However, the rule was challenged in court when it was issued, and the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan on February 9, 2016 pending resolution of the court challenges. The EPA published a proposal on October 16, 2017 to repeal the Clean Power Plan. In addition, the EPA published an Advance Notice of Proposed Rulemaking seeking comments on regulatory options for replacing the Clean Power Plan. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Nonetheless, OG&E’s current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in Note 14 in "Item 8. Financial Statements and Supplementary Data" under "Pending Regulatory Matters," OG&E's plan to comply with the EPA’s MATS rule and Regional Haze Rule FIP includes converting two coal-fired generating units at the Muskogee Station to natural gas, among other measures. OG&E’s deployment of Smart Grid technology helps to reduce the peak load demand. OG&E is also deploying more renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas, and OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource areas in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.

EPA Startup, Shutdown and Malfunction Policy

On May 22, 2015, the EPA issued a final rule to address the provisions in the SIPs of 36 states (including Oklahoma) regarding the treatment of emissions that occur during startup, shutdown and malfunction operations. The final rule clarifies the EPA's Startup, Shutdown and Malfunction Policy. Although judicial challenges to the rule are ongoing, the Oklahoma Department of Environmental Quality submitted a SIP revision for the EPA's approval on November 7, 2016 to comply with this rule. This rule has resulted in permit modifications for certain OG&E units. The Company does not anticipate capital expenditures or a material impact to its consolidated financial position, results of operations or cash flows, as a result of adoption of this rule.


24
Exhibit 99.01

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015 to install the Dry Scrubber systems. The Dry Scrubbers are expected to be completed in mid to late 2018. More detail regarding the ECP can be found under the "Pending Regulatory Matters" section of Note 14 in "Item 8. Financial Statements and Supplementary Data."

Endangered Species

Certain federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats.  If such species are located in an area in which the Company conducts operations, or if additional species in those areas become subject to protection, the Company’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company could be required to implement expensive mitigation measures.

Waste

OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.

On December 19, 2014, the EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The final rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. The final rule is currently being appealed at the D.C. Circuit Court of Appeals. OG&E is in compliance with this rule at this time.

On January 16, 2018, the EPA proposed to approve the application from the State of Oklahoma to administer the Coal Combustion Residual rule in lieu of the "self-implementing" oversight authorities under the EPA coal ash rule of 2015. Oklahoma has incorporated all of the required elements of the EPA Coal Combustion Residual rule into the state permit program. Upon final approval by the EPA, the state Coal Combustion Residual program will operate in lieu of the self-implementing governance as per the final, 2015 EPA coal ash rule.

The Company has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts.  In 2017, the Company obtained refunds of $2.1 million from the recycling of scrap metal, salvaged transformers and used transformer oil.  This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials.  Similar savings are anticipated in future years.

Water
 
OG&E's operations are subject to the Federal Clean Water Act and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters.
The EPA issued a final rule on May 19, 2014 to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. OG&E submitted compliance plans to the State of Oklahoma in April 2015. On December 22, 2017, the Oklahoma Department of Environmental Quality issued a final permit for Muskogee Power Plant in compliance with the final 316(b) rule, which did not incur material cost. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation at other facilities following the future issuance of permits from the State of Oklahoma.

On September 30, 2015, the EPA issued a final rule addressing the effluent limitation guidelines for power plants under the Federal Clean Water Act. The final rule establishes technology and performance based standards that may apply to discharges of six waste streams including bottom ash transport water. Compliance with this rule occurs between 2018 and 2023. OG&E is evaluating what, if any, compliance actions are needed but is not able to quantify with any certainty what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the State of Oklahoma.


25
Exhibit 99.01

Site Remediation
 
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generate wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment.  At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.

For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 13 in "Item 8. Financial Statements and Supplementary Data."


26
Exhibit 99.01

Item 8.  Financial Statements and Supplementary Data.

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31 (In millions except per share data)
2017
2016
2015
OPERATING REVENUES
$
2,261.1

$
2,259.2

$
2,196.9

COST OF SALES
897.6

880.1

865.0

OPERATING EXPENSES
 
 
 
Other operation and maintenance
459.6

455.9

426.7

Depreciation and amortization
283.5

322.6

307.9

Taxes other than income
89.4

87.6

91.2

Total operating expenses
832.5

866.1

825.8

OPERATING INCOME
531.0

513.0

506.1

OTHER INCOME (EXPENSE)
 
 
 
Equity in earnings of unconsolidated affiliates
131.2

101.8

15.5

Allowance for equity funds used during construction
39.7

14.2

8.3

Other net periodic pension and postretirement (cost) benefit
(20.7
)
(9.7
)
(24.9
)
Other income
46.4

26.0

27.0

Other expense
(14.1
)
(16.9
)
(14.3
)
Net other income
182.5

115.4

11.6

INTEREST EXPENSE
 
 
 
Interest on long-term debt
153.6

143.2

147.8

Allowance for borrowed funds used during construction
(18.0
)
(7.5
)
(4.2
)
Interest on short-term debt and other interest charges
8.2

6.4

5.4

Interest expense
143.8

142.1

149.0

INCOME BEFORE TAXES
569.7

486.3

368.7

INCOME TAX (BENEFIT) EXPENSE
(49.3
)
148.1

97.4

NET INCOME
$
619.0

$
338.2

$
271.3

BASIC AVERAGE COMMON SHARES OUTSTANDING
199.7

199.7

199.6

DILUTED AVERAGE COMMON SHARES OUTSTANDING
200.0

199.9

199.6

BASIC EARNINGS PER AVERAGE COMMON SHARE
$
3.10

$
1.69

$
1.36

DILUTED EARNINGS PER AVERAGE COMMON SHARE
$
3.10

$
1.69

$
1.36

DIVIDENDS DECLARED PER COMMON SHARE
$
1.27000

$
1.15500

$
1.05000


















The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

27
Exhibit 99.01

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31 (In millions)
2017
2016
2015
Net income
$
619.0

$
338.2

$
271.3

Other comprehensive income (loss), net of tax:
 
 
 
Pension Plan and Restoration of Retirement Income Plan:
 
 
 
Amortization of deferred net loss, net of tax of $1.4, $1.7 and $2.2, respectively
2.5

2.8

2.5

Amortization of prior service cost, net of tax of $0.0, $0.0 and $0.0, respectively
(0.1
)
—

—

Net gain (loss) arising during the period, net of tax of $0.2, ($0.6) and ($5.8), respectively
0.4

(0.7
)
(9.5
)
Settlement cost, net of tax of $1.4, $3.2 and $2.9, respectively
2.2

5.0

4.6

Postretirement Benefit Plans:
 
 
 
Amortization of prior service cost, net of tax of ($0.3), ($1.0) and ($1.1), respectively
(0.6
)
(1.5
)
(1.8
)
Amortization of deferred net loss, net of tax of $0.0, $0.0 and $0.8, respectively
—

—

1.2

Prior service cost arising during the period, net of tax of $4.0, $0.0 and $0.0, respectively
6.3

—

—

Net (loss) gain arising during the period, net of tax of ($0.2), $0.1 and $5.6, respectively
(0.6
)
0.2

9.3

Settlement cost, net of tax of $0.2, $0.0 and $0.0, respectively
0.5

—

—

Other comprehensive income, net of tax
10.6

5.8

6.3

Comprehensive income
$
629.6

$
344.0

$
277.6



























The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

28
Exhibit 99.01

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31 (In millions)
2017
2016
2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
619.0

$
338.2

$
271.3

Adjustments to reconcile net income to net cash provided from operating activities:
 

 
Depreciation and amortization
283.5

322.6

307.9

Deferred income taxes and investment tax credits, net
(50.0
)
153.8

102.6

Equity in earnings of unconsolidated affiliates
(131.2
)
(101.8
)
(15.5
)
Distributions from unconsolidated affiliates
131.2

102.3

94.1

Allowance for equity funds used during construction
(39.7
)
(14.2
)
(8.3
)
Stock-based compensation
9.1

4.7

7.6

Regulatory assets
3.7

(21.4
)
(9.1
)
Regulatory liabilities
(3.7
)
(11.8
)
(27.5
)
Other assets
(0.7
)
15.4

10.4

Other liabilities
(65.5
)
(18.9
)
8.6

Change in certain current assets and liabilities:
 
 
 
Accounts receivable and accrued unbilled revenues, net
(21.8
)
(6.9
)
21.6

Income taxes receivable
13.6

(2.2
)
(1.2
)
Fuel, materials and supplies inventories
(3.6
)
32.4

(56.5
)
Fuel recoveries
53.0

(112.6
)
129.6

Other current assets
27.2

(26.2
)
(17.2
)
Accounts payable
27.1

(45.1
)
30.9

Other current liabilities
(66.7
)
36.4

17.8

Net cash provided from operating activities
784.5

644.7

867.1

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures (less allowance for equity funds used during construction)
(824.1
)
(660.1
)
(547.8
)
Investment in unconsolidated affiliates
(8.5
)
—

—

Return of capital - equity method investments
10.0

38.8

45.2

Proceeds from sale of assets
0.7

0.9

2.5

Net cash used in investing activities
(821.9
)
(620.4
)
(500.1
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 

Proceeds from long-term debt
592.1

—

—

Issuance (expense) of common stock
(0.1
)
—

7.2

(Decrease) increase in short-term debt
(67.8
)
236.2

(98.0
)
Payment of long-term debt
(225.1
)
(110.2
)
(0.2
)
Dividends paid on common stock
(247.6
)
(225.1
)
(204.6
)
Other
—

(0.1
)
(1.7
)
Net cash provided from (used in) financing activities
51.5

(99.2
)
(297.3
)
NET CHANGE IN CASH AND CASH EQUIVALENTS
14.1

(74.9
)
69.7

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
0.3

75.2

5.5

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
14.4

$
0.3

$
75.2
















The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

29
Exhibit 99.01

OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS

December 31 (In millions)
2017
2016
ASSETS
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
$
14.4

$
0.3

Accounts receivable, less reserve of $1.5 and $1.5, respectively
188.7

173.0

Accounts receivable - unconsolidated affiliates
1.9

2.5

Accrued unbilled revenues
66.5

59.7

Income taxes receivable
5.8

19.4

Fuel inventories
84.3

79.8

Materials and supplies, at average cost
80.8

81.7

Fuel clause under recoveries
—

51.3

Other
54.6

81.8

Total current assets
497.0

549.5

OTHER PROPERTY AND INVESTMENTS




Investment in unconsolidated affiliates
1,160.4

1,158.6

Other
76.7

73.6

Total other property and investments
1,237.1

1,232.2

PROPERTY, PLANT AND EQUIPMENT
 
 
In service
11,041.2

10,690.0

Construction work in progress
867.5

495.1

Total property, plant and equipment
11,908.7

11,185.1

Less accumulated depreciation
3,568.8

3,488.9

Net property, plant and equipment
8,339.9

7,696.2

DEFERRED CHARGES AND OTHER ASSETS
 
 
Regulatory assets
283.0

404.8

Other
55.7

56.9

Total deferred charges and other assets
338.7

461.7

TOTAL ASSETS
$
10,412.7

$
9,939.6
























The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

30
Exhibit 99.01

OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS (Continued)

December 31 (In millions)
2017
2016
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
CURRENT LIABILITIES
 
 
Short-term debt
$
168.4

$
236.2

Accounts payable
230.4

205.4

Dividends payable
66.4

60.4

Customer deposits
80.7

77.7

Accrued taxes
44.5

41.3

Accrued interest
44.0

40.4

Accrued compensation
35.9

45.1

Long-term debt due within one year
249.8

224.7

Fuel clause over recoveries
1.7

—

Other
28.7

96.0

Total current liabilities
950.5

1,027.2

LONG-TERM DEBT
2,749.6

2,405.8

DEFERRED CREDITS AND OTHER LIABILITIES
 
 
Accrued benefit obligations
192.7

274.8

Deferred income taxes
1,227.8

2,334.5

Regulatory liabilities
1,283.4

299.7

Other
157.6

153.8

Total deferred credits and other liabilities
2,861.5

3,062.8

Total liabilities
6,561.6

6,495.8

COMMITMENTS AND CONTINGENCIES (NOTE 13)


STOCKHOLDERS' EQUITY
 
 
Common stockholders' equity
1,114.8

1,105.8

Retained earnings
2,759.5

2,367.3

Accumulated other comprehensive loss, net of tax
(23.2
)
(29.3
)
Total stockholders' equity
3,851.1

