SECURITIES AND EXCHANGE COMMISSION
(Mark One)
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission File Number: 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
| | | | | | | | |
OklahomaCommission File Number
| Exact name of registrants as specified in their charters, address of principal executive offices and registrants' telephone number | 73-1481638I.R.S. Employer Identification No.
|
(State or other jurisdiction of1-12579
| OGE ENERGY CORP. | (I.R.S. Employer73-1481638
|
incorporation or organization)1-1097
| OKLAHOMA GAS AND ELECTRIC COMPANY | Identification No.)73-0382390
|
Oklahoma City, Oklahoma73101-0321
(Address405-553-3000
State or other jurisdiction of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code: incorporation or organization:405-553-3000
OklahomaSecurities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
Registrant | Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
OGE Energy Corp. | Common Stock | OGE | New York Stock Exchange |
Oklahoma Gas and Electric Company | None | N/A | N/A |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
þOGE Energy Corp. ☑ Yes Yes☐ No Oklahoma Gas and Electric Company ☑ oYes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
oOGE Energy Corp. ☐ Yes ☑ No Oklahoma Gas and Electric Company ☐ Yes ☑ þNo
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.þ
OGE Energy Corp. ☑ Yes Yes☐ No Oklahoma Gas and Electric Company ☑ oYes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).þ
OGE Energy Corp. ☑ Yes Yes☐ No Oklahoma Gas and Electric Company ☑ oYes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
| | | | | | | | | | | |
OGE Energy Corp. | Large accelerated filerAccelerated Filer | ☑ | Accelerated filer Filer | |
|
Non-accelerated filer Filer |
| Smaller reporting company | ☐ |
| | Emerging growth company | ☐ |
Oklahoma Gas and Electric Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | ☑ | Smaller reporting company | ☐ | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
OGE Energy Corp. ☑ Oklahoma Gas and Electric Company ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
OGE Energy Corp. ☐ Yes ☑ No Oklahoma Gas and Electric Company þ☐ Yes ☑ No
At June 28, 2019,30, 2022, the last business day of the registrant'sOGE Energy Corp.'s most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $8,519,482,559$7,719,815,032 based on the number of shares held by non-affiliates (200,175,812)(200,202,672) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $42.56.
$38.56.At June 30, 2022, there was no voting or non-voting common equity of Oklahoma Gas and Electric Company held by non-affiliates.
At January 31, 2020,2023, there were 200,177,358200,229,215 shares of OGE Energy Corp.'s common stock, par value $0.01 per share, outstanding.
At January 31, 2023, there were 40,378,745 shares of Oklahoma Gas and Electric Company's common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.
DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement for the Company's 2020OGE Energy Corp.'s 2023 annual meeting of shareowners is incorporated by reference into Part III of this Form 10-K.
This combined Form 10-K represents separate filings by OGE
ENERGY CORP.Energy Corp. and Oklahoma Gas and Electric Company. Information contained herein related to an individual registrant is filed by such registrant on its own behalf. Oklahoma Gas and Electric Company makes no representations as to the information relating to OGE Energy Corp.'s other operations.Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
FOR THE YEAR ENDED DECEMBER 31, 2019
The following is a glossary of frequently used abbreviations that are found throughout this Form 10-K.
| | | | | |
Abbreviation |
| Definition |
2017 Tax Act
| Tax Cuts and Jobs Act of 2017 |
20182021 Form 10-K |
| Annual Report on Form 10-K for the year ended December 31, 20182021 |
401(k) Plan |
| Qualified defined contribution retirement plan |
AES | AES-Shady Point, Inc. |
APSC |
| Arkansas Public Service Commission |
ArcLight group | Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively |
ASC | FASB
| Financial Accounting Standards Board Accounting Standards Codification |
ASU | FASB
| Financial Accounting Standards Board Accounting Standards Update |
| |
| |
| |
| |
| |
| |
CenterPoint |
| CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc. |
|
| Carbon dioxide |
Code |
| Internal Revenue Code of 1986 |
CompanyCOVID-19
| OGE Energy Corp., collectively with its subsidiaries
| Novel Coronavirus disease |
| |
Dry Scrubber |
| Dry flue gas desulfurization unit with spray dryer absorber |
| |
| |
EGT | Enable Gas Transmission, LLC, a wholly-owned subsidiary of Enable that operates a 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex Basins in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas |
Enable |
| Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint (prior to December 2, 2021) |
Enogex HoldingsEnergy Transfer
| Enogex Holdings LLC, the parent company of Enogex LLC and
| Energy Transfer LP, a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013) |
Enogex LLC | Enogex LLC,Delaware limited partnership, collectively with its subsidiaries (effective June 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC) |
EOIT | Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly-owned subsidiary of Enable that operates a 2,300-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma |
EPA |
| U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
Federal Clean Air Act | Federal Clean Air Act of 1970, as amended |
Federal Clean Water Act |
| Federal Water Pollution Control Act of 1972, as amended |
FERC |
| Federal Energy Regulatory Commission |
FIP |
| Federal Implementation Plan |
GAAP |
| Accounting principles generally accepted in the U.S. |
IRP |
| Integrated Resource Plan |
kVISO
| Kilovolt
| Independent system operator |
LDCkV
| Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area
| Kilovolt |
MATSLIBOR
| Mercury and Air Toxics Standards
| London Interbank Offered Rate |
MBbl/dMW
| Thousand barrels per day
| Megawatt |
MMBtuMWh
| Million British thermal unit
| Megawatt-hour |
| |
MRT | Enable Mississippi River Transmission, LLC, a wholly-owned subsidiary of Enable that operates a 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois |
| |
MW | Megawatt |
MWh | Megawatt-hour |
NAAQS |
| National Ambient Air Quality StandardsStandard |
NERC |
| North American Electric Reliability Corporation |
NGLs |
| Natural gas liquids, which are the hydrocarbon liquids contained within the natural gas stream |
|
| Notice of proposed rulemaking |
NOX |
| Nitrogen oxide |
OCC |
| Oklahoma Corporation Commission |
ODEQ |
| Oklahoma Department of Environmental Quality |
| |
OG&E |
| Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy |
OGE Energy | Holding
| OGE Energy Corp., collectively with its subsidiaries, holding company and parent company of OG&E |
OGE Holdings |
| OGE Enogex Holdings LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings LLC (prior to May 1, 2013) and 25.5 percent owner of Enable (prior to December 2, 2021) |
ODFA |
| Oklahoma Development Finance Authority |
OSHA | Federal
| U.S. Department of Labor's Occupational Safety and Health Act of 1970Administration |
Pension Plan |
| Qualified defined benefit retirement plan |
| |
| |
QF | Qualified cogeneration facility |
QF contract | Contract with QFs and small power production producers |
| | | | | |
Regional Haze Rule |
| The EPA's Regional Haze Rule |
Registrants |
| OGE Energy and OG&E |
Restoration of Retirement Income Plan |
| Supplemental retirement plan to the Pension Plan |
SESHRTO
| Southeast Supply Header, LLC, in which Enable owns a 50 percent interest as of December 31, 2019, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast
| Regional transmission organization |
SIP |
| State Implementation Plan |
|
| Sulfur dioxide |
SOFR |
| Secured Overnight Funding Rate |
SPP |
| Southwest Power Pool |
Stock Incentive Plan | 2013 Stock Incentive Plan |
System sales |
| Sales to OG&E's customers |
TBtu/d | Trillion British thermal units per day |
U.S. |
| United States of America |
USFWS |
| United States Fish and Wildlife Service |
Winter Storm Uri |
| Unprecedented, prolonged extreme cold weather event in February 2021 |
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FILING FORMAT
This combined Form 10-K is separately filed by OGE Energy and OG&E. Information in this combined Form 10-K relating to each individual Registrant is filed by such Registrant on its own behalf. OG&E makes no representation regarding information relating to any other companies affiliated with OGE Energy. Neither OGE Energy, nor any of OGE Energy's subsidiaries, other than OG&E, has any obligation in respect of OG&E's debt securities, and holders of such debt securities should not consider the financial resources or results of operations of OGE Energy nor any of OGE Energy's subsidiaries, other than OG&E (in relevant circumstances), in making a decision with respect to OG&E's debt securities. Similarly, none of OG&E nor any other subsidiary of OGE Energy has any obligation with respect to debt securities of OGE Energy. This combined Form 10-K should be read in its entirety. No one section of this combined Form 10-K deals with all aspects of the subject matter of this combined Form 10-K.
FORWARD-LOOKING STATEMENTS
Except for the historical statements contained herein, the matters discussed within this Form 10-K, including those matters discussed within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "forecast," "intend," "objective," "plan," "possible," "potential," "project""project," "target" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed within "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
•general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies, inflation rates and their impact on capital expenditures;
•the ability of the CompanyOGE Energy and its subsidiariesOG&E to access the capital markets and obtain financing on favorable terms, as well as inflation rates and monetary fluctuations;
•the ability to obtain timely and sufficient rate relief to allow for recovery, including through securitization, of items such as capital expenditures, fuel and purchased power costs, operating costs, transmission costs and deferred expenditures;
•prices and availability of electricity, coal and natural gas and NGLs;gas;
•the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;
•the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;
•business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;
•competitive factors, including the extent and timing of the entry of additional competition in the markets served by the Company;Registrants, potentially through deregulation;
•the impact on demand for OG&E's services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;
•technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
•factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
•availability and prices of raw materials and equipment for current and future construction projects;
•the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
•federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company'sRegistrants' markets;
•environmental laws, safety laws or other regulations that may impact the cost of operations, or restrict or change the way the Company operates its facilities;Registrants' facilities are operated or result in stranded assets;
•changes in accounting standards, rules or guidelines;
•the discontinuance of accounting principles for certain types of rate-regulated activities;
•the cost of protecting assets against, or damage due to, terrorism or cyberattacks, including losing control of our assets and potential ransoms, and other catastrophic events;
•creditworthiness of suppliers, customers and other contractual parties;parties, including large, new customers from emerging industries such as cryptocurrency;
•social attitudes regarding the utility, natural gas and power industries;
•identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;
•increased pension and healthcare costs;
•the impact of extraordinary external events, such as the pandemic health event resulting from COVID-19, and their collateral consequences;
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•national and global events that could adversely affect and/or exacerbate macroeconomic conditions, including inflationary pressures, rising interest rates, supply chain disruptions, economic recessions and uncertainty surrounding continued hostilities or sustained military campaigns;
•costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-K; and
•difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control; and
•other risk factors listed in the reports filed by the CompanyRegistrants with the Securities and Exchange Commission, including those listed within "Item 1A. Risk Factors" herein.
The Company undertakesRegistrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
The Company
The Company, incorporated in August 1995 in the State of Oklahoma,
OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity in Oklahoma and western Arkansas. Prior to September 30, 2022, OGE Energy also held investments in Enable and Energy Transfer, which offers natural gas, primarily in the south central U.S. The Company conductscrude oil and NGL services. OGE Energy reports these activities through two business segments: (i) electric utilitycompany operations and (ii) natural gas midstream operations.
TheFor periods prior to the December 2, 2021 closing of the Enable and Energy Transfer merger, OGE Energy accounted for its investment in Enable as an equity method investment and reported it within OGE Energy's natural gas midstream operations segment. For the period of December 2, 2021 through September 30, 2022, OGE Energy accounted for its investment in the Energy Transfer units it acquired in the merger as an investment in equity securities. As of the end of September 2022, OGE Energy had sold all of its Energy Transfer limited partner units, becoming primarily an electric
utility segmentcompany.
Electric Company Operations. OGE Energy's electric company operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and&E's rates 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.OGE Energy. OG&E is the largest electric utilitycompany 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. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment represents the Company'sincluded OGE Energy's investment in Energy Transfer's equity securities acquired in the Enable/Energy Transfer merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. Prior to OGE Energy's sale of all Energy Transfer limited partner units, the investment in Energy Transfer's equity securities was held through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is primarily engagedOGE Energy no longer has any ownership interest 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama. Atmidstream operations.
December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units.
The Company'sRegistrants' principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma, 73101-0321 (telephone 405-553-3000). At December 31, 2019, the Company had 2,425 employees, of which 80 are seconded to Enable. The Company'sOGE Energy's website address is www.ogeenergy.com.www.oge.com. Through the Company'sOGE Energy's website, under the heading "Investors," "SEC Filings," the CompanyOGE Energy makes available, free of charge, itsthe Registrants' annual reportreports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. The Company'sOGE Energy's website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K. Reports filed with the Securities and Exchange Commission are also made available on its website at www.sec.gov.
The Company's mission, through OG&E and the Company's equity interest in Enable,
OGE Energy's purpose is to fulfill its critical role in the nation's electric utilityenergize life, providing life-sustaining 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 energylife-enhancing products and services, while honoring its commitment to strengthen communities. Its business model is centered around growth and sustainability for employees (internally referred to as "members"), communities and customers as well as seeking growth opportunities in both businesses.
and the owners of OGE Energy, its shareholders.
OG&EOGE Energy is focused on:
delivering top-quartile safety results, while enabling members to deliver improved value to their communities, customers and shareholders;
•providing exceptionaltransforming the customer experiencesexperience by continuing to improvecentering decisions on customer interfaces, tools, productsimpact that will drive customer operations, communications program and services that deliver high customer satisfactionproduct development and operating productivity;the digital experience including increased personalization and self-service;
•providing safe, reliable energy to the communities and customers it serves, 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 customers, investors and members;
•continuingleading economic development and job growth by attracting new and diverse businesses to grow a zero-injury cultureimprove the infrastructure of the communities in Oklahoma and deliver top-quartile safety results;Arkansas;
•ensuring it has the necessary mix of generation resources to meet the long-term capacity needs of its customers; andour customers, with a progressively cleaner generation portfolio;
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•maintaining customer rates that are some of the most affordable in the country by continuing focus on operational excellenceinnovation, intellectual curiosity and efficiencies in orderexecution with excellence;
•delivering on earnings commitments to protectshareholders to enhance access to lower-cost debt and equity capital that is needed to deploy infrastructure for the customer bill.
Additionally, the Company wants to achieve a premium valuationlong-term economic health 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 four to six percent on a weather-normalized basis, maintaining a strong credit rating as well as projecting dividend increases to be consistent with utility earnings growth. 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 communities;
•having strong regulatory and legislative relationships.relationships, built on integrity, for the long-term benefit of our customers, communities, shareholders and members; and
developing and growing our members to be able to provide a greater contribution to the company's success, while also improving their own lives.
OGE Energy is focused on creating long-term shareholder value by targeting the consistent growth of earnings per share of five to seven percent at the electric company, supported by strong load growth enabled by low customer rates and a strategy of investing in lower risk infrastructure projects that improve the economic vitality of the communities it serves in Oklahoma and Arkansas. In the next five years, OGE Energy expects to continue to grow the dividend, targeting a dividend payout ratio of 65 to 70 percent. Over the next several years, OGE Energy expects earnings per share growth to exceed the dividend growth rate to help achieve this target. OGE Energy's financial objectives also include maintaining investment grade credit ratings and providing a strong and reliable dividend for shareholders.
OGE Energy's long-term sustainability is predicated on providing exceptional customer experiences, investing in grid improvements and increasingly cleaner generation resources, environmental stewardship, strong governance practices and caring for and supporting its members and communities.
Electric Operations - OG&E
TheOG&E provides retail electric utility segment generates, transmits, distributes and sells electric energyservice to approximately 889,000 customers in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the secondthird largest city in that state. Of the 267state, and other large communities that OG&E serves, 241 are located inwith their contiguous rural and suburban areas throughout Oklahoma and 26 are inwestern Arkansas. OG&E derived 92 percent of its total electric operating revenues in 20192022 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.
In 2022, OG&E's system control area peak demand in 2019 was 6,8177,301 MWs on August 12, 2019.July 19, 2022, and OG&E's load responsibility peak demand was 6,0656,498 MWs on August 12, 2019.July 19, 2022. The following table showspresents system sales and variations in system sales for 2019, 20182022, 2021 and 2017.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31 | 2019 | 2019 vs. 2018 | 2018 | 2018 vs. 2017 | 2017 |
System sales (Millions of MWh) | 28.4 | | 1.1% | | 28.1 | | 6.8% | | 26.3 | |
2020. | | | | | | | | | | | | | | | | |
Year Ended December 31 | | 2022 | | | 2022 vs. 2021 | | 2021 | | | 2021 vs. 2020 | | 2020 | |
System sales (Millions of MWh) | | | 30.0 | | | 8.3% | | | 27.7 | | | 2.6% | | | 27.0 | |
OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. It is possible that changes in regulatory policies or advances in technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production. OurOG&E's ability to maintain relatively low cost, efficient and reliable operations is a significant determinant of ourits competitiveness.
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| | | | | | | | | | | |
| OKLAHOMA GAS AND ELECTRIC COMPANY | | | |
| CERTAIN OPERATING STATISTICS | | | |
| | | |
| Year Ended December 31 | 2019 | 2018 | 2017 |
ELECTRIC ENERGY (Millions of MWh) | | | |
| Generation (exclusive of station use) | 17.0 | | 18.2 | | 18.5 | |
| Purchased | 14.0 | | 12.6 | | 11.0 | |
| Total generated and purchased | 31.0 | | 30.8 | | 29.5 | |
| OG&E use, free service and losses | (1.4) | | (1.3) | | (1.4) | |
| Electric energy sold | 29.6 | | 29.5 | | 28.1 | |
ELECTRIC ENERGY SOLD (Millions of MWh) | | | |
| Residential | 9.7 | | 9.7 | | 8.8 | |
| Commercial | 6.5 | | 6.6 | | 6.7 | |
| Industrial | 4.5 | | 4.5 | | 4.0 | |
| Oilfield | 4.6 | | 4.2 | | 3.7 | |
| Public authorities and street light | 3.1 | | 3.1 | | 3.1 | |
| | | |
| System sales | 28.4 | | 28.1 | | 26.3 | |
| Integrated market | 1.2 | | 1.4 | | 1.8 | |
| Total sales | 29.6 | | 29.5 | | 28.1 | |
ELECTRIC OPERATING REVENUES (In millions) | | | |
| Residential | $ | 891.1 | | $ | 901.0 | | $ | 884.1 | |
| Commercial | 503.1 | | 519.9 | | 532.8 | |
| Industrial | 223.0 | | 234.5 | | 229.7 | |
| Oilfield | 204.0 | | 193.5 | | 185.9 | |
| Public authorities and street light | 195.7 | | 204.0 | | 208.0 | |
| Sales for resale | 0.1 | | 0.2 | | 0.2 | |
| System sales revenues | 2,017.0 | | 2,053.1 | | 2,040.7 | |
| Provision for rate refund | (0.9) | | (6.0) | | 26.8 | |
| Integrated market | 38.4 | | 48.7 | | 23.5 | |
| Transmission | 148.0 | | 147.4 | | 151.2 | |
| Other | 29.1 | | 27.1 | | 18.9 | |
| Total operating revenues | $ | 2,231.6 | | $ | 2,270.3 | | $ | 2,261.1 | |
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) | | | |
| Residential | 731,797 | | 725,440 | | 719,441 | |
| Commercial | 98,565 | | 96,660 | | 95,073 | |
| Industrial | 2,965 | | 3,072 | | 3,096 | |
| Oilfield | 7,071 | | 7,110 | | 7,139 | |
| Public authorities and street light | 17,356 | | 17,090 | | 17,081 | |
| | | |
| Total customers | 857,754 | | 849,372 | | 841,830 | |
| AVERAGE RESIDENTIAL CUSTOMER SALES | | | |
| Average annual revenue | $ | 1,223.05 | | $ | 1,247.22 | | $ | 1,234.92 | |
Average annual use (kilowatt-hour) | 13,344 | | 13,466 | | 12,324 | |
Average price per kilowatt-hour (cents) | 9.17 | | 9.26 | | 10.02 | |
| | | | | | | | | | | | |
Year Ended December 31 | | 2022 | | | 2021 | | | 2020 | |
ELECTRIC ENERGY (Millions of MWh) | | | | | | | | | |
Generation (exclusive of station use) | | | 13.6 | | | | 16.3 | | | | 17.5 | |
Purchased | | | 19.0 | | | | 14.6 | | | | 12.9 | |
Total generated and purchased | | | 32.6 | | | | 30.9 | | | | 30.4 | |
OG&E use, free service and losses | | | (1.5 | ) | | | (1.6 | ) | | | (1.4 | ) |
Electric energy sold | | | 31.1 | | | | 29.3 | | | | 29.0 | |
ELECTRIC ENERGY SOLD (Millions of MWh) | | | | | | | | | |
Residential | | | 10.4 | | | | 9.6 | | | | 9.5 | |
Commercial | | | 7.9 | | | | 6.8 | | | | 6.3 | |
Industrial | | | 4.2 | | | | 4.2 | | | | 4.2 | |
Oilfield | | | 4.4 | | | | 4.2 | | | | 4.2 | |
Public authorities and street light | | | 3.1 | | | | 2.9 | | | | 2.8 | |
System sales | | | 30.0 | | | | 27.7 | | | | 27.0 | |
Integrated market | | | 1.1 | | | | 1.6 | | | | 2.0 | |
Total sales | | | 31.1 | | | | 29.3 | | | | 29.0 | |
ELECTRIC OPERATING REVENUES (In millions) | | | | | | | | | |
Residential | | $ | 1,307.0 | | | $ | 1,342.1 | | | $ | 869.0 | |
Commercial | | | 825.6 | | | | 766.9 | | | | 479.4 | |
Industrial | | | 322.4 | | | | 328.2 | | | | 197.3 | |
Oilfield | | | 306.7 | | | | 316.8 | | | | 172.3 | |
Public authorities and street light | | | 298.9 | | | | 289.5 | | | | 176.9 | |
System sales revenues | | | 3,060.6 | | | | 3,043.5 | | | | 1,894.9 | |
Provision for rate refund | | | (1.2 | ) | | | — | | | | 3.8 | |
Integrated market | | | 163.8 | | | | 468.9 | | | | 49.6 | |
Transmission | | | 131.7 | | | | 140.2 | | | | 143.3 | |
Other | | | 20.8 | | | | 1.1 | | | | 30.7 | |
Total operating revenues | | $ | 3,375.7 | | | $ | 3,653.7 | | | $ | 2,122.3 | |
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) | | | | | | | | | |
Residential | | | 756,751 | | | | 749,091 | | | | 740,174 | |
Commercial | | | 105,018 | | | | 103,337 | | | | 100,200 | |
Industrial | | | 2,464 | | | | 2,585 | | | | 2,710 | |
Oilfield | | | 6,791 | | | | 6,804 | | | | 6,822 | |
Public authorities and street light | | | 17,735 | | | | 17,630 | | | | 17,483 | |
Total customers | | | 888,759 | | | | 879,447 | | | | 867,389 | |
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 2019, 862022, 88 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and sixfour percent to the FERC.
The OCC and the APSC require that, among other things, (i) the CompanyOGE Energy permits the OCC and the APSC access to the books and records of the CompanyOGE Energy and its affiliates relating to transactions with OG&E; (ii) the CompanyOGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) the CompanyOGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of the CompanyOGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
For information concerning OG&E's recently completed and currently pending regulatory proceedings, see Note 1614 within "Item 8. Financial Statements and Supplementary Data."
5
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. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects. See Note 1 within "Item 8. Financial Statements and Supplementary Data" for further discussion of OG&E's regulatory assets and liabilities.
OG&E's standard tariff rates include a cost of service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power.
OG&E offers several alternative customer programs and rate options, as described below.
•Under OG&E's Smart Grid-enabled SmartHours programs, "time-of-use"time-of-use and "variablevariable peak pricing"pricing rates offer customers the ability to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest.
•The guaranteed flat billGuaranteed Flat Bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year.
•The Renewable Energy Credit purchase program, athe Green Power Wind Rider and the Utility Solar Program are rate optionoptions that provides a "renewable energy" resource, ismake renewable energy resources available as a voluntary option to all of OG&E's&E Oklahoma retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of OG&E's conservation-minded customers.
•Load Reduction is a voluntary load curtailment program that provides those OG&E's&E commercial and industrial customers who enroll with the opportunity to curtail usage on a voluntary basis when OG&E'spower delivery system conditions merit curtailment action. Large customers greater than 50 MWs who enroll in the program are also required to participate in Direct Load Control, giving OG&E direct control over the curtailable portion of the customer's load. Customers that curtail their usage will receive paymentcredit for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days but may not be able to curtail every time that a curtailment event is required.
•OG&E offers certain qualifying customers "day-ahead price"day-ahead price and "flex price"flex price rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price"day-ahead price and "flex price"flex price rate options are based on OG&E's projected next day hourly operating costs.
OG&E has Public Schools-Demand and Public Schools Non-Demand rate classes that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to ourits military partners.
The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.
OG&E's standard tariff rates include a cost of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. OG&E's current rate order from the APSC includes a formula rate rider that provides for an annual 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 test period. The initial term for the formula rate rider iswas not to exceed five years from the date of the APSC final order in the last general rate review, May 18, 2017, unless additional approval iswas obtained from the APSC.
As further described in Note 14 within “Item 8. Financial Statements and Footnotes,” in September 2022, the APSC denied OG&E's extension request for the formula rate rider, as the APSC and OG&E did not agree on the APSC's approved debt-to-equity ratio for OG&E. Despite the denial of the extension request, the APSC ruled on January 20, 2023 that OG&E is able to undertake two more true-up updates to its formula rate rider with adjustments to rates occurring in April 2023 and April 2024. Subsequent to the April 2024 update, the formula rate rider will continue until new rates are set in a future general rate review.
OG&E offers several alternative customer programs and rate options, as described below.
•The "time-of-use"time-of-use and "variablevariable peak pricing"pricing tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest.
•The Renewable Energy Credit purchase program a tariffand the Universal Solar Program are rate optionoptions that provides a "renewable energy" resource, ismake renewable energy resources available as a voluntary option to all of OG&E's&E Arkansas retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of ourOG&E's conservation-minded customers.
•Load Reduction is a voluntary load curtailment program that provides OG&E's commercial and industrial customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action.
•OG&E offers certain qualifying customers a "day-ahead price"day-ahead price and flex price rate optionoptions which allowsallow participating customers to adjust their electricity consumption based on a price signal received from OG&E. The "day-ahead price" isday-ahead price and flex price rate options are based on OG&E's projected next day hourly operating costs.
Fuel Supply and Generation
The following table presents the OG&E-generated energy produced and the weighted average cost of fuel used,purchased, by type, for the last three years is presented below.
| | | | | | | | | | | | | | | | | | | | |
| Fuel Mix (A) | | | Fuel Cost (In cents/Kilowatt-Hour) | | |
| Fuel | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 |
| Natural gas | 64% | | 48% | | 39% | | 2.188 | | 2.517 | | 2.821 | |
| Coal | 28% | | 45% | | 54% | | 2.029 | | 2.025 | | 2.069 | |
| Renewable | 8% | | 7% | | 7% | | — | | — | | — | |
| Total fuel | 100% | | 100% | | 100% | | 1.973 | | 2.122 | | 2.211 | |
| | | | | | | | | | | | |
| | Generation Mix (A) | |
| | 2022 | | | 2021 | | | 2020 | |
Natural gas | | | 60 | % | | | 48 | % | | | 62 | % |
Coal | | | 30 | % | | | 40 | % | | | 25 | % |
Renewable | | | 10 | % | | | 12 | % | | | 13 | % |
Total | | | 100 | % | | | 100 | % | | | 100 | % |
(A)FuelGeneration mix calculated as a percent of net MWhs generated.
The decreases in the weighted average cost of fuel in 2019 compared to 2018generated and in 2018 compared to 2017 were primarily due to lower natural gas prices. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC and the APSC.
6includes purchased power agreements.
OG&E participates in the SPP Integrated Marketplace. As part of the Integrated Marketplace, the SPP has balancing authority responsibilities for its market participants. The SPP Integrated Marketplace functions as a centralized dispatch, where market participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers. The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations and to determine which generating units will run at any given time for maximum cost-effectiveness within the SPP area. 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 recoveredgenerally recoverable through fuel adjustment clauses.
7
The following table presents the weighted-average cost of fuel used, by type, for the last three years.
| | | | | | | | | | | | |
| | Fuel Cost (A)
(In cents/Kilowatt-Hour) | |
| | 2022 | | | 2021 | | | 2020 | |
Natural gas | | | 7.032 | | | | 11.907 | | | | 2.077 | |
Coal | | | 3.253 | | | | 1.935 | | | | 1.821 | |
Renewable | | | — | | | | — | | | | — | |
Total | | | 5.480 | | | | 6.833 | | | | 1.863 | |
Total fuel and purchased power weighted-average cost was 5.096, 6.892 and 2.117 cents per kilowatt-hour in 2022, 2021 and 2020, respectively.
The changes in the weighted average cost of fuel in 2022 compared to 2021 and in 2021 compared to 2020 were primarily due to inflated fuel costs in 2021 during Winter Storm Uri. Fuel costs are generally recoverable through OG&E's fuel adjustment clauses that are approved by the OCC and the APSC, with the exception of Winter Storm Uri fuel costs in 2021 which were recovered in Oklahoma in 2022 through securitization and which are being recovered in Arkansas over 10 years through a regulatory asset mechanism. See Notes 1 and 14 within "Item 8. Financial Statements and Supplementary Data" for further discussion.
Of OG&E's 7,0817,240 total MWs of generation capability reflected in the table within "Item 2. Properties," 4,7664,904 MWs, or 67.367.7 percent, are from natural gas generation, 1,8541,534 MWs, or 26.221.2 percent, are from coal generation, 321 MWs, or 4.4 percent, are from dual-fuel generation (coal/gas), 449 MWs, or 6.36.2 percent, are from wind generation and 1232 MWs, or 0.20.5 percent, are from solar generation.
Coal
OG&E's coal-fired units are designed to burn low sulfur western sub-bituminous coal. In May 2019, OG&E added the River Valley units to its coal-fired fleet, which burns a blend of bituminous coal from the Arkoma Basin in Oklahoma and low-sulfur western sub-bituminous coal. The combination of all 2019 coal purchased had a weighted average sulfur content of 0.24 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.1 lbs. of SO2 per MMBtu.
For the first two quarters of 2020, OG&E has coal supply agreements for 100 percent of its coal requirements for the Sooner and Muskogee facilities. OG&E has secured 100 percent of its Arkoma Basin coal needs through May of 2021. OG&E plans to fill the remainder of its 2020 coal needs through additional term agreements, spot purchases and the use of existing inventory. OG&E has no coal supply agreements beyond May 2021. In 2019, OG&E purchased 2.8 million tons of coal from its Wyoming supplier and 0.1 million tons from its Oklahoma supplier. See "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and 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.
In 2022, OG&E expanded its physical storage capacity by entering into two storage service contracts. These two contracts provide OG&E security in both volume and price to further help protect customers against volatile natural gas prices.
Coal
OG&E's coal-fired units are designed to burn primarily low sulfur western sub-bituminous coal. The combination of all 2022 coal purchased had a weighted average sulfur content of 0.25 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.2 lbs. of SO2 per MMBtu.
For 2023 through 2025, OG&E has coal supply agreements for 100 percent of its expected coal requirements for both the Sooner and River Valley facilities. For the Muskogee facility, OG&E has a majority of its expected 2023 coal requirements met through a coal supply agreement and will fill any additional coal needs through term agreements, spot purchases and the use of existing inventory. In 2022, OG&E purchased 3.1 million tons of coal from its sub-bituminous suppliers and 0.011 million tons from its bituminous suppliers. See "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
8
Wind
OG&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms. OG&E's current wind power portfolio also includes purchased power contracts as listedpresented in the table below.
| | | | | | | | | | | | | | |
| Company | Location | Original 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 | |
| | | | |
following table. | | | | | | |
Company | Location | Original 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 | |
In 2015,
OG&E placed twocurrently owns and operates the solar sites locatedpresented in Oklahoma City, Oklahoma at the Mustang generating facility, into service. The Mustang solar sites have a combined maximum capacity of 2.5 MWs and consist of almost 10,000 photovoltaic panels.
following table. | | | | | | | | | | | | |
Name | | Location | | Year Completed | | Photovoltaic Panels | | | MWs | |
Mustang | | Oklahoma City, OK | | 2015 | | | 9,867 | | | | 2.5 | |
Covington | | Covington, OK | | 2018 | | | 38,000 | | | | 9.7 | |
Choctaw Nation | | Durant, OK | | 2020 | | | 15,344 | | | | 5.0 | |
Chickasaw Nation | | Davis, OK | | 2020 | | | 15,344 | | | | 5.0 | |
Branch | | Branch, AR | | 2021 | | | 15,444 | | | | 5.0 | |
Durant 2 | | Durant, OK | | 2022 | | | 15,471 | | | | 5.0 | |
In 2018, OG&E placed oneissued a request for proposals for solar site, located near Covington, Oklahoma, into service. The Covington solar site has a maximum capacity of 9.7 MWs and consists of almost 38,000 photovoltaic panels.
Currently, OG&E is building two solar sites, one near Durant, Oklahoma and one near Davis, Oklahoma, that will have a combined maximum capacity of 10.0 MWs and consist of over 30,000 photovoltaic panels.in 2022 based on generation needs established in its October 2021 IRP. OG&E will continue to evaluate the need to add additional solar sites to its generation portfolio based on customer demand, cost and reliability.
Safety and Health Regulation
OG&E is subject to a number of federal and state laws and regulations, including OSHA, the EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.
In addition, the OSHA Hazard Communication Standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
Natural Gas Midstream Operations - Enable
Overview
Enable is a publicly traded Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. Enable serves current and emerging production areas in the U.S., including several unconventional shale resource plays and local and regional end-user markets in the U.S. Enable's assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Enable's gathering and processing segment primarily provides natural gas gathering and processing to its producer customers and crude oil, condensate and produced water gathering services to its producer and refiner customers. Enable's transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to its producer, power plant, LDC and industrial end-user customers.
Gathering and Processing
Enable owns and operates substantial natural gas gathering and processing and crude oil, condensate and produced water gathering assets in five states. Enable's gathering and processing operations consist primarily of natural gas gathering and processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins, crude oil and condensate gathering assets serving the Anadarko Basin and crude oil and produced water gathering assets serving the Williston Basin. Enable provides a variety of services to the active producers in its operating areas, including gathering, compressing, treating and processing natural gas, fractionating NGLs and gathering crude oil, condensate and produced water. Enable serves shale and other unconventional plays in the basins in which it operates.
Enable generates revenues from producers in the basins in which it operates. For the year ended December 31, 2019, Enable's top ten natural gas producer customers accounted for approximately 68 percent of its natural gas gathered volumes. Enable's Anadarko Basin crude oil gathering systems gathers crude oil and condensate from producers, which are primarily delivered to one customer. The rates and terms of service on Enable's Anadarko Basin crude oil and condensate gathering system are regulated by the OCC. Enable's Williston Basin crude oil and produced water gathering systems serve one customer. The rates and terms of service on Enable's Williston Basin crude oil gathering systems, but not its produced water gathering systems, are regulated by the FERC. Enable's contracts typically provide for crude oil, condensate and produced water gathering services that are fee-based and for natural gas gathering and processing arrangements that are fee-based, or percent-of-liquids, percent-of-proceeds or keep-whole based.
Competition for Enable's gathering and processing systems is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Enable's gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable's primary competitors are other midstream companies who are active in the regions where Enable operates.
While the results of Enable's gathering and processing segment are not materially affected by seasonality, from time to time, its operations and construction of assets can be impacted by inclement weather.
Transportation and Storage
Enable owns and operates interstate and intrastate natural gas transportation and storage systems across nine states. Enable's transportation and storage systems consist primarily of its interstate systems, EGT and MRT, its intrastate system,
EOIT, and its investment in SESH. Enable's transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, LDCs and industrial end users as well as interconnected pipelines for delivery to additional markets. Enable's transportation and storage assets also provide facilities where natural gas can be stored by customers.
Enable's interstate and intrastate natural gas transportation and storage systems generate revenue primarily by serving large natural gas and electric utilities, as well as natural gas producers, industrial end-users and natural gas marketers. For the year ended December 31, 2019, approximately 26 percent of EGT's service revenue was attributable to contracts with one customer, CenterPoint. All of EGT's firm transportation and storage contracts for CenterPoint's LDCs are scheduled to expire in March 2021. CenterPoint's LDCs have received the required regulatory approvals to extend transportation and storage services with EGT. The term for the transportation and storage services provided to CenterPoint's LDCs in Arkansas, Louisiana, Oklahoma and northeast Texas is expected to be extended beyond March 2021, pursuant to the terms of the approved contracts.
For the year ended December 31, 2019, approximately 70 percent of MRT's service revenue was attributable to contracts with one customer, Spire Inc. MRT's firm transportation contracts representing 64 percent, 24 percent and 12 percent of Spire Inc.'s firm transportation capacity are scheduled to expire in July 2024, October 2025 and March 2026, respectively. All of Spire Inc.'s firm storage contracts are scheduled to expire in May 2021, which are subject to FERC rate case approval.
Enable's EGT, MRT and SESH transportation and storage services are typically provided under firm, fee-based transportation and storage agreements, with rates and terms of service regulated by the FERC. EOIT provides fee-based firm and interruptible transportation and storage services on both an intrastate and interstate basis.
Enable's interstate and intrastate pipelines compete with a variety of other interstate and intrastate pipelines in providing transportation and storage services within its operating areas. Enable's management views the principal elements of competition among pipelines as rates, terms of services, flexibility and reliability of service.
Customer demand for natural gas on EGT and MRT is usually greater during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. Customer demand for natural gas transportation and storage services on EOIT is usually greater during the summer, primarily due to demand by natural gas-fired power plants to serve residential and commercial electricity requirements, including for OG&E. SESH is generally not impacted by seasonality.
Environmental Matters
General
The activities of the CompanyOG&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 the Company'sRegistrants' 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 or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of itsthe Registrants' operations are in substantial compliance with current federal, state and local environmental standards.
President Biden's Administration has taken a number of actions that adopt policies and affect environmental regulations, including issuance of executive orders that instruct the EPA and other executive agencies to review certain rules that affect OG&E with a view to achieving nationwide reductions in greenhouse gas emissions. OG&E is monitoring these actions which are in various stages of being implemented. At this point in time, the impacts of these actions on the Registrants' results of operations, if any, cannot be determined with any certainty. In the past, environmental regulation causedmeantime, the Company to incur significant costs because the trend was to place more and more restrictions and limitations on the Company's activities. The Trump administration has delayed, reversed or proposed to repeal some of these regulations and generally has not sought to adopt new, more stringent regulations. Nonetheless, the Company continuesRegistrants continue to have obligations to take or complete action under previously adoptedcurrent environmental rules, and the Company cannot assure that future events, such as changes in political administrations, existing laws, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause it to incur significant costs for environmental matters.
Management continues to evaluate itsthe Registrants' compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market but at the current time, based on existing rules, does not expect capital expenditures for environmental control facilities to be material for 20202023 or 2021.2024. For further discussion of environmental matters and capital expenditures related to environmental factors that may affect the Company,Registrants, see "2019"2022 Capital Requirements, Sources of Financing and Financing Activities," "Future Capital Requirements" and "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Human Capital Management
Our company fulfills a critical role in the nation's electric utility infrastructure. In order to do so, we believe we need to attract, retain, motivate and develop a high quality, diverse workforce and provide a safe, inclusive and productive work environment for everyone. Our company's core values are teamwork, transparency, respect, integrity, public service, and individual safety and well-being. Our company's core beliefs are unleash potential, live safely, achieve together, create shared trust, value diversity and inclusion, take charge and values matter. We believe that our company's values and beliefs serve as a foundation for our relationships with our employees, who we refer to internally as "members" of the Registrants. These core values and beliefs are reinforced to all employees at the time of hire, annually through a review of our Code of Ethics and periodically through small and large group meetings. We believe the efforts described herein, among others, contribute to our members' sense of purpose for the work we perform and result in the retention of our members. This belief is supported by OGE Energy being named by Forbes as the #2 Best Employer in Oklahoma for
9
2022 based on safety of work environment, competitiveness of compensation, opportunities for advancement, openness to telecommuting and how likely members would be to recommend OGE Energy as an employer. At December 31, 2022, OGE Energy had 2,237 employees, of which 1,861 are OG&E employees.
Total Rewards
To help us attract and retain the most qualified individuals for our businesses, we provide a combination of strong compensation and comprehensive benefit offerings, including healthcare, health savings and flexible spending accounts, short-term and long-term incentive plans, retirement savings plans with company matching contributions, disability coverage, paid time off, parental leave and employee assistance programs. We also have a defined benefit pension plan that covers certain employees hired on or before December 1, 2009. Our employees are also offered two days of paid volunteer leave every year, which is intended to further enrich both their lives and the lives of others in the communities we serve.
Employee Recruiting, Development and Engagement
We make it a priority to attract, retain, motivate and develop a high-quality workforce. Our recruitment efforts begin with industry and career awareness efforts directed toward learning institutions, parents and students. We have built partnerships with universities, state career tech systems, state education departments, technical learning/trade schools, military bases and local school districts to increase awareness of the employment opportunities we provide and the total rewards packages that are tied to those opportunities. We build these relationships to create talent pipelines that will funnel qualified individuals back to our organization and the workforce needs we have identified.
We provide our employees with a variety of opportunities for career growth and development. Many of the positions in our company are highly specialized, so having appropriate training and succession planning is critical to business continuity and competitiveness. We provide leadership, career development and skill-building opportunities, including internal and external training as well as tuition reimbursement, to invest in the next generation of leaders for our company. The number of annual hours of training per employee that we target, and historically average, aligns with the benchmark published annually by the American Society of Training and Development.
OGE Energy, like many utilities across the country, is planning for and managing the effects of turnover of our workforce due to a significant number of retirements occurring now and expected during the next five to ten years, which is a period that will be impacted by major transformation of our business through technology investments, regulatory changes to our electric generation portfolio and upgrades to our distribution infrastructure. Management engages in ongoing succession planning discussions, which includes the annual involvement of OGE Energy's Board of Directors as it relates to officer succession planning.
OGE Energy conducts and/or participates in employee engagement surveys to seek feedback from its employees on a variety of topics, including understanding of and alignment with the company's strategy, objectives, values and beliefs, management practices, operational performance and the employee value proposition. OGE Energy shares the survey results with employees, and senior management incorporates the results of the surveys into their action plans in order to respond to the feedback and further enhance employee engagement.
Safety
At OGE Energy, safety is more than a priority; it is a value and is paramount in the work we perform. Our safety principles are core to who we are and what we do. These principles are communicated, demonstrated and embraced at all levels of the company and supported by our core belief to "Live Safely." To us, "Live Safely" means we protect ourselves and others from injury by constant engagement, "always living safely." Our goal is to have zero safety incidents every year, and we educate all employees on our incident and injury-free workplace vision through extensive training on safety culture and task specific training to perform their work safely.
To further our vision of safety excellence, our health and safety professionals, supervisors and Safety Task Force teams conduct routine work observations to verify employees and contractors are following safety protocols and procedures and provide coaching, if necessary. To further drive improvements in our safety performance, we report and analyze all near misses and incidents to understand the causal factors and associated corrective actions necessary to reduce the likelihood of recurrence. We share what we have learned company-wide to provide real-time learning opportunities for all employees. We continue to analyze trends and engage in discussions with our employees, creating a dialogue to enhance safety performance and work toward our incident and injury-free workplace. Our focus on safety has contributed to each of the last seven years being the safest in our 120-year history.
Since the inception of our safety principle that all incidents and injuries are preventable and embracing our incident and injury free vision, we have seen a sustained decline in our injury rate. We have reduced our 5-year averages for OSHA recordable injuries by
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73 percent and our Days Away, Restricted, Transfer Rate ("DART") by 78 percent since our 2011 baseline. The DART rate is an OSHA calculation that determines how safe businesses have been in a calendar year in reference to particular types of worker compensation injuries.
OG&E is subject to a number of federal, state and local regulations, which are administered by a variety of agencies. These agencies cover areas such as health and safety, transportation and the environment. OG&E has processes and procedures for these areas, and we believe we are in material compliance with all applicable regulations.
Diversity and Inclusion
Within our overall recruitment efforts, we are focused on diversity with the over-arching goal for the company's workforce to look like the communities we serve. Several of the talent pipeline partnerships referenced above are with organizations and trade schools whose student populations are diverse or raised in underrepresented communities. The company continues working with others to recruit diverse students to their programs, which can lead to potential employment for our positions. We have also formed relationships with universities to provide scholarships to students with diverse backgrounds and have focused on hiring individuals transitioning out of the military. For our workforce as a whole, the hiring percentage of members representing gender, racial and ethnically diverse communities has been trending upward for the past three years, and we expect that trend to continue. The retirement of our more tenured employees creates opportunities to promote or attract and hire additional individuals with diverse backgrounds.
We strive to reinforce the belief that our members are one of our greatest assets by creating a culture of respect throughout the company. One of our core beliefs is to "Value Diversity and Inclusion," which to us means that we embrace the uniqueness of each individual to make us a stronger and more resourceful organization, which enables us to serve and support the diverse communities where we live and work. We do this by, among other things, encouraging employees to treat others justly and considering their views in the decisions we make.
The company currently has eight employee-led Member Resource Groups ("MRGs") supporting Asian American & Pacific Islander, Black, Hispanic, LGBTQ+, Veteran and Women members along with new members and those dedicated to public service. All groups are voluntary and inclusive. Each MRG selects an officer of the company to serve as its Executive Sponsor. These MRGs are intended to foster a sense of belonging for all employees, inspire conversation, introduce new ways of thinking about issues, drive innovation among our diverse population of members and provide an opportunity for professional development, community involvement and recruitment.
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Information About Ourthe Registrants' Executive Officers
The following table below includespresents the names, titles and business experience for the most recent five years for those persons serving as Executive Officers of the RegistrantRegistrants as of February 26, 2020:
22, 2023: | | | | | | | | | | | |
Name | Age | Current Title and Business Experience | |
Sean Trauschke | 5255
| 20152018 - Present:
| Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. |
W. Bryan Buckler | 50 | 2015:
| President of OGE Energy Corp. |
Stephen E. Merrill | 55 | 20152021 - Present: | Chief Financial Officer of OGE Energy Corp. |
|
| 2019 - 2020: | Vice President of Investor Relations - Duke Energy Corporation |
|
| 2018 - 2019: | Director of Financial Planning and Analysis - Duke Energy Corporation |
Sarah R. Stafford | 3841
| 2018 - Present: | Controller and Chief Accounting Officer of OGE Energy Corp. |
|
| 2016 - 2018:
| Accounting Research Officer of OGE Energy Corp. |
Scott A. Briggs | 51 | 20152020 - 2016:Present:
| Senior ManagerVice President - Ernst & Young, LLPHuman Resources of OG&E
|
|
| 2019 - 2020: | Managing Director Human Resources of OG&E |
|
| 2018: | Chief Operating Officer of The Oklahoma Publishing Co., d/b/a The Oklahoma Media Company |
Robert J. Burch | 60 | 2020 - Present: | Vice President - Utility Technical Services of OG&E |
|
| 2018 - 2020: | Managing Director Utility Technical Services of OG&E |
|
| 2018: | Director Power Supply Services of OG&E |
Andrea M. Dennis | 4346
| 2019 - Present: | Vice President - Transmission and Distribution Operations of OG&E |
|
| 2019: | Managing Director Transmission and Distribution Operations of OG&E |
|
| 20152018 - 2019:
| Director System Operations of OG&E |
Kenneth R. GrantKeith E. Erickson
| 5549
| 20162022 - Present:
| Vice President - Sales and MarketingCustomer Operations of OG&E |
|
| 2015:2018 - 2022:
| Vice President - MarketingDirector of Sales and ProductBusiness Development of OG&E
|
| | 2015: | Managing Director Tech Solutions & Ops of OG&E |
Patricia D. Horn | 61 | 2015 - Present: | Vice President - Governance and Corporate Secretary of OGE Energy Corp. |
Donnie O. Jones | 5356
| 2019 - Present: | Vice President - Utility Operations of OG&E |
|
| 20152018 - 2019:
| Vice President - Power Supply Operations of OG&E |
Jean C. Leger, Jr.Cristina F. McQuistion
| 6158
| 20192020 - Present:
| Senior Vice President - Utility Operations of OG&E |
| | 2015 - 2019: | Vice President - Utility OperationsCorporate Responsibility and Stewardship of OG&EOGE Energy Corp. |
Cristina F. McQuistion
| 55
| 20172018 - Present:2020:
| Vice President - Chief Information Officer of OG&E |
Kenneth A. Miller | 56 | 20162019 - 2017:Present:
| Vice President - Chief Information OfficerPublic and Utility Strategy of OG&E |
| | 2015: | Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OG&E |
Kenneth A. Miller | 53 | 2019 - Present: | Vice President - State Regulatory and Legislative Affairs of OG&E |
|
| 2015 - 2018:
| State Treasurer of Oklahoma |
E. Keith MitchellDavid A. Parker
| 5746
| 20152020 - Present:
| Chief Operating OfficerVice President - Technology, Data and Security of OG&E
|
|
| 2015:2019 - 2020:
| Executive Vice President and Chief Operating Officer of Enable Midstream Partners, LP
|
| | | |
| | | |
William H. Sultemeier | 52 | 2017 - Present: | General CounselDirector Enterprise Security & Risk of OGE Energy Corp. |
|
| 2016:2018 - 2019:
| Partner - Jones DayDirector of Internal Audit of OGE Energy Corp.
|
Matthew J. Schuermann | 44 | 2015:2020 - Present:
| ShareholderVice President - Greenberg Traurig, LLPPower Supply Operations of OG&E
|
|
| 2019 - 2020: | Managing Director Power Plant Operations of OG&E |
|
| 2018 - 2019: | Special Projects Director of OG&E |
William H. Sultemeier | 55 | 2022 - Present: | General Counsel, Corporate Secretary and Chief Compliance Officer of OGE Energy Corp. |
|
| 2018 - 2022: | General Counsel and Chief Compliance Officer of OGE Energy Corp. |
Charles B. Walworth | 4548
| 20152018 - Present:
| Treasurer of OGE Energy Corp. |
Johnny W. Whitfield, Jr. | 46 | 2022 - Present: | Vice President - Business Intelligence and Supply Chain of OG&E |
|
| 2019 - 2022: | Director of Business Intelligence of OG&E |
|
| 2018 - 2019: | Sr. Manager of Resource Coordination of OG&E |
Christine O. Woodworth | 52 | 2021 - Present: | Vice President - Marketing and Communications of OG&E |
|
| 2018 - 2021: | Vice President of Public Relations - Sonic Drive-In, a fast-food restaurant chain |
No family relationship exists between any of the Executive Officers of the Registrant.Registrants. Messrs. Trauschke, Merrill,Buckler, Sultemeier, Walworth and Mses. HornMcQuistion and Stafford are also officers of OG&E. Each Executive Officer is to hold office until the next annual election of officers by the Board of Directors which is typically accomplished at the first regular board meeting following the next Annual Meeting of Shareholders, currently scheduled for May 21, 2020.
18, 2023.
Messrs. Trauschke and Merrill are members of the Board of Directors of Enable GP, LLC, the general partner of Enable.
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to the Company.Registrants. In addition to the other information in this Form 10-K and other documents filed by us and/or our subsidiaries with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.
The Registrants are subject to a variety of risks which can be classified as regulatory, operational, financial and general. Risk factors of OG&E are also risk factors of OGE Energy.
REGULATORY RISKS
OG&E's
The Registrants' profitability depends to a large extent on the ability of OG&E to fully recover its costs, including its cost of capital, from its customers in a timely manner, and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.
OG&E is subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs, including its cost of capital, from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk.risk, such as the Oklahoma and Arkansas fuel clause under recovery amounts as disclosed in Note 1 within "Item 8. Financial Statements and Footnotes." The utility commissions in the states where OG&E operates regulate many aspects of its utilityelectric operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utilityelectric operations is dependent on OG&E's ability to fully recover costs related to providing energyelectricity and utilitypower services to its customers in a timely manner. Any failure to obtain utility commission approval to increase rates to fully recover costs, or a delay in the receipt of such approval, could have an adverse impact on OG&E's results of operations. In addition, OG&E's jurisdictions have fuel adjustment clauses that permit OG&E to recover fuel and purchased power costs through rates without a general rate case,review, subject to a later determination that such fuel costs were prudently incurred. If the state regulatory commissions determine that the fuelsuch costs were not prudently incurred, recovery could be disallowed.
In recent years, the regulatory environments in which OG&E operates have received an increased amount of attention. It is possible that there could be changes in the regulatory environment that would impair OG&E's ability to fully recover costs historically paid by OG&E's customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. OG&E cannot assure that the OCC, APSC and the FERC will grant rate increases in the future or in the amounts requested, and they could instead lower OG&E's rates.
OG&E is
The Registrants are unable to predict the impact on itstheir operating results from future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations, legislation or the imposition of additional regulations or legislation could have an adverse impact on OG&E'sthe Registrants' results of operations.
OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a federal agency, whose regulatory paradigms and goals may not be consistent.
OG&E is a vertically integrated electric utility.company. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission.
OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to FERC regulation of its transmission activities and any wholesale sales. Exposure to inconsistent state and federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate, including a change in our authorized return on equity, may harm our financial position and results of operations.
Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, consolidated financial position or liquidity.
We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution
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control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.
In response to recent regulatory and judicial decisions and international accords, emissions of greenhouse gases including, most significantly, CO2, could be restricted in the future as a result of federal or state legal requirements or litigation relating to greenhouse gas emissions. No rules are currently in effect that require us to reduce our greenhouse gas emissions, but iflaws and regulations to which we must adhere change, and the Biden Administration's agenda includes a significant shift in environmental and energy policy, focusing on reducing greenhouse gas emissions and addressing climate change issues. Together, these actions reflect climate change issues and greenhouse gas emission reductions as central areas of focus for domestic and international regulations, orders and policies. In addition, a parallel focus on reducing greenhouse gas emissions is reflected in legislation introduced in Congress. For example, the Infrastructure Investment and Jobs Act and Inflation Reduction Act were passed into law in 2022. These laws present opportunities for federal grants and tax incentives intended to hasten the future economy-wide deployment of various greenhouse gas emission reducing technologies and approaches. These initiatives could lead to new and revised energy and environmental laws and regulations, including tax reforms relating to energy and environmental issues. Any such rules were to become effective, theychanges, as well as any enforcement actions or judicial decisions regarding those laws and regulations, could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Such changes also could affect the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry operations practices. These activities are subject to stringent and complex federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way OG&E can handle or dispose of its wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. OG&E may be unable to recover these costs from insurance or other regulatory mechanisms. Moreover, the possibility existsThe Biden Administration has suggested that it will enact stricter laws, regulations orand enforcement policies that could significantly increase compliance costs and the cost of any remediation that may become necessary.
If regulations are enacted regarding any of our generating units, as listed in "Item 2. Properties," it could potentially result in stranded assets.
In addition, we may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.
For further discussion of environmental matters that may affect the Company,Registrants, see "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
In addition to the potential for physical risk related to climate change (discussed below), climate change, and the risks related to our transition to a lower-carbon economy, creates financial risk. Transition risks represent those risks related to the social and economic changes needed to shift toward a lower carbon future. These risks are often interconnected, representing policy and regulatory changes, technology and market risks, and risks to our reputation and financial performance.
Potential regulation associated with climate change legislation could pose financial risks to OGE Energy and its affiliates. The U.S. is a party to the United Nations' "Paris Agreement" on climate change, and the Agreement along with other potential legislation and regulation discussed above, could result in enforceable greenhouse gas emission reduction requirements that could lead to increased compliance costs for OGE Energy and its affiliates. For example, in September 2022, the EPA created a non-rulemaking docket for public input related to the EPA's efforts to reduce emissions of greenhouse gases from new and existing fossil fuel-fired electric generating units under the Clean Air Act Section 111.
As we expand our cleaner energy generation asset mix, the ability to integrate renewable technologies into our operations and maintain reliability and affordability is key. The intermittency of renewables remains a critical challenge particularly as cost-efficient energy storage is still in development. Other technology risks include the need for significant upfront financial investments, lengthy development timelines, and the uncertainty of integration and scalability across our entire service territory.
In addition, to the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory costs, CO2 taxes or imposed costs, OGE Energy and its affiliates may be adversely impacted. There are also increasing risks for energy companies from shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change who may elect in the future to shift some or all of their investments into entities that emit lower levels of greenhouse gases or into non-energy related sectors. Institutional investors and lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable investing and lending practices
14
and some of them may elect not to provide funding for fossil fuel energy companies. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
In addition, we may be subject to financial risks from private party litigation relating to greenhouse gas emissions. Defense costs associated with such litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
We may not be able to recover the costs of our substantial investments in capital improvements and additions.
OG&E's
Our business plan calls for extensive investments in capital improvements and additions in OG&E, including modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with environmental requirements or to provide reliable operations. As discussed above, the Infrastructure Investment and Jobs Act and Inflation Reduction Act present opportunities for federal grants and tax incentives intended to hasten the future economy-wide deployment of various greenhouse gas emission reducing technologies and approaches. While we plan to pursue opportunities through the Infrastructure Investment and Jobs Act, we expect to typically be responsible for 50 percent of the dollars spent on investments related to this Act. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment. This could adversely affect OG&E'sthe Registrants' financial position and results of operations. While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.
OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. The SPP has implemented regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights. Collectively, the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. The Company records the SPP Integrated Marketplace transactions as sales or purchases with results reported as Revenues from Contracts with Customers or Cost of Sales in its Consolidated Financial Statements. OG&E'sOur revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP.
Increased competition resulting from restructuring efforts to restructure utility and energy markets or deregulation could have a significant financial and load growth impact on us and consequently impact our revenue.
revenue and affordability of services.
We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retailRetail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, impact profit margins and/or increased costs of capital. Further, we regularly engage in negotiations on renewals of franchise agreements with municipal governments within our service territories. Any such restructuring could have a significant impact on our consolidated financial position, results of operations and cash flows. Further, our load growth could be impacted, which could result in an impact on the affordability of our services. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our consolidated financial position, results of operations or cash flows.
Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business,
consolidatedfinancial position, results of operations, cash flows and access to capital.
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, consolidated financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our consolidated financial position, results of operations and cash flows.
We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
We are subject to substantial regulation from federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain permits, approvals and certifications from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
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The NERC is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. OneAs one of OG&E's regulators, the NERC has comprehensive regulations and standards related to the reliability and security of our operating systems and is continuously developing additional mandatory compliance requirements for the utility industry. The increasing development of NERC rules and standards will increase compliance costs and our exposure for potential violations of these standards.
OPERATIONAL RISKS
Our results of operations may be impacted by disruptions to fuel supply or the electric grid that are beyond our control.
We are exposed to risks related to performance of contractual obligations by our suppliers.suppliers and transporters. We are dependent on coal and natural gas for much of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short- and long-term contracts. We have certain supply and transportation contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply and transport coal and natural gas to us. The suppliers and transporters under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers and transporters under these agreements may not be required to supply coal and natural gas to usprovide the commodity or service under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather, and availability of equipment.equipment and labor shortages. Failure or delay by our suppliers and transporters of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm, generator or transmission facility outage on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our consolidated financial position, results of operations and cash flows.
OG&E's electric generation, transmission and distribution assets are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased purchasepurchased power costs, accidents and third-party liability.
OG&E owns and operates coal-fired, natural gas-fired, wind-powered and solar-powered generating assets. Operation of electric generation, transmission and distribution assets involves risks that can adversely affect energy output and efficiency levels or that could result in loss of human life, significant damage to property, environmental pollution and impairment of OG&E's operations. Included among these risks are:
•increased prices for fuel, and fuel transportation, purchased power and purchased capacity as existing contracts expire;
•facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
•operator error or safety related stoppages;
•disruptions in the delivery of electricity; and
•intentional destruction of electric grid equipment; and
•catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.
The occurrence of any of these events, if not fully covered by insurance or if insurance is not available, could have a material effect on our consolidated financial position and results of operations. Further, when unplanned maintenance work is required on power plants or other equipment, OG&E will not only incur unexpected maintenance expenses, but it may also have to make spot market purchases of replacement electricity that could exceed OG&E's costs of generation or be forced to retire a generation unit if the cost or timing of the maintenance is not reasonable and prudent. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.
Changes in technology, regulatory policies and customer electricity consumption may cause our assets to be less competitive and impact our results of operations.
OG&E is a vertically integrated electric company and primarily generates electricity at large central facilities. ThisWe believe this method is the most efficient and cost-effective method for power delivery, as it typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmillswind turbines and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations. OG&E's widespread use
16
of Smart Grid technology allowing for two-way communications between the utilityelectric company and its customers could enable the entry of technology companies into the interface between OG&E and its customers, resulting in unpredictable effects on our current business.
Reductions in customer electricity consumption, thereby reducing utility electric sales, could result from increased deployment of renewable energy technologies as well as increased efficiency of household appliances, among other general efficiency gains in technology. However, this potential reduction in load would not reduce our need for ongoing investments in our infrastructure to reliably serve our customers. Continued utility infrastructure investment without increased electricity sales could cause increased rates for customers, potentially resulting in further reductions in electricity sales and reduced profitability.
Economic conditions could negatively impact our business and our results of operations.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital. Economic conditions may also impact the valuation of certain long-lived assets, including our investment in unconsolidated affiliates, that are subject to impairment testing, potentially resulting in impairment charges, which could have a material adverse impact on our results of operations.
Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
In addition, economic conditions, particularly budget shortfalls, could increase the pressure on federal, state and local governments to raise additional funds by increasing corporate tax rates and/or delaying, reducing or eliminating tax credits, grants or other incentives that could have a material adverse impact on our consolidated results of operations and cash flows.
We are subject to financial risks associated with climate change.
Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to the Company. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced in 2017 that the U.S. would begin negotiations to re-enter the agreement with different terms. The withdrawal would become effective on November 4, 2020. While the "Paris Agreement" is not formally binding, it could lead to increased compliance costs for the Company should the U.S. not officially withdraw. In addition, to the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory imposed costs, CO2 taxes or costs associated with additional regulatory requirements, the Company may be adversely impacted. There are also increasing financial risks for energy companies from private party litigation relating to greenhouse gas emissions and from shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change who may elect in the future to shift some or all of their investments into entities that emit lower levels of greenhouse gases or into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
In addition, we may be subject to climate change lawsuits. Defense costs associated with such litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
We are subject to cybersecurity risks and increased reliance on processes automated by technology.
In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our consolidated financial position, results of operations and cash flows.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems which may result in a loss of service to customers and also subject OG&E to financial harm due to the significant expense to repair security breaches or system damage. OG&E's Smart Grid program further increases potential risks associated with cybersecurity attacks. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on our consolidated financial position, results of operations and cash flows.
Security threats continue to evolve and adapt. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, or confidential data, or to disrupt operations. None of these attempts has individually or in aggregate resulted in a security incident with a material impact on our financial condition or results of operations. Despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact. Our security procedures, which include among others, virus protection software, cybersecurity and our business continuity planning, including disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse effect of cybersecurity attacks on our systems, which could adversely impact our operations.
We maintain property, casualty and cybersecurity insurance that may cover certain resultant physical damage or third-party injuries caused by potential cyber events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities or sustained military campaigns may adversely impact our consolidated financial position, results of operations and cash flows.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility and natural gas midstream industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities or sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, flooding, earthquakes, prolonged droughts and the occurrence of wildfires, as well as seasonal temperature variations may adversely affect our consolidated financial position, results of operations and cash flows.
Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms, wind storms, flooding, earthquakes, prolonged droughts and the occurrence of wildfires, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period. In addition, prolonged droughts could cause a lack of sufficient water for use in cooling during the electricity generating process. Additionally, if
Physical risks from climate can be considered in both acute (event-driven) and chronic (longer-term shifts in climate patterns) terms. The effects of climate change exacerbatescould exacerbate physical changes in weather operations may be impactedand the extreme weather events discussed above, including prolonged droughts, rise in temperatures and more extreme weather events like wildfires and ice storms, among other weather impacts. We have observed some of these events in recent years, and the trend could continue. OG&E can incur significant restoration costs as discussed above.
a result of these weather events. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.
FINANCIAL RISKS
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our consolidated financial position, results of operations or cash flows.
We have a Pension Plan that covers a significant amount of ourcertain employees hired before December 1, 2009. We also have defined benefit postretirement plans that cover a significant amount of ourcertain employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. Based on our assumptions at December 31, 2019, weWe expect to make future contributions to maintain required funding levels. Itlevels as necessary, and it has been our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. We may continue to make voluntary contributions in the future. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our consolidated financial position and results of operations. Those factors are outside of our control.
In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees, will continue to rise. The increasing costs and funding requirements with our Pension Plan, health care plans and other employee benefits may adversely affect our consolidated financial position, results of operations or liquidity.
Finally, the Company provides retirement benefits and retiree health care benefits to 80 employees seconded to Enable. 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 $17.3 million. Settlement and curtailment charges
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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 days' notice.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workersOGE Energy is significantly higher than the national average. Over the next three years, 30 percent of our current employees will meet the eligibility requirements to retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.
We are a holding company with ourits primary assetsasset being investments in ourits subsidiary, and equity investments.
We areOG&E.
OGE Energy is a holding company and thus our investments in ourits primary asset is its subsidiary, and unconsolidated affiliate, accounted for under the equity method, are our primary assets.OG&E. Substantially all of ourOGE Energy's operations are conducted by our subsidiary and unconsolidated affiliate.its subsidiary. Consequently, ourOGE Energy's operating cash flow and ourits ability to pay our dividends and service ourits indebtedness utilizesare dependent upon the operating cash flow of our subsidiary and unconsolidated affiliateOG&E and the payment of funds by themOG&E to usOGE Energy in the form of dividends or distributions. At December 31, 2019, the Company2022, OGE Energy and its subsidiaryOG&E had outstanding indebtedness and other liabilities of $6.9$8.1 billion. Our subsidiary and unconsolidated affiliate areOG&E is a separate legal entitiesentity that havehas no obligation to pay any amounts due on ourOGE Energy's indebtedness or to make any funds available for that purpose, whether by dividends or otherwise.distributions. In addition, theirOG&E's ability to pay dividends or distributions to usOGE Energy depends on any statutory and contractual restrictions that may be applicable to such subsidiary,the entity, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of our subsidiary or unconsolidated affiliateOG&E on their respectiveits assets will generally have priority over ourOGE Energy claims (except to the extent that weOGE Energy may be a creditor of the subsidiaries and ourits claims are recognized) and claims by ourOGE Energy shareholders.
In addition, as discussed above, OG&E is regulated by state utility commissions in Oklahoma and Arkansas as well as a federal regulatory agency which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions or federal regulatory agency attempt to impose restrictions on the ability of OG&E to pay dividends to us,OGE Energy, it could adversely affect its ability to continue to pay dividends.
GENERAL RISKS
Governmental and market reactions to events involving other public companies or other energy companies that are beyond our control may have negative impacts on our business,financial position, results of operations, cash flows and access to capital.
Accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities and political contributions, could lead to public and regulatory scrutiny and suspicion for public companies, including those in the regulated and unregulated utility business. Accounting irregularities could cause regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also could increase their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect any of these types of events may have on our business, financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our financial position, results of operations and cash flows.
Economic conditions, including inflationary pressures and supply chain disruptions, could negatively impact our business and our results of operations.
Our operations have been and are affected by local, national and worldwide economic conditions. National and global events could adversely affect and/or exacerbate macroeconomic conditions, including inflationary pressures, rising interest rates, supply chain disruptions and economic recessions, which in turn affect our operations and our customers. The Registrants have experienced rising costs to produce electricity through increased fuel prices, raw material inflation, logistical challenges and certain component shortages. We are dependent upon others, such as fuel suppliers and transporters and suppliers for our capital projects, to help execute our operations. Supply chain disruption has resulted, and may continue to result, in delays in construction activities and equipment deliveries related to our capital projects.
The consequences of a recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity and general inflation could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital. Economic conditions may also impact the valuation of certain long-lived assets that are subject to impairment testing, potentially resulting in impairment charges, which could have a material adverse impact on our results of operations.
Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
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In addition, economic conditions, particularly budget shortfalls, could increase the pressure on federal, state and local governments to raise additional funds by increasing corporate tax rates and/or delaying, reducing or eliminating tax credits, grants or other incentives that could have a material adverse impact on our results of operations and cash flows.
We are subject to cybersecurity risks and increased reliance on processes dependent on technology.
In the regular course of our business, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems due to theft, ransomware, viruses, denial of service, hacking, acts of war or terrorism or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems which may result in a loss of service to customers and also subject OG&E to financial harm due to the significant expense to respond to security breaches or repair system damage. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on our financial position, results of operations and cash flows.
Security threats continue to evolve and adapt. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, or confidential data, or to disrupt operations. None of these attempts has individually or in aggregate resulted in a security incident with a material impact on our financial condition or results of operations. Despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact. Our security procedures, which include among others, virus protection software, cybersecurity controls and monitoring and our business continuity planning, including disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse effect of cybersecurity attacks on our systems, which could adversely impact our operations.
We maintain property, casualty and cybersecurity insurance that may cover certain resultant cyber and physical damage or third-party injuries caused by potential cyber events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.
The failure of our technology infrastructure, or the failure to enhance existing technology infrastructure and implement new technology, could adversely affect our business.
Our operations are dependent upon the proper functioning of our internal systems, including the technology and network infrastructure that support our underlying business processes. Any significant failure or malfunction of such technology infrastructure may result in disruptions of our operations. In the ordinary course of business, we rely on technology infrastructure, including the internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data. Our technology infrastructure is dependent upon global communications and cloud service providers, as well as their respective vendors, many of whom have at some point experienced significant system failures and outages in the past and may experience such failures and outages in the future. These providers' systems are susceptible to cybersecurity and data breaches, outages from fire, floods, power loss, telecommunications failures, physical attack and similar events. Failure to prevent or mitigate data loss from system failures or outages could materially adversely affect our results of operations, financial position and cash flows.
In addition to maintaining our current technology infrastructure, we believe the digital transformation of our business is key to driving internal efficiencies as well as providing additional capabilities to customers. Our technology infrastructure is critical to cost-effective, reliable daily operations and our ability to effectively serve our customers. We expect our customers to continue to demand more sophisticated technology-driven solutions, and we must enhance or replace our technology infrastructure in response. This involves significant development and implementation costs to keep pace with changing technologies and customer demand. If we fail to successfully implement critical technology infrastructure, or if it does not provide the anticipated benefits or meet customer demands,
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such failure could materially adversely affect our business strategy as well as impact our results of operations, financial position and cash flows.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business and could impact our ability to operate critical infrastructure. Continued hostilities or sustained military campaigns may adversely impact our financial position, results of operations and cash flows.
In late 2022, physical attacks on electric equipment owned by other electric utility companies in the U.S. resulted in the loss of power for a period of time. Authorities have indicated they believe these attacks may have been carried out by domestic extremists, as the U.S. electric grid is noted as being highly vulnerable to domestic terrorism. While the Registrants have experienced physical attacks on their electric equipment, these incidents have not been material to their operations. The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities or sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
Health epidemics and other outbreaks could adversely impact economic activity and conditions worldwide, which could have a material adverse effect on our results of operations and financial condition.
Health epidemics and other outbreaks, such as the COVID-19 pandemic, could adversely impact economic activity and conditions worldwide, by, among other things, leading to shutdowns, disrupting supply chains, increasing unemployment, resulting in customer slow payment or non-payment and decreasing commercial and industrial load. In response to health epidemics and other outbreaks, an extended slowdown of the United States' economic growth, demand for commodities and/or material changes in governmental policy could result in lower economic growth and lower demand for electricity in our key markets as well as the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and prospects.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is higher than the national average. Over the next three years, 23.4 percent of our current employees will meet the eligibility requirements to retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to continue to pay dividends.
Certain provisions inmanage and operate our charter documents have anti-takeover effects.
Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporation statute, may have the effect of delaying, deferring or preventing a change in control of the Company. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders' meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of the Company without stockholder approval, may make it more difficult for other persons, without the approval of our Board of Directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder's best interest.
business.We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
The terms of the indentures governing our debt securities do not fully prohibit usOGE Energy or our subsidiariesOG&E from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreements and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we now face may intensify.
Any reductions in our credit ratings or changes in benchmark interest rates could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
We cannot assure you that any of ourthe current credit ratings orof the ratings of our subsidiariesRegistrants will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with our credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.
The Registrants recently amended their credit facilities to switch from eurodollar loans based on LIBOR to term SOFR loans. SOFR is a relatively new reference rate, and its composition and characteristics are not the same as LIBOR. It is not possible to predict what effect the change to SOFR may have on our interest rates.
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Further, changes
As indicated above, SOFR is a relatively new reference rate. Any failure of SOFR to gain market acceptance could cause the SOFR to be modified or discontinued. The Registrants' current credit facilities provide a mechanism for determining an alternative rate of interest upon the occurrence of certain events related to the discontinuance of SOFR. The change to SOFR or transition to other alternative rates, whether in benchmarkconnection with borrowings under the current credit facilities, or borrowings under replacement facilities or lines of credit, could expose the Registrants' future borrowings to less favorable rates. If the change to SOFR, or other alternative rates, results in increased alternative interest rates such asor if the United Kingdom's Financial Conduct Authority's announcement that it intends to phase out the London interbank offered rate, or LIBOR, by the end of 2021, could result in increased financing costs. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. If the method for calculation of LIBOR changes, if LIBOR is no longer available or ifRegistrants' lenders have increased costs due to such phase out or changes, then the Registrants' debt that uses benchmark rates could be affected and, in LIBOR,turn, the Company may incur increases inRegistrants' cash flows and interest rates on any borrowings and/or may need to renegotiate our credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.
expense could be adversely impacted.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have revolving credit agreements for working capital, capital expenditures, acquisitions and other corporate purposes. In December 2022, OGE Energy entered into an amendment to its revolving credit facility that increased the permitted maximum debt to capitalization ratio from 65 percent to 70 percent. OG&E’s credit facility has a financial covenant requiring it to maintain a maximum debt to capitalization ratio of 65 percent. The levels of our debt could have important consequences, including the following:
•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
•our debt levels may limit our flexibility in responding to changing business and economic conditions.
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our consolidated financial position, results of operations and cash flows.
We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that counterparties who owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.
RISKS ASSOCIATED WITH OUR INVESTMENT IN ENABLE MIDSTREAM PARTNERS
The Company does not control EnableWe have seen increased interest for electric service from emerging industries such as crypto mining and therefore is not able to cause or prevent certain actions by Enable. The general partnershiphydrogen production, which are both large consumers of Enable is equally controlled by the Company and CenterPoint.
Enable has its own governing board; therefore, the Company is not able to exercise control over Enable. Accordingly, the Company is unable to cause or prevent certain actions by Enable. Further, the Company cannot control the actions of the other general partner, CenterPoint. Our interests may not align with those of CenterPoint, andelectricity. If this lack of control could adversely impact our investment in Enable.
A portion of our earnings and operating cash flows are based on the performance of Enable. If any of the following risks were to occur, our business, financial condition, results of operations or cash flows could be materially adversely affected.
Our operating cash flow is derived partially from cash distributions we receive from Enable.
Our operating cash flow is derived partially from cash distributions we receive from Enable. The amount of cash Enable can distribute on its units principally depends upon the amount of cash generated from its operations, which will fluctuate from quarter to quarter based on, among other things:
•the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;
•the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;
•the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;
•the relationship among prices for natural gas, NGLs and crude oil;
•cash calls and settlements of hedging positions;
•margin requirements on open price risk management assets and liabilities;
•the level of competition from other companies offering midstream services;
•adverse effects of governmental and environmental regulation;
•the level of its operation and maintenance expenses and general and administrative costs; and
•prevailing economic conditions.
In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including:
•the level and timing of capital expenditures it makes;
•the cost of acquisitions;
•its debt service requirements and other liabilities;
•fluctuations in working capital needs;
•its ability to borrow funds and access capital markets;
•restrictions contained in its debt agreements;
•the amount of cash reserves established by its general partner;
•distributions paid on its Series A Preferred Units; and
•other business risks affecting its cash levels.
Enable's contracts are subject to renewal risks.
As contracts with Enable's existing suppliers and customers expire, Enable generally seeks to negotiate extensions or renewals of those contracts or enters into new contracts with other suppliers and customers. Enable may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and gathering and processing customers with contracts that contain minimum volume commitments may desire to enter into contracts without minimum volume commitments. Likewise, Enable's transportation and storage customers may choose not to extend or renew expiring contracts based on the economics of the related areas of production. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable to Enable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.
Enable depends on a small numbercontinues, these types of customers forcould represent a significant portion of its gathering and processing revenues and its transportation and storageour revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.
For the year ended December 31, 2019, 57 percent of Enable's natural gas gathered volumes were attributable to the affiliates of Continental Resources, Inc., Vine Oil and Gas, GeoSouthern Energy Corporation, XTO Energy Inc. and Tapstone Corporation and 48 percent of its transportation and storage service revenues were attributable to affiliates of CenterPoint, Spire Inc., Continental Resources, Inc., American Electric Power Co. and the Company. The loss of all or even a portion of the gathering and processing or transportation and storage services for any of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.
The businesses of Enable are dependent, in part, on the drilling and production decisions of others.
The businesses of Enable are dependent on the drilling and production of natural gas and crude oil. Enable has no control over the level of drilling activity in its areas of operation, or the amount of natural gas, NGLs and crude oil reserves associated with wells connected to its systems. In addition, as the rate at which production from wells currently connected to its system naturally declines over time, its gross margin associated with those wells will also decline. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, its customers must continually obtain new natural gas, NGLs and crude oil supplies. The primary factors affecting its ability to obtain new supplies of natural gas, NGLs and crude oil and attract new customers to its assets are the level of successful drilling activity near its systems, its ability to compete for volumes from successful new wells and its ability to expand its capacity as needed. If Enable is not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities would decline, which could
adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us. Enable has no control over producers or their drilling and production decisions, which are affected by, among other things:
•the availability and cost of capital;
•prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;
•demand for natural gas, NGLs and crude oil;
•levels of reserves;
•geological considerations;
•environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing and the regulation of air emissions; and
•the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of new natural gas, NGLs and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond its control. Because of these and other factors, even if new reserves are known to exist in areas served by Enable's assets, producers may choose not to develop those reserves. Declines in natural gas, NGLs or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. Sustained low natural gas, NGLs or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in its areas of operation could lead to further reductions in the utilization of its systems, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
In addition, it may be more difficult to maintain or increase the current volumes on its gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which Enable operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, it may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time.
Enable's industry is highly competitive and increased competitive pressure could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.
Enable competes with similar enterprises in its respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Competitors include public and private energy companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than Enable. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enable provides to its customers. Excess pipeline capacity in the regions served by Enable's interstate pipelines could also increase competition and adversely impact the ability to renew or enter into new contracts with respect to available capacity when existing contracts expire. In addition, Enable's customers that are significant producers of natural gas or crude oil may develop their own gathering, processing, transportation and storage systems in lieu of using Enable. Enable's ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and storage services. All of these competitive pressures could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.
Enable derives a substantial portion of its gross margin from subsidiaries through which it holds a substantial portion of its assets.
Enable derives a substantial portion of its gross margin from, and holds a substantial portion of its assets through, its subsidiaries. As a result, it depends on distributions from its subsidiaries in order to meet its payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide Enable with funds for its payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit its subsidiaries' ability to make payments or other distributions, and its subsidiaries could agree to contractual restrictions on its ability to make distributions.
The right by Enable to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if Enable were a creditor of any subsidiary, its rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by them.
The amount of cash Enable has available for distribution to its limited partners depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which it records net income.
The amount of cash Enable has available for distribution depends primarily upon its cash flow rather than on profitability. Profitability is affected by non-cash items but cash flow is not. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.
Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates.
Enable's business plan calls for investment in capital improvements and additions. Capital expenditures could range from approximately $160 million to $240 million and maintenance capital could range from approximately $110 million to $130 million for the year ending December 31, 2020.
The construction of additions or modifications to Enable's existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond its control and may require the expenditure of significant amounts of capital, which may exceed estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs and availability of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if an existing pipeline is expanded or a new pipeline is constructed, the construction may occur over an extended period of time, and Enable may not receive any material increases in revenues or cash flows until the project is completed. In addition, Enable may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve an expected investment return, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
In connection with its capital investments, Enable may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enable relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate either in volume or timing due to numerous uncertainties inherent in estimating future production. To the extent estimates of the volume of new production are inaccurate, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us. To the extent estimates in the timing of new production are inaccurate, new facilities may be constructed in advance of the actual need for capacity or may not be constructed in time to accommodate volume flows, which could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable, and it may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.
Natural gas, NGLs and crude oil prices are volatile, and changes in these prices could adversely affect Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including us.
Enable's financial position, results of operations and ability to make cash distributions to us could be negatively affected by adverse changes in the prices of natural gas, NGLs and crude oil depending on factors that are beyond its control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and
other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquefied natural gas, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.
Enable's natural gas processing arrangements expose Enable to commodity price fluctuations. In 2019, 4 percent, 26 percent and 70 percent of Enable's processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which it purchases natural gas or NGLs under these arrangements, then its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected. Enable uses certain derivative instruments to manage its commodity price risk exposures.
At any given time, Enable's overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that it is a net buyer of natural gas) and a net long position in NGLs (meaning that it is a net seller of NGLs). As a result, Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected to the extent the price of NGLs decreases in relation to the price of natural gas.
Enable's exposure to credit risks of its customers, and any material nonpayment or nonperformance by its customers could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.
Some of Enable's customers may experience financial problems that could have a significant effect on its customers' creditworthiness. Severe financial problems encountered by its customers could limit Enable's ability to collect amounts owed to it, or to enforce performance of obligations under contractual arrangements. In addition, many of Enable's customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of its customers' liquidity and limit its customers' ability to make payments or perform on obligations to Enable. Furthermore, some of Enable's customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable. Financial problems experienced by its customers could result in the impairment of its assets, reduction of its operating cash flows and may also reduce or curtail its customers' future use of its products and services, which could reduce revenues.
Enable provides certain transportation and storage services under fixed-price "negotiated rate" contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts, and, as a result, costs could exceed revenues received under such contracts.
Enable has been authorized by the FERC to provide transportation and storage services at its facilities at negotiated rates. As of December 31, 2019, approximately 37 percent of Enable's aggregate contracted firm transportation capacity on EGT and MRT and 93 percent of its aggregate contracted firm storage capacity on EGT and MRT was subscribed under such "negotiated rate" contracts. The majority of Enable's aggregate contracted firm transportation capacity and all of Enable's aggregate contracted firm storage capacity under negotiated rate contracts on MRT are subject to FERC rate case approval. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated rates, is not assured under current FERC policies. If Enable's costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution to its unitholders, including us, could also decrease.
If third-party pipelines and other facilities interconnected to Enable's gathering, processing or transportation facilities become partially or fully unavailable to Enable for any reason, Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including us, could be adversely affected.
Enable depends upon (i) third-party pipelines to deliver natural gas to, and take natural gas from, its natural gas transportation systems, (ii) third-party pipelines and other facilities to take crude oil and produced water from its crude oil and produced water gathering systems, and, in some cases, (iii) third-party facilities to process natural gas from its gathering systems. It also depends on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of its processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual
components for end-use sale. For example, an outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of Enable's processing plants and gathering systems, and a prolonged outage or disruption could ultimately result in a reduction in the volume of natural gas Enable gathers and NGLs it is able to produce. Additionally, Enable depends on third parties to provide electricity for compression at many of its facilities. Since it does not own or operate any of these third-party pipelines or other facilities, continuing operation of those facilities is not within its control. If any of these third-party pipelines or other facilities become partially or fully unavailable to Enable for any reason, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.
Enable does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.
Enable does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Enable may obtain the rights to construct and operate its pipelines for a specific period of time on lands owned by governmental agencies, American Indian tribes or other third parties, including on American Indian allotments, title to which is held in trust by the U.S. A loss of these rights, through its inability to renew right-of-way contracts or otherwise, could cause a cease in operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.
Enable conducts a portion of its operations through joint ventures, which subjects them to additional risks that could adversely affect the success of its operations and financial position, results of operations and ability to make cash distributions to unitholders, including us.
Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream Partners, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering, LLC. It may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside the control of Enable. If these parties do not satisfy their obligations under these arrangements, Enable's business may be adversely affected.
The joint venture arrangements of Enable may involve risks not otherwise present when operating assets directly, including, for example:
•joint venture partners may share certain approval rights over major decisions;
•joint venture partners may not pay their share of the obligations, leaving Enable liable for the liabilities created as a result of those unpaid obligations;
•possible inability to control the amount of cash it will receive from the joint venture;
•it may incur liabilities as a result of an action taken by its joint venture partners;
•it may be required to devote significant management time to the requirements of and matters relating to the joint ventures;
•its insurance policies may not fully cover loss or damage incurred by both them and its joint venture partners in certain circumstances;
•its joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and
•disputes between them and its joint venture partners may result in delays, litigation or operational impasses.
The risks described above or the failure to continue joint ventures or to resolve disagreements with joint venture partners could adversely affect Enable's ability to transact the business that is the subject of such joint venture, which would in turn adversely affect its financial position and results of operations ability to make cash distributions to unitholders, including us. The agreements under which certain joint ventures were formed may subject them to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require them to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If it does not timely meet its financial commitments or otherwise do not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of its joint venture partners may have substantially greater financial resources than Enable has and it may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture.
Under certain circumstances, Enbridge Inc. could have the right to purchase an ownership interest in SESH at fair market value.
Enable owns a 50 percent ownership interest in SESH. The remaining 50 percent ownership interests are held by Enbridge Inc. As of December 31, 2019, CenterPoint owns 53.7 percent of Enable's common units, 100.0 percent of its Series A Preferred Units and a 40 percent economic interest in Enable GP, LLC. Pursuant to the terms of the limited liability company agreement of SESH, as amended (the SESH LLC Agreement), if, at any time, CenterPoint has a right to receive less than 50 percent of Enable's distributions through its interests in Enable and in the general partner, or does not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase Enable's interest in SESH at fair market value, subject to certain exceptions.
An impairment of long-lived assets, including intangible assets, equity method investments or goodwill could reduce Enable's earnings.
Long-lived assets, including intangible assets with finite useful lives and property, plant and equipment, are evaluated for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment of long-lived assets is recognized if the carrying amount is not recoverable and exceeds fair value.
Equity method investments are evaluated for impairment when events or circumstances indicate that the carrying value of the investment might not be recoverable. An impairment of an equity method investment is recognized if the fair value of the investment as a whole, and not the underlying assets, has declined and the decline is other than temporary. An example of an investment that Enable accounts for under the equity method is its investment in SESH. If Enable enters into additional joint ventures, it could have additional equity method investments.
Goodwill is evaluated for impairment on an annual basis as well as when events or circumstances change that would more likely than not reduce the fair value of a reporting unit to below its carrying amount. An impairment of goodwill is recognized if the carrying value of a reporting unit exceeds its fair value. Enable recorded an impairment to goodwill of $86 million during the year ended December 31, 2019. As of December 31, 2019, Enable has goodwill of $12 million associated with the Ark-La-Tex Basin reporting unit, which is included in the gathering and processing segment as a result of the acquisition of Align Midstream, LLC in the fourth quarter of 2017.
Enable could experience future events or circumstances that result in an impairment of long-lived assets, including intangible assets, equity method investments, or goodwill. If Enable recognizes an impairment, it would take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. As a result, an impairment could have an adverse effect on Enable's results of operations and its ability to satisfy the financial ratios or other covenants under its existing or future debt agreements.
Enable's business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely affect its financial position, results of operations or ability to make cash distributions to unitholders, including us.
Enable's operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:
•damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;
•inadvertent damage from construction, vehicles and farm and utility equipment;
•leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;
•ruptures, fires and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of its operations. A natural disaster or other hazard affecting the areas in which it operates could adversely affect Enable's results of operations. Enable is not fully insured against all risks inherent in its business. Enable currently has general liability and property insurance in place to cover certain of its facilities in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles. Enable has business interruption insurance coverage for some but not all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable's facilities may not be sufficient to restore the loss or damage without adversely affecting its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
The use of derivative contracts by Enable and its subsidiaries in the normal course of business could result in financial losses that could adversely affect its financial position, results of operations and its ability to make cash distributions to unitholders, including us.