3,443.8

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
10,412.7

$
9,939.6























The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

31
Exhibit 99.01

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31 (In millions)
2017
2016
STOCKHOLDERS' EQUITY
 
 
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 199.7 shares and 199.7 shares, respectively
$
2.0

$
2.0

Premium on common stock
1,112.8

1,103.8

Retained earnings
2,759.5

2,367.3

Accumulated other comprehensive loss, net of tax
(23.2
)
(29.3
)
Total stockholders' equity
3,851.1

3,443.8

 
 
 
LONG-TERM DEBT
 
 
SERIES
DUE DATE
 
 
Senior Notes - OGE Energy
 
 
1.87%
Variable Senior Notes, Series Due November 24, 2017
—

100.0

Senior Notes - OG&E
 
 
6.50%
Senior Notes, Series Due July 15, 2017
—

125.0

6.35%
Senior Notes, Series Due September 1, 2018
250.0

250.0

8.25%
Senior Notes, Series Due January 15, 2019
250.0

250.0

6.65%
Senior Notes, Series Due July 15, 2027
125.0

125.0

6.50%
Senior Notes, Series Due April 15, 2028
100.0

100.0

5.75%
Senior Notes, Series Due January 15, 2036
110.0

110.0

6.45%
Senior Notes, Series Due February 1, 2038
200.0

200.0

5.85%
Senior Notes, Series Due June 1, 2040
250.0

250.0

5.25%
Senior Notes, Series Due May 15, 2041
250.0

250.0

3.90%
Senior Notes, Series Due May 1, 2043
250.0

250.0

4.55%
Senior Notes, Series Due March 15, 2044
250.0

250.0

4.00%
Senior Notes, Series Due December 15, 2044
250.0

250.0

4.15%
Senior Notes, Series Due April 1, 2047
300.0

—

3.85%
Senior Notes, Series Due August 15, 2047
300.0

—

3.70%
Tinker Debt, Due August 31, 2062
9.7

9.9

Other Bonds - OG&E
 
 
0.65% - 1.86%
Garfield Industrial Authority, January 1, 2025
47.0

47.0

0.65% - 1.80%
Muskogee Industrial Authority, January 1, 2025
32.4

32.4

0.66% - 1.80%
Muskogee Industrial Authority, June 1, 2027
56.0

56.0

Unamortized debt expense
(20.8
)
(15.5
)
Unamortized discount
(9.9
)
(9.3
)
Total long-term debt
2,999.4

2,630.5

Less: long-term debt due within one year
(249.8
)
(224.7
)
Total long-term debt (excluding debt due within one year)
2,749.6

2,405.8

Total capitalization (including long-term debt due within one year)
$
6,850.5

$
6,074.3









The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

32
Exhibit 99.01

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY



(In millions)
Shares Outstanding
Common Stock
Premium on Common Stock
Retained Earnings
Accumulated Other Comprehensive (Loss) Income
Total
Balance at December 31, 2014
199.4

$
2.0

$
1,085.6

$
2,198.2

$
(41.4
)
$
3,244.4

Net income
—

—

—

271.3

—

271.3

Other comprehensive income, net of tax
—

—

—

—

6.3

6.3

Dividends declared on common stock
—

—

—

(209.7
)
—

(209.7
)
Issuance of common stock
0.2

—

7.2

—

—

7.2

Stock-based compensation
0.1

—

6.5

—

—

6.5

Balance at December 31, 2015
199.7

$
2.0

$
1,099.3

$
2,259.8

$
(35.1
)
$
3,326.0

Net income
—

—

—

338.2

—

338.2

Other comprehensive income, net of tax
—

—

—

—

5.8

5.8

Dividends declared on common stock
—

—

—

(230.7
)
—

(230.7
)
Stock-based compensation
—

—

4.5

—

—

4.5

Balance at December 31, 2016
199.7

$
2.0

$
1,103.8

$
2,367.3

$
(29.3
)
$
3,443.8

Net income
—

—

—

619.0

—

619.0

Cumulative effect of change in accounting principles
—

—

—

26.8

(4.5
)
22.3

Other comprehensive income, net of tax
—

—

—

—

10.6

10.6

Dividends declared on common stock
—

—

—

(253.6
)
—

(253.6
)
Expense of common stock
—

—

(0.1
)
—

—

(0.1
)
Stock-based compensation
—

—

9.1

—

—

9.1

Balance at December 31, 2017
199.7

$
2.0

$
1,112.8

$
2,759.5

$
(23.2
)
$
3,851.1






































The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

33
Exhibit 99.01

OGE ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.
Summary of Significant Accounting Policies

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.  

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

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

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

The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.  The "Distrigas" method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.  The Company adopted this method in January 1996 as a result of a recommendation by the OCC Staff.  The Company believes this method provides a reasonable basis for allocating common expenses.

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, 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.


34
Exhibit 99.01

The following table is a summary of OG&E's regulatory assets and liabilities:
December 31 (In millions)
2017
2016
Regulatory Assets
 
 
Current:
 
 
Oklahoma demand program rider under recovery (A)
$
31.6

$
51.0

SPP cost tracker under recovery (A)
7.7

10.0

Fuel clause under recoveries
—

51.3

Other (A)
1.5

9.5

Total current regulatory assets
$
40.8

$
121.8

Non-current:
 
 
Benefit obligations regulatory asset
$
177.2

$
232.6

Deferred storm expenses
42.2

35.7

Smart Grid
32.8

43.2

Unamortized loss on reacquired debt
12.3

13.4

Income taxes recoverable from customers, net
—

62.3

Other
18.5

17.6

Total non-current regulatory assets
$
283.0

$
404.8

Regulatory Liabilities
 
 
Current:
 
 
Fuel clause over recoveries
$
1.7

$
—

Other (B)
2.2

12.3

Total current regulatory liabilities
$
3.9

$
12.3

Non-current:
 
 
Income taxes refundable to customers, net
$
955.5

$
—

Accrued removal obligations, net
288.4

262.8

Pension tracker
32.3

35.5

Other
7.2

1.4

Total non-current regulatory liabilities
$
1,283.4

$
299.7

(A)
Included in Other Current Assets on the Consolidated Balance Sheets.
(B)
Included in Other Current Liabilities on the Consolidated Balance Sheets.

OG&E recovers program costs related to the Demand and Energy Efficiency Program. An extension of the demand program rider was approved in January 2016, which allows for the recovery through December 2018 of (i) energy efficiency program costs, (ii) lost revenues associated with certain achieved energy efficiency and demand savings, (iii) performance-based incentives and (iv) costs associated with research and development investments.

OG&E recovers certain SPP costs related to base plan charges from its customers and refunds certain SPP revenues received to its customers in Oklahoma through the SPP cost tracker.

Fuel clause under recoveries are generated from under recoveries from OG&E's customers when OG&E's cost of fuel exceeds the amount billed to its customers.  Fuel clause over recoveries are generated from over recoveries from OG&E's customers when the amount billed to its customers exceeds OG&E's cost of fuel.  OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills.  As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost. These expenses are recorded as a regulatory asset as OG&E had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to accumulated other comprehensive income.

35
Exhibit 99.01


The following table is a summary of the components of the benefit obligations regulatory asset:
December 31 (In millions)
2017
2016
Pension Plan and Restoration of Retirement Income Plan:
 
 
Net loss
$
172.4

$
199.9

Postretirement Benefit Plans:
 
 
Net loss
33.6

32.7

Prior service cost
(28.8
)
—

Total
$
177.2

$
232.6

 
The following amounts in the benefit obligations regulatory asset at December 31, 2017 are expected to be recognized as components of net periodic benefit cost in 2018: 
(In millions)
 
Pension Plan and Restoration of Retirement Income Plan:
 
Net loss
$
12.5

Postretirement Benefit Plans:
 
Net loss
4.0

Prior service cost
(6.1
)
Total
$
10.4


OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers any additional expenses incurred over $2.7 million. OG&E expects to recover the amounts deferred each year over a five-year period in accordance with historical practice.

OG&E previously recovered the cost of system-wide deployment of smart grid technology and implementing the smart grid pilot program through a rider. Costs not included in the rider are the incremental costs for web portal access, education and home energy reports, which are capped at $6.9 million, and the stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. These incremental and stranded costs were accumulated during the smart grid deployment and have been included in the Smart Grid asset in the regulatory assets and liabilities table above. As approved in the recent Oklahoma rate case effective May 1, 2017, these costs are now being recovered over a six year period.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt.  These amounts are recorded in interest expenses and are being amortized over the term of the long-term debt which replaced the previous long-term debt.  The unamortized loss on reacquired debt is recovered as a part of OG&E's cost of capital.

Income taxes refundable to customers, net, represent the reduction in accumulated deferred income taxes resulting from the reduction in the federal income tax rate, as part of the 2017 Tax Act.  These amounts will be returned to customers in varying amounts over approximately 80 years.  Currently, those amounts are shown net of income taxes recoverable from customers, which represents income tax benefits previously used to reduce OG&E's revenues, are treated as regulatory assets and are being amortized over the estimated remaining life of the assets to which they relate.  These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around.
 
Accrued removal obligations, net represent asset retirement costs previously recovered from ratepayers for other than legal obligations.

OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory liability in the regulatory assets and liabilities table above.
  
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

36
Exhibit 99.01

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.
              
Use of Estimates
 
In preparing the Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could have a material effect on the Company's Consolidated Financial Statements.  However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.  In management's opinion, the areas of the Company where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment. For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues.

Cash and Cash Equivalents
 
For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.  These investments are carried at cost, which approximates fair value.

Allowance for Uncollectible Accounts Receivable
 
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off.  To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized.  Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in the Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million at both December 31, 2017 and 2016.
 
New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed.  New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC.  The payment behavior of all existing customers is continuously monitored, and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil.  OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles.  The amount of fuel inventory was $84.3 million and $82.4 million at December 31, 2017 and 2016, respectively. Effective May 1, 2014, the gas storage services agreement with Enable was terminated. As a result of this contract termination, approximately 5.3 Bcf of cushion gas owned by OG&E and stored on the Enable system is being directed to OG&E's power plants over a five-year period during peak time of June 1 to August 31 at a rate of 11,500 MMBtu/day for a total of 1.06 Bcf per year. In 2014, approximately $11.0 million of cushion gas was reclassified from Plant-in-Service to Other Deferred Assets, representing natural gas in storage that will be removed from storage over four years. As of December 31, 2017, the remaining balance of cushion gas of $2.8 million is included in Fuel Inventories.
 
Property, Plant and Equipment
  
All property, plant and equipment is recorded at cost.  Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction.  Replacements of units of property are capitalized as plant.  For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property is charged to Accumulated Depreciation.  For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income

37
Exhibit 99.01

as Other Expense.  Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.
 
The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables.  The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures.  Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Consolidated Statements of Income.
December 31, 2017 (In millions)
Percentage Ownership
Total Property, Plant and Equipment
Accumulated Depreciation
Net Property, Plant and Equipment
McClain Plant (A)
77
%
$
226.8

$
71.4

$
155.4

Redbud Plant (A)(B)
51
%
$
496.6

$
136.0

$
360.6

(A)
Construction work in progress was $0.4 million and $7.8 million for the McClain and Redbud Plants, respectively.
(B)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million.

December 31, 2016 (In millions)
Percentage Ownership
Total Property, Plant and Equipment
Accumulated Depreciation
Net Property, Plant and Equipment
McClain Plant (A)
77
%
$
234.2

$
72.3

$
161.9

Redbud Plant (A)(B)
51
%
$
489.0

$
121.0

$
368.0

(A)
Construction work in progress was $0.2 million and $1.8 million for the McClain and Redbud Plants, respectively.
(B)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million.
 
The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes: 
December 31, 2017 (In millions)
Total Property, Plant and Equipment    
Accumulated Depreciation
Net Property, Plant and Equipment
OGE Energy (holding company):
 
 
 
Property, plant and equipment
$
6.1

$
—

$
6.1

OGE Energy property, plant and equipment
6.1

—

6.1

OG&E:
 
 
 
Distribution assets
4,057.1

1,259.1

2,798.0

Electric generation assets (A)
4,475.0

1,493.5

2,981.5

Transmission assets (B)
2,767.7

506.5

2,261.2

Intangible plant
181.8

135.8

46.0

Other property and equipment
421.0

173.9

247.1

OG&E property, plant and equipment
11,902.6

3,568.8

8,333.8

Total property, plant and equipment
$
11,908.7

$
3,568.8

$
8,339.9

(A)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million.
(B)
This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million.