Enable and its subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage its commodity and financial market risks. Enable and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Failure to attract and retain an appropriately qualified workforce could adversely impact Enable's results of operations.
Enable's business is dependent on its ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Enable's costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Enable's ability to manage and operate its business. If Enable is unable to successfully attract and retain an appropriately qualified workforce, its results of operations could be negatively affected.
As of December 31, 2019, Enable has 80 employees who are participants under OGE Energy Corp.'s defined benefit and retiree medical plans, who are seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy Corp. If seconding is terminated, employees of OGE Energy Corp. that Enable determines to hire are under no obligation to accept Enable's offer of employment on the terms Enable provides, or at all.
Enable's ability to grow is dependent in part on its ability to access external financing sources on acceptable terms.
Enable expects its operating subsidiaries will distribute all of their available cash to Enable and that it will distribute all of its available cash to its unitholders. As a result, Enable expects that it and its operating subsidiaries will rely significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. To the extent Enable or its operating subsidiaries are unable to finance growth externally or through internally generated cash flows, Enable's and its operating subsidiaries' cash distribution policy may significantly impair Enable's and its operating subsidiaries' ability to grow. In addition, because Enable and its operating subsidiaries distribute all available cash, Enable's and its operating subsidiaries' growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.
To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk it will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that Enable has to distribute on each unit. There are no limitations in the partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable or its operating subsidiaries to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that its operating subsidiaries have to distribute to it, and thus that it has to distribute to its unitholders, including us.
Enable depends in part on access to the capital markets and other external financing sources to fund its expansion capital expenditures, although Enable has also increasingly relied on cash flow generated from its operations to fund its
expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable's common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.
Enable's merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated, which could adversely affect its financial position, results of operations or future growth.
From time to time, Enable has made, and it intends to continue to make, acquisitions of businesses and assets. Such acquisitions involve substantial risks, including the following:
•acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
•it may assume liabilities that were not disclosed to it, that exceed its estimates, or for which its rights to indemnification from the seller are limited;
•it may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and
•acquisitions, or the pursuit of acquisitions, could disrupt its ongoing businesses, distract management, divert resources and make it difficult to maintain its current business standards, controls and procedures.
In addition, Enable's growth strategy includes, in part, the ability to make acquisitions on economically acceptable terms. If Enable is unable to make acquisitions or if its acquisitions do not perform as anticipated, Enable's future growth may be adversely affected.
Enable and its operating subsidiaries' debt levels may limit their flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2019, Enable had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on senior notes. In addition, as of December 31, 2019, Enable had $155.0 million outstanding under its commercial paper program and $250.0 million outstanding under its EOIT senior notes, excluding unamortized premium. Enable also has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.59 billion in borrowing capacity was available as of December 31, 2019. As of January 31, 2020, Enable had $119 million outstanding under its commercial paper program and $1.63 billion of available capacity under its revolving credit facility. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of debt could have important consequences, including the following:
•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;
•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;
•the debt level will make Enable more vulnerable to competitive pressures or a downturn in the business or the economy generally; and
•the debt level may limit flexibility in responding to changing business and economic conditions.
Enable's and its operating subsidiaries' ability to service their debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond its control. If operating results are not sufficient to service Enable's and its operating subsidiaries' current or future indebtedness, Enable and its subsidiaries may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.
Enable's credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond its control, which could adversely affect its financial condition, results of operations and ability to make cash distributions to its unitholders, including us.
Enable's credit facilities contain customary covenants that, among other things, limit the ability to:
•permit its subsidiaries to incur or guarantee additional debt;
•incur or permit to exist certain liens on assets;
•dispose of assets;
•merge or consolidate with another company or engage in a change of control;
•enter into transactions with affiliates on non-arm's length terms; and
•change the nature of its business.
Enable's credit facilities also require it to maintain certain financial ratios. Its ability to meet those financial ratios can be affected by events beyond its control, and assurance it will meet those ratios cannot be guaranteed. In addition, its credit facilities contain events of default customary for agreements of this nature.
Enable's ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, its ability to comply with these covenants may be impaired. If any of the restrictions, covenants, ratios or tests in its credit facilities is violated, a significant portion of its indebtedness may become immediately due and payable. In addition, its lenders' commitments to make further loans to Enable under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Affiliates of Enable's general partner, including CenterPoint and the Company, may compete with Enable, and neither the general partner nor its affiliates have any obligation to present business opportunities to Enable.
Under Enable's omnibus agreement, both CenterPoint and the Company are prohibited from, directly or indirectly, owning, operating, acquiring or investing in any business engaged in midstream operations located within the U.S., other than through Enable. This requirement applies to both CenterPoint and the Company for so long as either CenterPoint or the Company holds any interest in Enable's general partner or at least 20 percent of its common units. However, if CenterPoint or the Company acquires any business with midstream operations assets that have a value in excess of $50.0 million (or $100.0 million in the aggregate with such party's other acquired midstream operations assets that have not been offered to Enable), the acquiring party will be required to offer to Enable such assets for such value. If Enable does not purchase such assets, the acquiring party will be free to retain and operate such midstream assets, so long as the value of the assets does not reach certain thresholds.
As a result, under the circumstances described above, CenterPoint and the Company have the ability to construct or acquire assets that directly compete with Enable's assets. Pursuant to the terms of Enable's partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to Enable's general partner or any of its affiliates, including its executive officers and directors and CenterPoint and the Company. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for Enable will not have any duty to communicate or offer such opportunity to Enable. Any such person or entity will not be liable to Enable or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to Enable. This may create actual and potential conflicts of interest between Enable and affiliates of its general partner and result in less than favorable treatment of Enable and its common unitholders.
If Enable fails to maintain an effective system of internal controls, then it may not be able to accurately report financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in its financial reporting, which would harm Enable's business and the trading price of its common units.
Effective internal controls are necessary for Enable to provide reliable financial reports, prevent fraud and operate successfully as a public company. If its efforts to maintain an effective system of internal controls are not successful, it is unable to maintain adequate controls over its financial processes and reporting in the future or it is unable to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, its operating results could be harmed or fail to meet its reporting obligations. Ineffective internal controls also could cause investors to lose confidence in its reported financial information, which would likely have a negative effect on the trading price of Enable's common units.
Cybersecurity attacks or other disruptions of Enable's systems, networks and technology could adversely impact Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.
Enable has become increasingly dependent on the systems, networks and technology that it uses to conduct almost all aspects of its business, including the operation of its gathering, processing, transportation and storage assets, the recording of commercial transactions and the reporting of financial information. Enable depends on both its own systems, networks and technology as well as the systems, networks and technology of its vendors, customers and other business partners. Any disruption of these systems, networks and technology could disrupt the operation of Enable's business. Disruptions can result from a variety of causes, including natural disasters, the failure of software or equipment and manmade events, such as cybersecurity attacks or information security breaches. Cybersecurity attacks and information security breaches could result in the unauthorized use of confidential, proprietary or other information and in the disruption of Enable's critical business functions and operations, adversely affecting its reputation and subjecting it to possible legal claims and liability. In addition, Enable is not fully insured against all cybersecurity risks.
As cybersecurity attacks continue to evolve, Enable may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerabilities to cybersecurity attacks. In particular, Enable's implementation of various procedures and controls to monitor and mitigate security threats and to increase security for its personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date Enable has not experienced any material losses relating to cybersecurity attacks; however, there can be no assurance that it will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.
Terrorist attacks or other physical security threats could adversely affect Enable's business.
Enable's gathering, processing, transportation and storage assets may be targets of terrorist activities or other physical security threats that could disrupt its ability to conduct its business. It is possible that any of these occurrences, or a combination of them, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us. In addition, any physical damage to Enable's assets resulting from acts of terrorism may not be fully covered by Enable's insurance.
Enable may be unable to obtain or renew permits necessary for its operations, which could inhibit its ability to do business.
Performance of its operations require it obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable's compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect its ability to initiate or continue operations at the affected location or facility and on its financial condition, results of operations and ability to make cash distributions to unitholders, including us.
Additionally, in order to obtain permits and renewals of permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and American Indian tribal lands. Certain approval procedures may require preparation of archaeological surveys, wetland delineations, endangered species surveys and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable's project construction schedules.
Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including us.
Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase costs of construction, restrict or limit the output of certain facilities and/or require additional
pollution control equipment and otherwise increase costs. For instance, in May 2016, the EPA issued final standards governing methane emissions imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage and transmission facilities. These rules have required changes to Enable's operations, including the installation of new equipment to control emissions. Most recently, in August 2019, the EPA proposed amendments to the 2016 standards, and legal challenges to any final rulemaking that rescinds the 2016 standards are expected. As a result, Enable cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, several states are pursuing similar measures to regulate emissions of methane from new and existing sources. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations. Future federal and state regulations relating to Enable's gathering and processing, transmission and storage operations remain a possibility and could result in increased compliance costs on Enable's operations. Furthermore, if new or more stringent federal, state or local legal restrictions are adopted in areas where Enable's oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which could adversely affect demand for Enable's services to those customers.
There is inherent risk of the incurrence of environmental costs and liabilities in Enable's operations due to the handling of natural gas, NGLs, crude oil and produced water as well as air emissions related to its operations and historical industry operations and waste disposal practices. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact business activities in many ways, such as restricting the handling or disposing of wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from its properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. Private parties, including the owners of the properties through which its gathering and transportation systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non- compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of its pipelines could subject them to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Enable may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact its customers' production and operations, resulting in less demand for its services.
Increased regulation of hydraulic fracturing and waste water injection wells could result in reductions or delays in natural gas production by Enable's customers, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
Hydraulic fracturing is a common practice that is used by many of Enable's customers to stimulate production of natural gas and crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. The EPA has also issued regulations and guidance for hydraulic fracturing operations under several statutes.
Some states have adopted, and other states have considered adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Enable's oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for Enable's services to those customers.
State and federal regulatory agencies have also focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may
also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies have adopted their regulations or issued orders to address induced seismicity. For example, the OCC has implemented volume reduction plans, and at times required shut-ins, for disposal wells injecting wastewater from oil and gas operations into the Arbuckle formation. In February 2018, the OCC revised well completion seismicity guidelines for operators in the South Central Oklahoma Oil Province and the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties to reduce the threshold of seismic readings required to suspend hydraulic fracturing operations in some circumstances. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Enable cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal. Additional legislation or regulation could also lead to operational delays or increased operating costs for Enable's customers, which in turn could reduce the demand for Enable's services.
Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing or other regulatory mechanisms.
Enable and its customers' operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, adversely impact Enable's results of operations and ability to make cash distributions to unitholders, including us, limit the areas in which oil and natural gas production may occur and reduce demand for the products and services Enable provides.
There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases as well as to restrict or eliminate such future emissions. As a result, Enable's operations as well as the operations of its oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of greenhouse gases.
In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas emissions constitute a pollutant under the Clean Air Act, the EPA has adopted regulations that, among other things, increase permit reviews and monitoring of facilities emitting greenhouse gases and or restrict the emissions of greenhouse gases. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced in 2017 that the U.S. would 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.
Governmental, scientific and public concern over the threat of climate change arising from greenhouse gas emissions has resulted in increasing political risks in the U.S., including climate change related pledges, made by certain candidates seeking the office of the President of the U.S. in 2020, to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for greenhouse gas emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate greenhouse gas emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for Enable's services and products. Additionally, political, litigation and financial risks may result in Enable's oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing their ability to continue to operate in an economic manner, which also could reduce demand for Enable's services and products. One or more of these developments could have a material adverse effect on Enable's business, financial condition, results of operations and ability to make cash distributions to unitholders, including us.
Finally, many scientists have concluded that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect Enable's results of operations and ability to make cash distributions to unitholders, including us.
Enable's operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
The rates charged by several of Enable's pipeline systems, including interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. The FERC and state regulatory agencies also regulate other terms and conditions of the services it may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types or terms and conditions of service it might propose or offer, the profitability of its pipeline businesses could suffer. If it were permitted to raise its tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit profitability. Furthermore, competition from other pipeline systems may prevent them from raising its tariff rates even if permitted by regulatory agencies. The regulatory agencies that regulate its systems periodically implement new rules, regulations and terms and conditions of services subject to its jurisdiction. New initiatives or orders may adversely affect the rates charged for services or otherwise adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
Enable's natural gas interstate pipelines are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Generally, the FERC's authority over interstate natural gas transportation extends to:
•rates, operating terms, conditions of service and service contracts;
•certification and construction of new facilities;
•extension or abandonment of services and facilities or expansion of existing facilities;
•maintenance of accounts and records;
•acquisition and disposition of facilities;
•initiation and discontinuation of services;
•depreciation and amortization policies;
•conduct and relationship with certain affiliates;
•market manipulation in connection with interstate sales, purchases or natural gas transportation; and
•various other matters.
Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 to impose penalties for current violations of up to approximately $1.3 million per day for each violation and possible criminal penalties of up to approximately $1.3 million per violation.
The FERC's jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from the FERC. Certain minor expansions are authorized by blanket certificates that the FERC has issued by rule. Typically, a significant expansion project requires
review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that Enable will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that Enable did not anticipate. Enable's inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.
The FERC conducts audits to verify compliance with the FERC's regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. The FERC's regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require Enable to seek modification, or alternatively require Enable to modify its tariff so that the non-conforming provisions are generally available to all customers.
The rates, terms and conditions for transporting natural gas in interstate commerce on certain of Enable's intrastate pipelines and for services offered at certain of Enable's storage facilities are subject to the jurisdiction of the FERC under Section 311 of the Natural Gas Policy Act. Rates to provide such interstate transportation service must be "fair and equitable" under the Natural Gas Policy Act and are subject to review, refund with interest if found not to be fair and equitable, and approval by the FERC at least once every five years.
Enable's crude oil gathering systems in the Williston Basin are subject to common carrier regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that Enable maintain tariffs on file with the FERC setting forth the rates Enable charges for providing transportation services, as well as the rules and regulations governing such services. The Interstate Commerce Act also requires, among other things, that Enable's rates must be "just and reasonable" and that Enable provide service in a manner that is nondiscriminatory. Shippers on Enable's FERC-regulated crude oil gathering systems may protest its tariff filings, file complaints against its existing rates, or the FERC can investigate Enable's rates on its own initiative. If FERC finds that Enable's existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order Enable to reduce its rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.
Enable's operations may also be subject to regulation by state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.
The pipeline operations of Enable that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas and transportation services. State and local regulations generally focus on safety, environmental and, in some circumstances, prohibition of undue discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. The effect, if any, such changes might have on operations cannot be predicted, but Enable could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect the business. Any such state or local regulation could have an adverse effect on the business and the financial position, results of operations and ability to make cash distributions to unitholders, including us.
A change in the jurisdictional characterization of some of Enable's assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.
Enable's natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the Natural Gas Act, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of FERC under the Interstate Commerce Act. Nevertheless, FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, it cannot be assured that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although the FERC has not made a formal determination with respect to all of Enable's facilities it considers to be engaged in natural gas gathering or a formal determination with respect to its facilities that it considers to be engaged in intrastate crude oil gathering, Enable believes that its natural gas gathering facilities meet the
traditional tests that the FERC has used to determine that a pipeline is a natural gas gathering pipeline and Enable's intrastate crude oil gathering facilities meet the traditional tests that the FERC has used to determine that a pipeline is not engaged in interstate crude oil transportation. The distinction between FERC-regulated facilities, however, has been the subject of substantial litigation, and the FERC determines whether facilities are subject to regulation under the Natural Gas Act or the Interstate Commerce Act on a case-by-case basis, so the classification and regulation of its facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, could adversely affect Enable's financial condition, results of operations and ability to make cash distributions to its unitholders, including us. In addition, if any of Enable's facilities were found to have provided services or otherwise operated in violation of the Natural Gas Act, Natural Gas Policy Act or Interstate Commerce Act regulations, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.
Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, these operations could be adversely affected should it become subject to the application of state regulation of rates and services. Enable's gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. The effect, if any, such changes might have on its operations cannot be predicted, but additional capital expenditures could be required and increased costs could be incurred depending on future legislative and regulatory changes.
Enable may incur significant costs and liabilities resulting from compliance with pipeline safety laws and regulations, pipeline integrity and other similar programs and related repairs.
Certain of Enable's pipeline operations are subject to pipeline safety laws and regulations. The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration regulates safety requirements for the design, construction, maintenance and operation of its jurisdictional natural gas and hazardous liquids pipeline facilities. All of Enable's interstate and intrastate natural gas transportation pipeline facilities are Pipeline and Hazardous Materials Safety Administration jurisdictional and certain of Enable's natural gas gathering, NGLs and crude oil pipeline facilities are Pipeline and Hazardous Materials Safety Administration jurisdictional. Among other things, these laws and regulations require pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for pipelines located in “high consequence areas.” The regulations require operators, including Enable, to, among other things:
•perform ongoing assessments of pipeline integrity;
•develop a baseline plan to prioritize the assessment of a covered pipeline segment;
•identify and characterize applicable threats that could impact a high consequence area;
•improve data collection, integration, and analysis;
•repair and remediate pipelines as necessary; and
•implement preventive and mitigating action.
Failure to comply with the Pipeline and Hazardous Materials Safety Administration or comparable state pipeline safety regulations could result in a number of consequences which may have an adverse effect on Enable's operations. Enable incurs significant costs associated with its compliance with existing Pipeline and Hazardous Materials Safety Administration and comparable state pipeline regulations. Enable incurred maintenance capital expenditures and operation and maintenance expenses of $79.0 million in 2019 and currently estimates that it will incur maintenance capital expenditures and operation and maintenance expenses of up to $84.0 million in 2020 under its pipeline safety program, including costs related to integrity assessments and repairs, threat and risk analyses, implementing preventative and mitigative measures, and conducting activities to support the maximum allowable operating pressure for gas pipelines or the maximum operating pressure for hazardous liquid pipelines. Enable may incur significant cost associated with repair, remediation, preventive and mitigation measures associated with its integrity management programs for pipelines that are not currently subject to regulation by the Pipeline and Hazardous Materials Safety Administration.
Changes to existing pipeline safety regulations may result in increased operating and compliance costs. For example, the Pipeline and Hazardous Materials Safety Administration published three final rules on pipeline safety in October 2019. Enable is in the process of assessing the impact of these rules on its future costs of operations and revenue from operations. The Pipeline and Hazardous Materials Safety Administration is also working on two additional rules related to gas pipeline safety, which are expected to be effective by mid-2020. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require Enable to install new or modified safety controls, pursue new capital projects or
conduct maintenance programs on an accelerated basis, all of which could require Enable to incur increased and potentially significant operational costs.
Financial reform regulations under the Dodd-Frank Act could adversely affect Enable's ability to use derivative instruments to hedge risks associated with its business.
At times, Enable may hedge all or a portion of its commodity risk and its interest rate risk. The federal government regulates the derivatives markets and entities, including businesses like Enable, that participate in those markets through the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the Commodity Futures Trading Commission and the Securities and Exchange Commission to promulgate rules and regulations implementing the legislation. Under the Commodity Futures Trading Commission's regulations, Enable is subject to reporting and recordkeeping obligations for transactions involving non-financial swap transactions. The Commodity Futures Trading Commissions initially adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. In December 2013, the Commodity Futures Trading Commission published a notice of proposed rulemaking designed to implement new position limits regulation and in December 2016, the Commodity Futures Trading Commission's re-proposed regulations for position limits. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.
The Commodity Futures Trading Commission has imposed mandatory clearing requirements on certain categories of swaps, including certain interest rate swaps, but has exempted derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where a counterparty such as Enable has required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. Enable's management believes its hedging transactions qualify for this "commercial end-user" exception. The Dodd-Frank Act may also require Enable to comply with margin requirements in connection with its hedging activities, although the application of those provisions to Enable is uncertain at this time. The Dodd-Frank Act may also require the counterparties to its derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.
The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for Enable's industry (including requirements to post collateral which could adversely affect Enable's available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks Enable encounters, reduce its ability to monetize or restructure its existing derivatives contracts, and increase its exposure to less creditworthy counterparties, particularly if Enable is unable to utilize the commercial end user exception with respect to certain of its hedging transactions. If Enable reduces its use of hedging as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Enable's revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect its financial position, results of operations and its ability to make cash distributions to unitholders, including us.
Any reductions in Enable's credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships.
Enable cannot provide assurance that its credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of Enable's credit ratings are below investment grade, it may have higher future borrowing costs and it or its subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when Enable was experiencing significant working capital requirements or otherwise lacked liquidity, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.
Enable's Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.
Enable's Series A Preferred Units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. Enable cannot declare or pay a distribution to its common unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the cash distributions we receive from Enable, could adversely affect the market price for Enable's common units or could make it more difficult for Enable to sell its common units in the future.
Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by Enable's general partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10 percent on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date, and an annual rate of the London Interbank Offered Rate plus a spread of 850 basis points on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the "other preferred units") on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as Enable's Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Enable's Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on Enable's Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact its liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Enable's obligations to the holders of Series A Preferred Units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.
Enable's Series A Preferred Units contain covenants that may limit its business flexibility.
Enable's Series A Preferred Units contain covenants preventing it from taking certain actions without the approval of the holders of 66 2/3 percent of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede Enable's ability to take certain actions that its management or its board of directors may consider to be in the best interests of its unitholders. The affirmative vote of 66 2/3 percent of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend Enable's Partnership Agreement in any manner that would or could reasonably be expected to have a material adverse effect on the rights, preferences, obligations or privileges of the Series A Preferred Units. The affirmative vote of 66 2/3 percent of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) create or issue certain party securities with proceeds in an aggregate amount in excess of $700.0 million or create or issue any senior securities or (B) subject to Enable's right to redeem the Series A Preferred Units, approve certain fundamental transactions.
Enable's Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange, and Enable may not have sufficient funds to redeem its Series A Preferred Units if it is required to do so.
The holders of Enable's Series A Preferred Units may request that Enable list those units for trading on the New York Stock Exchange. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of Enable's Series A Preferred Units could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.
Enable may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.
Enable's partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that it may issue at any time without the approval of its unitholders. The issuance by Enable of additional common units or other equity securities of equal or senior rank will have the following effects:
•Enable's existing unitholders' proportionate ownership interest in Enable will decrease;
•the amount of distributable cash flow on each unit may decrease;
•because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of the common units may decline.
In addition, upon a change of control or certain fundamental transactions, Enable's Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for Enable's common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for Enable to sell its common units in the future.
Affiliates of Enable's general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units and may sell their interest in its general partner, which may impact its strategic direction.
As of January 31, 2020, CenterPoint held 233,856,623 of Enable's common units and 14,520,000 Series A Preferred Units, and the Company held 110,982,805 of Enable's common units. Enable's Series A Preferred Units are convertible into common units upon a change of control or certain fundamental transactions at the option of the holders of such units. Both Enable's common units held by CenterPoint and the Company, as well as Enable's Series A Preferred Units held by CenterPoint, are subject to certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. In addition, any sale of Enable's general partner by CenterPoint or the Company may impact Enable's strategic direction, business or results of operations.
Item 1B. Unresolved Staff Comments.
21
OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 1317 generating stations with an aggregate capability of 7,0817,240 MWs at December 31, 2019.2022. The following tables set forthtable presents information with respect to OG&E's electric generating facilities. Unless otherwise indicated, these electric generating facilities all of which are located in Oklahoma.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Fuel Capability | 2019 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) | |
| | | Year Installed | | | | | | |
| Station & Unit | | | | Unit Design Type | | | | | |
| Seminole | 1 | | | | 1971 | Steam-Turbine | Gas | 12.9 | % | 485 | | | |
| 2 | | | | 1973 | Steam-Turbine | Gas | 10.6 | % | 500 | | | |
| 3 | | | | 1975 | Steam-Turbine | Gas/Oil | 20.5 | % | 475 | | 1,460 | | |
| Muskogee | 4 | | | | 1977 | Steam-Turbine | Gas | 9.6 | % | 423 | | | |
| 5 | | | | 1978 | Steam-Turbine | Gas | 9.3 | % | 442 | | | |
| 6 | | | | 1984 | Steam-Turbine | Coal | 14.7 | % | 503 | | 1,368 | | |
| Sooner | 1 | | | | 1979 | Steam-Turbine | Coal | 41.7 | % | 516 | | | |
| 2 | | | | 1980 | Steam-Turbine | Coal | 38.1 | % | 515 | | 1,031 | | |
| Horseshoe Lake | 5A | | (B) | | 1971 | Combustion-Turbine | Gas/Jet Fuel | 1.4 | % | 33 | | | |
| 5B | | (B) | | 1971 | Combustion-Turbine | Gas/Jet Fuel | 1.3 | % | 31 | | | |
| 6 | | | | 1958 | Steam-Turbine | Gas/Oil | 22.0 | % | 163 | | | |
| 7 | | | | 1963 | Combined Cycle | Gas/Oil | 23.3 | % | 211 | | | |
| 8 | | | | 1969 | Steam-Turbine | Gas | 0.4 | % | 403 | | | |
| 9 | | | | 2000 | Combustion-Turbine | Gas | 28.7 | % | 44 | | | |
| 10 | | | | 2000 | Combustion-Turbine | Gas | 28.8 | % | 42 | | 927 | | |
| Redbud (C) | 1 | | | | 2003 | Combined Cycle | Gas | 54.2 | % | 154 | | | |
| 2 | | | | 2003 | Combined Cycle | Gas | 62.5 | % | 154 | | | |
| 3 | | | | 2003 | Combined Cycle | Gas | 59.1 | % | 153 | | | |
| 4 | | | | 2003 | Combined Cycle | Gas | 59.0 | % | 154 | | 615 | | |
| Mustang | 6 | | | | 2018 | Combustion-Turbine | Gas | 33.4 | % | 57 | | | |
| 7 | | | | 2018 | Combustion-Turbine | Gas | 31.3 | % | 57 | | | |
| 8 | | | | 2017 | Combustion-Turbine | Gas | 26.3 | % | 58 | | | |
| 9 | | | | 2018 | Combustion-Turbine | Gas | 31.2 | % | 58 | | | |
| 10 | | | | 2018 | Combustion-Turbine | Gas | 30.0 | % | 57 | | | |
| 11 | | | | 2018 | Combustion-Turbine | Gas | 30.7 | % | 57 | | | |
| 12 | | | | 2018 | Combustion-Turbine | Gas | 21.8 | % | 57 | | 401 | | |
| McClain (D) | 1 | | | | 2001 | Combined Cycle | Gas | 64.0 | % | 378 | | 378 | | |
| Frontier | 1 | | | | 1989 | Combined Cycle | Gas | 22.4 | % | 120 | | 120 | | |
| River Valley | 1 | | | | 1991 | Steam-Turbine | Coal | 17.7 | % | 160 | | | |
| 2 | | | | 1991 | Steam-Turbine | Coal | 17.1 | % | 160 | | 320 | | |
| Total Generating Capability (all stations, excluding renewable) | | | | | | | | 6,620 | | |
| | | | | | | | | |
| Renewable | | | | | | 2019 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) | |
| Year Installed | | | Number of Units | Fuel Capability | | | | |
| Station | | Location | | | | | | | |
| Crossroads | 2011 | Canton, OK | | 98 | | Wind | 41.2 | % | 2.3 | | 228 | | |
| Centennial | 2007 | Laverne, OK | | 80 | | Wind | 25.0 | % | 1.5 | | 120 | | |
| OU Spirit | 2009 | Woodward, OK | | 44 | | Wind | 37.4 | % | 2.3 | | 101 | | |
| Mustang | 2015 | Oklahoma City, OK | | 90 | | Solar | 21.3 | % | — | | 2 | | |
| Covington | 2018 | Covington, OK | | 4 | | Solar | 25.7 | % | 2.4 | | 10 | | |
| Total Generating Capability (renewable) | | | | | | | | 461 | | |
| | | | | | | | | | | | | | | | | | | | |
Station & Unit | | | | Year
Installed | | Unit Design
Type | | Fuel
Capability | | 2022
Capacity
Factor (A) | | | Unit
Capability
(MW) | | | Station
Capability
(MW) | |
Seminole | | 1 | | 1971 | | Steam-Turbine | | Gas | | | 10.5 | % | | | 500 | | | | |
| | 2 | | 1973 | | Steam-Turbine | | Gas | | | 13.2 | % | | | 510 | | | | |
| | 3 | | 1975 | | Steam-Turbine | | Gas | | | 10.9 | % | | | 498 | | | | 1,508 | |
Muskogee | | 4 | | 1977 | | Steam-Turbine | | Gas | | | 17.2 | % | | | 487 | | | | |
| | 5 | | 1978 | | Steam-Turbine | | Gas | | | 11.7 | % | | | 488 | | | | |
| | 6 | | 1984 | | Steam-Turbine | | Coal | | | 22.6 | % | | | 503 | | | | 1,478 | |
Sooner | | 1 | | 1979 | | Steam-Turbine | | Coal | | | 29.4 | % | | | 516 | | | | |
| | 2 | | 1980 | | Steam-Turbine | | Coal | | | 30.2 | % | | | 515 | | | | 1,031 | |
Horseshoe Lake | | 5A | (B) | 1971 | | Combustion-Turbine | | Gas/Jet Fuel | | | 4.0 | % | | | 33 | | | | |
| | 5B | (B) | 1971 | | Combustion-Turbine | | Gas/Jet Fuel | | | 3.9 | % | | | 31 | | | | |
| | 6 | | 1958 | | Steam-Turbine | | Gas | | | 16.5 | % | | | 170 | | | | |
| | 7 | | 1963 | | Steam-Turbine | | Gas | | | 1.4 | % | | | 211 | | | | |
| | 8 | | 1969 | | Steam-Turbine | | Gas | | | 3.0 | % | | | 377 | | | | |
| | 9 | | 2000 | | Combustion-Turbine | | Gas | | | 28.6 | % | | | 45 | | | | |
| | 10 | | 2000 | | Combustion-Turbine | | Gas | | | 27.1 | % | | | 43 | | | | 910 | |
Redbud (C) | | 1 | | 2003 | | Combined Cycle | | Gas | | | 37.1 | % | | | 154 | | | | |
| | 2 | | 2003 | | Combined Cycle | | Gas | | | 35.6 | % | | | 154 | | | | |
| | 3 | | 2003 | | Combined Cycle | | Gas | | | 32.5 | % | | | 152 | | | | |
| | 4 | | 2003 | | Combined Cycle | | Gas | | | 35.9 | % | | | 153 | | | | 613 | |
Mustang | | 6 | | 2018 | | Combustion-Turbine | | Gas | | | 19.4 | % | | | 57 | | | | |
| | 7 | | 2018 | | Combustion-Turbine | | Gas | | | 34.8 | % | | | 56 | | | | |
| | 8 | | 2017 | | Combustion-Turbine | | Gas | | | 1.5 | % | | | 58 | | | | |
| | 9 | | 2018 | | Combustion-Turbine | | Gas | | | 14.4 | % | | | 57 | | | | |
| | 10 | | 2018 | | Combustion-Turbine | | Gas | | | 19.2 | % | | | 57 | | | | |
| | 11 | | 2018 | | Combustion-Turbine | | Gas | | | 38.0 | % | | | 57 | | | | |
| | 12 | | 2018 | | Combustion-Turbine | | Gas | | | 37.0 | % | | | 57 | | | | 399 | |
McClain (D) | | 1 | | 2001 | | Combined Cycle | | Gas | | | 50.1 | % | | | 378 | | | | 378 | |
Frontier | | 1 | | 1989 | | Combined Cycle | | Gas | | | 40.4 | % | | | 121 | | | | 121 | |
River Valley | | 1 | | 1991 | | Steam-Turbine | | Coal/Gas | | | 35.0 | % | | | 161 | | | | |
| | 2 | | 1991 | | Steam-Turbine | | Coal/Gas | | | 16.2 | % | | | 160 | | | | 321 | |
Total Generating Capability (all stations, excluding renewable) | | | | | | | | | 6,759 | |
(A)20192022 Capacity Factor = 20192022 Net Actual Generation / (2019(2022 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)). Capacity Factors are impacted by events that reduce Net Actual Generation such as outages.
(B)Represents units located at Tinker Air Force Base that are maintained by Horseshoe Lake.
(C)Represents OG&E's 51 percent ownership interest in the Redbud Plant.
(D)Represents OG&E's 77 percent ownership interest in the McClain Plant.
22
| | | | | | | | | | | | | | | |
Renewable | | | | | 2022 | | | | | | | |
Station | Year Installed | Location | Number of
Units | Fuel Capability | Capacity Factor
(A) | | | Unit
Capability
(MW) | | | Station
Capability
(MW) | |
Crossroads | 2011 | Canton, OK | 98 | Wind | | 18.6 | % | | | 2.3 | | | | 228 | |
Centennial | 2007 | Laverne, OK | 80 | Wind | | 16.5 | % | | | 1.5 | | | | 120 | |
OU Spirit | 2009 | Woodward, OK | 44 | Wind | | 15.5 | % | | | 2.3 | | | | 101 | |
Mustang | 2015 | Oklahoma City, OK | 90 | Solar | | 26.4 | % | | < 0.1 | | | | 2 | |
Covington | 2018 | Covington, OK | 4 | Solar | | 18.1 | % | | | 2.5 | | | | 10 | |
Choctaw Nation | 2020 | Durant, OK | 2 | Solar | | 23.6 | % | | | 2.5 | | | | 5 | |
Chickasaw Nation | 2020 | Davis, OK | 2 | Solar | | 25.4 | % | | | 2.5 | | | | 5 | |
Branch | 2021 | Branch, AR | 2 | Solar | | 22.6 | % | | | 2.5 | | | | 5 | |
Durant 2 | 2022 | Durant, OK | 2 | Solar | | 10.4 | % | | | 2.5 | | | | 5 | |
Total Generating Capability (renewable) | | | | | | | | | | 481 | |
2022 Capacity Factor = 2022 Net Actual Generation / (2022 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)). Capacity Factors are impacted by events that reduce Net Actual Generation such as outages.
At December 31, 2019,2022, OG&E's transmission system included: (i) 5354 substations with a total capacity of 13.914.1 million kV-amps and 5,1225,190 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.9 million kV-amps and 277347 structure miles of lines in Arkansas. At December 31, 2022, OG&E's distribution system included: (i) 350 substations with a total capacity of 10.410.8 million kV-amps, 29,40629,544 structure miles of overhead lines, 3,0503,544 miles of underground conduit and 10,96711,183 miles of underground conductors in Oklahoma and (ii) 30 substations with a total capacity of 1.0 million kV-amps, 2,7862,801 structure miles of overhead lines, 315360 miles of underground conduit and 679660 miles of underground conductors in Arkansas.
During the three years ended December 31, 2019, the Company's2022, both Registrants' gross property, plant and equipment (excluding construction work in progress) additions were $2.5$2.2 billion, and gross retirements were $408.5$299.4 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper), long-term borrowings and permanent financings. The additions during this three-year period amounted to 19.515.2 percent of gross property, plant and equipment (excluding construction work in progress) for both Registrants at December 31, 2019.
Item 3. Legal Proceedings.
In the normal course of business, the Company isRegistrants are 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 hasRegistrants have 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.Registrants' financial statements. At the present time, based on currently available information, the Company believesRegistrants believe 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 itstheir financial statements and would not have a material adverse effect on the Company's consolidatedRegistrants' financial position, results of operations or cash flows.
Item 4. Mine Safety Disclosures.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The Company'sOGE Energy's common stock is listed for trading on the New York Stock Exchange under the ticker symbol "OGE." At December 31, 2019,2022, there were 13,57012,222 holders of record of the Company'sOGE Energy's common stock.
Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.
Performance Graph
The below graph shows a five-year comparison of cumulative total returns for OGE Energy's common stock, the S&P 500 Index and the S&P 1500 Composite Utilities Sector Index. The graph assumes that the value of the investment in OGE Energy's common stock and each index was $100 as of December 31, 2017, and that all dividends were reinvested.
The above graph and related information should not be deemed "soliciting material" or to be "filed" with the Securities Exchange Commission, nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that OGE Energy specifically incorporates such information by reference into such a filing. The graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.
Issuer Purchases of Equity Securities
Item 6. Selected Financial Data.
HISTORICAL DATA
| | | | | | | | | | | | | | | | | |
| Year Ended December 31 | 2019 | 2018 | 2017 | 2016 | 2015 |
| SELECTED FINANCIAL DATA | | | | | |
| (In millions, except per share data) | | | | | |
| | | | | |
| Results of Operations Data | | | | | |
| Operating revenues | $ | 2,231.6 | | $ | 2,270.3 | | $ | 2,261.1 | | $ | 2,259.2 | | $ | 2,196.9 | |
| Cost of sales | 786.9 | | 892.5 | | 897.6 | | 880.1 | | 865.0 | |
| Operating expenses | 940.4 | | 888.2 | | 831.6 | | 848.3 | | 825.0 | |
| Operating income | 504.3 | | 489.6 | | 531.9 | | 530.8 | | 506.9 | |
| Equity in earnings of unconsolidated affiliates | 113.9 | | 152.8 | | 131.2 | | 101.8 | | 15.5 | |
| Allowance for equity funds used during construction | 4.5 | | 23.8 | | 39.7 | | 14.2 | | 8.3 | |
| Other net periodic benefit expense | 9.8 | | 10.8 | | 21.6 | | 27.5 | | 25.7 | |
| Other income | 21.9 | | 21.7 | | 46.4 | | 26.0 | | 27.0 | |
| Other expense | 23.5 | | 23.4 | | 14.1 | | 16.9 | | 14.3 | |
| Interest expense | 147.9 | | 156.0 | | 143.8 | | 142.1 | | 149.0 | |
| Income tax expense (benefit) | 29.8 | | 72.2 | | (49.3) | | 148.1 | | 97.4 | |
| Net income | $ | 433.6 | | $ | 425.5 | | $ | 619.0 | | $ | 338.2 | | $ | 271.3 | |
| | | | | |
| | | | | |
| Basic earnings per average common share | $ | 2.17 | | $ | 2.13 | | $ | 3.10 | | $ | 1.69 | | $ | 1.36 | |
| Diluted earnings per average common share | $ | 2.16 | | $ | 2.12 | | $ | 3.10 | | $ | 1.69 | | $ | 1.36 | |
| Dividends declared per common share | $ | 1.50500 | | $ | 1.39500 | | $ | 1.27000 | | $ | 1.15500 | | $ | 1.05000 | |
| Balance Sheet Data (at period end) | | | | | |
| Property, plant and equipment, net | $ | 9,044.6 | | $ | 8,643.8 | | $ | 8,339.9 | | $ | 7,696.2 | | $ | 7,322.4 | |
| Total assets | $ | 11,024.3 | | $ | 10,748.6 | | $ | 10,412.7 | | $ | 9,939.6 | | $ | 9,580.6 | |
| Long-term debt (including Long-term debt due within one year) | $ | 3,195.2 | | $ | 3,146.9 | | $ | 2,999.4 | | $ | 2,630.5 | | $ | 2,738.8 | |
| Total stockholders' equity | $ | 4,139.5 | | $ | 4,005.1 | | $ | 3,851.1 | | $ | 3,443.8 | | $ | 3,326.0 | |
| Capitalization Ratios (A) | | | | | |
| Stockholders' equity | 56.4 | % | 56.0 | % | 56.2 | % | 56.7 | % | 54.7 | % |
| Long-term debt | 43.6 | % | 44.0 | % | 43.8 | % | 43.3 | % | 45.3 | % |
(A)
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)].
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
The Companyfollowing combined discussion is separately filed by OGE Energy and OG&E. However, OG&E does not make any representations as to information related solely to OGE Energy or the subsidiaries of OGE Energy other than itself.
Overview
OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity in Oklahoma and western Arkansas. Prior to September 30, 2022, OGE Energy also held investments in Enable and Energy Transfer, which offered natural gas, primarily in the south central U.S. The Company conductscrude oil and NGL services. OGE Energy reports these activities through two business segments: (i) electric utilitycompany and (ii) natural gas midstream operations. The accounts of the CompanyOGE Energy and its wholly-owned subsidiaries, including OG&E, are included in the Consolidated Financial Statements.OGE Energy's consolidated financial statements. All intercompany transactions and balances are eliminated in such consolidation. The Company generally usesFor periods prior to the December 2, 2021 closing of the Enable and Energy Transfer merger, OGE Energy accounted for its investment in Enable as an equity method investment and reported it within OGE Energy's natural gas midstream operations segment. For the period of accountingDecember 2, 2021 through September 30, 2022, OGE Energy accounted for investments where its ownership interest is between 20 percent and 50 percent andinvestment in the Energy Transfer units it lacksacquired in the power to direct activities that most significantly impact economic performance.
Themerger as an investment in equity securities. As of the end of September 2022, OGE Energy had sold all of its Energy Transfer limited partner units, becoming primarily an electric
utility segmentcompany.
Electric Company Operations. OGE Energy's electric company operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and&E's rates 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.OGE Energy. OG&E is the largest electric utilitycompany 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. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment represents the Company'sincluded OGE Energy's investment in Energy Transfer's equity securities acquired in the Enable/Energy Transfer merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. Prior to OGE Energy's sale of all Energy Transfer limited partner units, the investment in Energy Transfer's equity securities was held through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is primarily engagedOGE Energy no longer has any ownership interest in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gatheringmidstream operations.
Recent Developments
Oklahoma Fuel Cost Adjustment Show Cause
On September 29, 2022, the OCC Public Utility Division Staff initiated a cause to determine the appropriate methodology to recover OG&E's $424.0 million fuel clause under recovery balance as of August 31, 2022 and processing assetshow OG&E's fuel factors should be set going forward. The Staff requested that OG&E explain how it arrived at the noted under recovery balance, explain its fuel forecasting process, justify its amortization period of 24 months and explain the adequacy of its resource mix and fuel supply plans. Updated fuel factors were implemented by OG&E on October 1, 2022 to recover the balance from customers over 24 months. The Staff did not oppose OG&E's implementation of updated fuel factors on an interim basis and subject to refund. Despite several public deliberations, the OCC has not issued a final order in this proceeding. On January 1, 2023, OG&E implemented its annual redetermination of its fuel factors, without further action or opposition from the OCC.
Global Macroeconomic Pressures
Geopolitical events, and related governmental and business responses, continue to have an impact on the Registrants' operations, supply chains and end-user customers, including our end-user customers' ability to pay for electric service. The Registrants have experienced raw material inflation, logistical challenges and certain component shortages. Supply chain disruption has resulted, and may continue to result, in delays in construction activities and equipment deliveries related to OGE Energy's capital projects. The timing and extent of the financial impact from these events are strategically located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahomastill uncertain, and the Texas PanhandleRegistrants cannot predict the magnitude of the impact to Louisiana, from Louisiana to Illinoisthe results of their business and from Louisiana to Alabama. At December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent,results of Enable's outstanding units. Enable's general partner 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 accounts for its interestoperations.
OG&E's Regulatory Matters
Completed regulatory matters affecting current period results are discussed in Enable using the equity method of accounting. For additional information on the Company's equity investment in Enable and related party transactions, see Note 514 within "Item 8. Financial Statements and Supplementary Data."
Enable's business is impacted by commodity prices which have declined and otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable's systems, and the volumes on Enable's systems are negatively impacted if producers decrease drilling and production in those areas served. Both Enable's gathering and processing segment and Enable's transportation and storage segment can be impacted by drilling and production. Enable's gathering and processing segment primarily serve producers, and many producers utilize the services provided by Enable's transportation and storage segment. A decrease in volumes will decrease the cash flows from Enable's systems. 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 risks, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGLs 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 7, 2020, Enable announced a quarterly dividend distribution of $0.33050 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."
Overview
Company Strategy
The Company's mission, through OG&E and the Company's 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 it serves, 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 customers, investors and members;
•continuing to grow a zero-injury culture and deliver top-quartile safety results;
•ensuring it has the necessary mix of generation resources to meet the long-term needs of its 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 four to six percent on a weather-normalized basis, maintaining a strong credit rating as well as projecting dividend increases to be consistent with utility earnings growth. 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 2019OGE Energy 2022 Operating Results Compared to 2018
Net2021
OGE Energy's net income was $433.6$665.7 million, or $2.16$3.32 per diluted share, in 20192022 as compared to $425.5$737.3 million, or $2.12$3.68 per diluted share, in 2018.2021. The increasedecrease in net income of $8.1$71.6 million, or $0.04$0.36 per diluted share, in 20192022 as compared to 20182021 is further discussed below.
•An increase in net income at OG&E of $22.2$79.5 million, or $0.10$0.39 per diluted share of the Company'sOGE Energy's common stock, was primarily due to higher gross marginoperating revenues driven primarily by more favorable weather and revenues from the expirationrecovery of the cogeneration credit rider, lower income taxcapital investments (excluding impacts of recoverable fuel, purchased power and direct transmission expense and lower interest expense. This increase wasnot impacting earnings), partially offset by higher depreciation and amortization expense due to an increase in depreciation rates resulting from the Oklahoma general rate review order received in September 2022 and additional assets being placed into service, lower allowance for funds used during construction due to certain environmental projects being completed and placed into serviceas well as higher income taxes and higher other operation and maintenance expense.
•An increaseA decrease in net incomeloss of other operations (holding company) of $13.3$2.6 million, or $0.07$0.01 per diluted share of the Company'sOGE Energy's common stock, was primarily due to higher other income, higher income tax benefit relatedpartially offset by an increase in net interest expense due to higher stock-based compensation payoutsthe long-term debt issuance in 2019 and lower other operation and maintenance expense.May 2021.
•A decrease in net income at OGE Holdings (Natural Gas Midstream Operations) of $27.4$153.7 million, or $0.13$0.76 per diluted share of the Company'sOGE Energy's common stock, was primarily due to lowera prior year $344.4 million pre-tax gain on the Enable/Energy Transfer merger and the elimination of OGE Energy's equity in earnings of Enable in 2022, which waswere driven by Enable's goodwill impairment charge and higher interest expense, and higher other expense due to higher pension settlement charges for seconded Enable employees,the merger closing in December 2021, partially offset by a $282.1 million pre-tax gain on OGE Energy's investment in Energy Transfer's equity securities in 2022, distributions received from Energy Transfer of $34.0 million and lower income tax expense.
A more detailed discussion regarding the financial performance of OG&E and OGE Holdings for the year ended December 31, 20192022 as compared to December 31, 20182021 can be found under "Results of Operations" below. A discussion of the financial performance for the year ended December 31, 20182021 compared to December 31, 20172020 for OGE Energy and OG&E can be found within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2018 Form 10-K.
Recent Developments and Regulatory Matters
Further discussion can be found in Note 16 within "Item 8. Financial Statements and Supplementary Data."
Arkansas 2018 Formula Rate Plan Filing
Per OG&E's settlement in its last general rate review, OG&E filed an evaluation report under its Formula Rate Plan in October 2018. On March 6, 2019, the APSC approved a settlement agreement for a $3.3 million revenue increase, and new rates were effective as of April 1, 2019.
Arkansas 2019 Formula Rate Plan Filing
OG&E filed its second evaluation report under its Formula Rate Plan in October 2019. On January 29, 2020, OG&E, the General Staff of the APSC and the Office of the Arkansas Attorney General filed a settlement agreement requesting the APSC approve a $5.2 million revenue increase, with rates effective April 1, 2020. The settling parties agreed that the Series I grid modernization projects are prudent in both action and cost and that the Series II grid modernization projects are prudent in action only and the determination of prudence of costs will be reserved until the actual historical costs are reviewed. The settling parties also agreed that OG&E will no longer use projections for the remaining initial term or extension of its current Formula Rate Plan and that all costs will be included for recovery for the first time in the historical year. A hearing was held on February 5, 2020, and OG&E is awaiting a final decision from the APSC.
Approval for Acquisition of Existing Power Plants.
2023 Outlook
In May 2019, OG&E received approval from both the OCC and the FERC to acquire plants from AES and Oklahoma Cogeneration LLC. The OCC approved OG&E's acquisition price of $53.5 million, the requested rider mechanism for the AES plant and regulatory asset treatment for the Oklahoma Cogeneration LLC plant that will defer non-fuel operation and maintenance expenses, depreciation and ad valorem taxes. In August 2019, the APSC issued an order finding that the plants to be acquired were used and useful and that the acquisition of the plants was in the public interest. The APSC also approved the depreciation rates to be applied to the acquired plants. The cost OG&E paid for the acquired plants was reviewed by the APSC in OG&E's 2019 Formula Rate Plan filing, and parties reached a settlement agreement requesting the APSC approve the cost of the acquisition. OG&E is awaiting a final decision from the APSC.
OG&E completed the acquisition of the power plant from AES and placed it into service in May 2019, which is now named the River Valley power plant. OG&E completed the acquisition of the power plant from Oklahoma Cogeneration LLC and placed it into service in August 2019, which is now named the Frontier power plant.
FERC - Section 206 Filing
In May 2019, OG&E and the Oklahoma Municipal Power Authority agreed to a settlement regarding OG&E's formula transmission rates under the SPP Open Access Transmission Tariff which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. On November 21, 2019, the FERC approved the settlement agreement.
Oklahoma Rate Review Filing - December 2018
In May 2019, OG&E entered into a non-unanimous joint stipulation and settlement agreement regarding OG&E's general rate review request with the OCC staff, the Attorney General's Office of Oklahoma and certain other parties associated with the requested rate increase. Under the terms of the settlement agreement, OG&E would receive full recovery of its environmental investments in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas. Base rates would not change as a result of the settlement agreement due to the reduction of costs related to cogeneration contracts and the acceleration of unprotected deferred tax savings over a 10-year period. Further, OG&E's current depreciation rates and return on equity of 9.5 percent for purposes of calculating the allowance for funds used during construction and OG&E's various recovery riders that include a full return component would remain unchanged.
In July 2019, OG&E implemented interim rates, which were subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. In September 2019, the OCC issued a final order which approved the settlement agreement.
APSC - Environmental Compliance Plan Rider
In May 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing is an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing. A hearing on the merits was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.
2020 Outlook
Key assumptions for 2020 include:
the Registrants' 2023 outlook are discussed below.
OG&E
The Company projects OG&E
OGE Energy is projected to earn approximately $346$387 million to $357$416 million, or $1.72$1.93 to $1.78$2.07 per average diluted share, with a midpoint of $402 million, or $2.00 per average diluted share, in 20202023 and is based on the assumptions listed below. As a result of OGE Energy's sales of all Energy Transfer limited partner units in 2022, OGE Energy will not report earnings, and therefore guidance, for a natural gas midstream operations segment beginning in 2023.
OG&E (Electric Company)
OG&E is projected to earn approximately $400 million to $421 million, or $1.99 to $2.09 per average diluted share, with a midpoint of $411 million, or $2.04 per average diluted share, in 2023 and is based on the following assumptions:
•normal weather patterns are experienced for the remainder of the year;
•gross margin onoperating revenues growth driven by total retail load growth (weather normalized) of approximately $1.515 billion4 to $1.521 billion based on sales growth5 percent, or approximately 2.5 to 3.5 percent assuming an equivalent level of approximately one percent on a weather-adjusted basis;datamining load in 2023 as existed at the end of 2022;
•operating expenses of approximately $980 million$1.101 billion to $984 million,$1.109 billion, with operation and maintenance expenses comprising approximately 5145 percent of the total;
•net interest expense of approximately $148$204 million to $150$210 million which assumes a $1.8$4 million allowance for borrowed funds used during construction reduction to interest expense;expense and assumes a debt issuance at OG&E of up to $400 million in 2023 in addition to the $450 million that was issued in January 2023;
•other income of approximately $3.0$32 million including approximately $4.5$10 million of allowance for equity funds used during construction; and
•an effective tax rate of approximately 10.015 percent.
OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of its earnings in the third quarter due to the seasonal nature of air conditioning demand.
OGE Holdings
The Company projects the earnings contribution from its ownership interest in Enable for 2020 to be at the lower end
Other Operations (Primarily Holding Company)
A loss of Enable's guidance between approximately $94 million to $106$9 million, or $0.47 to $0.53$0.04 per average diluted share, and receive approximately $147is expected at the holding company, within a range of a loss of $5 million in cash distributions.
Consolidated OGE
The Company's 2020 earnings guidance is between approximately $440to $13 million, and $463 million of net income, or $2.19$0.02 to $2.31$0.06 per average diluted share, and is based on the following assumptions:
Other consolidated assumptions include:
•approximately 201201.0 million average diluted shares outstanding; and
•an effective tax rate of approximately 12.0 percent; and
•breakeven results projected at OGE Energy.
OG&E's Non-GAAP Financial Measures
Gross margin is defined by OG&E as operating revenues less cost of sales. Cost of sales, as reflected on the income statement, includes 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. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the years ended December 31, 2019 and 2018, see "OG&E (Electric Utility) Results of Operations" below.
Detailed below is a reconciliation of gross margin to revenue included in the 2020 Outlook.
| | | | | |
| |
| |
(In millions) | Twelve Months Ended December 31, 2020
(A) |
Operating revenues | $ | 2,247 | |
Cost of sales | 729 | |
Gross margin | $ | 1,518 | |
(A)Based on the midpoint of OG&E earnings guidance for 2020.
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 Enable charges its customers and the sales price of natural gas and NGLs that Enable sells. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that Enable purchases. Enable deducts the cost of natural gas and NGLs from total revenues 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. Enable's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the years ending December 31, 2019 and 2018, see "OGE Holdings (Natural Gas Midstream Operations) Results of Operations" below.
Results of Operations
The following discussion and analysis presents factors that affected the Company's consolidatedRegistrants' results of operations for the years ended December 31, 20192022 and 20182021 and the Company's consolidatedRegistrants' financial positionpositions at December 31, 20192022 and 2018.2021. The following information should be read in conjunction with the Consolidated Financial Statementsfinancial statements and Notesnotes 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) | 2019 | 2018 | |
| Net income | $ | 433.6 | | $ | 425.5 | | |
| Basic average common shares outstanding | 200.1 | | 199.7 | | |
| Diluted average common shares outstanding | 200.7 | | 200.5 | | |
| Basic earnings per average common share | $ | 2.17 | | $ | 2.13 | | |
| Diluted earnings per average common share | $ | 2.16 | | $ | 2.12 | | |
| Dividends declared per common share | $ | 1.50500 | | $ | 1.39500 | | |
| | | | | | | | |
OGE Energy | | Year Ended December 31, | |
(In millions except per share data) | | 2022 | | | 2021 | |
Net income | | $ | 665.7 | | | $ | 737.3 | |
Basic average common shares outstanding | | | 200.2 | | | | 200.1 | |
Diluted average common shares outstanding | | | 200.8 | | | | 200.3 | |
Basic earnings per average common share | | $ | 3.33 | | | $ | 3.68 | |
Diluted earnings per average common share | | $ | 3.32 | | | $ | 3.68 | |
Dividends declared per common share | | $ | 1.64820 | | | $ | 1.62500 | |
Results by Business Segment
| | | | | | | | | |
| Year Ended December 31, | | |
| (In millions) | 2019 | 2018 | |
| Net income (loss): | | | |
| OG&E (Electric Utility) | $ | 350.2 | | $ | 328.0 | | |
| OGE Holdings (Natural Gas Midstream Operations) | 81.4 | | 108.8 | | |
| Other operations (A) | 2.0 | | (11.3) | | |
| Consolidated net income | $ | 433.6 | | $ | 425.5 | | |
| | | | | | | | |
| | Year Ended December 31, | |
(In millions) | | 2022 | | | 2021 | |
Net income (loss): | | | | | | |
OG&E (Electric Company) | | $ | 439.5 | | | $ | 360.0 | |
OGE Holdings (Natural Gas Midstream Operations) (A) | | | 231.3 | | | | 385.0 | |
Other operations (B) | | | (5.1 | ) | | | (7.7 | ) |
OGE Energy net income | | $ | 665.7 | | | $ | 737.3 | |
(A)Net income for the year ended December 31, 2021 includes the $344.4 million gain ($264.8 million after tax) recognized for the Enable merger transaction, as further discussed in Note 1 within "Item 8. Financial Statements and Supplementary Data."
(b)Other operations primarily includes the operations of OGE Energythe holding company and consolidating eliminations.
The following discussion of results of operations by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements.
OGE Energy's consolidated financial statements.
27
| | | | | | | | | |
Year Ended December 31 (Dollars in millions) | 2019 | 2018 | |
| Operating revenues | $ | 2,231.6 | | $ | 2,270.3 | | |
| Cost of sales | 786.9 | | 892.5 | | |
| Other operation and maintenance | 492.5 | | 473.8 | | |
| Depreciation and amortization | 355.0 | | 321.6 | | |
| Taxes other than income | 89.5 | | 88.2 | | |
| Operating income | 507.7 | | 494.2 | | |
| Allowance for equity funds used during construction | 4.5 | | 23.8 | | |
| Other net periodic benefit expense | 1.2 | | 8.9 | | |
| Other income | 6.7 | | 14.1 | | |
| Other expense | 6.9 | | 3.4 | | |
| Interest expense | 140.5 | | 151.8 | | |
| Income tax expense | 20.1 | | 40.0 | | |
| Net income | $ | 350.2 | | $ | 328.0 | | |
| Operating revenues by classification: | | | |
| Residential | $ | 891.1 | | $ | 901.0 | | |
| Commercial | 503.1 | | 519.9 | | |
| Industrial | 223.0 | | 234.5 | | |
| Oilfield | 204.0 | | 193.5 | | |
| Public authorities and street light | 195.7 | | 204.0 | | |
| Sales for resale | 0.1 | | 0.2 | | |
| System sales revenues | 2,017.0 | | 2,053.1 | | |
| Provision for rate refund | (0.9) | | (6.0) | | |
| Integrated market | 38.4 | | 48.7 | | |
| Transmission | 148.0 | | 147.4 | | |
| Other | 29.1 | | 27.1 | | |
| Total operating revenues | $ | 2,231.6 | | $ | 2,270.3 | | |
| Reconciliation of gross margin to revenue: | | | |
| Operating revenues | $ | 2,231.6 | | $ | 2,270.3 | | |
| Cost of sales | 786.9 | | 892.5 | | |
| Gross margin | $ | 1,444.7 | | $ | 1,377.8 | | |
MWh sales by classification (In millions) | | | |
| Residential | 9.7 | | 9.7 | | |
| Commercial | 6.5 | | 6.6 | | |
| Industrial | 4.5 | | 4.5 | | |
| Oilfield | 4.6 | | 4.2 | | |
| Public authorities and street light | 3.1 | | 3.1 | | |
| | | |
| System sales | 28.4 | | 28.1 | | |
| Integrated market | 1.2 | | 1.4 | | |
| Total sales | 29.6 | | 29.5 | | |
| Number of customers | 857,754 | | 849,372 | | |
Weighted-average cost of energy per kilowatt-hour (In cents) | | | |
| Natural gas | 2.188 | | 2.517 | | |
| Coal | 2.029 | | 2.025 | | |
| Total fuel | 1.973 | | 2.122 | | |
| Total fuel and purchased power | 2.534 | | 2.900 | | |
| Degree days (A) | | | |
| Heating - Actual | 3,771 | | 3,776 | | |
| Heating - Normal | 3,354 | | 3,349 | | |
| Cooling - Actual | 2,018 | | 2,123 | | |
| Cooling - Normal | 2,095 | | 2,092 | | |
| | | | | | | | |
Year Ended December 31 (Dollars in millions) | | 2022 | | | 2021 | |
Operating revenues | | $ | 3,375.7 | | | $ | 3,653.7 | |
Fuel, purchased power and direct transmission expense | | | 1,662.4 | | | | 2,127.6 | |
Other operation and maintenance | | | 491.9 | | | | 464.7 | |
Depreciation and amortization | | | 460.9 | | | | 416.0 | |
Taxes other than income | | | 98.0 | | | | 99.3 | |
Operating income | | | 662.5 | | | | 546.1 | |
Allowance for equity funds used during construction | | | 6.9 | | | | 6.7 | |
Other net periodic benefit income (expense) | | | 1.2 | | | | (4.3 | ) |
Other income | | | 6.5 | | | | 7.1 | |
Other expense | | | 3.4 | | | | 1.8 | |
Interest expense | | | 157.8 | | | | 152.0 | |
Income tax expense | | | 76.4 | | | | 41.8 | |
Net income | | $ | 439.5 | | | $ | 360.0 | |
Operating revenues by classification: | | | | | | |
Residential | | $ | 1,307.0 | | | $ | 1,342.1 | |
Commercial | | | 825.6 | | | | 766.9 | |
Industrial | | | 322.4 | | | | 328.2 | |
Oilfield | | | 306.7 | | | | 316.8 | |
Public authorities and street light | | | 298.9 | | | | 289.5 | |
System sales revenues | | | 3,060.6 | | | | 3,043.5 | |
Provision for rate refund | | | (1.2 | ) | | | — | |
Integrated market | | | 163.8 | | | | 468.9 | |
Transmission | | | 131.7 | | | | 140.2 | |
Other | | | 20.8 | | | | 1.1 | |
Total operating revenues | | $ | 3,375.7 | | | $ | 3,653.7 | |
MWh sales by classification (In millions) | | | | | | |
Residential | | | 10.4 | | | | 9.6 | |
Commercial | | | 7.9 | | | | 6.8 | |
Industrial | | | 4.2 | | | | 4.2 | |
Oilfield | | | 4.4 | | | | 4.2 | |
Public authorities and street light | | | 3.1 | | | | 2.9 | |
System sales | | | 30.0 | | | | 27.7 | |
Integrated market | | | 1.1 | | | | 1.6 | |
Total sales | | | 31.1 | | | | 29.3 | |
Number of customers | | | 888,759 | | | | 879,447 | |
Weighted-average cost of energy per kilowatt-hour (In cents) | | | | | | |
Natural gas (A) | | | 7.032 | | | | 11.907 | |
Coal | | | 3.253 | | | | 1.935 | |
Total fuel (A) | | | 5.480 | | | | 6.833 | |
Total fuel and purchased power (A) | | | 5.096 | | | | 6.892 | |
Degree days (B) | | | | | | |
Heating - Actual | | | 3,652 | | | | 3,281 | |
Heating - Normal | | | 3,568 | | | | 3,452 | |
Cooling - Actual | | | 2,385 | | | | 1,896 | |
Cooling - Normal | | | 1,893 | | | | 1,912 | |
(A)Decreased primarily due to both elevated pricing from Winter Storm Uri and higher market prices related to increased natural gas prices in 2021.
(b)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. The calculation of heating and cooling degree normal days is based on a 30-year average and updated every ten years, which most recently occurred in mid-2021.
28
OG&E's net income increased $22.2$79.5 million, or 6.822.1 percent, in 20192022 as compared to 2018. Primary2021. The following section discusses the primary drivers for thisthe increase in net income are further discussed below.
Gross margin increased $66.9 million, or 4.9 percent, in
20192022 as compared to
2018.2021.Operating revenues decreased $278.0 million, or 7.6 percent, primarily driven by the below factors.
| | | | |
(In millions) | | $ Change | |
Fuel, purchased power and direct transmission expense (A) | | $ | (465.2 | ) |
Wholesale transmission revenue | | | (4.2 | ) |
Other | | | (2.8 | ) |
Industrial and oilfield sales | | | 5.0 | |
Non-residential demand and related revenues | | | 10.2 | |
New customer growth | | | 13.0 | |
Guaranteed Flat Bill program (B) | | | 16.3 | |
Quantity impacts (primarily weather) (C) | | | 68.0 | |
Price variance (D) | | | 81.7 | |
Change in operating revenues | | $ | (278.0 | ) |
(A)These expenses are generally recoverable from customers through regulatory mechanisms and are offset in Fuel, Purchased Power and Direct Transmission Expense in the statements of income, as further described below. The below factors contributed toprimary drivers of the changechanges in gross margin.fuel, purchased power and direct transmission expense during the period are further detailed in the table below.
| | | | | |
(In millions) | | $ Change | |
Price variance (A) | $ | 43.6 | |
| |
Weather (price and quantity) (B) | 18.2 | |
| |
| |
| |
| |
| |
Other | 5.1 | |
Change in gross margin | $ | 66.9 | |
(A) Increased primarily due to the expiration ofloss from the cogeneration credit rider.Guaranteed Flat Bill program in 2021 related to Winter Storm Uri. The Guaranteed Flat Bill program allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year which can result in variances when actual fuel and purchased power prices differ from what is included in Guaranteed Flat Bill Program rates.
(B) (C)Increased primarily due to highera 25.8 percent increase in cooling degree days for certain summer months duringand an 11.3 percent increase in heating degree days.
(D)Increased primarily due to the period, which resultedOklahoma general rate review order received in favorable weather impacts.
September 2022 that approved new rates effective July 1, 2022, the impact of the Arkansas Formula Rate Plan and increased recovery through rider mechanisms, such as the Storm Cost of salesRecovery Rider and energy efficiency riders.
Fuel, purchased power and direct transmission expense for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. TheAs described above, the actual cost of fuel used in electric generation and certain purchased power costs are passed through togenerally recoverable from 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 salesfuel, purchased power and direct transmission expense decreased $105.6$465.2 million, or 11.821.9 percent, in 2019 as compared to 2018. Theprimarily driven by the below factors contributed to the change in cost of sales.
| | | | | | | | | |
| (In millions) | | $ Change | % Change |
| | | |
| | | |
| Fuel expense (A) | | $ | (50.7) | | (13.1) | % |
| Purchased power costs: | | | |
| Purchases from SPP (B) | | 41.0 | | 16.0 | % |
| Cogeneration (C) | | (97.8) | | (86.9) | % |
| | | |
| Other | | 0.3 | | 0.5 | % |
| Transmission expense (D) | | 1.6 | | 2.2 | % |
| | | |
| Change in cost of sales | | $ | (105.6) | | |
| | | | | | | | |
(In millions) | | $ Change | | | % Change | |
Fuel expense (A) | | $ | (369.6 | ) | | | (33.2 | )% |
Purchased power costs: | | | | | | |
Purchases from SPP (B) | | | (94.2 | ) | | | (10.8 | )% |
Wind | | | 2.2 | | | | 3.9 | % |
Other | | | (0.3 | ) | | | (2.8 | )% |
Transmission expense | | | (3.3 | ) | | | (4.3 | )% |
Change in fuel, purchased power and direct transmission expense | | $ | (465.2 | ) | | | |
(A)Decreased primarily due to lower natural gas pricesinflated fuel costs in 2021 during 2019.Winter Storm Uri.
(B)Increased primarily due to a 37.1 percent increase in MWhs purchased during 2019.
(C)Decreased primarily due to the expiration of the AES cogeneration contracthigher market prices in January 2019 and the Oklahoma Cogeneration LLC contract in August 2019, as discussed in Note 15 within "Item 8. Financial Statements and Supplementary Data."2021 during Winter Storm Uri.
(D)Increased primarily due to higher SPP charges for the base plan projects of other utilities.
Other operation and maintenance expense increased $18.7$27.2 million, or 3.95.9 percent, in 2019 as compared to 2018. Theprimarily driven by the below factors contributed to the change in other operation and maintenance expense.
| | | | | | | | |
| (In millions) | | $ Change | % Change |
| New expenses related to River Valley power plant (A) | $ | 13.7 | | * | |
| Contract technical and construction services (B) | 7.2 | | 16.8 | % |
| Other | (2.2) | | (0.5) | % |
| | |
| Change in other operation and maintenance expense | $ | 18.7 | | |
*factors.Not applicable, as prior year expenses were zero.
| | | | | | | | |
(In millions) | | $ Change | | | % Change | |
Contract technical and construction services (A) | | $ | 6.7 | | | | 12.8 | % |
Materials and supplies (B) | | | 4.1 | | | | 15.5 | % |
Other | | | 3.9 | | | | 1.3 | % |
Vegetation management | | | 3.8 | | | | 9.9 | % |
Fees, permits and licenses | | | 3.3 | | | | 15.7 | % |
Fleet transportation (C) | | | 2.9 | | | | 35.3 | % |
Contract professional services | | | 2.5 | | | | 12.8 | % |
Change in other operation and maintenance expense | | $ | 27.2 | | | | |
(A)Additional other operation and maintenance expenses related to the purchase of the River Valley plant are primarily recovered through a rider mechanism, as discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data."
(B)Increased primarily due to higher equipment maintenance which included additional maintenance work at power plants.Arkansas storm restoration.
Increased primarily due to inflationary increases throughout the supply chain.
(C)Increased primarily due to higher fuel prices, including diesel which supports the majority of company fleet.
29
Depreciation and amortization expense increased $33.4$44.9 million, or 10.410.8 percent, primarily due to an increase in depreciation rates effective as of July 1, 2022 resulting from the Oklahoma general rate review order received in September 2022, additional assets being placed into service.
Allowance for equity funds used during construction decreased $19.3 million, or 81.1 percent, primarily dueservice and increased amortization of the regulatory asset related to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.
Other net periodic benefit expense decreased $7.7income changed $5.5 million, or 86.5 percent, primarily due to lower pension costs reflectedexpense driven by changes to the level of pension expense included in base rates, effective July 1, 2022, as a result of a June 2018approved in the Oklahoma general rate review settlement.
order received in September 2022.
Other income decreased $7.4Income tax expense increased $34.6 million, or 52.582.8 percent, reflecting additional income taxes primarily due to a decrease in the tax gross-up related to lower allowance for funds used during construction.
Interest on long-term debthigher pretax income and decreased
$19.1 million, or 12.1 percent, primarily duefederal and state tax credit generation, partially offset by higher amortization of net unfunded deferred taxes.
OGE Holdings (Natural Gas Midstream Operations)
On December 2, 2021, Energy Transfer completed its previously announced acquisition of Enable. Prior to the timingEnergy Transfer and Enable merger closing, OGE Energy's natural gas midstream operations segment included its equity method investment in Enable, and from December 2, 2021 to September 30, 2022, this segment included OGE Energy's investment in Energy Transfer's equity securities. Legacy Enable seconded employee pension and postretirement costs are also included for the year ended December 31, 2022. Therefore, results of higher interest rate debt maturing and being replaced with lower interest rate debt and dueoperations for the natural gas midstream operations segment are not comparable for the year ended December 31, 2022 compared to the deferralyear ended December 31, 2021. See "Investment in Equity Securities of interest expense for the Sooner Dry Scrubbers to a regulatory asset, as disclosedEnergy Transfer" in Note 1 within "Item 8. Financial Statements and Supplementary Data."
AllowanceData" for
borrowed funds used during constructionfurther discussion of the net proceeds from sales of Energy Transfer's equity securities, realized gain/loss on Energy Transfer's equity securities and dividend income recognized by OGE Energy. See OGE Energy's 2021 Form 10-K for discussion of the primary drivers of Enable's income statement information for the period of January 1, 2021 through December 2, 2021.
OGE Holdings' income tax expense decreased $8.9$52.9 million, or 76.152.4 percent, primarily due to lower construction workpre-tax income and tax adjustments from the sale of Energy Transfer limited partner units, partially offset by state deferred tax adjustments related to OGE Energy's midstream investment in progress balances resulting from certain environmental projects being completedEnergy Transfer subsequent to the acquisition of Enable.
Liquidity and placed into service.
Cash Flows
OGE Energy
| | | | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | $
Change | | | %
Change |
Net cash provided from (used in) operating activities (A) | | $ | 843.1 | | | $ | (313.3 | ) | | $ | 1,156.4 | | | * |
Net cash provided from (used in) investing activities (B) | | $ | 12.9 | | | $ | (749.1 | ) | | $ | 762.0 | | | * |
Net cash (used in) provided from financing activities (C) | | $ | (767.9 | ) | | $ | 1,061.3 | | | $ | (1,829.2 | ) | | * |
* Change is greater than 100 percent.
Income tax expense decreased $19.9 million, or 49.8 percent,Changed primarily due to an increase in cash received from customers, the amortizationreceipt of net refundable deferred taxessecuritization funds from the ODFA and highera decrease in vendor payments, including payments for fuel and purchased power costs related to Winter Storm Uri in 2021, partially offset by additional income tax credits.
OGE Holdings (Natural Gas Midstream Operations)
| | | | | | | | | |
| Year Ended December 31, | | |
| (In millions) | 2019 | 2018 | |
| Operating revenues | $ | — | | $ | — | | |
| Cost of sales | — | | — | | |
| Other operation and maintenance | 2.8 | | 1.4 | | |
| Depreciation and amortization | — | | — | | |
| Taxes other than income | 0.4 | | 0.6 | | |
| Operating loss | (3.2) | | (2.0) | | |
| Equity in earnings of unconsolidated affiliates | 113.9 | | 152.8 | | |
| | | |
| Other expense | 8.6 | | 4.9 | | |
| | | |
| Income before taxes | 102.1 | | 145.9 | | |
| Income tax expense | 20.7 | | 37.1 | | |
| | | |
| Net income attributable to OGE Holdings | $ | 81.4 | | $ | 108.8 | | |
Reconciliationpayments primarily relating to the sale of EquityEnergy Transfer's limited partner units in Earnings of Unconsolidated Affiliates2022.
See Note 5 within "Item 8. Financial Statements and Supplementary Data" for the reconciliation of Enable's net income to OGE Energy's equity in earnings of unconsolidated affiliates and the reconciliation of the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference).
Enable Results of Operations and Operating Data
The following tables present summarized financial information of Enable for the years ended December 31, 2019 and 2018.
| | | | | | | | | |
| Year Ended December 31, | | |
| (In millions) | 2019 | 2018 | |
| Reconciliation of gross margin to revenue: | | | |
| Total revenues | $ | 2,960 | | $ | 3,431 | | |
| Cost of natural gas and NGLs | 1,279 | | 1,819 | | |
| Gross margin | $ | 1,681 | | $ | 1,612 | | |
| Operating income | $ | 569 | | $ | 648 | | |
| Net income | $ | 360 | | $ | 485 | | |
| | | | | | | | | |
| Year Ended December 31, | | |
| 2019 | 2018 | |
| Natural gas gathered volumes - TBtu/d | 4.56 | | 4.48 | | |
| Transported volumes - TBtu/d | 6.18 | | 5.56 | | |
| Natural gas processed volumes - TBtu/d | 2.53 | | 2.40 | | |
| NGLs sold - MBbl/d (A)(B) | 131.59 | | 132.06 | | |
| Crude oil and condensate gathered volumes - MBbl/d | 128.46 | | 41.07 | | |
(A)Excludes condensate.
(B)NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.
OGE Holdings' income before taxes decreased $43.8 million, or 30.0 percent,Changed primarily due to a decrease in equity in earningsproceeds from the sale of Enable of $38.9 million, which was driven by a goodwill impairment charge and higher interest expense, and an increase in other expense of $3.7 million driven by higher pension settlement charges for seconded Enable employees. The following table presents summarized information regarding Enable's income statement changes for the year ended December 31, 2019, compared to the same period in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.
The decrease in the Company's equity in earnings of Enable was primarily due to the following:
| | | | | | | | | | |
| | | | |
| (In millions) | | | Income Statement Change at Enable | Impact to Company's Equity in Earnings |
| Gross margin | | | $ | 69.0 | | $ | 17.6 | |
| Operation and maintenance, General and administrative | | | $ | 25.0 | | $ | (6.4) | |
| Depreciation and amortization | | | $ | 35.0 | | $ | (8.9) | |
| Impairment | | | $ | 86.0 | | $ | (21.9) | |
| Interest expense | | | $ | 38.0 | | $ | (9.7) | |
Enable's gathering and processing business segment reported a decrease in operating income of $84.0 million. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for the year ended December 31, 2019, compared to the same period in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.
The decrease in Enable's gathering and processing business segment operating income was primarily due to the following:
| | | | | | | | |
| (In millions) | Income Statement Change at Enable | Impact to Company's Equity in Earnings |
| Gross margin | $ | 58.0 | | $ | 14.8 | |
| Operation and maintenance, General and administrative | $ | 8.0 | | $ | (2.0) | |
| Depreciation and amortization | $ | 45.0 | | $ | (11.5) | |
| Impairment | $ | 86.0 | | $ | (21.9) | |
Gathering and processing gross margin increased primarily due to the following:
•an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins and higher revenue associated with the amendment of certain minimum volume commitment contracts in the Arkoma Basin,Energy Transfer's limited partner units, partially offset by lower gathered volumes in the Arkoma Basin and lower shortfall payments associated with the expiration of minimum volume commitments contracts in the Arkoma Basin;
•an increase in realized gains on natural gas, condensate and NGLs derivatives;
•an increase in crude oil, condensate and produced water gathering revenues due to an increase related to a 2018 acquisition and an increase in volumes in the Williston Basin, partially offset by lower average gathering rates in the Williston Basin; and
•an increase in intercompany management fees; partially offset by
•a decrease in changes in the fair value of natural gas, condensate and NGLs derivatives;
•a decrease in revenues from NGLs sales less the cost of NGLs due to lower average sales prices for all NGLs products, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins;
•a decrease in processing service fees due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangement due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins; and
•a decrease in revenues from natural gas sales less the cost of natural gas due to lower average natural gas sales prices and lower sales volumes.
Enable's transportation and storage business segment reported an increase of $6.0 million in operating income. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for year ended December 31, 2019, compared to the same period in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.
The increase in Enable's transportation and storage business segment operating income was primarily due to the following:
| | | | | | | | |
| (In millions) | Income Statement Change at Enable | Impact to Company's Equity in Earnings |
| Gross margin | $ | 13.0 | | $ | 3.3 | |
| Operation and maintenance, General and administrative | $ | 18.0 | | $ | (4.6) | |
| Depreciation and amortization | $ | (10.0) | | $ | 2.6 | |
| | |
| | |
Transportation and storage gross margin increased primarily due to the following:
•an increase in firm transportation and storage services due to new intrastate and interstate transportation contracts, partially offset by lower revenue due to the reduction of contracted interstate storage capacity; and
•an increase in system management activities; partially offset by
•a decrease in revenues from NGLs sales less the cost of NGLs due to a decrease in average NGLs prices and lower volumes;
•a decrease in natural gas storage inventory due to additional lower of cost or net realizable value adjustments;
•a decrease in volume-dependent transportation revenues due to a decrease in off-system intrastate transportation offset by new off-system interstate transportation contracts; and
•a decrease in realized gains on natural gas derivatives.
Income tax expense decreased $16.4 million, or 44.2 percent, primarily due to lower pretax income combined with federal and state deferred tax adjustments related to the Company's investment in Enable.power delivery projects at OG&E.
Off-Balance Sheet Arrangement
OG&E Railcar Lease Agreement
As of December 31, 2019, OG&E has a noncancellable operating lease with a purchase option, covering 780 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 fuel adjustment clauses. At the end of the lease term, which is February 1, 2024, 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 $6.8 million.
Liquidity and Capital Resources
Cash Flows
| | | | | | | | | | | | | | | | | |
| | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | | $
Change | %
Change | | |
| Net cash provided from operating activities (A) | $ | 681.5 | | $ | 951.1 | | | $ | (269.6) | | (28.3) | % | | |
| Net cash used in investing activities (B) | $ | (624.7) | | $ | (576.0) | | | $ | (48.7) | | 8.5 | % | | |
| Net cash used in financing activities (C) | $ | (151.1) | | $ | (295.2) | | | $ | 144.1 | | (48.8) | % | | |
(A)DecreasedChanged primarily due to decreased amounts receivedproceeds from customers at OG&E and an increase in vendor payments.
(B)Increased primarily due to the acquisitionlong-term debt reflective of the River Valleydebt issuance in May 2021 and Frontier power plants.
(C)Decreased primarily due to an increase indecreased short-term debt, partially offset bywhich was used to provide additional liquidity for the issuance of less long-term debtfuel and purchased power costs incurred by OG&E related to Winter Storm Uri in 2019.2021.
Working Capital
Working capital is defined as the difference in current assets and current liabilities. The Company'sOGE Energy'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 OG&E's customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries. The following discussion addresses changes in OGE Energy's working capital balances at December 31, 20192022 compared to December 31, 2018.
30
Cash and Cash Equivalents decreased $94.3increased $88.1 million, or 100.0 percent, primarily due to normal business operations includingproceeds received from OGE Energy's sales of Energy Transfer limited partner units and OG&E's receipt of securitization funds from the fundingODFA, which OGE Energy intends to utilize to help fund the repayment of capital expenditures.
the senior notes due in May 2023.
Accounts Receivable and Accrued Unbilled Revenues decreased $18.8increased $97.0 million, or 7.942.7 percent, primarily due to mutual assistance paymentsan increase in billings to OG&E's retail customers reflecting higher usage and new rates as approved in the Oklahoma general rate review order received in 2019 and a decrease in customer billings.
September 2022, as well as increased fuel prices.
Fuel Inventories decreased $11.3Income Taxes Receivable increased $18.1 million, or 19.6 percent, primarily due to decreasedthe timing of cash payments to tax authorities.
Fuel Inventories increased $68.2 million, primarily due to higher prices and volumes of coal inventory related to the Dry Scrubber systems on Sooner Units 1 and 2 being placed into service and decreased gas inventory.
Materials and Supplies, at Average Cost decreased $36.1increased $62.6 million, or 28.553.1 percent, primarily due to decreasedincreased inventory related to long-term service agreements.
which is partly a result of the ongoing supply chain and inflation impacts of the current economic environment.
Fuel Clause Under Recoveries increased $37.5$363.0 million, primarily due to lower recoveries from OG&E Oklahoma retail customers as compared to the actual cost of fuel and purchased power.
OG&E has implemented updated fuel factors to address recovery of the fuel under recovery balance, as further discussed in Note 14 within "Item 8. Financial Statements and Supplementary Data."
Other Current Assets decreased $5.1increased $30.2 million, or 17.341.2 percent, primarily due to an increase in SPP deposits, partially offset by a decrease in under-recovered riders, partially offset by transportation and demand prepayments.
under recovered riders.
Short-term Debt increased $112.0decreased $486.9 million, or 100.0 percent, primarily due to normal business operations including the fundingrepayment of capital expenditures. The Companyshort-term borrowings used for general operating needs. OGE Energy borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements and term credit agreements.
Accounts Payable decreased $44.4increased $174.9 million, or 18.663.8 percent, primarily due to the timing of vendor payments.
Accrued Interest decreased $6.6 million, or 14.8 percent, primarily due to the payment of the OG&E $250.0 million senior notes due January 15, 2019 and related interest, as well as timing of payments and accruals.
Accrued Compensation decreased $7.2 million, or 15.1 percent, primarily due to 2018 incentive compensation payouts that occurred in the first quarter of 2019, partially offset by 2019 accruals.
Long-termLong-Term Debt Due Within One Year decreased $250.0increased $999.9 million, or 100.0 percent, due to the paymentreclassification of the OG&E $250.0 million senior notes due January 15, 2019.
long-term debt that will mature in May 2023.
Fuel Clause Over Recoveries increased $4.5 million, primarily due to higher recoveries from OG&E Arkansas retail customers as compared to the actual cost of fuel and purchased power.
Other Current Liabilities decreased $21.8increased $15.5 million, or 25.145.5 percent, primarily due to an increase in SPP projected payables as well as changes in amounts owed to customers. Included in the December 31, 2019 balance is SPP reserves of $18.9 million and reserves for tax refund and interim surcharge of $12.7 million.
20192022 Capital Requirements, Sources of Financing and Financing Activities
Total
OGE Energy's total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $885.6$1,051.0 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $12.0$0.5 million, resulting in total net capital requirements and contractual obligations of $897.6$1,051.5 million in 2019, of which $20.9 million was to comply with environmental regulations.2022. This compares to net capital requirements of $823.7$778.6 million and net contractual obligations of $76.4$1.0 million totaling $900.1$779.6 million in 2018, of which $139.8 million was to comply with environmental regulations.
2021.
In 2019, the Company's2022, OGE Energy's primary sources of capital were cash generated from operations, proceeds from the issuance of long- and short-term debt, sales of Energy Transfer's limited partner units and distributions received from Enable.Energy Transfer. Changes in working capital reflect the seasonal nature of the Company'sOGE Energy's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.
The Dodd-Frank Act
Derivative instruments have been used at times in managing OG&E's commodity price exposure. The Dodd-Frank Act, among other things, provides for regulation by the Commodity Futures Trading Commission of certain commodity-related contracts. Although OG&E qualifies for an end-user exception from mandatory clearing of commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and could add additional regulatory oversight over its contracting activities.
Future CapitalMaterial Cash Requirements
The Company'sOGE Energy's primary, needs for capitalmaterial cash requirements 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 CompanyFurther, working capital requirements can be seasonal. OGE Energy 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.
31
The Company's consolidatedfollowing table presents OGE Energy's estimates of capital expenditures for the years 20202023 through 2024 are shown in the following table.2027. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expendituresinvestments are customer-focused and targeted to maintain and operateimprove the Company's businesses) plus capital expenditures for knownsafety, resiliency and committed projects. reliability of OG&E's distribution and transmission grid and generation fleet, enhance the ability of OG&E's system to perform during extreme weather events and to serve OG&E's growing customer base.
| | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | 2027 | | | Total | |
Transmission | | $ | 125 | | | $ | 145 | | | $ | 160 | | | $ | 160 | | | $ | 160 | | | $ | 750 | |
Oklahoma distribution & grid advancement | | | 490 | | | | 490 | | | | 550 | | | | 550 | | | | 550 | | | | 2,630 | |
Arkansas distribution | | | 20 | | | | 20 | | | | 20 | | | | 20 | | | | 20 | | | | 100 | |
Generation | | | 115 | | | | 115 | | | | 120 | | | | 120 | | | | 120 | | | | 590 | |
Other (A) | | | 200 | | | | 180 | | | | 100 | | | | 100 | | | | 100 | | | | 680 | |
Total | | $ | 950 | | | $ | 950 | | | $ | 950 | | | $ | 950 | | | $ | 950 | | | $ | 4,750 | |
(A)Estimated capital expenditures for Enableassociated with OG&E's enterprise resource planning system project are not included in the table below.2023 and 2024.
| | | | | | | | | | | | | | | | | | | | |
| (In millions) | 2020 | 2021 | 2022 | 2023 | 2024 | Total |
| Transmission | $ | 45 | | $ | 40 | | $ | 35 | | $ | 35 | | $ | 35 | | $ | 190 | |
| Oklahoma distribution | 215 | | 225 | | 225 | | 225 | | 225 | | 1,115 | |
| Arkansas distribution | 30 | | 15 | | 15 | | 15 | | 15 | | 90 | |
| Generation | 135 | | 60 | | 60 | | 90 | | 60 | | 405 | |
| Reliability, resiliency, technology and other | 90 | | 335 | | 335 | | 335 | | 335 | | 1,430 | |
| Other | 60 | | 50 | | 60 | | 55 | | 55 | | 280 | |
| Total | $ | 575 | | $ | 725 | | $ | 730 | | $ | 755 | | $ | 725 | | $ | 3,510 | |
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.
requirements of OG&E's power supply, transmission and distribution operational teams and the expected resultant customer benefits. The investments above do not include amounts related to new generation capacity needs as outlined in OG&E's October 2021 IRP and recent changes to the SPP's planning reserve margin and resource capacity accreditation. OG&E intends to file for approval of the generation capacity investments and would expect to update its capital plan based on a final order. The annual level of investments in the transmission and distribution system could vary depending on the amount and timing of incremental generation capacity investments. Supply chain disruption may increase the risk of delays in construction activities and equipment deliveries related to OGE Energy's capital projects.