38
Exhibit 99.01

December 31, 2016 (In millions)
Total Property, Plant and Equipment    
Accumulated Depreciation
Net Property, Plant and Equipment
OGE Energy (holding company):
 
 
 
Property, plant and equipment
$
117.7

$
103.3

$
14.4

OGE Energy property, plant and equipment
117.7

103.3

14.4

OG&E:
 
 
 
Distribution assets
3,896.2

1,221.5

2,674.7

Electric generation assets (A)
4,155.9

1,493.3

2,662.6

Transmission assets (B)
2,548.8

481.3

2,067.5

Intangible plant
85.0

43.9

41.1

Other property and equipment
381.5

145.6

235.9

OG&E property, plant and equipment
11,067.4

3,385.6

7,681.8

Total property, plant and equipment
$
11,185.1

$
3,488.9

$
7,696.2

(A)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million.
(B)
This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million.

The following table summarizes the Company's unamortized computer software costs included in intangible plant above.
December 31 (In millions)
2017
2016
OGE Energy (holding company)
$
—

$
1.0

OG&E
37.5

36.5

Total
$
37.5

$
37.5


The following table summarizes the Company's amortization expense for computer software costs.
Year Ended December 31 (In millions)
2017
2016
2015
OGE Energy (holding company)
$
0.2

$
1.4

$
2.0

OG&E
8.8

8.0

6.9

Total
$
9.0

$
9.4

$
8.9

                
Depreciation and Amortization
  
The provision for depreciation, which was 2.5 percent and 3.0 percent of the average depreciable utility plant for 2017 and 2016, respectively, is calculated using the straight-line method over the estimated service life of the utility assets.  Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant and is based on the average life group method. In 2018, the provision for depreciation is projected to be 2.7 percent of the average depreciable utility plant.

Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2017, 98.6 percent will be amortized over 10.4 years with the remaining 1.4 percent of the intangible plant balance at December 31, 2017 being amortized over 23.7 years.  

Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset.  Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 37 to 59 year period.
 
Investment in Unconsolidated Affiliate

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does

39
Exhibit 99.01

not have the power to direct the activities that are considered most significant to the economic performance of Enable. The Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable at December 31, 2017 as presented in Note 12. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in the Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the Consolidated Statements of Cash Flows.

Asset Retirement Obligations

OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations.

The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from three to 74 years. 

The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2017 and 2016.
(In millions)
2017
2016
Balance at January 1
$
69.6

$
63.3

Accretion expense
3.1

2.8

Revisions in estimated cash flows (A)
2.4

3.6

Liabilities settled
—

(0.1
)
Balance at December 31
$
75.1

$
69.6

(A)
Assumptions changed related to the estimated timing of asbestos abatement and estimated cost of ash pond removal at two of OG&E's generating facilities.

Allowance for Funds Used During Construction
 
Allowance for funds used during construction, a non-cash item, is reflected as an increase to net Other Income and a reduction to Interest Expense in the Consolidated Statements of Income and as an increase to Construction Work in Progress in the Consolidated Balance Sheets.  Allowance for funds used during construction is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds.  Allowance for funds used during construction rates, compounded semi-annually, were 8.2 percent, 8.2 percent and 8.1 percent for the years ended December 31, 2017, 2016 and 2015, respectively.  

Collection of Sales Tax
 
In the normal course of its operations, OG&E collects sales tax from its customers.  OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities.  OG&E excludes the sales tax collected from its operating revenues.


40
Exhibit 99.01

Revenue Recognition
 
General
 
OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month.  As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month.  OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period.  The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
 
SPP Purchases and Sales
 
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 FERC-approved regional day-ahead and real-time markets for energy and operating services, 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 per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. These results are reported as Operating Revenues or Cost of Sales in the Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.
             
Fuel Adjustment Clauses
 
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.

Income Taxes

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions.  Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss.  Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property.  The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Consolidated Statements of Income.

On December 22, 2017, President Trump signed the 2017 Tax Act into law, significantly changing U.S. corporate income tax laws. The 2017 Tax Act reduces the corporate federal tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017. See Note 7 for further discussion of the effects of the 2017 Tax Act.

Accrued Vacation
 
The Company accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned but not taken.


41
Exhibit 99.01

Accumulated Other Comprehensive Income (Loss)
 
The following tables summarize changes in the components of accumulated other comprehensive loss attributable to OGE Energy during 2016 and 2017. All amounts below are presented net of tax.
 
Pension Plan and Restoration of Retirement Income Plan
Postretirement Benefit Plans
 
(In millions)
Net income
 (loss)
Prior service cost
Net income (loss)
Prior service cost
Total
Balance at December 31, 2015
$
(39.2
)
$
0.1

$
2.5

$
1.5

$
(35.1
)
Other comprehensive income (loss) before reclassifications
(0.7
)
—

0.2

—

(0.5
)
Amounts reclassified from accumulated other comprehensive income (loss)
2.8

—

—

(1.5
)
1.3

Settlement cost
5.0

—

—

—

5.0

Net current period other comprehensive income (loss)
7.1

—

0.2

(1.5
)
5.8

Balance at December 31, 2016
(32.1
)
0.1

2.7

—

(29.3
)
Other comprehensive income (loss) before reclassifications
0.4

—

(0.6
)
6.3

6.1

Amounts reclassified from accumulated other comprehensive income (loss)
2.5

(0.1
)
—

(0.6
)
1.8

Cumulative effect of change in accounting principle
(5.7
)
—

(0.1
)
1.3

(4.5
)
Settlement cost
2.2

—

0.5

—

2.7

Net current period other comprehensive income (loss)
(0.6
)
(0.1
)
(0.2
)
7.0

6.1

Balance at December 31, 2017
$
(32.7
)
$
—

$
2.5

$
7.0

$
(23.2
)


42
Exhibit 99.01

The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the years ended December 31, 2017 and 2016.
Details about Accumulated Other Comprehensive Income (Loss) Components
Amount Reclassified from Accumulated Other Comprehensive Income (Loss)
Affected Line Item in the Consolidated Statements of Comprehensive Income
 
Year Ended December 31,
 
(In millions)
2017
2016
 
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
 
 
 
Actuarial losses (A)
$
(3.9
)
$
(4.5
)
Other Net Periodic Pension and Postretirement (Cost) Benefit
Prior service cost
0.1

—

Other Net Periodic Pension and Postretirement (Cost) Benefit
Settlement (A)
(3.6
)
(8.2
)
Other Net Periodic Pension and Postretirement (Cost) Benefit
 
(7.4
)
(12.7
)
Income Before Taxes
 
(2.8
)
(4.9
)
Income Tax (Benefit) Expense
 
$
(4.6
)
$
(7.8
)
Net Income
 
 
 
 
Amortization of postretirement benefit plan items:
 
 
 
Prior service cost
$
0.9

$
2.5

Other Net Periodic Pension and Postretirement (Cost) Benefit
Settlement (A)
(0.7
)
—

Other Net Periodic Pension and Postretirement (Cost) Benefit
 
0.2

2.5

Income Before Taxes
 
0.1

1.0

Income Tax (Benefit) Expense
 
$
0.1

$
1.5

Net Income
 
 
 
 
Total reclassifications for the period
$
(4.5
)
$
(6.3
)
Net Income
(A)
These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost (see Note 11 for additional information).
 
The amounts in accumulated other comprehensive loss (gain) at December 31, 2017 that are expected to be recognized into earnings in 2018 are as follows:
(In millions)
 
Pension Plan and Restoration of Retirement Income Plan:
 
Net loss
$
(3.7
)
Prior service cost
(0.1
)
Postretirement Benefit Plans:
 
Prior service cost
2.3

Total, net of tax
$
(1.5
)


43
Exhibit 99.01

Environmental Costs
 
Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated.  Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations.  Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods.  Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology.  Accrued obligations are regularly adjusted as environmental assessments and estimates are revised and remediation efforts proceed.  For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost.  The Company had $17.1 million and $13.9 million in accrued environmental liabilities at December 31, 2017 and 2016, respectively, which are included in the Company's asset retirement obligations.
    
2.
Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The new revenue standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 2017. The Company has assessed the effect of this new guidance on its tariff-based sales, bundled arrangements and alternative revenue programs and is not aware of any issues that would have a material impact on the timing of revenue recognition. The new standard will not have a material impact on the Company's results of operations and financial position but will change the income statement presentation of revenues and require new disclosures. The Company adopted the new standard beginning in the first quarter of 2018 utilizing the modified retrospective transition method.
Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between current lease accounting and Topic 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as the Company, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition method and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has started evaluating its current lease contracts. The Company has not quantified the impact on its Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities.

In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842," which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that exist or expired before the entity's adoption of Topic 842 and that were not previously accounted for as leases under ASC 840, "Leases." Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 2018. The Company intends to elect this practical expedient during its adoption of Topic 842.

Employee Share-based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which amends ASC Topic 718, "Compensation - Stock Compensation." ASU 2016-09 includes provisions intended to simplify various aspects related to how share-based payments are accounted for and presented in the financial statements. The Company adopted this standard in the first quarter of 2017.

The new guidance, among other requirements, requires the following.

•
All of the tax effects related to share-based payments at settlement (or expiration) should be recorded through the income statement. Previously, tax benefits in excess of compensation cost, or windfalls, were recorded in equity, and tax deficiencies, or shortfalls, were recorded in equity to the extent of previous windfalls and then to the income statement. Under the new guidance, the windfall tax benefit is recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment

44
Exhibit 99.01

to opening retained earnings. Excess tax benefits are to be reported as operating activities on the statement of cash flows, which is a change from the previous requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. As a result of adopting ASU 2016-09, the Company recorded a cumulative effect of $22.3 million as a deferred tax asset with an offset in retained earnings in the Consolidated Balance Sheets. Going forward, tax benefits in excess of compensation cost previously recorded in equity will be recorded within the income statement, and the related cash impact will be recorded as an operating activity within the statement of cash flows.
 
•
Employee taxes paid when an employer withholds shares for tax-withholding purposes should be classified as a financing activity in the statement of cash flows, and this change should be applied retrospectively. As a result of the adoption, the Company reclassified shares withheld for employee taxes of $0.1 million and $1.7 million in 2016 and 2015, respectively, from operating activities to financing activities in the Consolidated Statements of Cash Flows. Going forward, shares withheld for employee taxes will be classified as a financing activity within the statement of cash flows.

•
A policy election between recognizing forfeited awards as they occur or estimating the number of awards expected to be forfeited should be made and disclosed. The Company will continue to estimate forfeitures in accounting for stock-based compensation.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit expense between those that are attributed to compensation for service and those that are not.  The service cost component of benefit expense continues to be presented within operating income, but entities are now required to present the other components of benefit expense as non-operating within the income statement.  Additionally, the new guidance only permits the capitalization of the service cost component of net benefit expense. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs.  The Company adopted the new guidance beginning in the first quarter of 2018, and, as a result, presents the service cost component of net benefit expense in operating income and the other components of net benefit expense as non-operating within its Consolidated Statements of Income. Further, as required by ASU 2017-07, the Company adjusted prior year income statements presentation of the net benefit expense components, which were previously presented in total within Other Operation and Maintenance on the Company's Consolidated Statements of Income. The Company elected the practical expedient allowed by ASU 2017-07 to utilize amounts disclosed in the Company's retirement plans and postretirement benefit plans note for prior periods as the estimation basis for applying the retrospective presentation requirements. Also, as required by ASU 2017-07, the Company only capitalizes the service cost component of net benefit expense, beginning in the first quarter of 2018. Capitalized amounts for prior periods were not adjusted, as this change was implemented on a prospective basis.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU 2018-02, "Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income" that permits a reclassification from accumulated other comprehensive income to retained earnings of the stranded tax effects resulting from application of the new federal corporate income tax rate, resulting from the 2017 Tax Act. Prior to ASU 2018-02, GAAP required the remeasurement of deferred tax assets and liabilities as a result of a change in tax laws or rates to be presented in net income from continuing operations. Adjusting temporary differences originally recorded to accumulated other comprehensive income through continuing operations resulted in a disproportionate effect lodged in accumulated other comprehensive income.  Under ASU 2018-02, entities are permitted, but not required, to reclassify from accumulated other comprehensive income to retained earnings those stranded tax effects resulting from the 2017 Tax Act.  ASU 2018-02 is effective for all entities for fiscal years beginning after December 2018 and interim periods within those fiscal years. Early adoption is permitted. The amendments would be applied either at the beginning of the period of adoption or retrospectively to each period in which the effect of the change in the federal corporate income tax rate is recognized. The Company adopted the new standard for the year ended December 31, 2017.  As a result of the adoption, the Company reclassified $4.5 million of deferred tax assets from accumulated other comprehensive income to retained earnings in the Consolidated Balance Sheets. 