The following table summarizespresents OGE Energy's total contractual obligations for the Company's contractual obligationsnext five years at December 31, 2019. See2022. For further detail of OGE Energy's contractual obligations, which include operating leases, long-term debt and purchase obligations and commitments (including information for maturities beyond the Company's Consolidated Statements of Capitalization andnext five years), see Notes 4, 9 and 1513, respectively, within "Item 8. Financial Statements and Supplementary Data" for additional information.
| | | | | | | | | | | | | | | | | |
| (In millions) | 2020 | 2021-2022 | 2023-2024 | After 2024 | Total |
| Maturities of long-term debt | $ | — | | $ | — | | $ | — | | $ | 3,229.9 | | $ | 3,229.9 | |
| Operating lease obligations: | | | | | |
| Railcars | 2.4 | | 4.6 | | 2.4 | | — | | 9.4 | |
| Wind farm land leases | 2.9 | | 5.8 | | 5.9 | | 34.7 | | 49.3 | |
| Office space lease | 0.9 | | 0.6 | | — | | — | | 1.5 | |
| Total operating lease obligations | 6.2 | | 11.0 | | 8.3 | | 34.7 | | 60.2 | |
| Purchase obligations and commitments: | | | | | |
| Minimum purchase commitments | 82.6 | | 105.5 | | 83.3 | | 332.0 | | 603.4 | |
| Expected wind purchase commitments | 55.7 | | 112.4 | | 114.3 | | 379.8 | | 662.2 | |
| Long-term service agreement commitments | 2.4 | | 4.8 | | 45.9 | | 111.1 | | 164.2 | |
| | | | | |
| Environmental compliance plan expenditures | 0.4 | | — | | — | | — | | 0.4 | |
| Total purchase obligations and commitments | 141.1 | | 222.7 | | 243.5 | | 822.9 | | 1,430.2 | |
| Total contractual obligations | 147.3 | | 233.7 | | 251.8 | | 4,087.5 | | 4,720.3 | |
| Amounts recoverable through fuel adjustment clause (A) | (140.7) | | (222.5) | | (200.0) | | (711.8) | | (1,275.0) | |
| Total contractual obligations, net | $ | 6.6 | | $ | 11.2 | | $ | 51.8 | | $ | 3,375.7 | | $ | 3,445.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | 2027 | | | Total | |
Total contractual obligations | | $ | 1,174.4 | | | $ | 167.0 | | | $ | 259.0 | | | $ | 102.0 | | | $ | 290.1 | | | $ | 1,992.5 | |
Amounts recoverable through fuel adjustment clause (A) | | | (168.8 | ) | | | (149.5 | ) | | | (123.8 | ) | | | (81.9 | ) | | | (82.3 | ) | | | (606.3 | ) |
Total contractual obligations, net | | $ | 1,005.6 | | | $ | 17.5 | | | $ | 135.2 | | | $ | 20.1 | | | $ | 207.8 | | | $ | 1,386.2 | |
(A)Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.
The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above)in Note 4 within "Item 8. Financial Statements and Supplementary Data") and certain purchased power costs are passed on 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 abovein Notes 4 and 13, respectively, within "Item 8. Financial Statements and Supplementary Data" may increase capital requirements, such costs are generally 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.
Otherwise, as discussed above, OGE Energy expects to meet these cash requirement needs through cash generated from operations, short-term borrowings and permanent financings.
Pension and Postretirement Benefit Plans
At December 31, 2019, 35.82022, 24.5 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income and other securities, and U.S. Treasury notes and bonds and mutual funds as presented in Note 1311 within "Item 8. Financial Statements and Supplementary Data." During 2019,2022, the actual returnsreturn on the Pension Plan were $85.2was a loss of $82.2 million, compared to an expected return on plan assets of $36.1$25.4 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 and $15.0 millionOGE Energy did not make any contribution to its Pension Plan in 20192022 and 2018, respectively. The Company hasmade a contribution of $40.0 million in 2021. OGE Energy does not determined whetherexpect it will need to make any contributions to the Pension Plan in 2020. The Company2023. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.
The following table presents the status of the Company'sOGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 20192022 and 2018.2021. 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 within "Item 8. Financial Statements and Supplementary Data") in the Company's Consolidated Balance Sheets.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 Statementsstatements of Incomeincome in future periods.
| | | | | | | | | | | | | | | | | | | | |
| Pension Plan | | Restoration of Retirement
Income Plan | | Postretirement
Benefit Plans | |
December 31 (In millions) | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 |
| Benefit obligations | $ | 616.1 | | $ | 615.9 | | $ | 10.3 | | $ | 9.6 | | $ | 136.5 | | $ | 135.8 | |
| Fair value of plan assets | 530.3 | | 522.8 | | — | | — | | 47.0 | | 45.3 | |
| Funded status at end of year | $ | (85.8) | | $ | (93.1) | | $ | (10.3) | | $ | (9.6) | | $ | (89.5) | | $ | (90.5) | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plan | | | Restoration of Retirement
Income Plan | | | Postretirement
Benefit Plans | |
December 31 (In millions) | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
Benefit obligations | | $ | 358.5 | | | $ | 502.9 | | | $ | 5.8 | | | $ | 5.9 | | | $ | 101.9 | | | $ | 137.3 | |
Fair value of plan assets | | | 293.0 | | | | 486.0 | | | | — | | | | — | | | | 32.8 | | | | 44.3 | |
Funded status at end of year | | $ | (65.5 | ) | | $ | (16.9 | ) | | $ | (5.8 | ) | | $ | (5.9 | ) | | $ | (69.1 | ) | | $ | (93.0 | ) |
The Company's
OGE Energy'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. AtPrior to the Company's September 2019 board meeting,approval of a change in the dividend in 2022, the Board of Directors approved management'sreviewed a recommendation from management of a six percentan increase in the quarterly dividend rate to $0.3875$0.4141 per share from $0.3650$0.41 per share and subsequently approved the recommendation to become effective with the dividend payment in October 2019.
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'sOGE Energy'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 CompanyOGE Energy 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.
In January 2023, OG&E issued $450.0 million of Senior Notes due January 15, 2033, as further discussed within "Long-Term Debt" below.
Short-Term Debt and Credit Facilities
The Company
OGE Energy borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. The Companyagreements and term credit agreements maturing in one year or less.
OGE Energy has unsecured five-year revolving credit facilities totaling $900.0 million$1.1 billion ($450.0550.0 million for the CompanyOGE Energy and $450.0$550.0 million for OG&E) that mature on March 8, 2023. These bank facilities, which can also be used as letter of credit facilities. As further discussed below, in May 2022, OGE Energy entered into a $100.0 million floating rate unsecured three-year credit agreement, of which $50.0 million is considered a revolving loan. The following tables highlight the Company'stable presents information about OGE Energy's revolving credit agreements as of December 31, 2022.
| | | | |
(Dollars in millions) | | December 31, 2022 | |
Balance of outstanding supporting letters of credit | | $ | 0.4 | |
Weighted-average interest rate of outstanding supporting letters of credit | | | 1.15 | % |
Net available liquidity under revolving credit agreements, commercial paper borrowings and letters of credit | | $ | 1,149.6 | |
Balance of cash and cash equivalents | | $ | 89.3 | |
The following table presents information about OGE Energy's total short-term debt activity as of and for the year ended December 31, 2019.
| | | | | |
(Dollars in millions)
| December 31, 2019 |
Balance of outstanding supporting letters of credit | $ | 0.3 | |
Weighted-average interest rate of outstanding supporting letters of credit | 1.00 | % |
Net available liquidity under revolving credit agreements | $ | 787.7 | |
Balance of cash and cash equivalents | $ | — | |
| |
(Dollars in millions)
| Year Ended December 31, 2019 |
Average balance of short-term debt | $ | 233.6 | |
Weighted-average interest rate of average balance of short-term debt | 2.62 | % |
Maximum month-end balance of short-term debt | $ | 479.7 | |
2022. | | | | |
(Dollars in millions) | | Year Ended December 31, 2022 | |
Average balance of short-term debt | | $ | 337.3 | |
Weighted-average interest rate of average balance of short-term debt | | | 0.97 | % |
Maximum month-end balance of short-term debt | | $ | 731.5 | |
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$1.0 billion in short-term borrowings at any one time for a two-year period beginning January 1, 20192023 and ending December 31, 2020. See Note 12 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the Company's short-term debt activity.
Issuance of
Long-Term Debt
In June 2019,May 2022, OGE Energy entered into a $100.0 million floating rate unsecured three-year credit agreement, of which $50.0 million is considered a revolving loan and $50.0 million is considered a term loan, and borrowed the full $50.0 million term loan, in order to preserve general financial flexibility within the company. Advances under this agreement were used to refinance existing indebtedness and for working capital and general corporate purposes of OGE Energy. The credit agreement, under certain circumstances, may be increased to a maximum commitment limit of $135.0 million and contains substantially the same covenants as OGE Energy's existing $550.0 million revolving credit agreement. The credit agreement is scheduled to terminate on May 24, 2025. At December 31, 2022, the weighted-average interest rate for the amount drawn on the term loan under this credit agreement was 3.48 percent.
In January 2023, OG&E issued $300.0$450.0 million of 3.30 percent senior notes5.40% Senior Notes due MarchJanuary 15, 2030.2033. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to repay short-termhelp fund the repayment of its $500.0 million 0.553% Senior Notes, Series due May 26, 2023 and the funding of its capital investment program and working capital needs.
OG&E expects to issue up to $400.0 million of long-term debt (including debt pertainingto support its current year capital investment plan and for the repayment of maturing debt.
Securitization of Oklahoma Winter Storm Uri Extreme Purchase Costs
As further discussed in Note 14 within "Item 8. Financial Statements and Supplementary Data," on July 20, 2022, the ODFA issued securitization bonds, and OG&E received proceeds of approximately $750 million for the sale of securitization property to the acquisition of the River Valley plant) andODFA. OG&E used these proceeds to fund ongoing capital expendituresthe Oklahoma Winter Storm Uri regulatory asset by recovering the authorized extreme, extraordinary fuel and working capital.
purchased power costs incurred during Winter Storm Uri, as well as carrying costs.
| | | | | | | | | | | | | | | | | | | | |
| Moody's Investors Service | Outlook
| S&P's Global Ratings | Outlook
| Fitch Ratings | Outlook |
| Rating | Outlook |
| Rating | Outlook |
| Rating | Outlook |
OG&E Senior Notes | A3 | Stable |
| A- | Stable |
| A | Stable |
OG&E Commercial Paper | P2 | Stable |
| A2 | Stable |
| F2 | Stable |
OGE Energy Senior Notes | Baa1 | Stable |
| BBB | Stable |
| BBB+ | Stable | BBB+ | Stable |
OGE Energy Commercial Paper | P2 | Stable |
| A2 | Stable |
| F2 | Stable |
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'sOGE Energy'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'sOGE Energy's short-term borrowings, but a reduction in the Company'sOGE Energy'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 CompanyOGE Energy 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 May 31, 2019, Moody's Investors Service lowered its rating for OG&E's senior unsecured and issuer ratings from A2 to A3 and commercial paper rating from P-1 to P-2. OG&E's industrial authority bond rating was lowered from VMIG 1 to VMIG 2. The Company's senior unsecured and commercial paper ratings were not changed, and the outlooks for both the Company and OG&E are stable. Increased debt-financed capital spending on mandated environmental compliance projects combined with lagging cash flow due to the 2017 Tax Act and recent Oklahoma rate reviews were cited as contributing factors
to OG&E's downgrades. Moody's Investors Service indicated that the stable outlook for both the Company and OG&E reflects a reduced capital plan, fewer rate review filings and a more predictable financial profile.
On October 25, 2019, S&P's Global Ratings raised its long-term issuer credit rating for OG&E from BBB+ to A- and raised its issue-level rating on OG&E's senior unsecured debt from BBB+ to A-. The S&P's Global Ratings commercial paper rating for OG&E was not changed, and the outlook for OG&E remains at stable. S&P's Global Ratings indicated the upgrade reflects its view of OG&E's separateness, insulation measures and stand-alone credit profile in accordance with their revised criteria. S&P's Global Ratings indicated the stable outlook on OG&E reflects their expectation that OG&E will continue to manage its regulatory risk in line with its peers and maintain financial measures consistent with S&P's Global Ratings' significant financial risk profile.
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.
The Company
OGE Energy does not expect to issue any common stock in 20202023 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 108 within "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company'sOGE Energy's common stock activity.
Pursuant to and Energy Transfer
During the Enable Limited Partnership Agreement, Enable madeyear ended December 31, 2022, OGE Energy received distributions of $144.0$34.0 million $141.2 million and $141.2 million to the Company duringfrom Energy Transfer. During the years ended December 31, 2019, 20182021 and 2017, respectively. 2020, OGE Energy received distributions of $73.4 million and $91.7 million, respectively, from Enable.
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Sale of Energy Transfer's Equity Securities
As requiredpreviously disclosed, OGE Energy intended to become primarily an electric company by Enable's Limited Partnership Agreement and General Partner Agreement, respectively,exiting its investment in Energy Transfer's equity securities. As of the last permitted distribution date is 60 days after the closeend of each quarter, and the distribution deadline is five days following distributions by Enable.
Funding of Benefit Plans
The Company expects to purchase an immaterial amount of sharesSeptember 2022, OGE Energy had sold all of its common stock on95.4 million Energy Transfer limited partner units, resulting in pre-tax net proceeds of $1,067.2 million. OGE Energy intends to use these proceeds to help repay the open market from time to time commencing during the first quarter of 2020 through the first quarter of 2022. These shares will be used to satisfy the Company's obligation to deliver shares of common stock$1.0 billion in connection with certain incentive compensation awards.
senior notes due in May 2023 and for general corporate purposes.
Critical Accounting Policies and Estimates
The Consolidated Financial Statementsfinancial statements and Notes to Consolidated Financial Statementsnotes thereto contain information that is pertinent to Management's Discussionmanagement's discussion and Analysis.analysis. In preparing the Consolidated Financial Statements,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 Statementsfinancial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Company's Consolidated Financial Statements.Registrants' financial statements. However, the Company believes it hasRegistrants believe they have taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the CompanyRegistrants 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 for all Company segments include the determination of Pension Planpension and postretirement 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, unbilled revenues and unbilled revenues.the allowance for uncollectible accounts receivable. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Audit Committee of the Company'sOGE Energy's Board of Directors. The Company discusses itsRegistrants discuss their significant accounting policies, including those that do not require management to make difficult, subjective or complex judgments or estimates, in Note 1 within "Item 8. Financial Statements and Supplementary Data."
Pension and Postretirement Benefit Plans
The CompanyPlan Assumptions
OGE Energy has a Pension Plan that covers a significant amount of the Company'scertain employees, including OG&E's employees, hired before December 1, 2009. Effective December 1, 2009, the Company'sOGE Energy's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. The CompanyOGE Energy also has defined benefit postretirement plans that cover a significant amount of itscertain employees, including OG&E's 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 1311 within "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 indicatespresents the sensitivity of the Pension Plan funded status to these variables.
| | | | | | | | |
|
| Change |
| Impact on Funded Status |
Actual plan asset returns |
| +/- 1 percent | | +/- $5.3$2.9 million |
Discount rate |
| +/- 0.25 percent | | +/- $12.3$5.6 million | |
Contributions |
| +/- $10 million | | +/- $10.0 million | |
The Company usesRegistrants use 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
35
judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts the CompanyRegistrants recognized in its consolidatedtheir financial statements. Tax positions taken by the CompanyRegistrants on itstheir 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.
Contingency Reserves
In the normal course of business, the Registrants are 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 Registrants have 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 financial statements.
Asset Retirement Obligations
The Company
OG&E has recorded asset retirement obligations that are being accreted over their respective lives ranging from tenfive to 68 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 freerisk-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. Management continuously monitors the future recoverability of regulatory assets. When in management's judgement future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate.
OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E readsmeasures its customers' metersmetered usage 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 in the Consolidated Balance Sheetsbalance sheets and in Operating Revenues from Contracts with Customers in the Consolidated Statementsstatements of Incomeincome 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. At December 31, 2019,2022 and 2021, Accrued Unbilled Revenues were $74.2 million and $65.0 million, respectively.
At December 31, 2022, 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 $0.4 million. At December 31, 2019 and 2018, Accrued Unbilled Revenues were $64.7 million and $62.6 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 generally 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.off and is adjusted for current conditions and supportable forecasts as necessary. To the extent the historical collection rates, when incorporating forecasted conditions, 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 in the balance sheets and is included in Other Operation and Maintenance Expense in the statements of income. The allowance for uncollectible accounts receivable was $1.9 million and $2.4 million at December 31, 2022 and 2021, respectively.
36
At December 31, 2019,2022, 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$0.2 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense in the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.7 million at December 31, 2019 and 2018, respectively.
Accounting Pronouncements
See Note 2 within "Item 8. Financial Statements and Supplementary Data" for further discussion of currentrecently adopted accounting pronouncementsstandards and recently issued accounting standards that are applicable tonot yet effective that could have a material impact on the Company.
Registrants' financial position, results of operations or cash flows upon adoption.
Commitments and Contingencies
In the normal course of business, the Company isRegistrants are 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 hasRegistrants have 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.financial statements. At the present time, based on currently available information, the Company believesRegistrants believe 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 itstheir financial statements and would not have a material adverse effect on the Company's consolidatedtheir financial position, results of operations or cash flows. See Notes 1513 and 1614 within "Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" for afurther discussion of the Company'sRegistrants' commitments and contingencies.
Environmental Laws and Regulations
The activities of the CompanyOG&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 the Company'sRegistrants' 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 or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of itsthe Registrants' operations are in substantial compliance with current federal, state and local environmental standards.
President Biden's Administration has taken a number of actions that adopt policies and affect environmental regulations, including issuance of executive orders that instruct the EPA and other executive agencies to review certain rules that affect OG&E with a view to achieving nationwide reductions in greenhouse gas emissions. OG&E is monitoring these actions which are in various stages of being implemented. At this point in time, the impacts of these actions on the Registrants' results of operations, if any, cannot be determined with any certainty.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
Federal Clean Air Act Overview
OG&E's operations are subject to the Federal Clean Air Act of 1970, 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.
Cross-State Air Pollution Rule
On September 7, 2016, the EPA finalized an update to the 2011 Cross-State Air Pollution Rule. The new rule applies to ozone-season NOX emissions from power plants in 22 eastern states (including Oklahoma). The rule utilizes a cap and trade program for NOX
emissions and went into effect on May 1, 2017 in Oklahoma. The 2016 rule reduces the 2011 Cross-State Air Pollution Rule emissions cap for all of OG&E's coal and gas facilities (except the River Valley and Frontier facilities which were not owned by OG&E until 2019) by 47 percent combined. OG&E and numerous other parties filed petitions for judicial and administrative review of the 2016 rule. On September 13, 2019, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion that deferred a decision on our challenges to the rule pending an EPA review and decision on a separate administrative petition that we filed. Subsequently, all of OG&E's judicial challenges were voluntarily dismissed, but the administrative petitions for reconsideration remain pending at the EPA.
OG&E is in complianceworking cooperatively with federal and state environmental agencies to create emission limits for OG&E's operations that are consistent with legal requirements for protecting health and the 2016 rule requirements which remain in effect. The Companyenvironment while being cost effective for OG&E to implement. Although various court proceedings are pending that challenge the validity or stringency of rules issued by federal and state environmental agencies, OG&E is not currently a party to any of these proceedings. At this time, OG&E does not anticipate at this time, additional material capital expenditures for compliance with the 2016 rule.
HazardousThe EPA revised the NAAQS for ozone in 2015. Although Oklahoma complies with the revised standard, the Federal Clean Air Pollutants Emission Standards
Act of 1970, as amended, requires states to submit to the EPA for approval a SIP to prohibit in-state sources from contributing
37
significantly to nonattainment of the NAAQS in another state. On February 16, 2012,October 28, 2018, Oklahoma submitted its SIP to the EPA related to these "Good Neighbor" requirements. On January 31, 2023, the EPA disapproved the SIPs of 19 states, including Oklahoma. In response to litigation, on April 6, 2022, the EPA also published a proposed FIP related to the "Good Neighbor" requirements intended to reduce interstate NOx emissions contributions. The proposed FIP, which includes Oklahoma among 24 other states, proposes to limit the current Oklahoma NOx emissions budgets over four years for certain generating units including OG&E's units beginning in 2023. It is anticipated the EPA will finalize the FIP by mid-March of 2023. OG&E filed comments to the proposed FIP with the EPA on June 21, 2022. OG&E is closely monitoring these issues; however, it is unknown at this time what, if any, potential material impacts will result from the EPA actions.
On January 27, 2023, the EPA published a proposed rule in the Federal Register to reconsider the primary (health-based) and secondary (welfare-based) NAAQS for Particulate Matter ("PM NAAQS"). The EPA is proposing to lower the primary annual PM2.5 to a level ranging from approximately 17 percent to 25 percent below the current standard and is proposing to retain the other PM NAAQS at their current levels. Particulate matter ("PM") is not a single pollutant but rather is a mixture of chemicals, solids and aerosols composed of small droplets of liquid, dry solid fragments and solid cores with liquid coatings. PM varies widely in size, shape and chemical composition and is defined by diameter for air quality regulatory purposes: PM10 and PM2.5. The EPA expects to issue a final MATSdecision on the PM standards in 2024. The EPA will determine which areas of the country meet the standards, such as making initial attainment/nonattainment designations, no later than two years after new standards are issued. States must develop and submit attainment plans no later than 18 months after the EPA finalizes nonattainment designations. This proposed rule regulating the emissions of certain hazardouscould impact regional air pollutants from electric generating units. The Company complied with the MATS rule by the April 16, 2016 deadline that appliedquality goals and emission limits for emission sources; however, it is unknown at this time what, if any, potential material impacts to OG&E by installing activated carbon injectionindividual operating permit emission limits will result from the EPA actions.
In July 2020, the ODEQ notified OG&E that the Horseshoe Lake generating units would be included in Oklahoma's second Regional Haze implementation period evaluation of visibility impairment impacts to the Wichita Mountains. OG&E submitted an analysis of all potential control measures for all coalNOx on these units (not includingto the River Valley facility which was not ownedODEQ. The ODEQ submitted a revised SIP to the EPA on August 12, 2022. It is unknown at this time what the outcome, or any potential material impacts, if any, will be from the evaluations by OG&E, until 2019). There is continuing litigation, to which the Company is not a party, challenging whetherODEQ and the EPA had statutory authority to issue the MATS rule. On December 27, 2018, the EPA released a proposed rule reconsidering certain elements of the 2012 ruleEPA.
OG&E monitors possible changes in response to lengthy litigation in the D.C. Circuit Court. The Company cannot predict the outcome of this litigation or regulatory proposal or how it will affect the Company.
National Ambient Air Quality Standards
The EPA is required to set NAAQSlegal standards 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 December 31, 2019, 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 indicated compliance with the NAAQS. The proposed designation was based on modeling that did not reflect the conversion of two of the coal units at Muskogee to natural gas. The State of Oklahoma's monitoring preliminarily indicates that ambient SO2 emissions in the area are well within the NAAQS. The EPA has indicated that it anticipates finalizing a designation at the end of 2020. At this time, the Company cannot determine with any certainty whether the proposed designation of Muskogee County will cause a material impact to the Company's financial results.
The Company continues to monitor these 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.
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 contributingincluding President Biden Administration's target of a 50 to the warming of the earth's atmosphere. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced52 percent reduction in 2017 that the U.S. would 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 foreconomy-wide net greenhouse gas emissions will be infrom 2005 levels by 2030 with full decarbonization of the futureelectric power industry by 2035 and the extentSeptember 2022 EPA non-rulemaking docket for public input related to which these commitments will be implemented through the EPA's efforts to reduce emissions of greenhouse gases from new and existing fossil fuel-fired electric generating units under Clean Air Act or any other existing statutes and new legislation.
Section 111. 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'sat OG&E's facilities, this could result in significant additional compliance costs that would affect the Company'sOG&E's future consolidated 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.
OG&E's current business strategy&E has resulted in reduced carbon dioxide emissions by over 40 percent compared to 2005 levels, and during the same period, emissions of ozone-forming NOx have been reduced by approximately 7580 percent and emissions of SO2 have been reduced by approximately 90 percent. OG&E expects to further reduce carbon dioxide emissions to 50 percent of 2005 levels by 2030. To comply with the EPA's MATS rule and Regional Haze Rule FIP,EPA rules, OG&E converted 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.
In October 2021, OG&E's service territory borders one&E issued its most recent IRP to the OCC and APSC that proposes to expand its renewable generation fleet, including the development of the nation's best wind resource areas, andadditional solar resources. OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has authorized 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.
On July 8, 2019, the EPA published the Affordable Clean Energy rule. Numerous parties, not including OG&E, have filed petitions for judicial review of the Affordable Clean Energy rule in the U.S. Court of Appeals for the District of Columbia Circuit. The Affordable Clean Energy rule requires states, including Oklahoma, to develop emission limitations for carbon dioxide for each existing coal-fired utility boiler within the state, including all of OG&E's coal units, and submit a compliance and implementation plan to the EPA by July 2022. The EPA will approve or disapprove the proposed state plan within 18 months of submittal and develop a federal implementation plan if the proposed state plan is disapproved. At this time, the Company cannot determine with any certainty whether the implementation plan will cause a material impact to its financial results.
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 and applications remain pending for other 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.
Regional Haze Regulation - Second Planning Period
In January 2017, the EPA finalized a rule that would revise certain provisions of the Regional Haze Rule. Notably, the EPA extended the due date for the second Regional Haze implementation period by three years to 2021 and made changes to the provisions for impacts to national parks and other protected wilderness areas. Petitions for Reconsideration to the EPA were filed by industry groups. While not acting on the petitions, the EPA announced on January 17, 2018 that it intends to commence a notice-and-comment rulemaking revisiting certain aspects of the rule. During 2019, the EPA released technical resources to assist states in developing SIPs, including a significant non-binding guidance document and updated atmospheric modeling which will allow states to better account for international emissions affecting regional haze in the U.S. At this time, the Company cannot predict the outcome of this rulemaking or SIP development or how it will affect the Company.
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 CompanyOG&E conducts operations, or if additional species in those areas become subject to protection, the Company'sOG&E's operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the CompanyOG&E could be required to implement expensive mitigation measures.
On November 9, 2021, the USFWS published a proposed rule to list the Alligator Snapping Turtle as threatened under the Endangered Species Act, along with a 4(d) rule that would provide conservation of the species. The habitat located within the OG&E service territory is limited to eastern Oklahoma and western Arkansas; however, the USFWS is proposing to exempt incidental take by industry for operation and maintenance and other routine activities that are conducted by using best management practices that reduce incidental take and conserve the habitat. The final rule for the listing decision was expected to occur in November 2022.
On September 14, 2022, the USFWS published a proposal to list the Tricolored Bat as endangered under the Endangered Species Act. According to the proposal, the current known range of the Tricolored Bat extends to 36 states, including Oklahoma and Arkansas.
On September 30, 2022, the USFWS proposed a voluntary permitting rule that would cover incidental take of bald and golden eagles from allowed activities by instituting voluntary mitigation actions. Some of the voluntary actions include retrofitting 11 non-electrocution-safe poles or 1/2 mile of non-electrocution-safe circuit to electrocution-safe as a result of eagle take or injury, retrofitting 10 percent of non-electrocution-safe infrastructure to electrocution-safe within the five-year term of the permit and incorporating an eagle shooting response strategy to investigate shootings near power line infrastructure. It is unknown at this time whether the voluntary permitting program will become a requirement. OG&E currently maintains an avian protection plan to help mitigate eagle impacts and has adopted the best management practices of the Avian Power Line Interaction Committee, of which OG&E is a member.
OG&E is closely monitoring each of these issues due to possible future impacts; however, it is unknown at this time what, if any, material impacts will result from the USFWS action.
On November 25, 2022, the USFWS published a final rule to list two distinct population segments of the Lesser Prairie Chicken; the southern distinct population segment located in west Texas and eastern New Mexico is proposed as endangered status, and the northern distinct population located in northwest Texas, northwest Oklahoma, Kansas and Colorado is proposed to be listed as threatened status with a 4(d) rule which would prohibit take of the chicken, such as destroying its habitat by building a transmission line or substation, without a permit or special authorization from the USFWS. At this time, OG&E expects this rule will not impact any current OG&E infrastructure and should allow for construction in areas that are considered previously disturbed.
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.
In 2015, 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 rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. In August 2019, the EPA proposed revisions to the 2015 coal ash rule in response to the D.C. Circuit Court of Appeals issuing a decision regarding the ongoing Coal Combustion Residuals litigation. The proposed changes do not appear to be material to OG&E at this time. OG&E completed the clean closure of one regulated inactive coal ash impoundment in August 2019.
On June 28, 2018, the EPA approved the State of Oklahoma's application for a state coal ash permitting program that will operate in lieuDuring 2022, approximately 95 percent of the federal coal ash program promulgated under the Federal Resource Conservationfrom OG&E's River Valley, Muskogee and Recovery Act. On September 26, 2018, a citizen suitSooner facilities was filed against the EPArecovered and reused in the U.S. District Court in the District of Columbia concerning the final approval. OG&E and others have moved to intervene on behalf of the EPA. The Company is monitoring regulatory developments relating to this rule, none of which appear to be material to OG&E at this time. OG&E is in compliance with this rule at this time.
The Company currently recycles and provides approximately 86 percent of its ash to the concretevarious ways, including soil stabilization, landfill cover, road base construction and cement industries for use as a component within their products. Usingand concrete production. Reusing fly ash in this way enables aggregate manufacturers to minimize their impact on the environment by avoidingreduces the need to extractmanufacture cement resulting in reductions in greenhouse gas emissions from cement and process other natural resources.
concrete production. Based on estimates from the American Coal Ash Association, OG&E fly ash reuse helped avoid over three million tons of CO
The Company emissions in the last 15 years.
OG&E has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2019, the Company2022, OG&E obtained refunds of $2.8$2.9 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.
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. The
Oklahoma Department of Environmental Quality issued final permits on December 22, 2017 and August 22, 2018 for Muskogee Power Plant and Seminole Power Plant, respectively, in compliance with the final 316(b) rule, and OG&E did not incur any material costs associated with the rule's implementation at either location. 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.
In 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 will occur by 2023; however, on April 12, 2017, the EPA granted a Petition for Reconsideration of the 2015 Rule. On
November 22, 2019,October 13, 2020, the EPA published a
proposedfinal rule to revise the technology-based effluent limitations for flue gas desulfurization waste water and bottom ash transport water.
On August 3, 2021, the EPA published notice in the Federal Register that it will undertake a supplemental rulemaking to revise the effluent limitation guidelines rule after completing its review of the October 2020 rule. The existing effluent limitation guidelines will remain in effect while the EPA undertakes this new rulemaking. OG&E is evaluating what, if any, compliance actions are needed but is not able to quantify with any certainty what
39
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 permitspermit requirements from the State of Oklahoma.
Since the purchase of the Redbud facility in 2008, OG&E made investments in the infrastructure that have led to OG&E's average use of approximately 2.5 billion gallons per year of treated municipal effluent for all of the needed cooling water at Redbud and McClain is approximately 2.6 billion gallons per year.McClain. This use of treated municipal effluent offsets the need for fresh water as cooling water, making fresh water available for other beneficial uses like drinking water, irrigation and recreation.
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 generates 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 further discussion regarding contingencies relating to environmental laws and regulations, see Note 1513 within "Item 8. Financial Statements and Supplementary Data."
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates and commodity prices. The Company'sRegistrants' exposure to changes in interest rates relates primarily to short-term variable-rate debt, commercial paper and commercial paper.future long-term debt issuances. The Company isRegistrants are exposed to commodity prices in its operations.
their operations to the extent any fuel price changes are not recovered in customer rates.
Risk Oversight Committee
Management monitorsThe Registrants manage market risks using a risk committee structure. The Company'sOGE Energy's Risk Oversight Committee, which consists primarily of the Chief Financial Officer, other corporate officers and members of management, is responsible for the overall development, implementation and enforcement of strategies and policies for all marketsignificant risk management activities of the Company. This committee's emphasis isRegistrants. In 2022, this committee and the Registrants' management applied a holistic perspective of risk measurementassessment and application of its strategies and policies targetingto manage the Company'sRegistrants' overall financial performance. OnThe Chief Financial Officer, acting in his role as the principal financial officer and as a quarterly basis,member of the Risk Oversight Committee, reports periodically to the Audit Committee of the Company'sOGE Energy's Board of Directors on the Company'sRegistrants' risk profile affecting anticipated financial results, including any significant risk issues.
The Company alsoAudit Committee updates the Board of Directors regarding the company's risk management practices and the steps management has a Corporate Risk Management Department. This group, in conjunction with the aforementioned committees, is responsible for establishingtaken to monitor and enforcing the Company's risk policies.
control applicable risks.
Risk Policies
Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of the Company'sOGE Energy's Board of Directors and senior executives of the CompanyRegistrants with confidence that the risks taken on by the Company'sRegistrants' business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to market risk management are being followed.
The Company'sRegistrants' exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. The Company manages itsRegistrants manage their interest rate exposure by monitoring and limiting the effects of market changes in interest rates. The CompanyRegistrants may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio, but the Company hasRegistrants have no intent at this time to utilize interest rate derivatives.
The fair value of the Company'sRegistrants' long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities or by calculating the net present value of the monthly payments discounted by the Company'sRegistrants' current borrowing rate. The following table showspresents the Company'sRegistrants' long-term debt maturities and the weighted-average interest rates by maturity date.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31 (Dollars in millions) | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | 12/31/19 Fair Value |
| Fixed-rate debt (A): | | | | | | | | |
| Principal amount | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | 3,094.5 | | $ | 3,094.5 | | $ | 3,510.4 | |
| Weighted-average interest rate | — | % | — | % | — | % | — | % | — | % | 4.60 | % | 4.60 | % | |
| Variable-rate debt (B): | | | | | | | | |
| Principal amount | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | 135.4 | | $ | 135.4 | | $ | 135.4 | |
| Weighted-average interest rate | — | % | — | % | — | % | — | % | — | % | 1.77 | % | 1.77 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Year Ended December 31
(Dollars in millions) | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | 2027 | | | Thereafter | | | Total | | | 12/31/22 Fair Value | |
OGE Energy (holding company) fixed-rate debt (A): | | | | | | | | | | | | | | | | | | | | | | | | |
Principal amount | | $ | 500.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 500.0 | | | $ | 491.2 | |
Weighted-average interest rate | | | 0.703 | % | | | — | % | | | — | % | | | — | % | | | — | % | | | — | % | | | 0.703 | % | | | |
OGE Energy (holding company) variable-rate debt (A): | | | | | | | | | | | | | | | | | | | | | | | | |
Principal amount | | $ | — | | | $ | — | | | $ | 50.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | 50.0 | | | $ | 50.0 | |
Weighted-average interest rate | | | — | % | | | — | % | | | 5.375 | % | | | — | % | | | — | % | | | — | % | | | 5.375 | % | | | |
OG&E fixed-rate debt (A): | | | | | | | | | | | | | | | | | | | | | | | | |
Principal amount | | $ | 500.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | 125.0 | | | $ | 3,269.3 | | | $ | 3,894.3 | | | $ | 3,484.4 | |
Weighted-average interest rate | | | 0.553 | % | | | — | % | | | — | % | | | — | % | | | 6.650 | % | | | 4.400 | % | | | 3.980 | % | | | |
OG&E variable-rate debt (B): | | | | | | | | | | | | | | | | | | | | | | | | |
Principal amount | | $ | — | | | $ | — | | | $ | 79.4 | | | $ | — | | | $ | 56.0 | | | $ | — | | | $ | 135.4 | | | $ | 135.4 | |
Weighted-average interest rate | | | — | % | | | — | % | | | 3.830 | % | | | — | % | | | 3.850 | % | | | — | % | | | 3.840 | % | | | |
(A)Prior to or when these debt obligations mature, the CompanyRegistrants may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.
(B)A hypothetical change of 100 basis points in the underlying variable interest rate incurred by the CompanyOG&E would change interest expense by $1.4 million annually.
41
Item 8. Financial Statements and Supplementary Data.