3.
Investment in Unconsolidated Affiliate and Related Party Transactions

On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint, agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.

45
Exhibit 99.01

Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost.
The general partner of Enable is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company deconsolidated its interest in Enogex Holdings and began accounting for its interest in Enable using the equity method of accounting.
In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At December 31, 2017, the Company owned 111.0 million common units, or 25.7 percent, of Enable's outstanding common units. Prior to August 30, 2017, of the Company's 111.0 million common units, 68.2 million units were subordinated. The subordination period began on the closing date of Enable’s initial public offering and extended until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. On August 30, 2017, the first day following the payment of the cash distribution for common and subordinated units for the second quarter of 2017, the subordination period expired for the Company's 68.2 million subordinated units.

On February 9, 2018, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $141.2 million, $141.2 million and $139.3 million during the years ended December 31, 2017, 2016 and 2015, respectively.

In 2016, CenterPoint Energy, Inc. announced that it was evaluating strategic alternatives for its investment in Enable. On July 18, 2016, CenterPoint Energy, Inc. and its wholly owned subsidiary, CenterPoint, provided notice to the Company of CenterPoint Energy Inc.’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint and all of the membership interests of the general partner of Enable owned by CenterPoint. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner. Under the terms of the right of first offer, the Company has 30 days from receipt of a notice from CenterPoint Energy Inc. to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint's common units and subordinated units. On August 17, 2016, the Company submitted to CenterPoint Energy Inc. a proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in the general partner of Enable and all of the common units and subordinated units of Enable owned by CenterPoint. In accordance with the Enable partnership Agreement, CenterPoint Energy Inc. had 30 days after the proposal was submitted to accept the Company's right of first offer proposal. The Company did not receive a reply from CenterPoint Energy Inc. within the required timeframe.

On January 16, 2017, CenterPoint Energy, Inc. and its wholly owned subsidiary, CenterPoint, provided a second notice to the Company of CenterPoint Energy Inc.'s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Inc. On February 15, 2017, under the terms of right of first offer, the Company submitted to CenterPoint Energy Inc. another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in the general partner of Enable and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint Energy Inc. within the required timeframe.

On July 15, 2017, CenterPoint Energy, Inc. and its wholly owned subsidiary, CenterPoint, provided a third notice to the Company of CenterPoint Energy Inc.'s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint and all of the membership interests of the general partner of Enable owned by CenterPoint. On August 14, 2017, under the terms of right of first offer, the Company submitted to CenterPoint Energy Inc. another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in the general partner of Enable and all of the common units and subordinated units of Enable owned by CenterPoint.


46
Exhibit 99.01

On December 1, 2017, CenterPoint Energy, Inc. and its wholly owned subsidiary, CenterPoint, announced that late-stage discussions regarding a transaction involving CenterPoint's interest in Enable terminated because parties could not reach agreement on a mutually acceptable transaction.

The Company cannot predict what future actions CenterPoint will take, if any, associated with their ownership interest in Enable.

Related Party Transactions - the Company and Enable

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below.

In connection with the formation of Enable, the Company and Enable entered into a Services Agreement, Employee Transition Agreement and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2017. Under these agreements, the Company charged operating costs to Enable of $2.3 million, $4.7 million and $12.4 million for December 31, 2017, 2016 and 2015, respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.  

The Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, CenterPoint, the Company and Enable agreed to continue the secondment to Enable for 192 employees that participate in the Company's defined benefit and retirement plans. The Company billed Enable for reimbursement of $29.5 million, $28.7 million and $32.7 million in 2017, 2016 and 2015, respectively, under the Transitional Seconding Agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $14.6 million. Settlement and curtailment charges associated with the Enable seconded employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 day notice.

The Company had accounts receivable from Enable of $2.0 million and $2.7 million as of December 31, 2017 and 2016, respectively, for amounts billed for transitional services, including the cost of seconded employees.

Related Party Transactions - OG&E and Enable

OG&E entered into a contract with Enable to provide transportation services effective May 1, 2014. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will be effective upon the conversion of units 4 and 5 at Muskogee from coal to gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2017, 2016 and 2015.

 
Year Ended December 31,
(In millions)
2017
2016
2015
Operating revenues:
 
 
 
Electricity to power electric compression assets
$
14.0

$
11.5

$
13.8

Cost of sales:
 
 
 
Natural gas transportation services
$
35.0

$
35.0

$
35.0

Natural gas purchases (sales)
(2.1
)
11.2

7.6


47
Exhibit 99.01


Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015.

Balance Sheet
December 31,
(In millions)
2017
2016
Current assets
$
416

$
396

Non-current assets
11,177

10,816

Current liabilities
1,279

362

Non-current liabilities
2,660

3,056

Income Statement
Year Ended December 31,
(In millions)
2017
2016
2015
Operating revenues
$
2,803

$
2,272

$
2,418

Cost of natural gas and NGLs
1,381

1,017

1,097

Operating income (loss)
528

385

(712
)
Net income (loss)
400

290

(752
)

The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes.  Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to Enable's equity of $2.2 billion.  Due to the contribution of Enogex LLC to Enable meeting the requirements of being in substance real estate and thus recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

The Company recorded equity in earnings of unconsolidated affiliates of $131.2 million, $101.8 million and $15.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in the net assets of Enable and is also adjusted for the elimination of the Enogex Holdings fair value adjustments. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described below.


48
Exhibit 99.01

The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for the years ended December 31, 2017 and 2016.
 
Year Ended December 31,
(In millions)
2017
2016
2015
Enable net income (loss)
$
400.3

$
289.5

$
(752.0
)
Distributions senior to limited partners
—

(9.1
)
—

Differences due to timing of OGE Energy and Enable accounting close
—

(12.2
)
12.1

Enable net income (loss) used to calculate OGE Energy's equity in earnings
$
400.3

$
268.2

$
(739.9
)
OGE Energy's percent ownership at period end
25.7
%
25.7
%
26.3
%
OGE Energy's portion of Enable net income (loss)
$
102.7

$
70.7

$
(194.4
)
Impairments recognized by Enable associated with OGE Energy's basis differences
—

2.6

178.4

OGE Energy's share of Enable net income (loss)
102.7

73.3

(16.0
)
Amortization of basis difference
11.3

11.6

13.5

Elimination of Enable fair value step up
17.2

16.9

18.0

Equity in earnings of unconsolidated affiliates
$
131.2

$
101.8

$
15.5


The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $714.2 million as of December 31, 2017. The basis difference is being amortized over approximately 30 years, beginning in May 2013. The following table reconciles the basis difference in Enable from December 31, 2016 to December 31, 2017.
(In millions)
 
 
Basis difference as of December 31, 2016
 
$
743.7

Change in Enable basis difference
 
(1.0
)
Amortization of basis difference
 
(11.3
)
Elimination of Enable fair value step up
 
(17.2
)
Basis difference as of December 31, 2017
 
$
714.2


2015 Goodwill Impairment. Enable tests its goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicated that the carrying value of goodwill may not be recoverable. Beginning in the fourth quarter of 2014 and continuing into 2015, the crude oil and natural gas industry was impacted by significant commodity price declines, which resulted in decreased producer activity in certain regions in which Enable operates. Based on the decline in producer activity and the forecasted impact on future periods, in addition to an increase in the weighted average cost of capital, Enable determined that the impact on its forecasted operating profits and cash flows for its gathering and processing and transportation and storage segments for the next five years would be significantly reduced. As a result, when Enable performed its annual goodwill impairment analysis as of October 1, 2015, it determined that the goodwill for the gathering and processing and transportation and storage reporting units was completely impaired in the amount of $1.086 billion as of September 30, 2015 and wrote off all of its goodwill in the third quarter of 2015.

Accordingly, the Company recorded a $108.4 million pre-tax charge in the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis differences.

4.
Fair Value Measurements
 
The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3).  Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The three levels defined in the fair value hierarchy are as follows:
 
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.

49
Exhibit 99.01

 
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability.  Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.  
 
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The Company had no financial instruments measured at fair value on a recurring basis at December 31, 2017 and 2016.  The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt whose fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy. The following table summarizes the fair value and carrying amount of the Company's financial instruments at December 31, 2017 and 2016.
 
2017
2016
December 31 (In millions)
Carrying Amount 
Fair
Value
Carrying Amount 
 Fair
Value
Long-term Debt (including Long-term Debt due within one year):
 
 
 
 
Senior Notes
$
2,854.3

$
3,242.8

$
2,385.5

$
2,657.2

OG&E Industrial Authority Bonds
135.4

135.4

135.4

135.4

Tinker Debt
9.7

9.8

9.9

11.3

OGE Energy Senior Notes
—

—

99.7

99.9


5.
Stock-Based Compensation

In 2013, the Company adopted, and its shareholders approved, the Stock Incentive Plan.  Under the Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries. The Company has authorized the issuance of up to 7,400,000 shares under the Stock Incentive Plan.
 
The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the years ended December 31, 2017, 2016 and 2015 related to the Company's performance units and restricted stock.
Year Ended December 31 (In millions)
2017
2016
2015
Performance units:
 
 
 
Total shareholder return
$
7.6

$
4.5

$
7.6

Earnings per share
1.4

—

0.7

Total performance units
9.0

4.5

8.3

Restricted stock
0.1

0.1

0.1

Total compensation expense
9.1

4.6

8.4

Less: Amount paid by unconsolidated affiliates
—

—

0.5

Net compensation expense
$
9.1

$
4.6

$
7.9

Income tax benefit
$
3.5

$
1.8

$
3.1


The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units.  In 2017, 2016 and 2015, there were 2,298 shares, 2,100 shares and 82,046 shares, respectively, of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock grants (net of forfeitures) and payouts of earned performance units. In 2017, there were 146 shares of restricted stock returned to the Company to satisfy tax liabilities.


50
Exhibit 99.01

Performance Units
 
Under the Stock Incentive Plan, the Company has issued performance units which represent the value of one share of the Company's common stock.  The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan).  Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement.  In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle.
 
The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on the Company's total shareholder return ranking relative to a peer group of companies.  The performance units granted based on earnings per share are contingently awarded and will be payable in shares of the Company's common stock based on the Company's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of the Company's Board of Directors. All of these performance units are classified as equity in the Consolidated Balance Sheets.  If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of the Company's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.

Performance Units – Total Shareholder Return
 
The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units.  Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle.  Dividends were not accrued or paid for awards prior to February 2014 and were therefore not included in the fair value calculation. Beginning with the February 2014 performance unit awards, dividends are accrued on a quarterly basis pending achievement of payout criteria and were therefore included in the fair value calculations.  Expected price volatility is based on the historical volatility of the Company's common stock for the past three years and was simulated using the Geometric Brownian Motion process.  The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant.  The expected life of the units is based on the non-vested period since inception of the award cycle.  There are no post-vesting restrictions related to the Company's performance units based on total shareholder return.  The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.
 
2017
2016
2015
Number of units granted
260,570

284,211

264,454

Fair value of units granted
$
41.77

$
20.97

$
31.02

Expected dividend yield
3.8
%
3.5
%
2.6
%
Expected price volatility
19.9
%
19.8
%
16.9
%
Risk-free interest rate
1.44
%
0.88
%
0.91
%
Expected life of units (in years)
2.80

2.84

2.85



51
Exhibit 99.01

Performance Units – Earnings Per Share

The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of the Company's common stock on the date of grant.  The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition.  The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable.  As a result, the compensation expense recognized for these performance units can vary from period to period.  There are no post-vesting restrictions related to the Company's performance units based on earnings per share. The number of performance units granted based on earnings per share and the grant date fair value are shown in the following table. 
 
2017
2016
2015
Number of units granted
86,857

94,735

88,156

Fair value of units granted
$
34.83

$
26.64

$
33.99


Restricted Stock
 
Under the Stock Incentive Plan, the Company issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments.  Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted stock was based on the closing market price of the Company's common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, the Company treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period on restricted stock granted prior to July 2014; therefore, dividends are included in the fair value calculation for such restricted stock granted prior to July 2014.

For restricted stock granted after July 2014, dividends will only be paid on restricted stock awards that vest. Accordingly, for restricted stock granted after July 2014, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock is based on the non-vested period since inception of the primarily three-year award cycle.  There are no post-vesting restrictions related to the Company's restricted stock.  The number of shares of restricted stock granted and the grant date fair value are shown in the following table. 
 
2017
2016
2015
Shares of restricted stock granted
3,145

1,881

958

Fair value of restricted stock granted
$
34.96

$
29.27

$
26.11



52
Exhibit 99.01

A summary of the activity for the Company's performance units and restricted stock at December 31, 2017 and changes in 2017 are shown in the following table.
 
Performance Units
 
 
 
Total Shareholder Return
Earnings Per Share
Restricted Stock
(Dollars in millions)
Number
of Units
 
Aggregate Intrinsic Value
Number
of Units
 
Aggregate Intrinsic Value
Number
of Shares
Aggregate Intrinsic Value
Units/shares outstanding at 12/31/16
664,045

 
 
221,350

 
 
4,912

 
Granted
260,570

(A)
 
86,857

(A)
 
3,145

 
Converted
(185,214
)
(B)
$
—

(61,742
)
(B)
$
—

N/A

 
Vested
N/A

 
 
N/A

 
 
(3,815
)
$
0.1

Forfeited
(14,850
)
 
 
(4,947
)
 
 
—

 
Units/shares outstanding at 12/31/17
724,551

 
$
2.4

241,518

 
$
7.2

4,242

$
0.1

Units/shares fully vested at 12/31/17
201,431

 
$
—

67,148

 
$
1.2

 
 
(A)
For performance units, this represents the target number of performance units granted.  Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.
(B)
These amounts represent performance units that vested at December 31, 2016 which were settled in February 2017.

A summary of the activity for the Company's non-vested performance units and restricted stock at December 31, 2017 and changes in 2017 are shown in the following table.
 
Performance Units
 
 
 
Total Shareholder Return
Earnings Per Share
Restricted Stock
 
Number
of Units
 
Weighted-Average
Grant Date
Fair Value
Number
of Units
 
Weighted-Average
Grant Date
Fair Value
Number
of Shares
Weighted-Average
Grant Date
Fair Value
Units/shares non-vested at 12/31/16
478,831

 
$
25.16

159,608

 
$
29.71

4,912

$
31.29

Granted
260,570

(A)
$
41.77

86,857

(A)
$
34.83

3,145

$
34.96

Vested
(201,431
)
 
$
31.18

(67,148
)
 
$
33.99

(3,815
)
$
31.71

Forfeited
(14,850
)
 
$
31.01

(4,947
)
 
$
31.12

—

$
—

Units/shares non-vested at 12/31/17
523,120

 
$
30.96

174,370

 
$
30.58

4,242

$
33.58

Units/shares expected to vest
492,446

(B)
 
164,148

(B)
 
4,242

 
(A)
For performance units, this represents the target number of performance units granted.  Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.
(B)
The intrinsic value of the performance units based on total shareholder return and earnings per share is $2.3 million and $5.7 million, respectively.

Fair Value of Vested Performance Units and Restricted Stock

A summary of the Company's fair value for its vested performance units and restricted stock is shown in the following table.
Year Ended December 31 (In millions)
2017
2016
2015
Performance units:
 
 
 
Total shareholder return
$
6.3

$
6.4

$
8.5

Earnings per share
1.2

—

—

Restricted stock
0.1

0.1

0.2



53
Exhibit 99.01

Unrecognized Compensation Cost

A summary of the Company's unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
December 31, 2017
Unrecognized Compensation Cost (In millions)
Weighted Average to be Recognized (In years)
Performance units:
 
 
Total shareholder return
$
8.5

1.75
Earnings per share
2.6

1.67
Total performance units
11.1

 
Restricted stock
0.1

1.34
Total
$
11.2

 

6.
Supplemental Cash Flow Information
 
The following table discloses information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments.  Cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds are also disclosed in the table.
Year Ended December 31 (In millions)
2017
2016
2015
NON-CASH INVESTING AND FINANCING ACTIVITIES
 
 
 
Power plant long-term service agreement
$
2.6

$
39.5

$
2.3

 
 
 
 
SUPPLEMENTAL CASH FLOW INFORMATION
 
 
 
Cash paid during the period for:
 
 
 
Interest (net of interest capitalized) (A)
$
139.6

$
141.9

$
145.4

Income taxes (net of income tax refunds)
(16.0
)
(5.9
)
(3.4
)
(A)
Net of interest capitalized of $18.0 million, $7.5 million and $4.2 million in 2017, 2016 and 2015, respectively.

7.
Income Taxes
 
2017 Tax Act

On December 22, 2017, President Trump signed the 2017 Tax Act into law, significantly changing U.S. corporate income tax laws. The 2017 Tax Act reduces the corporate federal tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017.

Among other things, the 2017 Tax Act repeals the alternative minimum tax regime for tax years beginning after December 31, 2017. For tax years beginning in 2018, 2019 and 2020, the alternative minimum tax credit carryforward can be utilized to offset regular tax with any remaining alternative minimum tax carryforwards eligible for a refund of 50 percent. Any remaining alternative minimum tax credit carryforwards will become fully refundable beginning in the 2021 tax year.  The 2017 Tax Act also limits a taxpayer’s ability to utilize net operating loss carryforwards to 80 percent of taxable income.  Additionally, net operating losses arising after 2017 can be carried forward indefinitely, but carryback is generally prohibited.  Net operating losses generated in tax years beginning before January 1, 2018 will not be subject to the taxable income limitation and will continue to have a two year carryback and 20 year carryforward period.  The 2017 Tax Act allows companies to expense 100 percent of the cost of qualified property placed in service after September 27, 2017 and before January 1, 2023 (an additional year is provided for certain property with longer production periods).  The 100 percent expense provision is phased down by 20 percent per calendar year beginning in 2023 (i.e., 80 percent, 60 percent, 40 percent and 20 percent for calendar years 2023 through 2026, respectively), with normal depreciation rules applicable after that.  The phase out begins in 2024 for certain property with longer production periods.  Companies can elect not to immediately expense qualified assets.  The 2017 Tax Act limits deductions for net interest expense to 30 percent of adjusted taxable income.  The 2017 Tax Act repeals deductions for qualified domestic production activities, entertainment, amusement or recreation expenses, membership dues for clubs and expenses incurred for the use of facilities in connection with these items.  The 2017 Tax Act retains the $1 million limitation on deductible compensation to covered employees.  However, it eliminates the current exception for performance-based compensation and expands the definition of covered employees

54
Exhibit 99.01

to include the chief financial officer.  The new executive compensation limitations are effective in 2018, with certain transition rules.

During 2017, the Company fully utilized all remaining federal net operating losses and alternative minimum tax credits. Changes made by the 2017 Tax Act related to alternative minimum tax and net operating loss utilization are not expected to have a material impact on the Company in the future. For regulated entities, such as OG&E, provisions in the 2017 Tax Act provide for unrestricted deduction of interest expense in lieu of full expensing of qualified property. Full expensing of qualified property will be available with regard to the Company's non-regulated investments, and the Company currently does not believe the interest expense limitations on non-regulated debt will have a significant impact. The Company will see some impact from other provisions related to non-deductible expenses, but those items are not expected to be material with respect to 2018.

ASC 740, "Income Taxes," requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled.  Therefore, at December 31, 2017, the Company remeasured deferred taxes based upon the new 21 percent tax rate.  For entities subject to ASC 980, "Accounting for Regulated Entities," such as OG&E, those entities are required to recognize a regulatory liability for the decrease in taxes payable for the change in tax rates that are expected to be returned to customers through future rates and to recognize a regulatory asset for the increase in taxes receivable for the change in tax rates that are expected to be recovered from customers through future rates.

As a result of remeasuring existing deferred taxes at the lower 21 percent tax rate, the Company reduced net deferred income tax liabilities by $1.273 billion, reduced income tax expense by $234.7 million and increased regulatory liabilities, net by $1.038 billion.

Staff Accounting Bulletin No. 118

On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the 2017 Tax Act. The Company has recognized the provisional tax impacts related to the revaluation of deferred tax assets and liabilities and included these amounts in its Consolidated Financial Statements for the year ended December 31, 2017. The ultimate impact may differ from these provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions the Company has made, additional regulatory guidance that may be issued and actions the Company may take as a result of the 2017 Tax Act. Any subsequent adjustment to these amounts will be recorded to adjust the initial recognition of tax reform in the quarter of 2018 when the analysis is complete.

The items comprising income tax (benefit) expense are as follows: 
Year Ended December 31 (In millions)
2017
2016
2015
Provision (benefit) for current income taxes: 
 
 
 
Federal
$
4.9

$
—

$
—

State
(4.2
)
(5.7
)
(5.2
)
Total provision (benefit) for current income taxes 
0.7

(5.7
)
(5.2
)
(Benefit) provision for deferred income taxes, net: 
 
 
 
Federal
(75.9
)
126.0

98.8

State
26.0

28.0

4.5

Total (benefit) provision for deferred income taxes, net 
(49.9
)
154.0

103.3

Deferred federal investment tax credits, net
(0.1
)
(0.2
)
(0.7
)
Total income tax (benefit) expense
$
(49.3
)
$
148.1

$
97.4

 
The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal tax examinations by tax authorities for years prior to 2014 or state and local tax examinations by tax authorities for years prior to 2013.  Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss.  Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property.  OG&E earns both federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which reduce the Company's effective tax rate.


55
Exhibit 99.01

The following schedule reconciles the statutory tax rates to the effective income tax rate:
Year Ended December 31
2017
2016
2015
Statutory federal tax rate
35.0
 %
35.0
 %
35.0
 %
Federal deferred tax revaluation
(41.2
)
—

—

Federal renewable energy credit (A)
(4.8
)
(6.8
)
(8.9
)
401(k) dividends
(0.5
)
(0.6
)
(0.7
)
Federal investment tax credits, net
(0.1
)
(0.8
)
(0.2
)
Other
(0.1
)
0.1

0.3

State income taxes, net of federal income tax benefit
2.0

1.9

0.1

Amortization of net unfunded deferred taxes
0.7

0.7

0.9

Remeasurement of state deferred tax liabilities
0.4

0.9

(0.8
)
Uncertain tax positions
—

0.1

0.7

Effective income tax rate
(8.6
)%
30.5
 %
26.4
 %
(A)
Represents credits associated with the production from OG&E's wind farms.

The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 2017 and 2016 were as follows:
December 31 (In millions)
2017
2016
Deferred income tax liabilities, net:
 
 
Accelerated depreciation and other property related differences
$
1,449.6

$
2,103.2

Investment in Enable Midstream Partners
441.7

657.3

Regulatory asset
18.9

34.4

Company Pension Plan
11.5

16.5

Bond redemption-unamortized costs
2.6

4.3

Derivative instruments
1.6

2.2

Income taxes (recoverable from) refundable to customers, net
(244.3
)
24.1

Federal tax credits
(218.5
)
(220.6
)
State tax credits
(141.7
)
(112.2
)
Postretirement medical and life insurance benefits
(25.2
)
(48.9
)
Net operating losses
(21.1
)
(31.7
)
Asset retirement obligations
(19.2
)
(24.5
)
Regulatory liabilities
(16.8
)
(34.6
)
Accrued liabilities
(7.4
)
(16.1
)
Accrued vacation
(2.1
)
(3.5
)
Other
(0.9
)
(14.0
)
Deferred federal investment tax credits
(0.5
)
(0.8
)
Uncollectible accounts
(0.4
)
(0.6
)
Total deferred income tax liabilities, net
$
1,227.8

$
2,334.5


As of December 31, 2017, the Company has classified $16.4 million of unrecognized tax benefits as a reduction of deferred tax assets recorded. Management is currently unaware of any issues under review that could result in significant additional payments, accruals or other material deviation from this amount.


56
Exhibit 99.01

Following is a reconciliation of the Company’s total gross unrecognized tax benefits as of the years ended December 31, 2017, 2016 and 2015.
(In millions)
2017
2016
2015
Balance at January 1
$
20.7

$
20.2

$
16.1

Tax positions related to current year:
 
 
 
Additions
—

0.5

4.1

Balance at December 31
$
20.7

$
20.7

$
20.2


As of December 31, 2017, 2016 and 2015, there were $16.4 million, $13.5 million and $13.2 million of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.