CONSOLIDATED STATEMENTS OF INCOME
| | | | | | | | | | | | |
Year Ended December 31 (In millions except per share data) | | 2022 | | | 2021 | | | 2020 | |
OPERATING REVENUES | | | | | | | | | |
Revenues from contracts with customers | | $ | 3,304.2 | | | $ | 3,588.7 | | | $ | 2,069.8 | |
Other revenues | | | 71.5 | | | | 65.0 | | | | 52.5 | |
Operating revenues | | | 3,375.7 | | | | 3,653.7 | | | | 2,122.3 | |
FUEL, PURCHASED POWER AND DIRECT TRANSMISSION EXPENSE | | | 1,662.4 | | | | 2,127.6 | | | | 644.6 | |
OPERATING EXPENSES | | | | | | | | | |
Other operation and maintenance | | | 501.4 | | | | 463.1 | | | | 462.8 | |
Depreciation and amortization | | | 460.9 | | | | 416.0 | | | | 391.3 | |
Taxes other than income | | | 101.5 | | | | 102.8 | | | | 101.4 | |
Operating expenses | | | 1,063.8 | | | | 981.9 | | | | 955.5 | |
OPERATING INCOME | | | 649.5 | | | | 544.2 | | | | 522.2 | |
OTHER INCOME (EXPENSE) | | | | | | | | | |
Gain (loss) on equity securities (Note 1) | | | 282.1 | | | | (8.6 | ) | | | — | |
Equity in earnings (losses) of unconsolidated affiliates | | | — | | | | 169.8 | | | | (668.0 | ) |
Allowance for equity funds used during construction | | | 6.9 | | | | 6.7 | | | | 4.8 | |
Other net periodic benefit expense | | | (12.9 | ) | | | (6.1 | ) | | | (3.9 | ) |
Other income | | | 74.6 | | | | 26.3 | | | | 37.5 | |
Gain on Enable/Energy Transfer transaction, net (Note 1) | | | — | | | | 344.4 | | | | — | |
Other expense | | | (44.6 | ) | | | (39.9 | ) | | | (35.2 | ) |
Net other income (expense) | | | 306.1 | | | | 492.6 | | | | (664.8 | ) |
INTEREST EXPENSE | | | | | | | | | |
Interest on long-term debt | | | 162.1 | | | | 154.8 | | | | 152.8 | |
Allowance for borrowed funds used during construction | | | (4.0 | ) | | | (3.5 | ) | | | (1.9 | ) |
Interest on short-term debt and other interest charges | | | 8.2 | | | | 7.0 | | | | 7.6 | |
Interest expense | | | 166.3 | | | | 158.3 | | | | 158.5 | |
INCOME (LOSS) BEFORE TAXES | | | 789.3 | | | | 878.5 | | | | (301.1 | ) |
INCOME TAX EXPENSE (BENEFIT) | | | 123.6 | | | | 141.2 | | | | (127.4 | ) |
NET INCOME (LOSS) | | $ | 665.7 | | | $ | 737.3 | | | $ | (173.7 | ) |
BASIC AVERAGE COMMON SHARES OUTSTANDING | | | 200.2 | | | | 200.1 | | | | 200.1 | |
DILUTED AVERAGE COMMON SHARES OUTSTANDING | | | 200.8 | | | | 200.3 | | | | 200.1 | |
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE | | $ | 3.33 | | | $ | 3.68 | | | $ | (0.87 | ) |
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE | | $ | 3.32 | | | $ | 3.68 | | | $ | (0.87 | ) |
| | | | | | | | | | | |
Year Ended December 31 (In millions except per share data) | 2019 | 2018 | 2017 |
| OPERATING REVENUES | | | |
| Revenues from contracts with customers | $ | 2,175.5 | | $ | 2,211.7 | | $ | — | |
| Other revenues | 56.1 | | 58.6 | | — | |
| Operating revenues | 2,231.6 | | 2,270.3 | | 2,261.1 | |
| | | |
| | | |
| | | |
| COST OF SALES | 786.9 | | 892.5 | | 897.6 | |
| | | |
| | | |
| | | |
| OPERATING EXPENSES | | | |
| Other operation and maintenance | 491.8 | | 474.6 | | 458.7 | |
| Depreciation and amortization | 355.0 | | 321.6 | | 283.5 | |
| | | |
| | | |
| Taxes other than income | 93.6 | | 92.0 | | 89.4 | |
| Operating expenses | 940.4 | | 888.2 | | 831.6 | |
| OPERATING INCOME | 504.3 | | 489.6 | | 531.9 | |
| OTHER INCOME (EXPENSE) | | | |
| Equity in earnings of unconsolidated affiliates | 113.9 | | 152.8 | | 131.2 | |
| Allowance for equity funds used during construction | 4.5 | | 23.8 | | 39.7 | |
| Other net periodic benefit expense | (9.8) | | (10.8) | | (21.6) | |
| Other income | 21.9 | | 21.7 | | 46.4 | |
| Other expense | (23.5) | | (23.4) | | (14.1) | |
| Net other income | 107.0 | | 164.1 | | 181.6 | |
| INTEREST EXPENSE | | | |
| Interest on long-term debt | 138.3 | | 157.4 | | 153.6 | |
| Allowance for borrowed funds used during construction | (2.8) | | (11.7) | | (18.0) | |
| Interest on short-term debt and other interest charges | 12.4 | | 10.3 | | 8.2 | |
| Interest expense | 147.9 | | 156.0 | | 143.8 | |
| INCOME BEFORE TAXES | 463.4 | | 497.7 | | 569.7 | |
| INCOME TAX EXPENSE (BENEFIT) | 29.8 | | 72.2 | | (49.3) | |
| NET INCOME | $ | 433.6 | | $ | 425.5 | | $ | 619.0 | |
| | | |
| | | |
| BASIC AVERAGE COMMON SHARES OUTSTANDING | 200.1 | | 199.7 | | 199.7 | |
| DILUTED AVERAGE COMMON SHARES OUTSTANDING | 200.7 | | 200.5 | | 200.0 | |
| BASIC EARNINGS PER AVERAGE COMMON SHARE | $ | 2.17 | | $ | 2.13 | | $ | 3.10 | |
| DILUTED EARNINGS PER AVERAGE COMMON SHARE | $ | 2.16 | | $ | 2.12 | | $ | 3.10 | |
| | | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
42
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
Net income (loss) | | $ | 665.7 | | | $ | 737.3 | | | $ | (173.7 | ) |
Other comprehensive income (loss), net of tax: | | | | | | | | | |
Pension Plan and Restoration of Retirement Income Plan: | | | | | | | | | |
Amortization of prior service cost, net of tax of $0.1, $0.0 and $0.0, respectively | | | 0.2 | | | | 0.1 | | | | — | |
Amortization of deferred net loss, net of tax of $0.2, $0.9 and $1.2, respectively | | | 1.4 | | | | 1.6 | | | | 3.9 | |
Net gain (loss) arising during the period, net of tax of ($2.4), $0.0 and ($1.7), respectively | | | (7.6 | ) | | | 1.4 | | | | (5.1 | ) |
Prior service cost arising during the period, net of tax of $0.0, ($0.3) and $0.0, respectively | | | — | | | | (1.1 | ) | | | — | |
Settlement cost, net of tax of $4.3, $2.7 and $0.7, respectively | | | 13.6 | | | | 6.0 | | | | 2.2 | |
Postretirement benefit plans: | | | | | | | | | |
Amortization of prior service credit, net of tax of ($0.1), ($0.4) and ($0.6), respectively | | | (0.2 | ) | | | (1.4 | ) | | | (1.7 | ) |
Amortization of deferred net (gain) loss, net of tax of $0.0, $0.0 and $0.0, respectively | | | — | | | | 0.1 | | | | (0.1 | ) |
Net gain (loss) arising during the period, net of tax of $1.7, ($0.2) and ($0.8), respectively | | | 5.5 | | | | (0.7 | ) | | | (2.4 | ) |
Curtailment cost, net of tax of $0.0, $0.0 and ($0.1), respectively | | | — | | | | — | | | | (0.3 | ) |
Other comprehensive gain (loss) from unconsolidated affiliates, net of tax $0.0, $0.3 and ($0.2), respectively | | | — | | | | 1.3 | | | | (0.7 | ) |
Other comprehensive income (loss), net of tax | | | 12.9 | | | | 7.3 | | | | (4.2 | ) |
Comprehensive income (loss) | | $ | 678.6 | | | $ | 744.6 | | | $ | (177.9 | ) |
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Net income | $ | 433.6 | | $ | 425.5 | | $ | 619.0 | |
| Other comprehensive income (loss), net of tax: | | | |
| Pension Plan and Restoration of Retirement Income Plan: | | | |
| Amortization of deferred net loss, net of tax of $1.1, $1.1 and $1.4, respectively | 3.4 | | 3.3 | | 2.5 | |
| Amortization of prior service credit, 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 $(2.6), ($4.7) and $0.2, respectively | (8.3) | | (14.1) | | 0.4 | |
| | | |
| Settlement cost, net of tax of $2.7, $1.6 and $1.4, respectively | 8.6 | | 4.7 | | 2.2 | |
| Postretirement Benefit Plans: | | | |
| Amortization of prior service credit, net of tax of ($0.6), ($0.6) and ($0.3), respectively | (1.7) | | (1.7) | | (0.6) | |
| Amortization of deferred net gain, net of tax of $0.0, $0.0 and $0.0, respectively | (0.2) | | — | | — | |
| Prior service cost arising during the period, net of tax of $0.0, $0.0 and $4.0, respectively | — | | — | | 6.3 | |
| Net gain (loss) arising during the period, net of tax of ($0.1), $0.7 and ($0.2), respectively | (0.2) | | 2.1 | | (0.6) | |
| | | |
| Settlement cost, net of tax of $0.0, $0.0 and $0.2, respectively | — | | — | | 0.5 | |
| Other comprehensive loss from unconsolidated affiliates, net of tax ($0.2), $0.0 and $0.0, respectively | (0.6) | | — | | — | |
| | | |
| | | |
| Other comprehensive income (loss), net of tax | 1.0 | | (5.7) | | 10.6 | |
| Comprehensive income | $ | 434.6 | | $ | 419.8 | | $ | 629.6 | |
| | | |
| | | |
| | | |
| | | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
43
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | |
| Net income | $ | 433.6 | | $ | 425.5 | | $ | 619.0 | |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | |
| Depreciation and amortization | 355.0 | | 321.6 | | 283.5 | |
| | | |
| Deferred income taxes and investment tax credits, net | 27.6 | | 78.5 | | (50.0) | |
| Equity in earnings of unconsolidated affiliates | (113.9) | | (152.8) | | (131.2) | |
| Distributions from unconsolidated affiliates | 125.5 | | 141.2 | | 131.2 | |
| Allowance for equity funds used during construction | (4.5) | | (23.8) | | (39.7) | |
| | | |
| | | |
| Stock-based compensation expense | 13.9 | | 13.4 | | 9.1 | |
| | | |
| Regulatory assets | (47.1) | | (10.8) | | 3.7 | |
| Regulatory liabilities | (45.6) | | (16.5) | | (3.7) | |
| Other assets | (3.8) | | 6.2 | | (0.7) | |
| Other liabilities | 19.2 | | 1.0 | | (65.5) | |
| Change in certain current assets and liabilities: | | | |
| Accounts receivable and accrued unbilled revenues, net | 18.8 | | 19.8 | | (21.8) | |
| | | |
| | | |
| Income taxes receivable | (1.0) | | (4.1) | | 13.6 | |
| Fuel, materials and supplies inventories | 4.2 | | 27.3 | | (3.6) | |
| | | |
| Fuel recoveries | (33.0) | | (3.4) | | 53.0 | |
| Other current assets | 5.1 | | 25.1 | | 27.2 | |
| Accounts payable | (34.5) | | 29.7 | | 27.1 | |
| | | |
| | | |
| | | |
| Other current liabilities | (38.0) | | 73.2 | | (66.7) | |
| Net cash provided from operating activities | 681.5 | | 951.1 | | 784.5 | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | |
| Capital expenditures (less allowance for equity funds used during construction) | (635.5) | | (573.6) | | (824.1) | |
| Investment in unconsolidated affiliates | (7.7) | | (2.5) | | (8.5) | |
| Return of capital - unconsolidated affiliates | 18.5 | | — | | 10.0 | |
| | | |
| Proceeds from sale of assets | — | | 0.1 | | 0.7 | |
| | | |
| | | |
| Net cash used in investing activities | (624.7) | | (576.0) | | (821.9) | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | |
| Increase (decrease) in short-term debt | 112.0 | | (168.4) | | (67.8) | |
| Proceeds from long-term debt | 296.5 | | 396.0 | | 592.1 | |
| Payment of long-term debt | (250.1) | | (250.1) | | (225.1) | |
| Dividends paid on common stock | (299.2) | | (272.2) | | (247.6) | |
| | | |
| Cash paid for employee equity-based compensation and expense of common stock | (10.3) | | (0.5) | | (0.1) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Net cash provided from (used in) financing activities | (151.1) | | (295.2) | | 51.5 | |
| NET CHANGE IN CASH AND CASH EQUIVALENTS | (94.3) | | 79.9 | | 14.1 | |
| CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 94.3 | | 14.4 | | 0.3 | |
| CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | — | | $ | 94.3 | | $ | 14.4 | |
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | |
Net income (loss) | | $ | 665.7 | | | $ | 737.3 | | | $ | (173.7 | ) |
Adjustments to reconcile net income (loss) to net cash provided from (used in) operating activities: | | | | | | | | | |
Depreciation and amortization | | | 460.9 | | | | 416.0 | | | | 391.3 | |
Deferred income taxes and other tax credits, net | | | (154.0 | ) | | | 125.9 | | | | (134.5 | ) |
(Gain) loss on investment in equity securities (Note 1) | | | (282.1 | ) | | | 8.6 | | | | — | |
Gain on Enable/Energy Transfer transaction (Note 1) | | | — | | | | (353.0 | ) | | | — | |
Equity in (earnings) losses of unconsolidated affiliates | | | — | | | | (169.8 | ) | | | 668.0 | |
Distributions from unconsolidated affiliates | | | — | | | | 73.4 | | | | 91.7 | |
Allowance for equity funds used during construction | | | (6.9 | ) | | | (6.7 | ) | | | (4.8 | ) |
Stock-based compensation expense | | | 9.7 | | | | 9.8 | | | | 9.8 | |
Regulatory assets | | | 702.2 | | | | (874.9 | ) | | | (112.0 | ) |
Regulatory liabilities | | | (118.4 | ) | | | (71.2 | ) | | | (64.0 | ) |
Other assets | | | 18.9 | | | | (9.8 | ) | | | (9.2 | ) |
Other liabilities | | | (6.6 | ) | | | (8.1 | ) | | | (26.3 | ) |
Change in certain current assets and liabilities: | | | | | | | | | |
Accounts receivable and accrued unbilled revenues, net | | | (97.0 | ) | | | (1.9 | ) | | | 3.1 | |
Income taxes receivable | | | (18.1 | ) | | | 5.5 | | | | 2.8 | |
Fuel, materials and supplies inventories | | | (130.1 | ) | | | (3.4 | ) | | | (8.9 | ) |
Fuel recoveries | | | (363.0 | ) | | | (180.5 | ) | | | 63.3 | |
Other current assets | | | (30.2 | ) | | | (22.7 | ) | | | (16.8 | ) |
Accounts payable | | | 155.4 | | | | 7.5 | | | | 59.8 | |
Other current liabilities | | | 36.7 | | | | 4.7 | | | | (26.8 | ) |
Net cash provided from (used in) operating activities | | | 843.1 | | | | (313.3 | ) | | | 712.8 | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | |
Capital expenditures (less allowance for equity funds used during construction) | | | (1,050.9 | ) | | | (778.5 | ) | | | (650.5 | ) |
Proceeds from sales of equity securities | | | 1,067.2 | | | | — | | | | — | |
Cash received in Enable/Energy Transfer transaction (Note 1) | | | — | | | | 35.0 | | | | — | |
Other | | | (3.4 | ) | | | (5.6 | ) | | | (4.4 | ) |
Net cash provided from (used in) investing activities | | | 12.9 | | | | (749.1 | ) | | | (654.9 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | |
Proceeds from long-term debt | | | 49.3 | | | | 997.8 | | | | 297.1 | |
(Decrease) increase in short-term debt | | | (486.9 | ) | | | 391.9 | | | | (17.0 | ) |
Payment of long-term debt | | | (0.1 | ) | | | (0.1 | ) | | | (0.1 | ) |
Dividends paid on common stock | | | (329.3 | ) | | | (324.9 | ) | | | (314.9 | ) |
Cash paid for employee equity-based compensation and expense of common stock | | | (0.9 | ) | | | (3.4 | ) | | | (7.1 | ) |
Purchase of treasury stock | | | — | | | | — | | | | (14.7 | ) |
Other | | | — | | | | — | | | | (0.1 | ) |
Net cash (used in) provided from financing activities | | | (767.9 | ) | | | 1,061.3 | | | | (56.8 | ) |
NET CHANGE IN CASH AND CASH EQUIVALENTS | | | 88.1 | | | | (1.1 | ) | | | 1.1 | |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | | | — | | | | 1.1 | | | | — | |
CASH AND CASH EQUIVALENTS AT END OF YEAR | | $ | 88.1 | | | $ | — | | | $ | 1.1 | |
SUPPLEMENTAL CASH FLOW INFORMATION | | | | | | | | | |
Cash paid during the period for: | | | | | | | | | |
Interest (net of interest capitalized of $4.0, $3.5 and $1.9, respectively) | | $ | 164.0 | | | $ | 156.4 | | | $ | 153.4 | |
Income taxes (net of income tax refunds) | | $ | 276.0 | | | $ | 8.7 | | | $ | 3.9 | |
NON-CASH INVESTING AND FINANCING ACTIVITIES | | | | | | | | | |
Power plant long-term service agreement | | $ | 0.8 | | | $ | 2.4 | | | $ | 6.8 | |
Investment in Energy Transfer's equity securities (Note 1) | | $ | — | | | $ | 793.7 | | | $ | — | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
44
CONSOLIDATED BALANCE SHEETS
| | | | | | | | |
December 31 (In millions) | | 2022 | | | 2021 | |
ASSETS | | | | | | |
CURRENT ASSETS | | | | | | |
Cash and cash equivalents | | $ | 88.1 | | | $ | — | |
Accounts receivable, less reserve of $1.9 and $2.4, respectively | | | 250.1 | | | | 162.3 | |
Accrued unbilled revenues | | | 74.2 | | | | 65.0 | |
Income taxes receivable | | | 20.7 | | | | 2.6 | |
Fuel inventories | | | 108.8 | | | | 40.6 | |
Materials and supplies, at average cost | | | 180.5 | | | | 117.9 | |
Fuel clause under recoveries | | | 514.9 | | | | 151.9 | |
Other | | | 103.5 | | | | 73.3 | |
Total current assets | | | 1,340.8 | | | | 613.6 | |
OTHER PROPERTY AND INVESTMENTS | | | | | | |
Equity securities investment in Energy Transfer | | | — | | | | 785.1 | |
Other | | | 105.8 | | | | 120.0 | |
Total other property and investments | | | 105.8 | | | | 905.1 | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | |
In service | | | 14,695.2 | | | | 13,899.8 | |
Construction work in progress | | | 436.1 | | | | 252.0 | |
Total property, plant and equipment | | | 15,131.3 | | | | 14,151.8 | |
Less: accumulated depreciation | | | 4,584.5 | | | | 4,318.9 | |
Net property, plant and equipment | | | 10,546.8 | | | | 9,832.9 | |
DEFERRED CHARGES AND OTHER ASSETS | | | | | | |
Regulatory assets | | | 524.3 | | | | 1,230.8 | |
Other | | | 27.0 | | | | 24.0 | |
Total deferred charges and other assets | | | 551.3 | | | | 1,254.8 | |
TOTAL ASSETS | | $ | 12,544.7 | | | $ | 12,606.4 | |
| | | | | | | | |
December 31 (In millions) | 2019 | 2018 |
| ASSETS | | |
| CURRENT ASSETS | | |
| Cash and cash equivalents | $ | — | | $ | 94.3 | |
| Accounts receivable, less reserve of $1.5 and $1.7, respectively | 153.8 | | 174.7 | |
| | |
| Accrued unbilled revenues | 64.7 | | 62.6 | |
| Income taxes receivable | 10.9 | | 9.9 | |
| Fuel inventories | 46.3 | | 57.6 | |
| Materials and supplies, at average cost | 90.6 | | 126.7 | |
| Fuel clause under recoveries | 39.5 | | 2.0 | |
| | |
| Other | 24.4 | | 29.5 | |
| Total current assets | 430.2 | | 557.3 | |
| OTHER PROPERTY AND INVESTMENTS | | |
| Investment in unconsolidated affiliates | 1,151.5 | | 1,177.5 | |
| Other | 82.7 | | 73.4 | |
| Total other property and investments | 1,234.2 | | 1,250.9 | |
| PROPERTY, PLANT AND EQUIPMENT | | |
| In service | 12,771.1 | | 11,994.8 | |
| Construction work in progress | 141.6 | | 376.4 | |
| Total property, plant and equipment | 12,912.7 | | 12,371.2 | |
| Less: accumulated depreciation | 3,868.1 | | 3,727.4 | |
| Net property, plant and equipment | 9,044.6 | | 8,643.8 | |
| DEFERRED CHARGES AND OTHER ASSETS | | |
| Regulatory assets | 306.0 | | 285.8 | |
| | |
| | |
| Other | 9.3 | | 10.8 | |
| Total deferred charges and other assets | 315.3 | | 296.6 | |
| TOTAL ASSETS | $ | 11,024.3 | | $ | 10,748.6 | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
45
CONSOLIDATED BALANCE SHEETS (Continued)
| | | | | | | | |
December 31 (In millions) | | 2022 | | | 2021 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | | | | | | |
CURRENT LIABILITIES | | | | | | |
Short-term debt | | $ | — | | | $ | 486.9 | |
Accounts payable | | | 448.9 | | | | 274.0 | |
Dividends payable | | | 82.9 | | | | 82.1 | |
Customer deposits | | | 88.8 | | | | 81.1 | |
Accrued taxes | | | 54.0 | | | | 52.9 | |
Accrued interest | | | 41.1 | | | | 40.8 | |
Accrued compensation | | | 37.0 | | | | 37.7 | |
Long-term debt due within one year | | | 999.9 | | | | — | |
Other | | | 49.6 | | | | 34.1 | |
Total current liabilities | | | 1,802.2 | | | | 1,089.6 | |
LONG-TERM DEBT | | | 3,548.7 | | | | 4,496.4 | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | |
Accrued benefit obligations | | | 176.9 | | | | 159.8 | |
Deferred income taxes | | | 1,233.5 | | | | 1,333.3 | |
Deferred investment tax credits | | | 12.0 | | | | 12.8 | |
Regulatory liabilities | | | 1,147.1 | | | | 1,231.1 | |
Other | | | 210.9 | | | | 227.1 | |
Total deferred credits and other liabilities | | | 2,780.4 | | | | 2,964.1 | |
Total liabilities | | | 8,131.3 | | | | 8,550.1 | |
COMMITMENTS AND CONTINGENCIES (NOTE 13) | | | | | | |
STOCKHOLDERS' EQUITY | | | | | | |
Common stockholders' equity | | | 1,134.5 | | | | 1,125.8 | |
Retained earnings | | | 3,290.9 | | | | 2,955.4 | |
Accumulated other comprehensive loss, net of tax | | | (11.9 | ) | | | (24.8 | ) |
Treasury stock, at cost | | | (0.1 | ) | | | (0.1 | ) |
Total stockholders' equity | | | 4,413.4 | | | | 4,056.3 | |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | | $ | 12,544.7 | | | $ | 12,606.4 | |
| | | | | | | | |
December 31 (In millions) | 2019 | 2018 |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | |
| CURRENT LIABILITIES | | |
| Short-term debt | $ | 112.0 | | $ | — | |
| Accounts payable | 194.9 | | 239.3 | |
| Dividends payable | 77.6 | | 72.9 | |
| Customer deposits | 83.0 | | 83.6 | |
| Accrued taxes | 41.9 | | 44.0 | |
| Accrued interest | 37.9 | | 44.5 | |
| Accrued compensation | 40.6 | | 47.8 | |
| Long-term debt due within one year | — | | 250.0 | |
| Fuel clause over recoveries | 4.8 | | 0.3 | |
| Other | 65.2 | | 87.0 | |
| Total current liabilities | 657.9 | | 869.4 | |
| LONG-TERM DEBT | 3,195.2 | | 2,896.9 | |
| DEFERRED CREDITS AND OTHER LIABILITIES | | |
| Accrued benefit obligations | 225.0 | | 225.7 | |
| Deferred income taxes | 1,375.8 | | 1,310.9 | |
| Deferred investment tax credits | 7.1 | | 7.2 | |
| Regulatory liabilities | 1,223.5 | | 1,270.7 | |
| | |
| Other | 200.3 | | 162.7 | |
| Total deferred credits and other liabilities | 3,031.7 | | 2,977.2 | |
| Total liabilities | 6,884.8 | | 6,743.5 | |
| COMMITMENTS AND CONTINGENCIES (NOTE 15) | | |
| STOCKHOLDERS' EQUITY | | |
| Common stockholders' equity | 1,131.3 | | 1,127.7 | |
| Retained earnings | 3,036.1 | | 2,906.3 | |
| Accumulated other comprehensive loss, net of tax | (27.9) | | (28.9) | |
| | |
| | |
| | |
| Total stockholders' equity | 4,139.5 | | 4,005.1 | |
| TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 11,024.3 | | $ | 10,748.6 | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
46
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| | | | | | | | | |
December 31 (In millions except per share data) | | 2022 | | | 2021 | |
STOCKHOLDERS' EQUITY | | | | | | |
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.2 shares and 200.1 shares, respectively | | $ | 2.0 | | | $ | 2.0 | |
Premium on common stock | | | 1,132.5 | | | | 1,123.8 | |
Retained earnings | | | 3,290.9 | | | | 2,955.4 | |
Accumulated other comprehensive loss, net of tax | | | (11.9 | ) | | | (24.8 | ) |
Treasury stock, at cost, 0.0 and 0.0 shares, respectively | | | (0.1 | ) | | | (0.1 | ) |
Total stockholders' equity | | | 4,413.4 | | | | 4,056.3 | |
| | | | | | | |
LONG-TERM DEBT | | | | | | | |
SERIES | DUE DATE | | | | | | |
Senior Notes - OGE Energy | | | | | | | |
0.703% | Senior Notes, Series Due May 26, 2023 | | | 500.0 | | | | 500.0 | |
1.875% - 5.375% | Term Loan Due May 24, 2025 | | | 50.0 | | | | — | |
Senior Notes - OG&E | | | | | | | |
0.553% | Senior Notes, Series Due May 26, 2023 | | | 500.0 | | | | 500.0 | |
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 | |
3.80% | Senior Notes, Series Due August 15, 2028 | | | 400.0 | | | | 400.0 | |
3.30% | Senior Notes, Series Due March 15, 2030 | | | 300.0 | | | | 300.0 | |
3.25% | Senior Notes, Series Due April 1, 2030 | | | 300.0 | | | | 300.0 | |
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 | | | | 300.0 | |
3.85% | Senior Notes, Series Due August 15, 2047 | | | 300.0 | | | | 300.0 | |
3.80% | Tinker Debt, Due August 31, 2062 | | | 9.3 | | | | 9.3 | |
| | | | | | | |
Other Bonds - OG&E | | | | | | | |
0.11% - 3.98% | Garfield Industrial Authority, January 1, 2025 | | | 47.0 | | | | 47.0 | |
0.11% - 3.95% | Muskogee Industrial Authority, January 1, 2025 | | | 32.4 | | | | 32.4 | |
0.11% - 3.98% | Muskogee Industrial Authority, June 1, 2027 | | | 56.0 | | | | 56.0 | |
Unamortized debt expense | | | (22.2 | ) | | | (23.8 | ) |
Unamortized discount | | | (8.9 | ) | | | (9.5 | ) |
Total long-term debt | | | 4,548.6 | | | | 4,496.4 | |
Less: long-term debt due within one year | | | (999.9 | ) | | | — | |
Total long-term debt (excluding long-term debt due within one year) | | | 3,548.7 | | | | 4,496.4 | |
Total capitalization (including long-term debt due within one year) | | $ | 8,962.0 | | | $ | 8,552.7 | |
| | | | | | | | | | | |
December 31 (In millions except per share data) | | 2019 | 2018 |
| STOCKHOLDERS' EQUITY | | | |
| Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.1 shares and 199.7 shares, respectively | | $ | 2.0 | | $ | 2.0 | |
| Premium on common stock | | 1,129.3 | | 1,125.7 | |
| Retained earnings | | 3,036.1 | | 2,906.3 | |
| Accumulated other comprehensive loss, net of tax | | (27.9) | | (28.9) | |
| | | |
| | | |
| | | |
| Total stockholders' equity | | 4,139.5 | | 4,005.1 | |
| | | |
| LONG-TERM DEBT | | | |
| SERIES | DUE DATE | | |
| Senior Notes - OG&E | | | | |
| | | |
| 8.25% | | Senior Notes, Series Due January 15, 2019 | — | | 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 | |
| 3.80% | | Senior Notes, Series Due August 15, 2028 | 400.0 | | 400.0 | |
| 3.30% | | Senior Notes, Series Due March, 15, 2030 | 300.0 | | — | |
| 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 | | 300.0 | |
| 3.85% | | Senior Notes, Series Due August 15, 2047 | 300.0 | | 300.0 | |
| 3.80% | | Tinker Debt, Due August 31, 2062 | 9.5 | | 9.6 | |
| Other Bonds - OG&E | | | | |
| 1.20% - 2.50% | Garfield Industrial Authority, January 1, 2025 | 47.0 | | 47.0 | |
| 1.19% - 2.35% | Muskogee Industrial Authority, January 1, 2025 | 32.4 | | 32.4 | |
| 1.20% - 2.48% | | Muskogee Industrial Authority, June 1, 2027 | 56.0 | | 56.0 | |
| Unamortized debt expense | | | (24.2) | | (22.9) | |
| Unamortized discount | | | (10.5) | | (10.2) | |
| Total long-term debt | | 3,195.2 | | 3,146.9 | |
| Less: long-term debt due within one year | | — | | (250.0) | |
| Total long-term debt (excluding long-term debt due within one year) | | 3,195.2 | | 2,896.9 | |
| Total capitalization (including long-term debt due within one year) | | $ | 7,334.7 | | $ | 7,152.0 | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
47
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, 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 ($1.2700 per share) | — | | — | | — | | (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 | |
| Net income | — | | — | | — | | 425.5 | | — | | | | 425.5 | |
| | | | | | | | |
| Other comprehensive loss, net of tax | — | | — | | — | | — | | (5.7) | | | | (5.7) | |
| Dividends declared on common stock ($1.3950 per share) | — | | — | | — | | (278.7) | | — | | | | (278.7) | |
| Expense of common stock | — | | — | | (0.1) | | — | | — | | | | (0.1) | |
| Stock-based compensation | — | | — | | 13.0 | | — | | — | | | | 13.0 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Balance at December 31, 2018 | 199.7 | | $ | 2.0 | | $ | 1,125.7 | | $ | 2,906.3 | | $ | (28.9) | | | | $ | 4,005.1 | |
| Net income | — | | — | | — | | 433.6 | | — | | | | 433.6 | |
| Other comprehensive income, net of tax | — | | — | | — | | — | | 1.0 | | | | 1.0 | |
| Dividends declared on common stock ($1.5050 per share) | — | | — | | — | | (303.8) | | — | | | | (303.8) | |
| | | | | | | | |
| Stock-based compensation | 0.4 | | — | | 3.6 | | — | | — | | | | 3.6 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Balance at December 31, 2019 | 200.1 | | $ | 2.0 | | $ | 1,129.3 | | $ | 3,036.1 | | $ | (27.9) | | | | $ | 4,139.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | | Treasury Stock | | | Premium on Common | | | Retained | | | Accumulated Other Comprehensive (Loss) | | | | |
(In millions) | | Shares | | | Value | | | Shares | | | Value | | | Stock | | | Earnings | | | Income | | | Total | |
Balance at December 31, 2019 | | | 200.1 | | | $ | 2.0 | | | | — | | | $ | — | | | $ | 1,129.3 | | | $ | 3,036.1 | | | $ | (27.9 | ) | | $ | 4,139.5 | |
Net loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | (173.7 | ) | | | — | | | | (173.7 | ) |
Other comprehensive loss, net of tax | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (4.2 | ) | | | (4.2 | ) |
Dividends declared on common stock ($1.5800 per share) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (317.8 | ) | | | — | | | | (317.8 | ) |
Purchase of treasury stock | | | — | | | | — | | | | 0.4 | | | | (14.7 | ) | | | — | | | | — | | | | — | | | | (14.7 | ) |
Stock-based compensation | | | — | | | | — | | | | (0.3 | ) | | | 9.4 | | | | (6.7 | ) | | | — | | | | — | | | | 2.7 | |
Balance at December 31, 2020 | | | 200.1 | | | $ | 2.0 | | | | 0.1 | | | $ | (5.3 | ) | | $ | 1,122.6 | | | $ | 2,544.6 | | | $ | (32.1 | ) | | $ | 3,631.8 | |
Net income | | | — | | | | — | | | | — | | | | — | | | | — | | | | 737.3 | | | | — | | | | 737.3 | |
Other comprehensive income, net of tax | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 7.3 | | | | 7.3 | |
Dividends declared on common stock ($1.6250 per share) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (326.5 | ) | | | — | | | | (326.5 | ) |
Stock-based compensation | | | — | | | | — | | | | (0.1 | ) | | | 5.2 | | | | 1.2 | | | | — | | | | — | | | | 6.4 | |
Balance at December 31, 2021 | | | 200.1 | | | $ | 2.0 | | | | — | | | $ | (0.1 | ) | | $ | 1,123.8 | | | $ | 2,955.4 | | | $ | (24.8 | ) | | $ | 4,056.3 | |
Net income | | | — | | | | — | | | | — | | | | — | | | | — | | | | 665.7 | | | | — | | | | 665.7 | |
Other comprehensive income, net of tax | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 12.9 | | | | 12.9 | |
Dividends declared on common stock ($1.6482 per share) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (330.2 | ) | | | — | | | | (330.2 | ) |
Stock-based compensation | | | 0.1 | | | | — | | | | — | | | | — | | | | 8.7 | | | | — | | | | — | | | | 8.7 | |
Balance at December 31, 2022 | | | 200.2 | | | $ | 2.0 | | | | — | | | $ | (0.1 | ) | | $ | 1,132.5 | | | $ | 3,290.9 | | | $ | (11.9 | ) | | $ | 4,413.4 | |
The accompanying Combined Notes to Consolidated Financial Statements are an integral part hereof.
48
OGE ENERGY CORP.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
OPERATING REVENUES | | | | | | | | | |
Revenues from contracts with customers | | $ | 3,304.2 | | | $ | 3,588.7 | | | $ | 2,069.8 | |
Other revenues | | | 71.5 | | | | 65.0 | | | | 52.5 | |
Operating revenues | | | 3,375.7 | | | | 3,653.7 | | | | 2,122.3 | |
FUEL, PURCHASED POWER AND DIRECT TRANSMISSION EXPENSE | | | 1,662.4 | | | | 2,127.6 | | | | 644.6 | |
OPERATING EXPENSES | | | | | | | | | |
Other operation and maintenance | | | 491.9 | | | | 464.7 | | | | 464.4 | |
Depreciation and amortization | | | 460.9 | | | | 416.0 | | | | 391.3 | |
Taxes other than income | | | 98.0 | | | | 99.3 | | | | 97.2 | |
Operating expenses | | | 1,050.8 | | | | 980.0 | | | | 952.9 | |
OPERATING INCOME | | | 662.5 | | | | 546.1 | | | | 524.8 | |
OTHER INCOME (EXPENSE) | | | | | | | | | |
Allowance for equity funds used during construction | | | 6.9 | | | | 6.7 | | | | 4.8 | |
Other net periodic benefit income (expense) | | | 1.2 | | | | (4.3 | ) | | | (3.1 | ) |
Other income | | | 6.5 | | | | 7.1 | | | | 5.0 | |
Other expense | | | (3.4 | ) | | | (1.8 | ) | | | (2.6 | ) |
Net other income | | | 11.2 | | | | 7.7 | | | | 4.1 | |
INTEREST EXPENSE | | | | | | | | | |
Interest on long-term debt | | | 157.4 | | | | 152.7 | | | | 152.8 | |
Allowance for borrowed funds used during construction | | | (4.0 | ) | | | (3.5 | ) | | | (1.9 | ) |
Interest on short-term debt and other interest charges | | | 4.4 | | | | 2.8 | | | | 3.9 | |
Interest expense | | | 157.8 | | | | 152.0 | | | | 154.8 | |
INCOME BEFORE TAXES | | | 515.9 | | | | 401.8 | | | | 374.1 | |
INCOME TAX EXPENSE | | | 76.4 | | | | 41.8 | | | | 34.7 | |
NET INCOME | | | 439.5 | | | | 360.0 | | | | 339.4 | |
Other comprehensive income, net of tax | | | — | | | | — | | | | — | |
COMPREHENSIVE INCOME | | $ | 439.5 | | | $ | 360.0 | | | $ | 339.4 | |
The accompanying Combined Notes to Financial Statements are an integral part hereof.
49
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | |
Net income | | $ | 439.5 | | | $ | 360.0 | | | $ | 339.4 | |
Adjustments to reconcile net income to net cash provided from (used in) operating activities: | | | | | | | | | |
Depreciation and amortization | | | 460.9 | | | | 416.0 | | | | 391.3 | |
Deferred income taxes and other tax credits, net | | | 220.5 | | | | 44.6 | | | | 40.9 | |
Allowance for equity funds used during construction | | | (6.9 | ) | | | (6.7 | ) | | | (4.8 | ) |
Stock-based compensation expense | | | 2.9 | | | | 2.2 | | | | 3.0 | |
Regulatory assets | | | 702.2 | | | | (874.9 | ) | | | (112.0 | ) |
Regulatory liabilities | | | (118.4 | ) | | | (71.2 | ) | | | (64.0 | ) |
Other assets | | | — | | | | (2.2 | ) | | | (3.4 | ) |
Other liabilities | | | (5.6 | ) | | | (11.2 | ) | | | (24.3 | ) |
Change in certain current assets and liabilities: | | | | | | | | | |
Accounts receivable and accrued unbilled revenues, net | | | (96.6 | ) | | | (3.0 | ) | | | 4.5 | |
Fuel, materials and supplies inventories | | | (130.1 | ) | | | (3.4 | ) | | | (8.9 | ) |
Fuel recoveries | | | (363.0 | ) | | | (180.5 | ) | | | 63.3 | |
Other current assets | | | (30.1 | ) | | | (21.4 | ) | | | (17.3 | ) |
Accounts payable | | | 135.8 | | | | (11.0 | ) | | | 64.8 | |
Income taxes payable - parent | | | 8.0 | | | | 0.7 | | | | (5.3 | ) |
Other current liabilities | | | 19.3 | | | | 3.3 | | | | (26.8 | ) |
Net cash provided from (used in) operating activities | | | 1,238.4 | | | | (358.7 | ) | | | 640.4 | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | |
Capital expenditures (less allowance for equity funds used during construction) | | | (1,050.9 | ) | | | (778.5 | ) | | | (650.5 | ) |
Net cash used in investing activities | | | (1,050.9 | ) | | | (778.5 | ) | | | (650.5 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | |
Capital contribution from OGE Energy | | | — | | | | 530.0 | | | | — | |
Proceeds from long-term debt | | | — | | | | 499.8 | | | | 297.1 | |
Payment of long-term debt | | | (0.1 | ) | | | (0.1 | ) | | | (0.1 | ) |
Dividends paid on common stock | | | — | | | | (265.0 | ) | | | (325.0 | ) |
Changes in advances with parent | | | (187.4 | ) | | | 372.5 | | | | 38.1 | |
Net cash (used in) provided from financing activities | | | (187.5 | ) | | | 1,137.2 | | | | 10.1 | |
NET CHANGE IN CASH AND CASH EQUIVALENTS | | | — | | | | — | | | | — | |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | | | — | | | | — | | | | — | |
CASH AND CASH EQUIVALENTS AT END OF YEAR | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | |
SUPPLEMENTAL CASH FLOW INFORMATION | | | | | | | | | |
Cash paid during the period for: | | | | | | | | | |
Interest (net of interest capitalized of $4.0, $3.5 and $1.9, respectively) | | $ | 154.6 | | | $ | 148.9 | | | $ | 150.2 | |
Income taxes (net of income tax refunds) | | $ | (152.6 | ) | | $ | (3.2 | ) | | $ | (0.2 | ) |
NON-CASH INVESTING AND FINANCING ACTIVITIES | | | | | | | | | |
Power plant long-term service agreement | | $ | 0.8 | | | $ | 2.4 | | | $ | 6.8 | |
The accompanying Combined Notes to Financial Statements are an integral part hereof.
50
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
| | | | | | | | |
December 31 (In millions) | | 2022 | | | 2021 | |
ASSETS | | | | | | |
CURRENT ASSETS | | | | | | |
Accounts receivable, less reserve of $1.9 and $2.4, respectively | | $ | 249.4 | | | $ | 162.0 | |
Accrued unbilled revenues | | | 74.2 | | | | 65.0 | |
Advances to parent | | | 91.0 | | | | — | |
Fuel inventories | | | 108.8 | | | | 40.6 | |
Materials and supplies, at average cost | | | 180.5 | | | | 117.9 | |
Fuel clause under recoveries | | | 514.9 | | | | 151.9 | |
Other | | | 97.8 | | | | 67.7 | |
Total current assets | | | 1,316.6 | | | | 605.1 | |
OTHER PROPERTY AND INVESTMENTS | | | 4.4 | | | | 3.9 | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | |
In service | | | 14,689.1 | | | | 13,893.7 | |
Construction work in progress | | | 436.1 | | | | 252.0 | |
Total property, plant and equipment | | | 15,125.2 | | | | 14,145.7 | |
Less: accumulated depreciation | | | 4,584.5 | | | | 4,318.9 | |
Net property, plant and equipment | | | 10,540.7 | | | | 9,826.8 | |
DEFERRED CHARGES AND OTHER ASSETS | | | | | | |
Regulatory assets | | | 524.3 | | | | 1,230.8 | |
Other | | | 24.5 | | | | 21.4 | |
Total deferred charges and other assets | | | 548.8 | | | | 1,252.2 | |
TOTAL ASSETS | | $ | 12,410.5 | | | $ | 11,688.0 | |
The accompanying Combined Notes to Financial Statements are an integral part hereof.
51
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
| | | | | | | | |
December 31 (In millions) | | 2022 | | | 2021 | |
LIABILITIES AND STOCKHOLDER'S EQUITY | | | | | | |
CURRENT LIABILITIES | | | | | | |
Accounts payable | | $ | 395.8 | | | $ | 240.6 | |
Advances from parent | | | — | | | | 101.3 | |
Customer deposits | | | 88.8 | | | | 81.1 | |
Accrued taxes | | | 46.5 | | | | 50.8 | |
Accrued interest | | | 40.8 | | | | 40.4 | |
Accrued compensation | | | 27.8 | | | | 27.8 | |
Long-term debt due within one year | | | 500.0 | | | | — | |
Other | | | 49.3 | | | | 33.8 | |
Total current liabilities | | | 1,149.0 | | | | 575.8 | |
LONG-TERM DEBT | | | 3,498.9 | | | | 3,996.5 | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | |
Accrued benefit obligations | | | 98.3 | | | | 75.1 | |
Deferred income taxes | | | 1,271.1 | | | | 1,000.4 | |
Deferred investment tax credits | | | 12.0 | | | | 12.8 | |
Regulatory liabilities | | | 1,147.1 | | | | 1,231.1 | |
Other | | | 188.9 | | | | 193.5 | |
Total deferred credits and other liabilities | | | 2,717.4 | | | | 2,512.9 | |
Total liabilities | | | 7,365.3 | | | | 7,085.2 | |
COMMITMENTS AND CONTINGENCIES (NOTE 13) | | | | | | |
STOCKHOLDER'S EQUITY | | | | | | |
Common stockholder's equity | | | 1,574.6 | | | | 1,571.7 | |
Retained earnings | | | 3,470.6 | | | | 3,031.1 | |
Total stockholder's equity | | | 5,045.2 | | | | 4,602.8 | |
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | | $ | 12,410.5 | | | $ | 11,688.0 | |
The accompanying Combined Notes to Financial Statements are an integral part hereof.
52
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
| | | | | | | | | | |
December 31 (In millions except per share data) | | 2022 | | | 2021 | |
STOCKHOLDER'S EQUITY | | | | | | |
Common stock, par value $2.50 per share; authorized 100.0 shares; and outstanding 40.4 shares and 40.4 shares, respectively | | $ | 100.9 | | | $ | 100.9 | |
Premium on common stock | | | 1,473.7 | | | | 1,470.8 | |
Retained earnings | | | 3,470.6 | | | | 3,031.1 | |
Total stockholder's equity | | | 5,045.2 | | | | 4,602.8 | |
| | | | | | | | |
LONG-TERM DEBT | | | | | | | | |
SERIES | | DUE DATE | | | | | | |
Senior Notes | | | | | | | | |
0.553% | | Senior Notes, Series Due May 26, 2023 | | | 500.0 | | | | 500.0 | |
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 | |
3.80% | | Senior Notes, Series Due August 15, 2028 | | | 400.0 | | | | 400.0 | |
3.30% | | Senior Notes, Series Due March 15, 2030 | | | 300.0 | | | | 300.0 | |
3.25% | | Senior Notes, Series Due April 1, 2030 | | | 300.0 | | | | 300.0 | |
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 | | | | 300.0 | |
3.85% | | Senior Notes, Series Due August 15, 2047 | | | 300.0 | | | | 300.0 | |
3.80% | | Tinker Debt, Due August 31, 2062 | | | 9.3 | | | | 9.3 | |
| | | | | | | | |
Other Bonds | | | | | | | | |
0.11% - 3.98% | | Garfield Industrial Authority, January 1, 2025 | | | 47.0 | | | | 47.0 | |
0.11% - 3.95% | | Muskogee Industrial Authority, January 1, 2025 | | | 32.4 | | | | 32.4 | |
0.11% - 3.98% | | Muskogee Industrial Authority, June 1, 2027 | | | 56.0 | | | | 56.0 | |
Unamortized debt expense | | | | | (21.9 | ) | | | (23.7 | ) |
Unamortized discount | | | | | (8.9 | ) | | | (9.5 | ) |
Total long-term debt | | | | | 3,998.9 | | | | 3,996.5 | |
Less: long-term debt due within one year | | | (500.0 | ) | | | — | |
Total long-term debt (excluding long-term debt due within one year) | | | 3,498.9 | | | | 3,996.5 | |
Total capitalization (including long-term debt due within one year) | | $ | 9,044.1 | | | $ | 8,599.3 | |
The accompanying Combined Notes to Financial Statements are an integral part hereof.
53
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
| | | | | | | | | | | | | | | | | | | | |
(In millions) | | Shares Outstanding | | | Common Stock | | | Premium on Common Stock | | | Retained Earnings | | | Total | |
Balance at December 31, 2019 | | | 40.4 | | | $ | 100.9 | | | $ | 935.7 | | | $ | 2,921.7 | | | $ | 3,958.3 | |
Net income | | | — | | | | — | | | | — | | | | 339.4 | | | | 339.4 | |
Dividends declared on common stock | | | — | | | | — | | | | — | | | | (325.0 | ) | | | (325.0 | ) |
Stock-based compensation | | | — | | | | — | | | | 2.9 | | | | — | | | | 2.9 | |
Balance at December 31, 2020 | | | 40.4 | | | $ | 100.9 | | | $ | 938.6 | | | $ | 2,936.1 | | | $ | 3,975.6 | |
Net income | | | — | | | | — | | | | — | | | | 360.0 | | | | 360.0 | |
Dividends declared on common stock | | | — | | | | — | | | | — | | | | (265.0 | ) | | | (265.0 | ) |
Capital contribution from OGE Energy | | | — | | | | — | | | | 530.0 | | | | — | | | | 530.0 | |
Stock-based compensation | | | — | | | | — | | | | 2.2 | | | | — | | | | 2.2 | |
Balance at December 31, 2021 | | | 40.4 | | | $ | 100.9 | | | $ | 1,470.8 | | | $ | 3,031.1 | | | $ | 4,602.8 | |
Net income | | | — | | | | — | | | | — | | | | 439.5 | | | | 439.5 | |
Stock-based compensation | | | — | | | | — | | | | 2.9 | | | | — | | | | 2.9 | |
Balance at December 31, 2022 | | | 40.4 | | | $ | 100.9 | | | $ | 1,473.7 | | | $ | 3,470.6 | | | $ | 5,045.2 | |
The accompanying Combined Notes to Financial Statements are an integral part hereof.
54
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Index of Combined Notes to Financial Statements
The Combined Notes to the Financial Statements are a combined presentation for OGE Energy and OG&E. The following table indicates the Registrant(s) to which each Note applies.
1.Summary of Significant Accounting Policies
Organization
The CompanyOGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity in Oklahoma and western Arkansas. Prior to September 30, 2022, OGE Energy also held investments in Enable and Energy Transfer, which offered natural gas, primarily in the south central U.S. The Company conductscrude oil and NGL services. OGE Energy reports these activities through two business segments: (i) electric utilitycompany and (ii) natural gas midstream operations. The accounts of the CompanyOGE Energy and its wholly-owned subsidiaries, including OG&E, are included in the Consolidated Financial Statements.OGE Energy's consolidated financial statements. All intercompany transactions and balances are eliminated in such consolidation. The Company generally usesFor periods prior to the December 2, 2021 closing of the Enable and Energy Transfer merger, OGE Energy accounted for its investment in Enable as an equity method investment and reported it within OGE Energy's natural gas midstream operations segment. For the period of accountingDecember 2, 2021 through September 30, 2022, OGE Energy accounted for investments where its ownership interest is between 20 percent and 50 percent andinvestment in the Energy Transfer units it lacksacquired in the power to direct activities that most significantly impact economic performance.
Themerger as an investment in equity securities, as further discussed below. As of the end of September 2022, OGE Energy had sold all of its Energy Transfer limited partner units, becoming primarily an electric
utility segmentcompany.
Electric Company Operations. OGE Energy's electric company operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and&E's rates 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.OGE Energy. OG&E is the largest electric utilitycompany 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.
TheNatural Gas Midstream Operations. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment represents the Company'sincluded OGE Energy's investment in Energy Transfer's equity securities acquired in the Enable/Energy Transfer merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. Prior to OGE Energy's sale of all Energy Transfer limited partner units, the investment in Energy Transfer's equity securities was held through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is primarily 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.Enable's general partner 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 accountsOGE Energy accounted for its interestinvestment in Enable using theEnergy Transfer as an investment in equity methodsecurities, as further discussed under "Investment in Equity Securities of accounting.Energy Transfer" below.
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 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.
The following table ispresents a summary of OG&E's regulatory assets and liabilities.
| | | | | | | | |
December 31 (In millions) | 2019 | 2018 |
| REGULATORY ASSETS | | |
| Current: | | |
| Fuel clause under recoveries | $ | 39.5 | | $ | 2.0 | |
| | |
| Production tax credit rider over credit (A) | 1.7 | | 6.9 | |
| Oklahoma demand program rider under recovery (A) | — | | 6.4 | |
| Other (A) | 7.5 | | 3.2 | |
| Total current regulatory assets | $ | 48.7 | | $ | 18.5 | |
| Non-current: | | |
| Benefit obligations regulatory asset | $ | 167.2 | | $ | 188.2 | |
| Deferred storm expenses | 65.5 | | 36.5 | |
| Sooner Dry Scrubbers | 20.6 | | 4.5 | |
| Smart Grid | 18.4 | | 25.6 | |
| Unamortized loss on reacquired debt | 10.6 | | 11.4 | |
| Arkansas deferred pension expenses | 8.0 | | 6.8 | |
| | |
| Pension tracker | 2.3 | | — | |
| Other | 13.4 | | 12.8 | |
| Total non-current regulatory assets | $ | 306.0 | | $ | 285.8 | |
| REGULATORY LIABILITIES | | |
| Current: | | |
| Reserve for tax refund and interim surcharge (B) | $ | 12.7 | | $ | 15.4 | |
| Fuel clause over recoveries | 4.8 | | 0.3 | |
| SPP cost tracker over recovery (B) | 2.6 | | 16.8 | |
| Oklahoma demand program rider over recovery (B) | 2.0 | | — | |
| Transmission cost recovery rider over recovery (B) | — | | 2.7 | |
| Other (B) | 6.9 | | 1.4 | |
| Total current regulatory liabilities | $ | 29.0 | | $ | 36.6 | |
| Non-current: | | |
| Income taxes refundable to customers, net | $ | 899.2 | | $ | 937.1 | |
| Accrued removal obligations, net | 318.5 | | 308.1 | |
| Pension tracker | — | | 18.7 | |
| Other | 5.8 | | 6.8 | |
| Total non-current regulatory liabilities | $ | 1,223.5 | | $ | 1,270.7 | |
| | | | | | | | |
December 31 (In millions) | | 2022 | | | 2021 | |
REGULATORY ASSETS | | | | | | |
Current: | | | | | | |
Oklahoma fuel clause under recoveries | | $ | 474.3 | | | $ | 140.4 | |
Arkansas fuel clause under recoveries | | | 40.6 | | | | 11.5 | |
Oklahoma Energy Efficiency Rider under recoveries (A) | | | 7.7 | | | | 11.7 | |
Other (A) | | | 4.7 | | | | 19.0 | |
Total current regulatory assets | | $ | 527.3 | | | $ | 182.6 | |
Non-current: | | | | | | |
Oklahoma deferred storm expenses | | $ | 206.3 | | | $ | 172.8 | |
Benefit obligations regulatory asset | | | 119.7 | | | | 109.2 | |
Arkansas Winter Storm Uri costs | | | 78.2 | | | | 88.9 | |
Pension tracker | | | 57.2 | | | | 42.9 | |
Sooner Dry Scrubbers | | | 18.1 | | | | 18.9 | |
Arkansas deferred pension expenses | | | 12.3 | | | | 12.1 | |
Unamortized loss on reacquired debt | | | 8.0 | | | | 8.9 | |
COVID-19 impacts | | | 7.7 | | | | 8.2 | |
Frontier Plant deferred expenses | | | 5.2 | | | | 6.7 | |
Oklahoma Winter Storm Uri costs | | | — | | | | 747.9 | |
Other | | | 11.6 | | | | 14.3 | |
Total non-current regulatory assets | | $ | 524.3 | | | $ | 1,230.8 | |
REGULATORY LIABILITIES | | | | | | |
Current: | | | | | | |
SPP cost tracker over recovery (B) | | $ | 3.0 | | | $ | — | |
Other (B) | | | 2.5 | | | | 2.5 | |
Total current regulatory liabilities | | $ | 5.5 | | | $ | 2.5 | |
Non-current: | | | | | | |
Income taxes refundable to customers, net | | $ | 894.7 | | | $ | 930.7 | |
Accrued removal obligations, net | | | 250.5 | | | | 296.8 | |
Other | | | 1.9 | | | | 3.6 | |
Total non-current regulatory liabilities | | $ | 1,147.1 | | | $ | 1,231.1 | |
(A)Included in Other Current Assets in the Consolidated Balance Sheets.balance sheets.