Where applicable, the Company classifies income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2017, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions.
The Company sustained federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. As a result, the Company had accrued federal and state income tax benefits carrying into 2017. During 2017, the remaining federal net operating loss was utilized. State operating losses are being carried forward for utilization in future years. In addition to the tax operating losses, the Company was unable to utilize the various tax credits that were generated during these years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, the Company anticipates future taxable income will be sufficient to utilize remaining losses and credits before they begin to expire. The following table summarizes these carry forwards:
(In millions)
Carry Forward Amount
Deferred Tax Asset
Earliest Expiration Date
State operating loss
$
472.1

$
21.1

2030
Federal tax credits
218.5

218.5

2029
State tax credits:
 
 
 
Oklahoma investment tax credits
144.1

113.8

N/A
Oklahoma capital investment board credits
8.5

8.5

N/A
Oklahoma zero emission tax credits
24.1

19.4

2020

8.
Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan
 
The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan in 2017.  The Company may, from time to time, issue shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2017, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.


57
Exhibit 99.01

Earnings Per Share
 
Basic earnings per share is calculated by dividing net income by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock. Basic and diluted earnings per share for the Company were calculated as follows:
(In millions except per share data)
2017
2016
2015
Net income
$
619.0

$
338.2

$
271.3

Average common shares outstanding:
 
 
 
Basic average common shares outstanding
199.7

199.7

199.6

Effect of dilutive securities:
 
 
 
Contingently issuable shares (performance and restricted stock units)
0.3

0.2

—

Diluted average common shares outstanding
200.0

199.9

199.6

Basic earnings per average common share
$
3.10

$
1.69

$
1.36

Diluted earnings per average common share
$
3.10

$
1.69

$
1.36

Anti-dilutive shares excluded from earnings per share calculation
—

—

—

 
Dividend Restrictions

The Company’s Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. As there is no preferred stock outstanding, that restriction did not place any effective limit on the Company’s ability to pay dividends to its shareholders. Pursuant to the leverage restriction in the Company’s revolving credit agreement, the Company must maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $605.3 million of the Company’s retained earnings from being paid out in dividends. Accordingly, approximately $2.2 billion of the Company’s retained earnings as of December 31, 2017 are unrestricted for the payment of dividends.

The Company utilizes receipts from its equity investment in Enable and dividends from OG&E to pay dividends to its shareholders. Enable’s partnership agreement requires that it distribute all "available cash," as defined as cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter. Pursuant to the Federal Power Act, OG&E is restricted from paying dividends from its capital accounts. Dividends are paid from retained earnings. Pursuant to the leverage restriction in OG&E’s revolving credit agreement, OG&E must also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $600.1 million of OG&E’s retained earnings from being paid out in dividends. Accordingly, approximately $1.8 billion of OG&E’s retained earnings as of December 31, 2017 are unrestricted for the payment of dividends.

9.
Long-Term Debt
 
A summary of the Company's long-term debt is included in the Consolidated Statements of Capitalization.  At December 31, 2017, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day.  The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:
SERIES
DATE DUE
AMOUNT
 
 
 
 
(In millions)
0.65%
-
1.86%
Garfield Industrial Authority, January 1, 2025
$
47.0

0.65%
-
1.80%
Muskogee Industrial Authority, January 1, 2025
32.4

0.66%
-
1.80%
Muskogee Industrial Authority, June 1, 2027
56.0

Total (redeemable during next 12 months)
$
135.4


58
Exhibit 99.01


All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase.  The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased.  The repayment option may only be exercised by the holder of a bond for the principal amount.  When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase.  This process occurs once per week.  Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds.  If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds.  As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-Term Debt in the Company's Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

Long-Term Debt Maturities
 
Maturities of the Company'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.  
 
The Company has previously incurred costs related to debt refinancing.  Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset. Unamortized debt expense and unamortized premium and discount on long-term debt are classified as Long-Term Debt in the Consolidated Balance Sheets and are being amortized over the life of the respective debt.

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.

10.
Short-Term Debt and Credit Facilities
 
On March 8, 2017, the Company and OG&E each entered into new $450.0 million unsecured five-year revolving credit facilities to replace existing facilities. Each of these new facilities is scheduled to terminate on March 8, 2022. However, the Company and OG&E have the right to request an extension of the revolving credit facility termination date under their respective facility for an additional one-year period, which can be exercised up to two times. All such extension requests are subject to majority lender group approval (and only the commitments of those lenders that consent to such extension (or that agree to replace any non-consenting lender) will be extended for such additional period).

Borrowings under the new facilities bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.69 percent to 1.275 percent, or an alternate base rate, plus a margin of 0.00 percent to 0.275 percent. The new facilities have a facility fee that ranges from 0.06 percent to 0.225 percent. Interest rate margins and facility fees are based on the Company's and OG&E's then-current senior unsecured credit ratings, as applicable.

Each of the facilities provides for issuance of letters of credit, provided that (i) the aggregate outstanding credit exposure shall not exceed the amount of the revolving credit facility and (ii) the aggregate outstanding stated amount of letters of credit issued under such facility shall not exceed a specified maximum sublimit ($100 million for each of the Company and OG&E). Advances under the facilities may be used to refinance existing indebtedness and for working capital and general corporate purposes of the respective borrower and its subsidiaries, including commercial paper liquidity support, letters of credit, acquisitions and distributions.

Each of the facilities is unsecured and, under certain circumstances, may be increased (by up to $150 million in each case for the Company and OG&E) to a maximum revolving commitment limit of $600 million. Advances of revolving loans and letters of credit under the facilities are subject to certain conditions precedent, including the accuracy of certain representations and warranties and the absence of any default or unmatured default.


59
Exhibit 99.01

The Company and OG&E's facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E's facilities each also contain covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement.  As of December 31, 2017, the Company had $168.4 million of short-term debt compared to $236.2 million at December 31, 2016.  The following table provides information regarding the Company's revolving credit agreements at December 31, 2017.
 
Aggregate
Amount
Weighted-Average
 
 
Entity
Commitment 
Outstanding (A)
Interest Rate
Expiration
 
(In millions)
 
 
 
 
OGE Energy (B)
$
450.0

$
168.4

1.62
%
(D)
March 8, 2022

OG&E (C)
450.0

0.3

0.95
%
(D)
March 8, 2022

Total
$
900.0

$
168.7

1.62
%
 
 
 
(A)
Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2017.
(B)
This bank facility is available to back up the Company's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  
(C)
This bank facility 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.  
(D)
Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company'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 the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit. 
 
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis.  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.

11.
Retirement Plans and Postretirement Benefit Plans
 
Pension Plan and Restoration of Retirement Income Plan
 
It is the Company's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by the Company's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.  The Company made a $20.0 million contribution to its Pension Plan in both 2017 and 2016. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2018.  Any contribution to the Pension Plan during 2018 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. The Company 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.

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2017 and 2015, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, the Company recorded

60
Exhibit 99.01

pension settlement charges of $15.3 million in the fourth quarter of 2017 and $21.7 million during 2015. The pension settlement charges did not increase the Company's total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.6 million during 2016.
 
The Company provides a Restoration of Retirement Income Plan to those participants in the Company's Pension Plan whose benefits are subject to certain limitations of the Code.  Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the federal tax laws.  The Restoration of Retirement Income Plan is intended to be an unfunded plan.

Obligations and Funded Status
 
The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2017 and 2016. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1) in the Company's Consolidated Balance Sheets.  The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods. The benefit obligation for the Company's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for the Company's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2017 was $626.9 million and $7.5 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2016 was $608.0 million and $6.1 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are as follows:
 
Pension Plan
Restoration of Retirement
Income Plan
Postretirement
Benefit Plans
 December 31 (In millions)
2017
2016
2017
2016
2017
2016
Change in benefit obligation
 
 
 
 
 
 
Beginning obligations
$
672.2

$
680.0

$
7.0

$
25.1

$
215.9

$
225.3

Service cost
15.5

15.8

0.3

0.3

0.6

0.8

Interest cost
26.2

25.5

0.3

0.4

7.2

9.5

Plan settlements
(50.2
)
—

—

(20.6
)
(28.1
)
—

Plan amendments
—

—

—

—

(39.6
)
—

Participants' contributions
—

—

—

—

3.5

3.6

Actuarial losses (gains)
38.6

4.7

0.7

1.8

5.6

(7.6
)
Benefits paid
(14.8
)
(53.8
)
(0.2
)
—

(15.7
)
(15.7
)
Ending obligations
$
687.5

$
672.2

$
8.1

$
7.0

$
149.4

$
215.9

 
 
 
 
 
 
 
Change in plans' assets
 
 
 
 
 
 
Beginning fair value
$
595.9

$
581.7

$
—

$
—

$
53.1

$
55.3

Actual return on plans' assets
84.4

48.0

—

—

2.8

2.0

Employer contributions
20.0

20.0

0.2

20.6

34.6

7.9

Plan settlements
(50.2
)
—

—

(20.6
)
(28.1
)
—

Participants' contributions
—

—

—

—

3.5

3.6

Benefits paid
(14.8
)
(53.8
)
(0.2
)
—

(15.7
)
(15.7
)
Ending fair value
$
635.3

$
595.9

$
—

$
—

$
50.2

$
53.1

Funded status at end of year
$
(52.2
)
$
(76.3
)
$
(8.1
)
$
(7.0
)
$
(99.2
)
$
(162.8
)


61
Exhibit 99.01

Net Periodic Benefit Cost
 
Pension Plan
Restoration of Retirement
Income Plan
Postretirement Benefit Plans
Year Ended December 31 (In millions)
2017
2016
2015
2017
2016
2015
2017
2016
2015
Included in Other Operation and Maintenance:
 
 
 
 
 
 
 
 
 
Service cost
$
15.5

$
15.8

$
16.1

$
0.3

$
0.3

$
1.3

$
0.6

$
0.8

$
1.5

Included in Other Net Periodic Pension and Postretirement (Cost) Benefit:
 
 
 
 
 
 
 
 
 
Interest cost
26.2

25.5

26.1

0.3

0.4

0.7

7.2

9.5

10.3

Expected return on plan assets
(42.6
)
(41.5
)
(46.0
)
—

—

—

(2.2
)
(2.3
)
(2.4
)
Amortization of net loss
17.4

16.5

18.0

0.4

0.7

0.6

2.0

2.6

13.9

Amortization of unrecognized prior service cost (A)
(0.1
)
(0.1
)
0.4

0.1

0.1

0.1

(3.5
)
(8.8
)
(16.5
)
Settlement
15.3

—

21.7

—

8.6

—

0.6

—

—

Total net periodic benefit cost
31.7

16.2

36.3

1.1

10.1

2.7

4.7

1.8

6.8

Less: Amount paid by unconsolidated affiliates
4.3

5.1

4.2

—

0.3

0.1

0.3

0.2

1.3

Net periodic benefit cost (B)
$
27.4

$
11.1

$
32.1

$
1.1

$
9.8

$
2.6

$
4.4

$
1.6

$
5.5

(A)
Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B)
In addition to the $32.9 million, $22.5 million and $40.2 million of net periodic benefit cost recognized in 2017, 2016 and 2015, respectively, OG&E recognized the following:

•
a change in pension expense in 2017, 2016 and 2015 of $(2.3) million, $9.9 million and $(3.1) million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1);
•
an increase in postretirement medical expense in 2017, 2016 and 2015 of $6.2 million, $7.9 million and $5.8 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and
•
a deferral of pension expense in 2017, 2016 and 2015 of $1.1 million, $0.1 million and $1.9 million related to the Arkansas jurisdictional portion of the pension settlement charge of $15.3 million, $8.6 million and $21.7 million, respectively.

(In millions)
2017
2016
2015
Capitalized portion of net periodic pension benefit cost
$
4.4

$
4.0

$
5.0

Capitalized portion of net periodic postretirement benefit cost
1.2

0.8

1.9

       
Rate Assumptions
 
Pension Plan and
Restoration of Retirement Income Plan
Postretirement
Benefit Plans
Year Ended December 31
2017
2016
2015
2017
2016
2015
Discount rate
3.60
%
4.00
%
4.00
%
3.70
%
4.20
%
4.25
%
Rate of return on plans' assets
7.50
%
7.50
%
7.50
%
4.00
%
4.00
%
4.00
%
Compensation increases
4.20
%
4.20
%
4.20
%
N/A

N/A

N/A

Assumed health care cost trend:
 

 

 

 

 

 

Initial trend
N/A

N/A

N/A

7.50
%
6.75
%
6.10
%
Ultimate trend rate
N/A

N/A

N/A

4.50
%
4.50
%
4.50
%
Ultimate trend year
N/A

N/A

N/A

2030

2026

2026

N/A - not applicable
 
The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The discount rate used to determine net

62
Exhibit 99.01

benefit cost for the current year is the same discount rate used to determine the benefit obligation as of the previous year's balance sheet date.

The overall expected rate of return on plan assets assumption was 7.50 percent in both 2017 and 2016, which was used in determining net periodic benefit cost due to recent returns on the Company's long-term investment portfolio.  The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans.  This assumption is reexamined at least annually and updated as necessary.  The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans.  Future health care cost trend rates are assumed to be 6.50 percent in 2018 with the rates trending downward to 4.50 percent by 2026.  A one-percentage point change in the assumed health care cost trend rate would have the following effects: 
ONE-PERCENTAGE POINT INCREASE
Year Ended December 31 (In millions)
2017
2016
2015
Effect on aggregate of the service and interest cost components
$
—

$
—

$
—

Effect on accumulated postretirement benefit obligations
0.1

0.2

0.2

ONE-PERCENTAGE POINT DECREASE
Year Ended December 31 (In millions)
2017
2016
2015
Effect on aggregate of the service and interest cost components
$
—

$
—

$
0.1

Effect on accumulated postretirement benefit obligations
0.3

0.7

0.7


Pension Plan Investments, Policies and Strategies
 
The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.
Projected Benefit Obligation Funded Status Thresholds
<90%
95%
100%
105%
110%
115%
120%
Fixed income
50%
58%
65%
73%
80%
85%
90%
Equity
50%
42%
35%
27%
20%
15%
10%
Total
100%
100%
100%
100%
100%
100%
100%

Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.
        Asset Class
Target Allocation
Minimum
Maximum
Domestic Large Cap Equity                                        
40%
35%
60%
Domestic Mid-Cap Equity                                           
15%
5%
25%
Domestic Small-Cap Equity
25%
5%
30%
International Equity                                           
20%
10%
30%
 
The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company's members and the Company's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. 

The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above.  More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.


63
Exhibit 99.01

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period.  Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style.  The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years.  Each investment manager is expected to outperform its respective benchmark.  Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:
Asset Class
Comparative Benchmark(s)
Active Duration Fixed Income
Bloomberg Barclays Aggregate
Long Duration Fixed Income
Duration blended Barclays Long Government/Credit & Barclays Universal
Equity Index
Standard & Poor's 500 Index
Mid-Cap Equity
Russell Midcap Index
 
Russell Midcap Value Index
Small-Cap Equity
Russell 2000 Index
 
Russell 2000 Value Index
International Equity
Morgan Stanley Capital Investment ACWI ex-U.S.
 
The fixed income managers are expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance.  Exposure to any single issuer, other than the U.S. government, its agencies or its instrumentalities (which have no limits), is limited to five percent of the fixed income portfolio as measured by market value.  At least 75 percent of the invested assets must possess an investment-grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings.  The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio.  The purchase of any of the Company's equity, debt or other securities is prohibited.
 
The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets and reinvest cash flow into existing business.  The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index.  The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000.  The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets.  The manager is required to operate under certain restrictions including regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-U.S. Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the U.S. All of the equities which are purchased for the international portfolio are thoroughly researched.  All securities are freely traded on a recognized stock exchange, and there are no over-the-counter derivatives.  The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).
 
For all domestic equity investment managers, no more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of the Company's Investment Committee is received.  The purchase of securities on margin is prohibited as is securities lending.  Private placement or venture capital may not be purchased.  All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment.  The purchase of any of the Company's equity, debt or other securities is prohibited.  The purchase of equity or debt issues of the portfolio manager's organization is also prohibited.  The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.


64
Exhibit 99.01

Pension Plan Investments
 
The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2017 and 2016. There were no Level 3 investments held by the Pension Plan at December 31, 2017 and 2016. 
(In millions)
December 31, 2017
Level 1
Level 2
Net Asset Value (A)
Common stocks
$
225.9

$
225.9

$
—

$
—

U.S. Treasury notes and bonds (B)
169.7

169.7

—

—

Mortgage- and asset-backed securities
43.4

—

43.4

—

Corporate fixed income and other securities
153.8

—

153.8

—

Commingled fund (C)
29.9

—

—

29.9

Foreign government bonds
4.0

—

4.0

—

U.S. municipal bonds
1.2

—

1.2

—

Money market fund
4.3

—

—

4.3

Mutual fund
7.8

7.8

—

—

Futures:
 


 
 
U.S. Treasury futures (receivable)
13.4

—

13.4

—

U.S. Treasury futures (payable)
(11.4
)
—

(11.4
)
—

Cash collateral
0.3

0.3

—

—

Forward contracts:
 
 
 
 
Receivable (foreign currency)
0.1

—

0.1

—

Total Pension Plan investments
$
642.4

$
403.7

$
204.5

$
34.2

Receivable from broker for securities sold
—

 

 

 
Interest and dividends receivable
3.2

 

 

 
Payable to broker for securities purchased
(10.3
)
 

 

 
Total Pension Plan assets
$
635.3

 

 

 

65
Exhibit 99.01

(In millions)
December 31, 2016
Level 1
Level 2
Net Asset Value (A)
Common stocks
$
237.1

$
237.1

$
—

$
—

U.S. Treasury notes and bonds (B)
122.3

122.3

—

—

Mortgage-backed securities
59.2

—

59.2

—

Corporate fixed income and other securities
137.6

—

137.6

—

Commingled fund (C)
23.8

—

—

23.8

Foreign government bonds
5.2

—

5.2

—

U.S. municipal bonds
1.9

—

1.9

—

Money market fund
2.2

—

—

2.2

Mutual fund
9.0

9.0

—

—

Futures:
 
 
 
 
U.S. Treasury futures (receivable)
10.7

—

10.7

—

U.S. Treasury futures (payable)
(2.3
)
—

(2.3
)
—

Cash collateral
0.3

0.3

—

—

Forward contracts:
 
 
 
 
Receivable (foreign currency)
0.2

—

0.2

—

Total Pension Plan investments
$
607.2

$
368.7

$
212.5

$
26.0

Receivable from broker for securities sold
—

 

 

 
Interest and dividends receivable
3.0

 

 

 
Payable to broker for securities purchased
(14.3
)
 

 

 
Total Pension Plan assets
$
595.9

 

 

 
(A)
GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.
(B)
This category represents U.S. Treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher.
(C)
This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.
 
The three levels defined in the fair value hierarchy and examples of each are as follows:
 
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common stocks, U.S. Treasury notes and bonds, mutual funds and cash collateral.
 
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability.  Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage- and asset-backed securities, U.S. municipal bonds, foreign government bonds, U.S. Treasury futures contracts and forward contracts.
 
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Postretirement Benefit Plans

In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for eligible retired members.  Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits, while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as the Company specifies from time to time toward the cost of coverage for postretirement benefits.  The benefits are subject to deductibles, co-payment provisions and other limitations.  OG&E charges

66
Exhibit 99.01

postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

The Company's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and the Company covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. The Company provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to a Company-sponsored health reimbursement arrangement. Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses.

In August 2017, the Company adopted an amendment to the retiree medical plan.  Effective January 1, 2018, the Company will reduce the amount of supplemental Medicare coverage for Medicare-eligible retirees, providing a fixed stipend based on current market analysis in August 2017. The Company will continue to allow those Medicare-eligible retirees to acquire coverage from a company-provided third-party administrator. The effect of these plan amendments is reflected in the Company’s December 31, 2017 Consolidated Balance Sheet as a reduction to the postretirement benefit obligation of $42.9 million.

In August 2017, the Company settled the retiree life plan in its entirety and paid $26.4 million to participants in August 2017. No gain or loss was recognized upon settlement, and the effect of the settlement is reflected in the Company’s December 31, 2017 Consolidated Balance Sheet as a reduction in the Accrued Benefit Obligations of $27.9 million and related other comprehensive income and regulatory asset of $2.1 million.
 
Postretirement Plans Investments
 
The following tables summarize the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2017 and 2016.  There were no Level 2 investments held by the postretirement benefit plans at December 31, 2017 and 2016.
(In millions)
December 31, 2017
Level 1
Level 3
Group retiree medical insurance contract
$
40.2

$
—

$
40.2

Mutual funds investment:
 
 
 
U.S. equity investments
9.5

9.5

—

Cash
0.5

0.5

—

Total plan investments
$
50.2

$
10.0

$
40.2

(In millions)
December 31, 2016
Level 1
Level 3
Group retiree medical insurance contract
$
44.7

$
—

$
44.7

Mutual funds investment:
 
 
 
U.S. equity investments
8.1

8.1

—

Money market funds investment
0.3

0.3

—

Total plan investments
$
53.1

$
8.4

$
44.7


The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans' pro-rata share of the total assets in the contract.
 

67
Exhibit 99.01

The following table summarizes the postretirement benefit plans' investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
Year Ended December 31 (In millions)
2017
Group retiree medical insurance contract:
 
Beginning balance
$
44.7

Interest income
0.8

Dividend income
0.5

Net unrealized gains related to instruments held at the reporting date
0.3

Claims paid
(5.9
)
Realized losses
(0.1
)
Investment fees
(0.1
)
Ending balance
$
40.2

 
Medicare Prescription Drug, Improvement and Modernization Act of 2003
 
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs.  The following table summarizes the gross benefit payments the Company expects to pay related to its postretirement benefit plans, including prescription drug benefits.
 
 
 
(In millions)
Gross Projected
Postretirement
Benefit
Payments
2018
$
11.4

2019
11.5

2020
11.6

2021
11.6

2022
11.7

After 2022
48.6


 The following table summarizes the benefit payments the Company expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan.  These expected benefits are based on the same assumptions used to measure the Company's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. 
 
(In millions)
Projected Benefit Payments
2018
$
65.6

2019
62.0

2020
63.4

2021
62.3

2022
61.1

After 2022
285.0


Post-Employment Benefit Plan
 
Disabled employees receiving benefits from the Company's Group Long-Term Disability Plan are entitled to continue participating in the Company's Medical Plan along with their dependents.  The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented.  The obligation also includes future medical benefits expected to be paid to current employees participating in the Company's Group Long-Term Disability Plan and their dependents, as defined in the Company's Medical Plan.
 
The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation.  The estimated future medical benefits are projected to grow with expected future medical cost trend rates and

68
Exhibit 99.01

are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits.  The Company's post-employment benefit obligation was $2.5 million and $2.4 million at December 31, 2017 and 2016, respectively.
 
401(k) Plan
 
The Company provides a 401(k) Plan, and each regular full-time employee of the Company or a participating affiliate is eligible to participate in the 401(k) Plan immediately.  All other employees of the Company or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period.  Participants who have reached age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof, (ii) a contribution made on a non-Roth after-tax basis or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.

No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan.  The Company match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan requirements, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates.  The Company contributed $13.2 million, $11.9 million and $11.6 million in 2017, 2016 and 2015, respectively, to the 401(k) Plan.
 
Deferred Compensation Plan
 
The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan.  The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.
 
Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers.  The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan. Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2017, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's common stock. The Company accounts for the contributions related to the Company's executive officers in this plan as Accrued Benefit Obligations, and the Company accounts for the contributions related to the Company's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.  The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets.  The appreciation of these investments is accounted for as Other Income, and the increase in the liability under the plan is accounted for as Other Expense in the Consolidated Statements of Income.
  

69
Exhibit 99.01

12.
Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) natural gas midstream operations segment. Other Operations primarily includes the operations of the holding company. 

Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.

The following tables summarize the results of the Company's business segments for the years ended December 31, 2017, 2016 and 2015.
2017
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
2,261.1

$
—

$
—

$
—

$
2,261.1

Cost of sales
897.6

—

—

—

897.6

Other operation and maintenance
470.7

(0.3
)
(10.8
)
—

459.6

Depreciation and amortization
280.9

—

2.6

—

283.5

Taxes other than income
84.8

1.0

3.6

—

89.4

Operating income (loss)
527.1

(0.7
)
4.6

—

531.0

Equity in earnings of unconsolidated affiliates
—

131.2

—

—

131.2

Other income (expense)
58.6

(0.5
)
(5.9
)
(0.9
)
51.3

Interest expense
138.4

—

6.3

(0.9
)
143.8

Income tax expense (benefit) (A)
141.8

(195.2
)
4.1

—

(49.3
)
Net income (loss)
$
305.5

$
325.2

$
(11.7
)
$
—

$
619.0

Investment in unconsolidated affiliates
$
—

$
1,151.9

$
8.5

$
—

$
1,160.4

Total assets
$
9,255.6

$
1,155.3

$
109.1

$
(107.3
)
$
10,412.7

Capital expenditures
$
824.1

$
—

$
—

$
—

$
824.1

(A) The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act. See Note 7 for further discussion of the effects of the 2017 Tax Act.