(B)Included in Other Current Liabilities in the Consolidated Balance Sheets.balance sheets.
Fuel clause under and over recoveries are generated from OG&E's customers when OG&E's cost of fuel either exceeds or is less than the amount billed to its customers, respectively. 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.
As approved by the OCC, OG&E utilizes a rider separate from base rates to credit customers for production tax credits.
OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand ProgramEnergy Efficiency Rider, which operates on a three-year program cycle. The current program cycle, which runs through 2021,
2024, includes recovery 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 includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers to a regulatory asset any additional expenses incurred over $2.7 million. OG&E typically recovers the amounts deferred each year over a five to ten year period in accordance with historical practice.
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 historically has 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.
The following table
ispresents a summary of the components of the benefit obligations regulatory
asset:asset. | | | | | | | | |
December 31 (In millions) | | 2022 | | | 2021 | |
Pension Plan and Restoration of Retirement Income Plan: | | | | | | |
Net loss | | $ | 110.0 | | | $ | 89.6 | |
Postretirement Benefit Plans: | | | | | | |
Net loss | | | 9.7 | | | | 23.2 | |
Prior service cost | | | — | | | | (3.6 | ) |
Total | | $ | 119.7 | | | $ | 109.2 | |
| | | | | | | | |
December 31 (In millions) | 2019 | 2018 |
| Pension Plan and Restoration of Retirement Income Plan: | | |
| Net loss | $ | 160.5 | | $ | 185.3 | |
| | |
| Postretirement Benefit Plans: | | | |
| Net loss | 23.3 | | 25.6 | |
| Prior service cost | (16.6) | | (22.7) | |
| Total | $ | 167.2 | | $ | 188.2 | |
In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. The following amounts in the benefit obligations regulatory asset at December 31, 2019 are expected to be recognized as components of net periodic benefit cost in 2020:
| | | | | |
(In millions) | |
Pension Plan and Restoration of Retirement Income Plan: | |
Net loss | $ | 11.4 | |
| |
Postretirement Benefit Plans: | | |
Net loss | 2.8 | |
Prior service cost | (6.1) | |
Total | $ | 8.1 | �� |
OCC allowed OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers tocreate a regulatory asset any additional expenses incurred over $2.7 million.for the Oklahoma portion of all deferred costs, and the Oklahoma Winter Storm Uri regulatory asset was fully recovered in July 2022 through OG&E's receipt of securitization funds from the ODFA, as further discussed in Note 14. In 2021, the APSC allowed OG&E expects to recover the amounts deferred each year over a five-year period in accordance with historical practice.
As approved by the OCC in June 2018, OG&E deferred the non-fuel incremental operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes for the Dry Scrubbers at Sooner Units 1 and 2 as a regulatory asset. As approved by the OCC, these costs are being recovered over 25 years.
OG&E deferred tocreate a regulatory asset for the incrementalArkansas portion of all deferred costs and, stranded costs that were accumulated during Smart Grid deployment, including (i) costs for web portal access, (ii) costs for education and home energy reports and (iii) stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. As approved byas ordered in January 2023, to amortize the OCC and APSC, these costs are being recoveredregulatory asset balance over 10 years using a six-year period.
Unamortized loss on reacquired debt is comprisedweighted average cost of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expense 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 recoveredcapital as a part of OG&E's cost of capital.
Arkansas includes a certain level of pension expensecarrying charge, as further discussed in base rates. When the Pension Plan experiences a settlement, which represents an acceleration of future pension costs, OG&E defers to a regulatory asset the Arkansas jurisdictional portion of each settlement, which historically was recovered from customers over the average life of the remaining plan participants. A portion of these settlements is being recovered in current rates, and recovery of additional amounts will be requested as additional settlements occur. For additional information related to settlements, see Note 13.
OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. 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 review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory asset in the table above.
As
discussed in Note 14, the OCC recently approved recovery of the over/under-recovery balance of the Pension tracker over 15 years, which is a
result of 2018 filingschange from the previous five-year recovery period.
As approved by the OCC, OG&E deferred the non-fuel incremental operation and maintenance expenses, depreciation, debt cost associated with the OCC, APSCcapital investment and FERC,related ad valorem taxes for the Dry Scrubbers at Sooner Units 1 and 2 as a regulatory asset, and these costs are being recovered over 25 years.
Arkansas includes a certain level of pension expense in base rates. When the Pension Plan experiences a settlement, which represents an acceleration of future pension costs, OG&E established mechanismsdefers to refunda regulatory asset the Arkansas jurisdictional portion of each settlement, which historically has been recovered from customers over the average life of the remaining plan participants. A portion of these settlements is being recovered in current rates, and recovery of additional amounts will be requested as additional settlements occur. For additional information related to customerssettlements, see Note 11.
Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the amountearly retirement of excessOG&E's long-term debt. These amounts are recorded in interest expense 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.
In response to the COVID-19 pandemic, the OCC and APSC issued orders allowing OG&E to defer certain expenses related to its COVID-19 response, such as incremental expenses that were related to the suspension of or delay in disconnection of service and additional expenses associated with ensuring the continuity of electric utility service. As discussed in Note 14, the OCC approved recovery of these costs over five years in OG&E's most recent Oklahoma general rate review.
OG&E deferred to a regulatory asset the Oklahoma jurisdictional portion of costs, including non-fuel operation and maintenance expenses, depreciation, taxes received through rates, with an ongoing adjustment for any excess accumulated deferredother than income taxes resulting fromand a return on capital, for its investment in the 2017 Tax Act. Additional amounts due to customers will be refundedFrontier plant. The OCC approved recovery of these costs within base rates through the Oklahoma general rate review order received in accordance with agreements in each jurisdiction.
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 and in Arkansas through the transmission cost recovery rider.
Income taxes refundable to customers, net, primarily represents the reduction in accumulated deferred income taxes resultingthat resulted from the reduction in the federal income tax rate as part of the Tax Cuts and Jobs Act of 2017 Tax Act and includesas well as other state tax rate changes, partially offset by income taxes recoverable from customers that represent income tax benefits previouslyprimarily related to the equity component of the allowance for funds used to reduce OG&E's revenues (treated as regulatory assets).during construction. These net liabilities will be returned to customers in varying amounts over approximately 80 years, and the assets will be amortized over the estimated remaining life of the assets to which they relate, as the temporary differences that generated the income tax benefits turn around.
Accrued removal obligations, net represents asset retirement costs previously recovered from ratepayers for other than legal obligations.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects.
In preparing the Consolidated Financial Statements,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 Statementsfinancial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Company's Consolidated Financial Statements.Registrants' financial statements. However, the Company believes it hasRegistrants believe they have taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the CompanyRegistrants 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 include the determination of Pension Planpension and postretirement 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, unbilled revenues and unbilled revenues.the allowance for uncollectible accounts receivable.
Cash and Cash Equivalents
For purposes of the Consolidated Financial Statements,financial statements, the Company considersRegistrants consider 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 generally 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.off and is adjusted for current conditions and supportable forecasts as necessary. To the extent the historical collection rates, when incorporating forecasted conditions, 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 in the Consolidated Balance Sheetsbalance sheets and is included in Other Operation and Maintenance Expense in the Consolidated Statementsstatements of Income.income. The allowance for uncollectible accounts receivable was $1.5$1.9 million and $1.7$2.4 million at December 31, 20192022 and 2018,2021, respectively.
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, oil and oil.alternative fuel. 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 $46.3$108.8 million and $57.6$40.6 million at December 31, 20192022 and 2018,2021, respectively.
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 net of any salvage proceeds 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 Statementsstatements of Incomeincome as Other Expense. Repair and replacement of minor items of property are included in the Consolidated Statementsstatements of Incomeincome as Other Operation and Maintenance Expense.
The following 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 Statementsstatements of Income.
| | | | | | | | | | | | | | |
December 31, 2019 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| McClain Plant (A) | 77 | % | $ | 254.4 | | $ | 83.5 | | $ | 170.9 | |
| Redbud Plant (A)(B) | 51 | % | $ | 529.9 | | $ | 159.0 | | $ | 370.9 | |
| | | | | | | | | | | | | | | | |
December 31, 2022 (In millions) | | Percentage Ownership | | | Total Property, Plant and Equipment | | | Accumulated Depreciation | | | Net Property, Plant and Equipment | |
McClain Plant (A) | | | 77 | % | | $ | 261.9 | | | $ | 119.4 | | | $ | 142.5 | |
Redbud Plant (A)(B) | | | 51 | % | | $ | 542.1 | | | $ | 225.2 | | | $ | 316.9 | |
(A)Construction work in progress was $0.2$0.7 million and $1.4$1.5 million for the McClain and Redbud Plants, respectively.
(B)This amount includes a plant acquisition adjustment of $148.3$148.3 million and accumulated amortization of $61.8$78.2 million.
| | | | | | | | | | | | | | |
December 31, 2018 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| McClain Plant (A) | 77 | % | $ | 227.2 | | $ | 78.2 | | $ | 149.0 | |
| Redbud Plant (A)(B) | 51 | % | $ | 493.9 | | $ | 145.3 | | $ | 348.6 | |
| | | | | | | | | | | | | | | | |
December 31, 2021 (In millions) | | Percentage Ownership | | | Total Property, Plant and Equipment | | | Accumulated Depreciation | | | Net Property, Plant and Equipment | |
McClain Plant (A) | | | 77 | % | | $ | 258.5 | | | $ | 109.0 | | | $ | 149.5 | |
Redbud Plant (A)(B) | | | 51 | % | | $ | 538.2 | | | $ | 203.4 | | | $ | 334.8 | |
(A)Construction work in progress was $0.2$0.2 million and $0.9$0.2 million for the McClain and Redbud Plants, respectively.
(B)This amount includes a plant acquisition adjustment of $148.3$148.3 million and accumulated amortization of $56.3$72.8 million.
The Company'sfollowing tables present the Registrants' major classes of property, plant and equipment and related accumulated depreciation are divided into the following major classes:
| | | | | | | | | | | |
December 31, 2019 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| OGE Energy: | | | |
| Property, plant and equipment | $ | 6.1 | | $ | — | | $ | 6.1 | |
| OGE Energy property, plant and equipment | 6.1 | | — | | 6.1 | |
| OG&E: | | | |
| Distribution assets | 4,468.6 | | 1,381.1 | | 3,087.5 | |
| Electric generation assets (A) | 4,838.6 | | 1,601.0 | | 3,237.6 | |
| Transmission assets (B) | 2,901.1 | | 565.5 | | 2,335.6 | |
| Intangible plant | 225.2 | | 145.4 | | 79.8 | |
| Other property and equipment | 473.1 | | 175.1 | | 298.0 | |
| OG&E property, plant and equipment | 12,906.6 | | 3,868.1 | | 9,038.5 | |
| Total property, plant and equipment | $ | 12,912.7 | | $ | 3,868.1 | | $ | 9,044.6 | |
| | | | | | | | | | | | |
December 31, 2022 (In millions) | | Total Property, Plant and Equipment | | | Accumulated Depreciation | | | Net Property, Plant and Equipment | |
OG&E: | | | | | | | | | |
Distribution assets | | $ | 5,781.3 | | | $ | 1,527.1 | | | $ | 4,254.2 | |
Electric generation assets (A) | | | 5,188.1 | | | | 1,982.7 | | | | 3,205.4 | |
Transmission assets (B) | | | 3,180.5 | | | | 667.9 | | | | 2,512.6 | |
Intangible plant | | | 384.0 | | | | 193.6 | | | | 190.4 | |
Other property and equipment | | | 591.3 | | | | 213.2 | | | | 378.1 | |
OG&E property, plant and equipment | | | 15,125.2 | | | | 4,584.5 | | | | 10,540.7 | |
Non-OG&E property, plant and equipment | | | 6.1 | | | | — | | | | 6.1 | |
Total OGE Energy property, plant and equipment | | $ | 15,131.3 | | | $ | 4,584.5 | | | $ | 10,546.8 | |
(A)This amount includes a plant acquisition adjustment of $148.3$148.3 million and accumulated amortization of $61.8$78.3 million.
(B)This amount includes a plant acquisition adjustment of $3.3$3.3 million and accumulated amortization of $0.8$1.0 million.
| December 31, 2018 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
| OGE Energy: | | |
| Property, plant and equipment | $ | 6.1 | | $ | — | | $ | 6.1 | | |
| OGE Energy property, plant and equipment | 6.1 | | — | | 6.1 | | |
December 31, 2021 (In millions) | | | Total Property, Plant and Equipment | | | Accumulated Depreciation | | | Net Property, Plant and Equipment | |
| OG&E: | OG&E: | | | | | | | | | | |
| Distribution assets | Distribution assets | 4,229.4 | | 1,324.5 | | 2,904.9 | | | $ | 5,225.8 | | | $ | 1,477.5 | | | $ | 3,748.3 | |
| Electric generation assets (A) | Electric generation assets (A) | 4,657.2 | | 1,572.8 | | 3,084.4 | | | | 5,037.9 | | | | 1,839.0 | | | | 3,198.9 | |
| Transmission assets (B) | Transmission assets (B) | 2,846.7 | | 534.2 | | 2,312.5 | | | | 3,038.2 | | | | 627.0 | | | | 2,411.2 | |
| Intangible plant | Intangible plant | 187.6 | | 135.1 | | 52.5 | | | | 301.1 | | | | 171.7 | | | | 129.4 | |
| Other property and equipment | Other property and equipment | 444.2 | | 160.8 | | 283.4 | | | | 542.7 | | | | 203.7 | | | | 339.0 | |
| OG&E property, plant and equipment | OG&E property, plant and equipment | 12,365.1 | | 3,727.4 | | 8,637.7 | | | | 14,145.7 | | | | 4,318.9 | | | | 9,826.8 | |
| Total property, plant and equipment | $ | 12,371.2 | | $ | 3,727.4 | | $ | 8,643.8 | | |
Non-OG&E property, plant and equipment | | | | 6.1 | | | | — | | | | 6.1 | |
Total OGE Energy property, plant and equipment | | | $ | 14,151.8 | | | $ | 4,318.9 | | | $ | 9,832.9 | |
(A)This amount includes a plant acquisition adjustment of $148.3$148.3 million and accumulated amortization of $56.3$72.8 million.
(B)This amount includes a plant acquisition adjustment of $3.3$3.3 million and accumulated amortization of $0.7$0.9 million.
OG&E's unamortized computer software costs, included in intangible plant above, were $71.3$143.2 million and $44.3$103.7 million at December 31, 20192022 and 2018,2021, respectively.
The following table summarizes the Company's OG&E's amortization expense for computer software costs.costs was $23.5 million, $18.1 million and $14.9 million for the years ended December 31, 2022, 2021 and 2020, respectively.
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| OGE Energy | $ | — | | $ | — | | $ | 0.2 | |
| OG&E | 11.0 | | 9.6 | | 8.8 | |
| Total | $ | 11.0 | | $ | 9.6 | | $ | 9.0 | |
Depreciation and Amortization
The provision for depreciation, which was 2.7 percent and 2.6 percent of the average depreciable utility plant for both 20192022 and 2018,2021, 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 2020,2023, 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, 2019, 98.92022, 43.1 percent will be amortized over 10.46.7 years, with56.3 percent will be amortized over 13.8 years and the remaining 1.10.6 percent of the intangible plant balance at December 31, 2019 beingwill be amortized over 23.722.4 years.
Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired assets. Plant acquisition adjustments include $148.3$148.3 million for the Redbud Plant, which is being amortized over a 27- year life, and $3.3$3.3 million for certain transmission substation facilities in OG&E's service territory, which areis being amortized over a 37 to 59 year-year period.
Investment in Unconsolidated Affiliates
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 not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; therefore, 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, 2019 as presented in Note 14. 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 CompanyOG&E has recorded asset retirement obligations that are being accreted over their respective lives ranging from tenfive to 68 years. years. Asset retirement obligations are included in Other Deferred Credits in the Registrants' balance sheets.
The following table summarizespresents changes to the Company'sOG&E's asset retirement obligations during the years ended December 31, 20192022 and 2018.
| | | | | | | | |
| (In millions) | 2019 | 2018 |
| Balance at January 1 | $ | 83.9 | | $ | 75.1 | |
| Accretion expense | 1.0 | | 3.4 | |
| Revisions in estimated cash flows (A) | (2.4) | | 6.8 | |
| | |
| Liabilities settled (B) | (9.0) | | (1.4) | |
| Balance at December 31 | $ | 73.5 | | $ | 83.9 | |
(A)2021.Assumptions changed related to the estimated cost of the removal of wind turbine assets and asbestos removal at OG&E's generating facilities.
(B)Asset retirement obligations were settled for asbestos removal and for the closure of an ash pond at OG&E's generating facilities.
77 | | | | | | | | |
(In millions) | | 2022 | | | 2021 | |
Balance at January 1 | | $ | 80.2 | | | $ | 79.6 | |
Accretion expense | | | 0.6 | | | | 0.6 | |
Liabilities settled | | | (2.5 | ) | | | — | |
Balance at December 31 | | $ | 78.3 | | | $ | 80.2 | |
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 CompanyOG&E had $18.7$24.2 million and $23.4$25.8 million in accrued environmental liabilities at December 31, 20192022 and 2018,2021, respectively, which are included in the Company's OG&E's asset retirement obligations.obligations.
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 Statementsstatements of Incomeincome and as an increase to Construction Work in Progress in the Consolidated Balance Sheets.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 7.64.8 percent, 7.67.4 percent and 8.27.3 percent for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, 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.
Revenue Recognition
OG&E recognizes revenue from electric sales when power is delivered to customers. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E readsmeasures its customers' metersmetered usage 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 in the Consolidated Balance Sheetsbalance sheets and in Revenues from Contracts with Customers in the Consolidated Statementsstatements of Incomeincome 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.
Integrated Market and Transmission
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. Purchases and sales are based on the fixed transaction price determined by the market at the time of the purchase or sale and the MWh quantity purchased or sold. These results are reported as Revenues from Contracts with Customers or Cost of SalesFuel, Purchased Power and Direct Transmission Expense in the Consolidated Financial Statements.statements of income. OG&E&E's revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.
OG&E's transmission revenues are generated by the use of OG&E's transmission network by the SPP, which operates the network, on behalf of other transmission owners. OG&E recognizes revenue on the sale of transmission service to its customers over time as the service is provided in the amount OG&E has a right to invoice. Transmission service to the SPP is billed monthly based on a fixed transaction price determined by OG&E's FERC-approved formula transmission rates along with other SPP-specific charges and the megawatt quantity reserved.
Other Revenues
Revenues from Alternative Revenue Programs
Other Revenues in the Consolidated Statementsstatements of Incomeincome is comprised of certain rider revenue that includes alternative revenue measures as defined in ASC 980, "Regulated Operations," which details two types of alternative revenue programs. The first type adjusts billings for the effects of weather abnormalities or broad external factors or to compensate OG&E for demand-side management initiatives (i.e., no-growth plans and similar conservation efforts). The second type provides for additional billings (i.e., incentive awards) for the achievement of certain objectives, such as reducing costs, reaching specified milestones or demonstratively improving customer service. Once the specific events permitting billing of the additional revenues under either program type have been completed, OG&E recognizes the additional revenues if (i) the program is established by an order from OG&E's regulatory commission that allows for automatic
adjustment of future rates; (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery; and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.
Fuel Adjustment Clauses
The actual cost of fuel used in electric generation and certain purchased power costs are passed through togenerally recoverable from OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.
Leases
The Company evaluatesRegistrants evaluate all contracts under ASC 842 to determine if the contract is or contains a lease and to determine classification as an operating or finance lease. If a lease is identified, the Company recognizesRegistrants recognize a right-of-use asset and a lease liability in its Consolidated Balance Sheets.their balance sheets. The Company recognizesRegistrants recognize and measuresmeasure a lease liability when it concludesthey conclude the contract contains an identified asset that the Company controlsRegistrants control through having the right to obtain substantially all of the economic benefits and the right to direct the use of the identified asset. The liability is equal to the present value of lease payments, and the asset is based on the liability, subject to adjustment, such as for initial direct costs. Further, the Company utilizesRegistrants utilize an incremental borrowing rate for purposes of measuring lease liabilities, if the discount rate is not implicit in the lease. To calculate the incremental borrowing rate, the Company startsRegistrants start with a current pricing report for the Company'stheir senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjustsadjust for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted by ASC 842, the CompanyRegistrants made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from nonleasenon-lease components when recognizing and measuring lease liabilities. For income statement purposes, the Company recordsRegistrants record operating lease expense on a straight-line basis.
Income Taxes
The Company
OGE Energy files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. OG&E is a part of the consolidated tax return of OGE Energy. Income taxes are generally allocated to each company in the affiliated group, including OG&E, based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utilitycompany property have been deferred and will be amortized to income over the life of the related property. The Company usesRegistrants use 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 recognizesRegistrants recognize interest related to unrecognized tax benefits in Interest Expense and recognizesrecognize penalties in Other Expense in the Consolidated Statementsstatements of Income.income. Deferred tax assets are evaluated for future realization and reduced by a valuation allowance to the extent the Registrants believe they will not be realized.
Accrued Vacation
The Company accruesRegistrants accrue 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.
OGE Energy charges operating costs to OG&E based on several factors, and operating costs directly related to OG&E are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method, which is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted this method as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.
OGE Energy charged operating costs to OG&E of $135.5 million, $139.3 million and $140.6 million during the years ended December 31, 2022, 2021 and 2020, respectively. In 2022, no dividends were declared from OG&E to OGE Energy. In 2021 and 2020, OG&E declared dividends to OGE Energy of $265.0 million and $325.0 million, respectively.
Accumulated Other Comprehensive Income (Loss)
The following tables summarizetable presents changes in the components of accumulated other comprehensive income (loss) attributable to the CompanyOGE Energy during 20182022 and 2019.2021. All amounts below are presented net of tax.
| | | | | | | | | | | | | | | | | | |
| Pension Plan and Restoration of Retirement Income Plan | | Postretirement Benefit Plans | | | | | |
(In millions) | Net Gain (Loss) | | Prior Service Cost (Credit) | | Net Gain (Loss) | | Prior Service Cost (Credit) | | Other Comprehensive Gain (Loss) from Unconsolidated Affiliates | | Total | |
Balance at December 31, 2020 | $ | (33.9 | ) | $ | (0.2 | ) | $ | 1.7 | | $ | 1.6 | | $ | (1.3 | ) | $ | (32.1 | ) |
Other comprehensive income (loss) before reclassifications | | 1.4 | | | (1.1 | ) | | (0.7 | ) | | — | | | 1.3 | | | 0.9 | |
Amounts reclassified from accumulated other comprehensive income (loss) | | 1.6 | | | 0.1 | | | 0.1 | | | (1.4 | ) | | — | | | 0.4 | |
Settlement cost | | 6.0 | | | — | | | — | | | — | | | — | | | 6.0 | |
Net current period other comprehensive income (loss) | | 9.0 | | | (1.0 | ) | | (0.6 | ) | | (1.4 | ) | | 1.3 | | | 7.3 | |
Balance at December 31, 2021 | | (24.9 | ) | | (1.2 | ) | | 1.1 | | | 0.2 | | | — | | | (24.8 | ) |
Other comprehensive income (loss) before reclassifications | | (7.6 | ) | | — | | | 5.5 | | | — | | | — | | | (2.1 | ) |
Amounts reclassified from accumulated other comprehensive income (loss) | | 1.4 | | | 0.2 | | | — | | | (0.2 | ) | | — | | | 1.4 | |
Settlement cost | | 13.6 | | | — | | | — | | | — | | | — | | | 13.6 | |
Net current period other comprehensive income (loss) | | 7.4 | | | 0.2 | | | 5.5 | | | (0.2 | ) | | — | | | 12.9 | |
Balance at December 31, 2022 | $ | (17.5 | ) | $ | (1.0 | ) | $ | 6.6 | | $ | — | | $ | — | | $ | (11.9 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| Pension Plan and Restoration of Retirement Income Plan | | | | Postretirement Benefit Plans | | | | | |
| (In millions) | Net Gain
(Loss) | | | | Net Gain (Loss) | Prior Service Cost (Credit) | Other Comprehensive Loss from Unconsolidated Affiliates | | | Total |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Balance at December 31, 2017 | $ | (32.7) | | | | | $ | 2.5 | | $ | 7.0 | | $ | — | | | | $ | (23.2) | |
| Other comprehensive income (loss) before reclassifications | (14.1) | | | | | 2.1 | | — | | — | | | | (12.0) | |
| Amounts reclassified from accumulated other comprehensive income (loss) | 3.3 | | | | | — | | (1.7) | | — | | | | 1.6 | |
| | | | | | | | | | |
| Settlement cost | 4.7 | | | | | — | | — | | — | | | | 4.7 | |
| Net current period other comprehensive income (loss) | (6.1) | | | | | 2.1 | | (1.7) | | — | | | | (5.7) | |
| Balance at December 31, 2018 | (38.8) | | | | | 4.6 | | 5.3 | | — | | | | (28.9) | |
| Other comprehensive income (loss) before reclassifications | (8.3) | | | | | (0.2) | | — | | (0.6) | | | | (9.1) | |
| Amounts reclassified from accumulated other comprehensive income (loss) | 3.4 | | | | | (0.2) | | (1.7) | | — | | | | 1.5 | |
| Settlement cost | 8.6 | | | | | — | | — | | — | | | | 8.6 | |
| Net current period other comprehensive income (loss) | 3.7 | | | | | (0.4) | | (1.7) | | (0.6) | | | | 1.0 | |
| Balance at December 31, 2019 | $ | (35.1) | | | | | $ | 4.2 | | $ | 3.6 | | $ | (0.6) | | | | $ | (27.9) | |
The following table summarizespresents significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the years ended December 31, 20192022 and 2018.
| | | | | | | | | | | |
| Details about Accumulated Other Comprehensive Income (Loss) Components | Amount Reclassified from Accumulated Other Comprehensive Income (Loss) | | Affected Line Item in the Consolidated Statements of Income |
| Year Ended December 31, | | |
| (In millions) | 2019 | 2018 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Amortization of Pension Plan and Restoration of Retirement Income Plan items: | | | |
| Actuarial losses | $ | (4.5) | | $ | (4.4) | | (A) |
| | | |
| Settlement cost | (11.3) | | (6.3) | | (A) |
| (15.8) | | (10.7) | | Income Before Taxes |
| (3.8) | | (2.7) | | Income Tax Expense |
| | | |
| | | |
| $ | (12.0) | | $ | (8.0) | | Net Income |
| | | |
| Amortization of postretirement benefit plans items: | | | |
| | | |
| Prior service credit | $ | 2.3 | | $ | 2.3 | | (A) |
| Actuarial gains | 0.2 | | — | | (A) |
| 2.5 | | 2.3 | | Income Before Taxes |
| 0.6 | | 0.6 | | Income Tax Expense |
| $ | 1.9 | | $ | 1.7 | | Net Income |
| | | |
| | | |
| | | |
| Total reclassifications for the period, net of tax | $ | (10.1) | | $ | (6.3) | | Net Income |
| | | | | | | | |
Details about Accumulated Other Comprehensive Income (Loss) Components | Amount Reclassified from Accumulated Other Comprehensive Income (Loss) | | Affected Line Item in
OGE Energy's Statements of Income |
| Year Ended December 31, | | |
(In millions) | 2022 | | | 2021 | | |
Amortization of Pension Plan and Restoration of Retirement Income Plan items: | | | | | | |
Actuarial losses | $ | (1.6 | ) | | $ | (2.5 | ) | (A) |
Prior service cost | | (0.3 | ) | | | (0.1 | ) | (A) |
Settlement cost | | (17.9 | ) | | | (8.7 | ) | (A) |
| | (19.8 | ) | | | (11.3 | ) | Income Before Taxes |
| | (4.6 | ) | | | (3.6 | ) | Income Tax Expense |
| $ | (15.2 | ) | | $ | (7.7 | ) | Net Income |
| | | | | | |
Amortization of postretirement benefit plans items: | | | | | | |
Prior service credit | $ | 0.3 | | | $ | 1.8 | | (A) |
Actuarial losses | | — | | | | (0.1 | ) | (A) |
| | 0.3 | | | | 1.7 | | Income Before Taxes |
| | 0.1 | | | | 0.4 | | Income Tax Expense |
| $ | 0.2 | | | $ | 1.3 | | Net Income |
| | | | | | |
Total reclassifications for the period, net of tax | $ | (15.0 | ) | | $ | (6.4 | ) | Net Income |
(A)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 1311 for additional information).
The amountsInvestment in Unconsolidated Affiliates and Related Party Transactions (Enable)
On December 2, 2021, Energy Transfer completed its acquisition of Enable, and all of the 110,982,805 common units of Enable owned by OGE Energy were exchanged for 95,389,721 common units of Energy Transfer. As part of the transaction, Energy Transfer also acquired the general partner interests of Enable from OGE Energy and CenterPoint for cash consideration. OGE Energy accounted for its investment in Enable as an equity method investment until the merger with Energy Transfer closed on December 2, 2021. As a result of the transaction, OGE Energy recorded a pre-tax gain of $344.4 million, which contemplates the December 2, 2021 fair value of the Energy Transfer securities, the December 2, 2021 balance of OGE Energy's equity method investment in Enable, the $35.0 million cash payment received as part of the transaction ($5.0 million from Energy Transfer and $30.0 million from CenterPoint), the accumulated other comprehensive loss (gain)impact of OGE Energy's share of Enable's interest rate derivative losses and OGE Energy's transaction costs of $8.6 million. Further discussion of the transaction can be found in OGE Energy's 2021 Form 10-K.
Under the equity method, the investment was adjusted each period for contributions made, distributions received and OGE Energy's share of the investee's comprehensive income as adjusted for basis differences.
OGE Energy considered distributions received from Enable which did not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and were classified as operating activities in the statements of cash flows. OGE Energy considered distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and were classified as investing activities in the statements of cash flows.
In this Form 10-K, Enable activity is included for the relevant portion of OGE Energy's 2021 information presented through December 2, 2021. The below information is provided for prior year context.
The following tables present summarized unaudited financial information for 100 percent of Enable as of December 2, 2021 and for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020.
| | | | |
Balance Sheet | | December 2, 2021 | |
(In millions) | | | |
Current assets | | $ | 594 | |
Non-current assets | | $ | 11,227 | |
Current liabilities | | $ | 1,254 | |
Non-current liabilities | | $ | 3,281 | |
| | | | | | | | |
| | Period of | | | | |
Income Statement | | January 1, 2021 through
December 2, 2021 | | | Year Ended
December 31, 2020 | |
(In millions) | | | | | | |
Total revenues | | $ | 3,466 | | | $ | 2,463 | |
Cost of natural gas and NGLs (excluding depreciation and amortization) | | $ | 1,959 | | | $ | 965 | |
Operating income | | $ | 634 | | | $ | 465 | |
Net income | | $ | 461 | | | $ | 52 | |
The following table presents a reconciliation of OGE Energy's equity in earnings (losses) of unconsolidated affiliates for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020.
| | | | | | | | |
| | Period of | | | | |
(In millions) | | January 1, 2021 through
December 2, 2021 | | | Year Ended
December 31, 2020 | |
Enable net income | | $ | 461.0 | | | $ | 52.0 | |
Differences due to timing of OGE Energy and Enable accounting close | | | 9.0 | | | | — | |
Enable net income used to calculate OGE Energy's equity in earnings | | $ | 470.0 | | | $ | 52.0 | |
OGE Energy's percent ownership at period end | | | 25.5 | % | | | 25.5 | % |
OGE Energy's portion of Enable net income | | $ | 119.8 | | | $ | 13.2 | |
Amortization of basis difference and dilution recognition (A) | | | 50.0 | | | | 98.8 | |
Impairment of OGE Energy's equity method investment in Enable (B) | | | — | | | | (780.0 | ) |
Equity in earnings (losses) of unconsolidated affiliates (C) | | $ | 169.8 | | | $ | (668.0 | ) |
(A)Includes loss on dilution, net of proportional basis difference recognition.
(B)During the year ended December 31, 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable as, effective March 31, 2020, OGE estimated the fair value of its investment in Enable was below the book value and concluded the decline in value was not temporary.
(C)For the year ended December 31, 2020, Enable recorded a $225.0 million impairment on an equity method investment, which ran through OGE Energy's portion of Enable net income and was offset by basis differences that flow through the amortization of basis difference and dilution recognition line item above.
Distributions received from Enable were $73.4 million and $91.7 million during the years ended December 31, 2021 and 2020, respectively.
Related Party Transactions - OGE Energy and Enable
Prior to December 2, 2021, OGE Energy charged operating costs to Enable based on several factors, and operating costs directly related to Enable were assigned as such.
Further, OGE Energy and Enable were parties to several agreements whereby OGE Energy provided specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, OGE Energy charged operating costs to Enable of $0.3 million and $0.4 million for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020, respectively.
OGE Energy also provided retirement benefits and retiree health care benefits to employees previously seconded to Enable. OGE Energy billed Enable for reimbursement of $12.2 million and $17.3 million in 2021 and 2020, respectively, under the former seconding agreement for employment costs. As of a result of the merger between Enable and Energy Transfer, the seconding agreement was terminated, and those employees are no longer employed by OGE Energy. If lump sum payments were made to those employees previously seconded to Enable, OGE Energy would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at OGE Energy by $5.1 million. Settlement and curtailment charges associated with the employees previously seconded to Enable are not reimbursable to OGE Energy.
OGE Energy had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $0.3 million as of December 31, 2021, which is included in Accounts Receivable in OGE Energy's balance sheets.
Related Party Transactions - OG&E and Enable
Enable provided gas transportation services to OG&E pursuant to agreements that granted Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. Upon the closing of the merger between Enable and Energy Transfer, these contracts were assumed by Energy Transfer. The following table presents summarized related party transactions between OG&E and Enable during the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020.
| | | | | | | | |
| | Period of | | | | |
(In millions) | | January 1, 2021 through
December 2, 2021 | | | Year Ended
December 31, 2020 | |
Operating revenues: | | | | | | |
Electricity to power electric compression assets | | $ | 13.3 | | | $ | 15.1 | |
Fuel, purchased power and direct transmission expense: | | | | | | |
Natural gas transportation services | | $ | 32.7 | | | $ | 32.8 | |
Natural gas purchases (sales) | | $ | (33.5 | ) | | $ | 2.7 | |
Investment in Equity Securities of Energy Transfer
For the period of December 2, 2021 through September 30, 2022, OGE Energy accounted for its investment in Energy Transfer's equity securities as an equity investment with a readily determinable fair value under ASC 321, "Investments – Equity Securities." As of the end of September 2022, OGE Energy had sold all of its 95.4 million Energy Transfer limited partner units, resulting in pre-tax net proceeds of $1,067.2 million. Prior to exiting its Energy Transfer investment, OGE Energy presented the Energy Transfer equity securities at fair value in its balance sheet. OGE Energy presents realized gains and losses of the equity securities, as well as dividend income from the investment, within the Other Income (Expense) section in its statement of income, as appropriate. During the year ended December 31, 2022, OGE Energy recognized a gain of $282.1 million related to its investment in Energy Transfer's equity securities. Due to OGE Energy's sale of all Energy Transfer limited partner units, at December 31, 2019 that are expected to be recognized into earnings in 2020 are as follows:
| | | | | |
(In millions)2022, there is | |
Pension Plan and Restoration of Retirement Income Plan: | |
Net gain | $ | (4.2) | |
| |
Postretirement Benefit Plans: | | |
Net loss | 0.2 | |
Prior service cost | 2.3 | |
| |
| |
Total, net of tax | $ | (1.7) | |
Reclassifications
Certain prior year amounts have been reclassified to conform unrecognized gain or loss related to the currentinvestment. For the period between December 2, 2021 and December 31, 2021, OGE Energy had an unrealized loss of $8.6 million related to its investment in Energy Transfer's equity securities. During the year presentation.ended December 31, 2022, OGE Energy received distributions of $34.0 million from Energy Transfer, which are presented within Other Income in OGE Energy's 2022 consolidated income statement.
2.Accounting Pronouncements
Recently AdoptedIn November 2021, the Financial Accounting Standards
Leases. In February 2016, the FASB Board issued ASU 2016-02, "Leases2021-10, "Government Assistance (Topic 842).832) Disclosures by Business Entities about Government Assistance." The main difference between prior leaseThis standard requires additional annual disclosures when a business receives government assistance and uses a grant or contribution accounting and ASC 842 is the recognition of right-of-use assets and lease liabilitiesmodel by lessees for those leases classified as operating leases under currentanalogy to other accounting guidance. Lessees,guidance such as the Company, recognize a right-of-use assetgrant model under International Accounting Standards 20, "Accounting for Government Grants and a lease liability for virtually allDisclosures of their leases, other than leases that meetGovernment Assistance" and GAAP ASC 958-605, "Not-for-Profit Entities - Revenue Recognition." The standard was effective January 1, 2022, and the definition of a short-term lease. The liability is equal to the present value of lease payments. The asset is based on the liability, subject to adjustment for items such as initial direct costs. For income statement purposes, ASC 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases result in straight-line expense, while finance leases result in a front-loaded expense pattern, similar to prior capital leases. Classification of operating and finance leases is based on criteria that are largely similar to those applied in
prior lease guidance but without the explicit thresholds. The CompanyRegistrants adopted this standard
prospectively. As further discussed in Note 14, the ODFA issued securitization bonds in July 2022, and, in connection with this securitization transaction, OG&E received approximately $750 million from the ODFA to fund the extreme fuel and purchased power costs incurred by OG&E during Winter Storm Uri. The Registrants accounted for this transaction by analogy to the grant model under International Accounting Standards 20, as the Registrants believe there is no specific GAAP guidance directly applicable to the Registrants' facts and circumstances. The Registrants recorded the receipt of proceeds from the ODFA and removal of the Oklahoma Winter Storm Uri regulatory asset by debiting Cash and Cash Equivalents and crediting Regulatory Assets in their 2022 condensed balance sheets. Further, this transaction is reflected within Operating Activities in the first quarterRegistrants' 2022 condensed statements of 2019 utilizingcash flows.
In September 2022, the modified retrospective transition method.
Various practical expedients for the application of ASC 842 were approved, and the Company elected to apply the below:
•a package of practical expedients allowing entities to not reassess (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases and (iii) initial direct costs for any existing leases;
•an option that permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under ASC 842 land easements that exist or expired before the entity's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840, "Leases"; and
•an option that permits an entity to elect to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, provided that if an entity elects this additional (and optional) transition method, the entity will provide the required ASC 840 disclosures for all periods that continue to be reported under ASC 840.
The Company evaluated its current lease contracts and, at January 1, 2019, recognized $34.5 million and $39.1 million of operating lease right-of-use assets and liabilities, respectively, for railcar, wind farm land and office space leases in the Consolidated Balance Sheet. The new standard did not have a material impact on the Company's 2019 Consolidated Statement of Income. Further, the Company evaluated its existing processes and controls regarding lease identification, accounting and presentation and implemented changes as necessary in order to adequately address the requirements of ASC 842.
Financial Instruments-Credit Losses. In June 2016, the FASBAccounting Standards Board issued ASU No. 2016-13, "Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Information.2022-04, "Liabilities - Supplier Finance Programs (Subtopic 405-50)." The amendments in this update require entities to measure all expected credit losses of financial assets held atthat a reporting date based on historical experience, current conditions and reasonable and supportable forecasts in order to record credit lossesbuyer in a more timely manner. ASU 2016-13 also amendssupplier finance program disclose in each annual reporting period: (i) the accountingkey terms of the program, including a description of the payment terms and assets pledged as security or other forms of guarantees provided for credit losses on available-for-sale debt securitiesthe committed payment to the finance provider and purchased financial assets with credit deterioration. ASU 2016-13(2) the amount outstanding that remains unpaid by the buyer as of year-end, a description of where those obligations are presented in the balance sheet and a rollforward of those obligations during the annual period. The standard is effective for fiscal years beginning after December 2019 and is applied utilizing a modified-retrospective approach. The Company determined the only financial instrument that the Company currently holds and is required to measure under ASU 2016-13 is its trade receivables. Upon adoption of this ASU, the Company considers forecasts of future economic conditions in addition to the historical data utilized prior to ASU 2016-13 when measuring the reserve for trade receivables. The Company evaluated its reserve for trade receivables in light of the new guidance and determined that no adjustment was necessary to the amount recorded as of January 1, 2020.
Accounting2023, except for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. In August 2018, the FASB issued ASU 2018-15, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." The new guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. ASU 2018-15amendment on rollforward information, which is effective for fiscal years beginning after December 2019 and can be applied either retrospectively or prospectively to all implementation costs incurred afterJanuary 1, 2024. Early adoption is permitted. The Registrants are currently evaluating the dateimpact of adoption. adopting this standard on their financial statements.
The CompanyRegistrants believe that other recently adopted and prospectively applied the new guidance beginning in the first quarter of 2020, which didrecently issued accounting standards that are not yet effective do not appear to have a material effectimpact on the Consolidated Financial StatementsRegistrants' financial position, results of operations or cash flows upon adoption.
Issued Accounting Standards Not Yet Adopted
Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740)." The new guidance simplifies the accounting for income taxes by removing certain exceptions to the general principles in ASC 740 and improves consistent application of existing guidance. ASU 2019-12 will be effective for the Company as of January 1, 2021 and can be early adopted. The Company is currently assessing the impact of these rule changes on its Consolidated Financial Statements.
Investments - Equity Method and Joint Ventures. In January 2020, the FASB issued ASU 2020-01, "Investments - Equity Securities (Topic 321), Investments - Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815)." The new guidance makes targeted improvements to address certain aspects of accounting for financial instruments, clarifying the interaction of the accounting for equity securities under ASC 321 and investments accounted for under the equity method of accounting in ASC 323. ASU 2020-01 should be applied prospectively and will be effective for the
Company as of January 1, 2021. The Company is currently assessing the impact of these rule changes on its Consolidated Financial Statements.
The following table
disaggregates the Company'spresents OG&E's revenues from contracts with customers
disaggregated by customer classification.