70
Exhibit 99.01

2016
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
2,259.2

$
—

$
—

$
—

$
2,259.2

Cost of sales
880.1

—

—

—

880.1

Other operation and maintenance
469.0

(0.2
)
(12.9
)
—

455.9

Depreciation and amortization
316.4

—

6.2

—

322.6

Taxes other than income
84.0

—

3.6

—

87.6

Operating income (loss)
509.7

0.2

3.1

—

513.0

Equity in earnings of unconsolidated affiliates
—

101.8

—

—

101.8

Other income (expense)
26.9

(7.8
)
(5.3
)
(0.2
)
13.6

Interest expense
138.1

—

4.2

(0.2
)
142.1

Income tax expense (benefit)
114.4

40.5

(6.8
)
—

148.1

Net income
$
284.1

$
53.7

$
0.4

$
—

$
338.2

Investment in unconsolidated affiliates
$
—

$
1,158.6

$
—

$
—

$
1,158.6

Total assets
$
8,669.4

$
1,521.6

$
89.0

$
(340.4
)
$
9,939.6

Capital expenditures
$
660.1

$
—

$
—

$
—

$
660.1


2015
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
2,196.9

$
—

$
—

$
—

$
2,196.9

Cost of sales
865.0

—

—

—

865.0

Other operation and maintenance
428.5

2.5

(4.3
)
—

426.7

Depreciation and amortization
299.9

—

8.0

—

307.9

Taxes other than income
87.1

—

4.1

—

91.2

Operating income (loss)
516.4

(2.5
)
(7.8
)
—

506.1

Equity in earnings of unconsolidated affiliates (A)
—

15.5

—

—

15.5

Other income (expense)
4.0

(4.6
)
(3.0
)
(0.3
)
(3.9
)
Interest expense
146.7

—

2.6

(0.3
)
149.0

Income tax expense (benefit)
104.8

(1.0
)
(6.4
)
—

97.4

Net income (loss)
$
268.9

$
9.4

$
(7.0
)
$
—

$
271.3

Investment in unconsolidated affiliates
$
—

$
1,194.4

$
—

$
—

$
1,194.4

Total assets
$
8,525.5

$
1,439.5

$
174.6

$
(559.0
)
$
9,580.6

Capital expenditures
$
551.6

$
—

$
(3.8
)
$
—

$
547.8

(A)
The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of Enable's goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of the goodwill impairment.


71
Exhibit 99.01

13.
Commitments and Contingencies
 
Operating Lease Obligations
The Company has operating lease obligations expiring at various dates, primarily for OG&E railcar leases, OG&E wind farm land leases and the Company's noncancellable operating lease.  Future minimum payments for noncancellable operating leases are as follows: 
Year Ended December 31 (In millions)
2018
2019
2020
2021
2022
After 2022
Total
Operating lease obligations:
 
 
 
 
 
 
 
Railcars
$
1.7

$
20.9

$
—

$
—

$
—

$
—

$
22.6

Wind farm land leases
2.5

2.5

2.9

2.9

2.9

40.6

54.3

Noncancellable operating lease
0.6

—

—

—

—

—

0.6

Total operating lease obligations
$
4.8

$
23.4

$
2.9

$
2.9

$
2.9

$
40.6

$
77.5


Payments for operating lease obligations were $6.2 million, $9.3 million and $7.7 million for the years ended December 31, 2017, 2016 and 2015, respectively.

OG&E 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.

OG&E Wind Farm Land Lease Agreements

OG&E has operating leases related to land for its Centennial, OU Spirit and Crossroads wind farms expiring at various dates. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their useful life.

Noncancellable Operating Lease

On August 29, 2012, the Company executed a five-year lease agreement for office space from September 1, 2013 to August 31, 2018. This lease has rent escalations which increase after five years and allows for leasehold improvements.


72
Exhibit 99.01

Other Purchase Obligations and Commitments
 
The Company's other future purchase obligations and commitments estimated for the next five years are as follows: 
(In millions)
2018
2019
2020
2021
2022
Total
Other purchase obligations and commitments:
 
 
 
 
 
 
Cogeneration capacity and fixed operation and maintenance payments
$
72.8

$
65.3

$
53.2

$
49.5

$
45.4

$
286.2

Expected cogeneration energy payments
35.7

35.6

35.9

37.1

38.3

182.6

Minimum fuel purchase commitments
139.8

36.2

24.6

24.6

24.6

249.8

Expected wind purchase commitments
58.7

56.5

56.9

57.3

57.8

287.2

Long-term service agreement commitments
7.9

41.9

2.4

2.4

2.4

57.0

Mustang Modernization expenditures
24.9

—

—

—

—

24.9

Environmental compliance plan expenditures
63.0

8.9

0.2

—

—

72.1

Total other purchase obligations and commitments
$
402.8

$
244.4

$
173.2

$
170.9

$
168.5

$
1,159.8


Public Utility Regulatory Policy Act of 1978

At December 31, 2017, OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019, and a QF contract with AES-Shady Point, Inc. which expires on January 15, 2023.  These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978.  Stated generally, the Public Utility Regulatory Policy Act of 1978 and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a QF.  The rate for such power to be paid by OG&E was approved by the OCC.  The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E, and the other is a capacity charge, which OG&E must pay the QF for having the capacity available.  However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E's obligation to pay the capacity charge is suspended.  The total cost of cogeneration payments is recoverable in rates from customers.  For the 320 MWs AES-Shady Point, Inc. QF contract and the 120 MWs Oklahoma Cogeneration LLC QF contract, OG&E purchases 100 percent of the electricity generated by the QFs.

As part of the QF contract with AES-Shady Point Inc., OG&E had the option beginning in July 2017 to provide notice to AES-Shady Point Inc. to terminate the contract in January 2018. On July 17, 2017, OG&E and AES-Shady Point, Inc. amended the agreement to allow OG&E the ability, through July 17, 2018, to provide AES-Shady Point Inc. a termination notice that would terminate the agreement on January 15, 2019.
 
For the years ended December 31, 2017, 2016 and 2015, OG&E made total payments to cogenerators of $115.2 million, $124.8 million and $124.0 million, respectively, of which $63.0 million, $66.3 million and $69.5 million, respectively, represented capacity payments.  All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Sales.
 
OG&E Minimum Fuel Purchase Commitments
 
OG&E has coal contracts for purchases through June 2018. 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.


73
Exhibit 99.01

OG&E Wind Purchase Commitments
 
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

The following table summarizes OG&E's wind power purchases for the years ended December 31, 2017, 2016 and 2015. 
Year Ended December 31 (In millions)
2017
2016
2015
CPV Keenan
$
29.0

$
29.2

$
26.7

Edison Mission Energy
22.1

21.1

19.7

NextEra Energy
7.4

7.3

7.0

FPL Energy
2.6

3.4

3.2

Total wind power purchased
$
61.1

$
61.0

$
56.6


OG&E Long-Term Service Agreement Commitments
 
OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 4,800 factored-fired starts. On December 30, 2015, the McClain Long-Term Service Agreement was amended to define the terms and conditions for the exchange of spare rotors between OG&E and General Electric International, Inc. Based on historical usage and current expectations for future usage, this contract is expected to run until 2031. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.
 
OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2029. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

Enable Gas Transportation Agreement

OG&E contracts with Enable for firm non-notice load following gas transportation services under a five year contract. The contract will expire in April 2019. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will be effective upon the conversion of units 4 and 5 at Muskogee from coal to gas.

Environmental Laws and Regulations
 
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.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. OG&E is managing several potentially material uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. Management continues to

74
Exhibit 99.01

evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
 
Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015 to install the Dry Scrubber systems. The Dry Scrubbers are expected to be completed in mid to late 2018. More detail regarding the ECP can be found under the "Pending Regulatory Matters" in Note 14.

Clean Power Plan

On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO2 emissions from existing fossil-fuel-fired power plants along with state-specific CO2 reduction standards expressed as both rate-based (lbs./MWh) and mass-based (tons/yr.) goals. However, the rule was challenged in court when it was issued, and the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan on February 9, 2016 pending resolution of the court challenges. The EPA published a proposal on October 16, 2017 to repeal the Clean Power Plan. In addition, the EPA published an Advance Notice of Proposed Rulemaking seeking comments on regulatory options for replacing the Clean Power Plan. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Other
 
In the normal course of business, the Company 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, the Company 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 the Company's Consolidated Financial Statements. At the present time, based on current available information, the Company 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 the Company's consolidated financial position, results of operations or cash flows. 

14.
Rate Matters and Regulation
 
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 the Company.  The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E, (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions.  In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

Completed Regulatory Matters

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

75
Exhibit 99.01

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. The formula rate rider provides for an adjustment to rates 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 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.

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.


76
Exhibit 99.01

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. The Company is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.
  
OG&E anticipates the total cost of Dry Scrubbers will be $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.

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.

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.


77
Exhibit 99.01

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.  The Company 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 the Company'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. The Company 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 the Company's consolidated financial position, results of operations and cash flows.



78
Exhibit 99.01

15.
Quarterly Financial Data (Unaudited)

Due to the seasonal fluctuations and other factors of the Company's businesses, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In the Company's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows:
Quarter Ended (In millions, except per share data)
 
March 31
June 30
September 30
December 31
Total
Operating revenues
2017
$
456.0

$
586.4

$
716.8

$
501.9

$
2,261.1

 
2016
$
433.1

$
551.4

$
743.9

$
530.8

$
2,259.2

Operating income
2017
$
45.7

$
145.8

$
244.5

$
95.0

$
531.0

 
2016
$
38.5

$
135.2

$
258.0

$
81.3

$
513.0

Net income
2017
$
36.0

$
104.8

$
183.4

$
294.8

$
619.0

 
2016
$
25.2

$
71.5

$
183.6

$
57.9

$
338.2

Basic earnings per average common share (A)
2017
$
0.18

$
0.52

$
0.92

$
1.48

$
3.10


2016
$
0.13

$
0.35

$
0.92

$
0.29

$
1.69

Diluted earnings per average common share (A)
2017
$
0.18

$
0.52

$
0.92

$
1.48

$
3.10


2016
$
0.13

$
0.35

$
0.92

$
0.29

$
1.69

(A)
Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.


79
Exhibit 99.01

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Stockholders and the Board of Directors of OGE Energy Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of OGE Energy Corp. (the "Company") as of December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "financial statements"). In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We did not audit the consolidated financial statements of Enable Midstream Partners, LP ("Enable"), a partnership in which the Company has a 25.7 percent interest at December 31, 2017. The Company’s investment in Enable constituted 11.1 percent and 11.7 percent of the Company’s total assets as of December 31, 2017 and 2016, respectively, and the Company’s equity earnings in the net income of Enable constituted 23.0 percent, 20.9 percent and 4.2 percent of the Company’s income before taxes for the years ended December 31, 2017, 2016 and 2015, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Enable, is based solely on the report of the other auditors.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 21, 2018 expressed an unqualified opinion thereon.

Adoption of New Accounting Standard

As discussed in Note 2 to the consolidated financial statements, the Company adopted Accounting Standards Update 2017-07 and as a result changed its method of accounting for the presentation of pension and postretirement benefit costs in 2017, 2016, and 2015.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/  Ernst & Young LLP
 
 
 

 
We have served as the Company's auditor since 2002.

Oklahoma City, Oklahoma
February 21, 2018, except for the impact of the matters
discussed in Note 2 pertaining to the adoption of ASU
2017-07, as to which the date is May 17, 2018.

80
Exhibit 99.01

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Stockholders and the Board of Directors of OGE Energy Corp.

Opinion on Internal Control over Financial Reporting

We have audited OGE Energy Corp.'s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, OGE Energy Corp. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2017 consolidated financial statements of the Company and our report dated February 21, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ Ernst & Young LLP
 
 
 

 
Oklahoma City, Oklahoma
February 21, 2018

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