The Company'sOG&E's operating revenues disaggregated by customer classification can be found in "OG&E (Electric
Utility)Company) Results of Operations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
| | | | | | | | | | | | |
| | Year Ended December 31, | |
(In millions) | | 2022 | | | 2021 | | | 2020 | |
Residential | | $ | 1,272.6 | | | $ | 1,309.1 | | | $ | 842.7 | |
Commercial | | | 803.5 | | | | 749.2 | | | | 465.6 | |
Industrial | | | 317.2 | | | | 323.0 | | | | 192.6 | |
Oilfield | | | 304.2 | | | | 312.8 | | | | 169.2 | |
Public authorities and street light | | | 291.6 | | | | 284.4 | | | | 172.3 | |
System sales revenues | | | 2,989.1 | | | | 2,978.5 | | | | 1,842.4 | |
Provision for rate refund | | | (1.2 | ) | | | — | | | | 3.8 | |
Integrated market | | | 163.8 | | | | 468.9 | | | | 49.6 | |
Transmission | | | 131.7 | | | | 140.2 | | | | 143.3 | |
Other | | | 20.8 | | | | 1.1 | | | | 30.7 | |
Revenues from contracts with customers | | $ | 3,304.2 | | | $ | 3,588.7 | | | $ | 2,069.8 | |
| | | | | | | | |
| | |
| | |
| Year Ended December 31, | |
| (In millions) | 2019 | 2018 |
| Residential | $ | 865.8 | | $ | 877.8 | |
| Commercial | 486.6 | | 500.0 | |
| Industrial | 217.8 | | 228.9 | |
| Oilfield | 200.4 | | 190.4 | |
| Public authorities and street light | 190.3 | | 197.4 | |
| System sales revenues | 1,960.9 | | 1,994.5 | |
| Provision for rate refund | (0.9) | | (6.0) | |
| Integrated market | 38.4 | | 48.7 | |
| Transmission | 148.0 | | 147.4 | |
| Other | 29.1 | | 27.1 | |
| Revenues from contracts with customers | $ | 2,175.5 | | $ | 2,211.7 | |
Leases
Based on itstheir evaluation of all contracts under ASC 842, as described in Note 1, the CompanyRegistrants concluded it hasthey have operating lease obligations for OG&E railcar leases, OG&E wind farm land leases and the Company's office space lease.
as described below.
Operating Leases
OG&E Railcar Lease Agreement
Effective February 1, 2019, OG&E renewedholds a railcar lease agreement for 780 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 recoveredrecoverable through OG&E's fuel adjustment clauses. On February 1, 2024, 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 $6.8$6.8 million.
Effective October 1, 2022, OG&E entered into an additional railcar lease agreement for 135 rotary gondola railcars to transport coal with a term of October 1, 2022 to December 31, 2025.
OG&E Wind Farm Land Lease Agreements
OG&E has operating leases related to land for OG&E's Centennial, OU Spirit and Crossroads wind farms with terms of 25 to 30 years. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. While lease liabilities are not remeasured as a result of changes to the Consumer Price Index, changes to the Consumer Price Index are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. 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.
Office Space Lease
The Company has a noncancellable office space lease agreement, with a term from September 1, 2018 to August 31, 2021, that allows for leasehold improvements.
Financial Statement Information and Maturity Analysis of Lease Liabilities
Operating lease cost was $6.0 million, $4.9 million and $6.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. The following table presentstables present amounts recognized for operating leases in the Company's 2019 Consolidated Cash Flow StatementRegistrants' income statements, cash flow statements and Balance Sheetbalance sheets and supplemental information related to those amounts recognized, as well as a maturity analysis of the Company's operating lease liabilities.
| | | | | | |
| | |
(In millions) | Year Ended December 31, 2019 | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Cash paid for amounts included in the measurement of lease liabilities: | | |
| | |
Operating cash flows for operating leases | $ | 5.6 | | |
| | |
Right-of-use assets obtained in exchange for new operating lease liabilities | $ | 10.7 | | |
| | |
| | |
| | |
| | |
(Dollars in millions) | December 31, 2019 | |
Right-of-use assets at period end (A) | $ | 40.9 | | |
Operating lease liabilities at period end (B) | $ | 45.8 | | |
Operating lease weighted-average remaining lease term (in years)
| 13.1 | |
Operating lease weighted-average discount rate | 3.9 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
| | Year Ended December 31, | | | Year Ended December 31, | |
(In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Operating lease cost | | $ | 5.9 | | | $ | 6.3 | | | $ | 6.4 | | | $ | 5.9 | | | $ | 5.7 | | | $ | 5.5 | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | | | | | | | | | | | | |
Operating cash flows for operating leases | | $ | 5.3 | | | $ | 6.3 | | | $ | 6.4 | | | $ | 5.3 | | | $ | 5.7 | | | $ | 5.5 | |
Right-of-use assets obtained in exchange for new operating lease liabilities | | $ | 1.5 | | | $ | — | | | $ | 1.4 | | | $ | 1.5 | | | $ | — | | | $ | 1.4 | |
| | | | | | | | | | | | | |
| OGE Energy | | | OG&E | |
(Dollars in millions) | December 31, 2022 | | December 31, 2021 | | | December 31, 2022 | | December 31, 2021 | |
Right-of-use assets at period end (A) | $ | 30.2 | | $ | 33.0 | | | $ | 30.2 | | $ | 33.0 | |
Operating lease liabilities at period end (B) | $ | 34.8 | | $ | 37.6 | | | $ | 34.8 | | $ | 37.6 | |
Operating lease weighted-average remaining lease term (in years) | | 11.6 | | | 12.2 | | | | 11.6 | | | 12.2 | |
Operating lease weighted-average discount rate | | 4.0 | % | | 3.9 | % | | | 4.0 | % | | 3.9 | % |
| | | | | | | | |
| December 31, | |
| Future minimum operating lease payments as of: | 2019 | 2018(C)(D) |
| (In millions) | | |
| 2019 | $ | — | | $ | 22.1 | |
| 2020 | 6.2 | | 3.9 | |
| 2021 | 5.8 | | 3.5 | |
| 2022 | 5.2 | | 2.9 | |
| 2023 | 5.2 | | 2.9 | |
| 2024 | 3.1 | | 3.0 | |
| Thereafter | 34.7 | | 34.6 | |
| Total future minimum lease payments | 60.2 | | $ | 72.9 | |
| Less: Imputed interest | 14.4 | | |
| Present value of net minimum lease payments | $ | 45.8 | | |
(A) Included in Property, Plant and Equipment in the 2019 Consolidated Balance Sheet.Registrants' balance sheets.
(B)Included in Other Deferred Credits and Other Liabilities in the 2019 Consolidated Balance Sheet.
(C) Amounts included for comparability and accounted for in accordance with ASC 840, "Leases."
(D) At the end of the railcar lease term, which was February 1, 2019, OG&E had the option to either purchase the railcars at a stipulated fair market value or renew the lease. OG&E renewed the lease effective February 1, 2019. If OG&E chose not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars was less than the stipulated fair market value, OG&E would have been responsible for the difference in those values up to a maximum of $16.2 million.
84Registrants' balance sheets.
5.Investment in Unconsolidated Affiliates and Related Party Transactions
In 2013, the Company, CenterPoint and the ArcLight group formed Enable as a private limited partnership, and 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 recorded the contribution at historical cost. 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 was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion. Since the contribution of Enogex LLC to Enable was recorded 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. As prior real estate sales accounting guidance was superseded by ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets," the Company recognizes gains or losses on sales or dilution events in the Company's investment in Enable within the Company's earnings, net of proportional basis difference recognition.
At December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On December 31, 2019, Enable's common unit price closed at $10.03. The Company recorded equity in earnings of unconsolidated affiliates of $113.9 million, $152.8 million and $131.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's 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. The basis difference is being amortized, beginning in 2013, over the average life of the assets to which the basis difference is attributed, which is approximately 30 years. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above. These amortizations may also include gain or loss on dilution, net of proportional basis difference recognition.
Summarized unaudited financial information for 100 percent of Enable is presented below as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017.
| | | | | | | | |
| December 31, | |
| Balance Sheet | 2019 | 2018 |
| (In millions) | | |
| Current assets | $ | 389 | | $ | 449 | |
| Non-current assets | $ | 11,877 | | $ | 11,995 | |
| Current liabilities | $ | 780 | | $ | 1,615 | |
| Non-current liabilities | $ | 4,077 | | $ | 3,211 | |
| | | | | | | | | | | |
| Year Ended December 31, | | |
| Income Statement | 2019 | 2018 | 2017 |
| (In millions) | | | |
| Total revenues | $ | 2,960 | | $ | 3,431 | | $ | 2,803 | |
| Cost of natural gas and NGLs | $ | 1,279 | | $ | 1,819 | | $ | 1,381 | |
| Operating income | $ | 569 | | $ | 648 | | $ | 528 | |
| Net income | $ | 360 | | $ | 485 | | $ | 400 | |
The following table reconciles OGE Energy's equity in earnings of unconsolidated affiliates for the years ended December 31, 2019, 2018 and 2017.
| | | | | | | | | | | |
| Year Ended December 31, | | |
| (In millions) | 2019 | 2018 | 2017 |
| Enable net income | $ | 360.0 | | $ | 485.3 | | $ | 400.3 | |
| | | |
| | | |
| | | |
| OGE Energy's percent ownership at period end | 25.5 | % | 25.6 | % | 25.7 | % |
| OGE Energy's portion of Enable net income | $ | 91.8 | | $ | 124.4 | | $ | 102.7 | |
| Amortization of basis difference and dilution recognition (A) | 22.1 | | 28.4 | | 28.5 | |
| Equity in earnings of unconsolidated affiliates | $ | 113.9 | | $ | 152.8 | | $ | 131.2 | |
(A) Includes loss on dilution, net of proportional basis difference recognition.
The following table reconciles the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2018 to December 31, 2019.
| | | | | | |
(In millions) | | |
Basis difference at December 31, 2018 | | $ | 680.3 | |
| | |
Amortization of basis difference (A) | | (27.8) | |
| | |
Basis difference at December 31, 2019 | | $ | 652.5 | |
(A) Includes proportional basis difference recognition due to dilution.
On February 7, 2020, Enable announcedpresents a quarterly dividend distribution of $0.33050 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,maturity analysis 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 $144.0 million, $141.2 million and $141.2 million during the years ended December 31, 2019, 2018 and 2017, respectively.
Related Party Transactions
The Company chargesRegistrants' operating costs to OG&E and Enable based on several factors, and operating costs directly related to OG&E and/or Enable are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method, which is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.
The Company and Enable
The Company and Enable are currently parties to several agreements whereby the Company provides specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $0.5 million, $0.6 million and $2.3 million for December 31, 2019, 2018 and 2017, respectively.
Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of December 31, 2019, 80 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $23.2 million, $27.5 million and $29.5 million in 2019, 2018 and 2017, respectively, under the 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 $17.3 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 days' notice.
86 | | | | | | | | |
Future minimum operating lease payments as of December 31: | | OGE Energy | | | OG&E | |
(In millions) | | | | | | |
2023 | | $ | 5.7 | | | $ | 5.7 | |
2024 | | | 3.7 | | | | 3.7 | |
2025 | | | 3.5 | | | | 3.5 | |
2026 | | | 3.0 | | | | 3.0 | |
2027 | | | 3.0 | | | | 3.0 | |
Thereafter | | | 25.7 | | | | 25.7 | |
Total future minimum lease payments | | | 44.6 | | | | 44.6 | |
Less: Imputed interest | | | 9.8 | | | | 9.8 | |
Present value of net minimum lease payments | | $ | 34.8 | | | $ | 34.8 | |
The Company had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $0.8 million and $1.7 million as of December 31, 2019 and 2018, which are included in Accounts Receivable in the Company's Consolidated Balance Sheets.
OG&E and Enable
Enable provides gas transportation services to OG&E pursuant to an agreement, which expires in May 2024, that 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. Further, an additional gas transportation services contract with Enable became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2019, 2018 and 2017.
| | | | | | | | | | | |
| Year Ended December 31, | | |
| (In millions) | 2019 | 2018 | 2017 |
| Operating revenues: | | | |
| Electricity to power electric compression assets | $ | 15.9 | | $ | 16.3 | | $ | 14.0 | |
| Cost of sales: | | | |
| Natural gas transportation services | $ | 41.2 | | $ | 37.9 | | $ | 35.0 | |
| | | |
| Natural gas (sales) purchases | $ | (6.0) | | $ | (3.2) | | $ | (2.1) | |
6.Fair Value Measurements
The classification of the Company'sRegistrants' 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.
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 CompanyOG&E had 0no financial instruments measured at fair value on a recurring basis at December 31, 20192022 and 2018.2021. The following table summarizespresents OGE Energy's previous financial instrument measured at fair value on a recurring basis and the carrying amount and fair value of the Company'sRegistrants' financial instruments at December 31, 20192022 and 2018,2021, as well as the classification level within the fair value hierarchy.
| | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | |
December 31 (In millions) | Carrying Amount | Fair
Value | Carrying Amount | Fair
Value | Classification |
| Long-term Debt (including Long-term Debt due within one year): | | | | | |
| OG&E Senior Notes | $ | 3,050.3 | | $ | 3,500.4 | | $ | 3,001.9 | | $ | 3,178.2 | | Level 2 | |
| OG&E Industrial Authority Bonds | $ | 135.4 | | $ | 135.4 | | $ | 135.4 | | $ | 135.4 | | Level 2 | |
| Tinker Debt | $ | 9.5 | | $ | 10.0 | | $ | 9.6 | | $ | 8.7 | | Level 3 | |
| | | | | |
87 | | | | | | | | | | | | | | |
| 2022 | | | 2021 | | |
December 31 (In millions) | Carrying
Amount | | Fair
Value | | | Carrying
Amount | | Fair
Value | | Classification |
Financial instrument measured at fair value on a recurring basis: | | | | | | | | | | |
OGE Energy investment in Energy Transfer's equity securities | $ | — | | $ | — | | | $ | 785.1 | | $ | 785.1 | | Level 1 |
Financial instruments for which fair value is only disclosed: | | | | | | | | | | |
Long-term Debt (including Long-term Debt due within one year): | | | | | | | | | | |
OGE Energy Senior Notes | $ | 499.9 | | $ | 491.2 | | | $ | 499.9 | | $ | 497.8 | | Level 2 |
OGE Energy Term Loan | $ | 49.8 | | $ | 50.0 | | | $ | — | | $ | — | | Level 2 |
OG&E Senior Notes | $ | 3,854.2 | | $ | 3,477.1 | | | $ | 3,851.8 | | $ | 4,460.2 | | Level 2 |
OG&E Industrial Authority Bonds | $ | 135.4 | | $ | 135.4 | | | $ | 135.4 | | $ | 135.4 | | Level 2 |
Tinker Debt | $ | 9.3 | | $ | 7.3 | | | $ | 9.3 | | $ | 10.0 | | Level 3 |
7.Stock-Based Compensation
In 2013, the Company2022, OGE Energy adopted, and its shareholders approved, the 2022 Stock Incentive Plan. The 2022 Stock Incentive Plan replaced the 2013 Stock Incentive Plan, and no further awards will be granted under the 2013 Stock Incentive Plan. Under the 2022 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 CompanyOGE Energy and its subsidiaries. The Companysubsidiaries, including OG&E. OGE Energy has authorized the issuance of up to 7,400,0008,417,755 shares under the 2022 Stock Incentive Plan.
The following table summarizespresents the Company'sRegistrants' pre-tax compensation expense and related income tax benefit for the years ended December 31, 2019, 20182022, 2021 and 20172020 related to the Company's performance units and restricted stock units.
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Performance units: | | | |
| Total shareholder return | $ | 8.7 | | $ | 8.2 | | $ | 7.6 | |
| Earnings per share | 4.3 | | 5.1 | | 1.4 | |
| Total performance units | 13.0 | | 13.3 | | 9.0 | |
| Restricted stock units | 0.9 | | 0.1 | | 0.1 | |
| | | |
| | | |
| Total compensation expense | $ | 13.9 | | $ | 13.4 | | $ | 9.1 | |
| Income tax benefit | $ | 3.6 | | $ | 3.4 | | $ | 3.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Performance units: | | | | | | | | | | | | | | | | | | |
Total shareholder return | | $ | 7.2 | | | $ | 7.5 | | | $ | 7.9 | | | $ | 2.2 | | | $ | 1.8 | | | $ | 2.3 | |
Earnings per share (A) | | | — | | | | — | | | | 1.0 | | | | — | | | | — | | | | 0.3 | |
Total performance units | | | 7.2 | | | | 7.5 | | | | 8.9 | | | | 2.2 | | | | 1.8 | | | | 2.6 | |
Restricted stock units | | | 2.5 | | | | 2.3 | | | | 0.9 | | | | 0.7 | | | | 0.4 | | | | 0.4 | |
Total compensation expense | | $ | 9.7 | | | $ | 9.8 | | | $ | 9.8 | | | $ | 2.9 | | | $ | 2.2 | | | $ | 3.0 | |
Income tax benefit | | $ | 2.3 | | | $ | 2.5 | | | $ | 2.5 | | | $ | 0.7 | | | $ | 0.6 | | | $ | 0.8 | |
In 2019, the Compensation Committee of OGE Energy's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. The Company has issued newfinal grants of performance units based on earnings per share vested as of December 31, 2020 and were paid out in March 2021.
During the year ended December 31, 2020, OGE Energy purchased 405,000 shares of its common stock, and 247,252 of these shares were used during 2020 to satisfy payouts of earned performance units and restricted stock unit grants and payoutsto the Registrants' employees pursuant to OGE Energy's 2013 Stock Incentive Plan. During the year ended December 31, 2020, there was also an immaterial number of earned performance units. In 2019, 2018 and 2017, there were 443,900 shares 26,211 shares and 2,298 shares, respectively, of new common stock issued pursuant to the Company'sOGE Energy's 2013 Stock Incentive Plan related to satisfy restricted stock unit grants andto employees.
During the year ended December 31, 2021, 154,523 shares of treasury stock were used to satisfy payouts of earned performance units.
units and restricted stock unit grants to the Registrants' employees pursuant to OGE Energy's 2013 Stock Incentive Plan.
Performance Units
UnderDuring the year ended December 31, 2022, OGE Energy issued 27,278 shares of new common stock pursuant to OGE Energy's 2013 Stock Incentive Plan and issued an immaterial amount of treasury stock to satisfy payouts of restricted stock unit grants to the CompanyRegistrants' employees.
Performance Units
Under the 2013 Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of the Company'sOGE Energy's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the 2013 Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the CompanyOGE Energy 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 Company estimatesRegistrants estimate expected forfeitures in accounting for performance unit compensation expense.
The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company'sOGE Energy'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'sOGE Energy'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 theseThese performance units are classified as equity in the Consolidated Balance Sheets.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'sOGE Energy'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 are accrued on a quarterly basis pending achievement of payout criteria and are included in the fair value calculations. Expected price volatility is based on the historical volatility of
the Company'sOGE Energy's common stock for the past three years and
wasis 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'sOGE Energy's performance units based on total shareholder return.
The following table presents 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.return. | | | | | | | | | | | | | | | | | | | |
| OGE Energy | | | OG&E | |
| 2022 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2020 | |
Number of units granted | | 216,437 | | | 249,909 | | | 201,552 | | | | 60,923 | | | 68,720 | | | 67,975 | |
Fair value of units granted | $ | 41.10 | | $ | 38.14 | | $ | 38.03 | | | $ | 41.10 | | $ | 38.14 | | $ | 38.03 | |
Expected dividend yield | | 4.8 | % | | 4.7 | % | | 3.5 | % | | | 4.8 | % | | 4.7 | % | | 3.5 | % |
Expected price volatility | | 29.0 | % | | 29.0 | % | | 15.0 | % | | | 29.0 | % | | 29.0 | % | | 15.0 | % |
Risk-free interest rate | | 1.71 | % | | 0.22 | % | | 1.17 | % | | | 1.71 | % | | 0.22 | % | | 1.17 | % |
Expected life of units (in years) | | 2.85 | | | 2.84 | | | 2.85 | | | | 2.85 | | | 2.85 | | | 2.85 | |
| | | | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Number of units granted | 208,647 | | 261,916 | | 260,570 | |
| Fair value of units granted | $ | 47.00 | | $ | 36.86 | | $ | 41.77 | |
| Expected dividend yield | 4.0 | % | 3.6 | % | 3.8 | % |
| Expected price volatility | 17.0 | % | 19.0 | % | 19.9 | % |
| Risk-free interest rate | 2.47 | % | 2.38 | % | 1.44 | % |
Expected life of units (in years) | 2.86 | 2.86 | 2.80 |
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. In 2019, the Compensation Committee of the Company's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. For 2018 and 2017, the number of performance units granted based on earnings per share and the grant date fair value are shown in the following table.
| | | | | | | | | |
| | 2018 | 2017 |
| Number of units granted | | 87,308 | | 86,857 | |
| Fair value of units granted | | $ | 31.03 | | $ | 34.83 | |
Restricted Stock Units
Under the 2013 Stock Incentive Plan, the CompanyOGE Energy has issued restricted stock units to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace, and for the 2019 grant cycle, restricted stock units were granted in lieu of performance units based on earnings per share.marketplace. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to the CompanyOGE Energy or a subsidiary. These restricted stock units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.
The fair value of the restricted stock units was based on the closing market price of the Company'sOGE Energy's common stock on the grant date. Compensation expense for the restricted stock units 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, for those restricted stock units that vest in one-third annual increments over a three-year cycle, the CompanyOGE Energy treats its restricted stock units 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 will only be paid on restricted stock unit awards that vest; therefore, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock units 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'sOGE Energy's restricted stock units.
The following table presents the number of restricted stock units granted and the grant date fair value are shown in the following table. value. | | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
| | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Restricted stock units granted | | | 116,539 | | | | 89,197 | | | | 67,193 | | | | 32,804 | | | | 22,911 | | | | 22,665 | |
Fair value of restricted stock units granted | | $ | 35.72 | | | $ | 31.11 | | | $ | 43.69 | | | $ | 35.72 | | | $ | 30.91 | | | $ | 43.69 | |
| | | | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Restricted stock units granted | 75,929 | | 826 | | 3,145 | |
| Fair value of restricted stock units granted | $ | 41.71 | | $ | 36.28 | | $ | 34.96 | |
Performance Units and Restricted Stock Units Activity
AThe following tables present a summary of the activity for the Company'sRegistrants' performance units and restricted stock units atfor the year ended December 31, 2019 and changes in 2019 are shown in2022. The table designated as "OGE Energy" below includes the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Units | | | | | | Restricted
Stock Units | | |
| Total Shareholder Return | | | Earnings Per Share | | | | | |
| (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 12/31/18 | 755,480 | | | | 251,825 | | | | 2,711 | | | |
| Granted | 208,647 | | (A) | | | — | | | | | 75,929 | | | |
| | | | | | | | | |
| Converted | (274,078) | | (B) | | $ | 19.8 | | (91,356) | | (B) | | $ | 7.2 | | N/A | | | |
| Vested | N/A | | | | N/A | | | | (2,161) | | | $ | 0.1 | |
| Forfeited | (25,232) | | | | (5,298) | | | | (3,599) | | | |
| Units/shares outstanding at 12/31/19 | 664,817 | | | $ | 35.4 | | 155,171 | | | $ | 11.5 | | 72,880 | | | $ | 3.2 | |
| Units/shares fully vested at 12/31/19 | 222,163 | | | $ | 11.5 | | 74,053 | | | $ | 6.6 | | | | |
| | | | | | | | | | | | | | | |
OGE Energy | Performance Units | | | Restricted Stock Units | |
(Dollars in millions) | Number
of Units | | | Aggregate Intrinsic Value | | | Number
of Shares | | | Aggregate Intrinsic Value | |
Units/shares outstanding at 12/31/21 | | 581,252 | | | | | | | 133,671 | | | | |
Granted | | 216,437 | | (A) | | | | | 116,539 | | | | |
Converted | | (172,748 | ) | (B) | $ | — | | | N/A | | | | |
Vested | N/A | | | | | | | (47,995 | ) | | $ | 1.9 | |
Forfeited | | (16,566 | ) | | | | | | (12,732 | ) | | | |
Units/shares outstanding at 12/31/22 | | 608,375 | | | $ | 34.1 | | | | 189,483 | | | $ | 7.5 | |
Units/shares fully vested at 12/31/22 | | 161,690 | | (C) | $ | 3.7 | | | N/A | | | N/A | |
| | | | | | | | | | | | | | | |
OG&E | Performance Units | | | Restricted Stock Units | |
(Dollars in millions) | Number
of Units | | | Aggregate Intrinsic Value | | | Number
of Shares | | | Aggregate Intrinsic Value | |
Units/shares outstanding at 12/31/21 | | 161,310 | | | | | | | 35,613 | | | | |
Granted | | 60,923 | | (A) | | | | | 32,804 | | | | |
Converted | | (48,195 | ) | (B) | $ | — | | | N/A | | | | |
Vested | N/A | | | | | | | (11,807 | ) | | $ | 0.5 | |
Forfeited | | (4,217 | ) | | | | | | (4,342 | ) | | | |
Employee migration | | 802 | | (D) | | | | | 491 | | (D) | | |
Units/shares outstanding at 12/31/22 | | 170,623 | | | $ | 9.6 | | | | 52,759 | | | $ | 2.1 | |
Units/shares fully vested at 12/31/22 | | 44,550 | | (C) | $ | 1.0 | | | N/A | | | N/A | |
(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 0zero percent to 200 percent of the target.
(B)These amounts represent performance units that were canceled at December 31, 2021 due to the performance metric threshold not being met.
(C)These amounts represent performance units that vested at December 31, 20182022. Actual expected amounts to be paid out in 2023 will differ based on the percentage at which were settled in February 2019.the performance metric was met and are dependent upon Compensation Committee approval.
Due to certain employees transferring between OG&E and OGE Energy.
AThe following tables present a summary of the activity for the Company'sRegistrants' non-vested performance units and restricted stock units atfor the year ended December 31, 2019 and changes in 2019 are shown in2022. The table designated as "OGE Energy" below includes the following table.OG&E standalone activity, as OGE Energy represents consolidated results.
| | | | | | | | | | | | | | | |
OGE Energy | Performance Units | | | Restricted Stock Units | |
| Number
of Units | | | Weighted-Average
Grant Date
Fair Value | | | Number
of Shares | | | Weighted-Average
Grant Date
Fair Value | |
Units/shares non-vested at 12/31/21 | | 408,504 | | | $ | 38.05 | | | | 133,671 | | | $ | 35.64 | |
Granted | | 216,437 | | (A) | $ | 41.10 | | | | 116,539 | | | $ | 35.72 | |
Vested | | (161,690 | ) | | $ | 38.04 | | | | (47,995 | ) | | $ | 39.63 | |
Forfeited | | (16,566 | ) | | $ | 39.45 | | | | (12,732 | ) | | $ | 35.95 | |
Units/shares non-vested at 12/31/22 | | 446,685 | | | $ | 39.53 | | | | 189,483 | | | $ | 33.75 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Units | | | | | | Restricted
Stock Units | | |
| Total Shareholder Return | | | Earnings Per Share | | | | | |
| 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 12/31/18 | 481,402 | | | $ | 39.17 | | 160,469 | | | $ | 32.82 | | 2,711 | | | $ | 35.00 | |
| Granted | 208,647 | | (A) | | $ | 47.00 | | — | | | | $ | — | | 75,929 | | | | $ | 41.71 | |
| | | | | | | | | |
| Vested | (222,163) | | | $ | 41.76 | | (74,053) | | | $ | 34.83 | | (2,161) | | | $ | 34.66 | |
| Forfeited | (25,232) | | | $ | 41.45 | | (5,298) | | | $ | 32.07 | | (3,599) | | | $ | 41.78 | |
| Units/shares non-vested at 12/31/19 | 442,654 | | | $ | 41.43 | | 81,118 | | | $ | 31.03 | | 72,880 | | | $ | 41.66 | |
| Units/shares expected to vest | 418,331 | | (B) | | | 77,617 | | (B) | | | 54,102 | | (B) | | |
| | | | | | | | | | | | | | | |
OG&E | Performance Units | | | Restricted Stock Units | |
| Number
of Units | | | Weighted-Average
Grant Date
Fair Value | | | Number
of Shares | | | Weighted-Average
Grant Date
Fair Value | |
Units/shares non-vested at 12/31/21 | | 113,115 | | | $ | 38.10 | | | | 35,613 | | | $ | 35.52 | |
Granted | | 60,923 | | (A) | $ | 41.10 | | | | 32,804 | | | $ | 35.72 | |
Vested | | (44,550 | ) | | $ | 38.03 | | | | (11,807 | ) | | $ | 39.71 | |
Forfeited | | (4,217 | ) | | $ | 39.96 | | | | (4,342 | ) | | $ | 35.93 | |
Employee migration | | 802 | | (B) | $ | 42.18 | | | | 491 | | (B) | $ | 34.83 | |
Units/shares non-vested at 12/31/22 | | 126,073 | | | $ | 39.53 | | | | 52,759 | | | $ | 33.78 | |
(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 0zero percent to 200 percent of the target.
(B)The intrinsic value of the performance units based on total shareholder returnDue to certain employees transferring between OG&E and earnings per share is $22.8 million and $4.7 million, respectively. The intrinsic value of restricted stock units is $2.4 million.
Fair Value of Vested Performance Units and Restricted Stock Units
AThe following table presents a summary of the
Company'sRegistrants' fair value for
its vested performance units and restricted stock
units is shown in the following table.units. | | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Performance units: | | | | | | | | | | | | | | | | | | |
Total shareholder return | | $ | 6.2 | | | $ | 8.1 | | | $ | 8.7 | | | $ | 1.7 | | | $ | 2.3 | | | $ | 2.8 | |
Earnings per share | | $ | — | | | $ | — | | | $ | 2.5 | | | $ | — | | | $ | — | | | $ | 0.8 | |
Restricted stock units | | $ | 2.1 | | | $ | 2.2 | | | $ | 0.1 | | | $ | 0.5 | | | $ | 0.5 | | | $ | 0.1 | |
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Performance units: | | | |
| Total shareholder return | $ | 9.3 | | $ | 5.9 | | $ | 6.3 | |
| Earnings per share | $ | 5.2 | | $ | 4.9 | | $ | 1.2 | |
| Restricted stock units | $ | 0.1 | | $ | 0.1 | | $ | 0.1 | |
Unrecognized Compensation Cost
AThe following table presents a summary of the
Company'sRegistrants' unrecognized compensation cost for
its non-vested performance units and restricted stock units and the weighted-average periods over which the compensation cost is expected to be
recognized are shown in the following table.recognized. | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
December 31, 2022 | | Unrecognized
Compensation Cost
(In millions) | | | Weighted Average
to be Recognized
(In years) | | | Unrecognized
Compensation Cost
(In millions) | | | Weighted Average
to be Recognized
(In years) | |
Performance units | | $ | 7.7 | | | | 1.66 | | | $ | 2.2 | | | | 1.65 | |
Restricted stock units | | | 3.5 | | | | 1.76 | | | | 0.7 | | | | 1.77 | |
Total unrecognized compensation cost | | $ | 11.2 | | | | | | $ | 2.9 | | | | |
| | | | | | | | |
| December 31, 2019 | Unrecognized Compensation Cost (In millions) | Weighted Average to be Recognized (In years) |
| Performance units: | | |
| Total shareholder return | $ | 8.7 | | 1.67 |
| Earnings per share | 0.8 | | 1.00 |
| Total performance units | 9.5 | | |
| Restricted stock units | 1.5 | | 1.98 |
| Total unrecognized compensation cost | $ | 11.0 | | |
Income Taxes
8.
Income Tax Expense (Benefit)Supplemental Cash Flow Information
The following table presents 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, netthe components of income tax refunds are also presented in the table.expense (benefit).
| | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Provision (benefit) for current income taxes: | | | | | | | | | | | | | | | | | | |
Federal | | $ | 250.8 | | | $ | 16.4 | | | $ | 8.4 | | | $ | (141.2 | ) | | $ | (9.0 | ) | | $ | (3.8 | ) |
State | | | 28.8 | | | | 1.7 | | | | 0.5 | | | | (0.9 | ) | | | 9.0 | | | | (0.6 | ) |
Total provision (benefit) for current income taxes | | | 279.6 | | | | 18.1 | | | | 8.9 | | | | (142.1 | ) | | | — | | | | (4.4 | ) |
Provision (benefit) for deferred income taxes, net: | | | | | | | | | | | | | | | | | | |
Federal | | | (110.8 | ) | | | 133.1 | | | | (105.2 | ) | | | 219.9 | | | | 58.3 | | | | 45.7 | |
State | | | (45.2 | ) | | | (10.0 | ) | | | (31.1 | ) | | | (1.4 | ) | | | (16.5 | ) | | | (6.6 | ) |
Total provision (benefit) for deferred income taxes, net | | | (156.0 | ) | | | 123.1 | | | | (136.3 | ) | | | 218.5 | | | | 41.8 | | | | 39.1 | |
Total income tax expense (benefit) | | $ | 123.6 | | | $ | 141.2 | | | $ | (127.4 | ) | | $ | 76.4 | | | $ | 41.8 | | | $ | 34.7 | |
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| NON-CASH INVESTING AND FINANCING ACTIVITIES | | | |
| | | |
| Power plant long-term service agreement | $ | 28.9 | | $ | (9.2) | | $ | (2.6) | |
| | | |
| | | |
| | | |
| SUPPLEMENTAL CASH FLOW INFORMATION | | | |
| Cash paid during the period for: | | | |
| Interest (net of interest capitalized) (A) | $ | 152.2 | | $ | 153.8 | | $ | 139.6 | |
| Income taxes (net of income tax refunds) | $ | 5.5 | | $ | 2.8 | | $ | (16.0) | |
(A)
Net of interest capitalized of $2.8 million, $11.7 million and $18.0 million in 2019, 2018 and 2017, respectively.
9.Income Taxes
Income Tax Expense (Benefit)
The items comprising income tax expense (benefit) are as follows:
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Provision (benefit) for current income taxes: | | | |
| Federal | $ | (6.4) | | $ | (1.9) | | $ | 4.9 | |
| State | 5.1 | | (4.4) | | (4.2) | |
| Total provision (benefit) for current income taxes | (1.3) | | (6.3) | | 0.7 | |
| Provision (benefit) for deferred income taxes, net: | | | | | | |
| Federal | 48.5 | | 74.7 | | (75.9) | |
| State | (17.4) | | 3.7 | | 26.0 | |
| Total provision (benefit) for deferred income taxes, net | 31.1 | | 78.4 | | (49.9) | |
| Deferred federal investment tax credits, net | — | | 0.1 | | (0.1) | |
| Total income tax expense (benefit) | $ | 29.8 | | $ | 72.2 | | $ | (49.3) | |
The CompanyOGE Energy files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. OG&E is a part of the consolidated income tax return of OGE Energy. With few exceptions, the Company isRegistrants are no longer subject to U.S. federal tax or state and local examinations by tax authorities for years prior to 2016.2018. Income taxes are generally allocated to each company in the affiliated group, including OG&E, based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utilitycompany property have been deferred and will be amortized to income over the life of the related property. Additionally, OG&E earnsearned federal tax credits associated with production from its wind facilities.facilities through January 2022. Oklahoma production and investment state tax credits are also earned on investments in electric and solar generating facilities which further reduce OG&E's effective tax rate.
The following schedule reconcilestable presents a reconciliation of the statutory tax rates to the effective income tax rate:
| | | | | | | | | | | |
| Year Ended December 31 | 2019 | 2018 | 2017 |
| Statutory federal tax rate | 21.0 | % | 21.0 | % | 35.0 | % |
| Executive compensation limitation | 0.2 | | 0.2 | | — | |
| Federal renewable energy credit (A) | (6.0) | | (5.1) | | (4.8) | |
| Amortization of net unfunded deferred taxes | (4.5) | | (2.1) | | 0.7 | |
| State income taxes, net of federal income tax benefit | (1.2) | | 0.4 | | 2.0 | |
| Stock-based compensation | (1.2) | | — | | — | |
| Remeasurement of state deferred tax liabilities | (0.8) | | (0.4) | | 0.4 | |
| Other | (0.7) | | 0.4 | | (0.1) | |
| 401(k) dividends | (0.4) | | (0.3) | | (0.5) | |
| Federal deferred tax revaluation | — | | 0.4 | | (41.2) | |
| Federal investment tax credits, net | — | | — | | (0.1) | |
| | | |
| Effective income tax rate | 6.4 | % | 14.5 | % | (8.6) | % |
| | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
Year Ended December 31 | | 2022 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2020 | |
Statutory federal tax rate | | | 21.0 | % | | 21.0 | % | | 21.0 | % | | | 21.0 | % | | 21.0 | % | | 21.0 | % |
State income taxes, net of federal income tax
benefit | | | (1.0 | ) | | 0.9 | | | (1.4 | ) | | | (0.4 | ) | | (1.4 | ) | | (1.6 | ) |
Stock-based compensation | | | — | | | 0.1 | | | (0.3 | ) | | | — | | | — | | | — | |
Executive compensation limitation | | | 0.1 | | | 0.1 | | | 0.2 | | | | — | | | — | | | — | |
Amortization of net unfunded deferred taxes | | | (3.2 | ) | | (2.1 | ) | | (4.4 | ) | | | (5.0 | ) | | (4.6 | ) | | (4.8 | ) |
Federal renewable energy credit (A) | | | — | | | (2.0 | ) | | (5.0 | ) | | | — | | | (4.4 | ) | | (5.4 | ) |
Remeasurement of state deferred taxes due to Energy Transfer merger (B) | | | — | | | (1.1 | ) | | — | | | | — | | | — | | | — | |
Remeasurement of state deferred tax liabilities | | | (0.6 | ) | | (0.6 | ) | | 0.9 | | | | — | | | — | | | — | |
401(k) dividends | | | (0.2 | ) | | (0.2 | ) | | (0.4 | ) | | | — | | | — | | | — | |
Impairment of OGE Energy's investment in Enable (C) | | | — | | | — | | | 31.6 | | | | — | | | — | | | — | |
Other | | | (0.4 | ) | | — | | | 0.1 | | | | (0.8 | ) | | (0.2 | ) | | 0.1 | |
Effective income tax rate | | | 15.7 | % | | 16.1 | % | | 42.3 | % | | | 14.8 | % | | 10.4 | % | | 9.3 | % |
(A)Represents credits primarily associated with the production from OG&E's wind farms.
In connection with the Enable and Energy Transfer merger, the state income tax rates were expected to decrease, as Energy Transfer operates in significantly more states with generally lower tax rates than the historic Enable operating area.
(C)92As discussed in Note 1, OGE Energy recorded a $780.0 million impairment on its investment in Enable in March 2020, which resulted in a tax benefit being recorded that caused a significant variance to the effective tax rate. This variance has been presented in the table as a single line item in order to facilitate comparability of other components of the effective tax rate.
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 following table presents the components of Deferred Income Taxes at December 31, 20192022 and 2018 were as follows:2021.
| | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
December 31 (In millions) | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
Deferred income tax liabilities, net: | | | | | | | | | | | | |
Accelerated depreciation and other property related differences | | $ | 1,714.5 | | | $ | 1,677.3 | | | $ | 1,714.5 | | | $ | 1,677.3 | |
Investment in Energy Transfer's equity securities | | | — | | | | 363.5 | | | | — | | | | — | |
Regulatory assets | | | 54.8 | | | | 52.1 | | | | 54.7 | | | | 52.1 | |
Pension Plan | | | 18.0 | | | | 10.7 | | | | 35.4 | | | | 32.0 | |
Other | | | (5.1 | ) | | | 7.4 | | | | (5.8 | ) | | | (4.7 | ) |
Derivative instruments | | | 2.4 | | | | 2.2 | | | | — | | | | — | |
Bond redemption-unamortized costs | | | 1.6 | | | | 1.8 | | | | 1.6 | | | | 1.8 | |
Income taxes recoverable from customers, net | | | (216.7 | ) | | | (225.8 | ) | | | (216.7 | ) | | | (225.8 | ) |
State tax credits | | | (221.2 | ) | | | (221.2 | ) | | | (208.5 | ) | | | (205.9 | ) |
Federal tax credits | | | — | | | | (208.4 | ) | | | — | | | | (209.8 | ) |
Regulatory liabilities | | | (60.8 | ) | | | (72.0 | ) | | | (60.8 | ) | | | (72.0 | ) |
Asset retirement obligations | | | (18.8 | ) | | | (19.4 | ) | | | (18.8 | ) | | | (19.4 | ) |
Postretirement medical and life insurance benefits | | | (19.2 | ) | | | (19.2 | ) | | | (12.7 | ) | | | (13.0 | ) |
Accrued liabilities | | | (11.2 | ) | | | (9.5 | ) | | | (7.3 | ) | | | (7.3 | ) |
Deferred federal investment tax credits | | | (2.9 | ) | | | (3.1 | ) | | | (2.9 | ) | | | (3.1 | ) |
Net operating losses | | | — | | | | (1.0 | ) | | | — | | | | — | |
Accrued vacation | | | (1.4 | ) | | | (1.5 | ) | | | (1.1 | ) | | | (1.2 | ) |
Uncollectible accounts | | | (0.5 | ) | | | (0.6 | ) | | | (0.5 | ) | | | (0.6 | ) |
Total deferred income tax liabilities, net | | $ | 1,233.5 | | | $ | 1,333.3 | | | $ | 1,271.1 | | | $ | 1,000.4 | |
| | | | | | | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
December 31 (In millions) | 2019 | 2018 |
| Deferred income tax liabilities, net: | | |
| Accelerated depreciation and other property related differences | $ | 1,656.8 | | $ | 1,605.3 | |
| | |
| Investment in Enable | 478.2 | | 469.9 | |
| Regulatory assets | 28.4 | | 17.4 | |
| Company Pension Plan | 4.1 | | 7.6 | |
| Bond redemption-unamortized costs | 2.2 | | 2.4 | |
| Derivative instruments | 1.6 | | 1.7 | |
| Other | 0.4 | | 1.1 | |
| | |
| | |
| Federal tax credits | (238.0) | | (237.8) | |
| Income taxes recoverable from customers, net | (229.9) | | (239.6) | |
| State tax credits | (185.8) | | (156.0) | |
| Regulatory liabilities | (68.1) | | (78.8) | |
| Postretirement medical and life insurance benefits | (23.3) | | (23.6) | |
| Asset retirement obligations | (19.2) | | (21.5) | |
| Net operating losses | (16.6) | | (20.2) | |
| Accrued liabilities | (10.7) | | (12.5) | |
| Accrued vacation | (2.1) | | (2.3) | |
| | |
| Deferred federal investment tax credits | (1.8) | | (1.8) | |
| Uncollectible accounts | (0.4) | | (0.4) | |
| | |
| Total deferred income tax liabilities, net | $ | 1,375.8 | | $ | 1,310.9 | |
As of December 31, 2019,2022, the Company hasRegistrants have classified $16.4$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.
Following isThe following table presents a reconciliation of the Company'sRegistrants' total gross unrecognized tax benefits as of the years ended December 31, 2019, 20182022, 2021 and 2017.2020.
| | | | | | | | | | | | |
(In millions) | | 2022 | | | 2021 | | | 2020 | |
Balance at January 1 | | $ | 22.4 | | | $ | 21.9 | | | $ | 20.7 | |
Tax positions related to current year: | | | | | | | | | |
Additions | | | — | | | | 1.7 | | | | 1.2 | |
Reductions | | | (1.7 | ) | | | (1.2 | ) | | | — | |
Balance at December 31 | | $ | 20.7 | | | $ | 22.4 | | | $ | 21.9 | |
| | | | | | | | | | | |
| (In millions) | 2019 | 2018 | 2017 |
| Balance at January 1 | $ | 20.7 | | $ | 20.7 | | $ | 20.7 | |
| Tax positions related to current year: | | | |
| Additions | — | | — | | — | |
| | | |
| | | |
| Balance at December 31 | $ | 20.7 | | $ | 20.7 | | $ | 20.7 | |
As of each of December 31, 2019, 20182022, 2021 and 2017,2020, there were $16.4$16.4 million, $18.1 million and $17.6 million, respectively, of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.
Where applicable, the Company classifiesRegistrants classify income tax-related interest and penalties as interest expense and other expense, respectively. During the yearyears ended December 31, 2019,2022, 2021 and 2020, there were 0no income tax-related interest or penalties recorded with regard to uncertain tax positions.
The CompanyRegistrants recognize tax benefits from an uncertain tax position only if it is more likely than not the tax position will be sustained on examination by taxing authorities based on the technical merits of the position. The tax benefits in the financial statements from such positions are then measured based on the largest benefit that has a greater than 50 percent likelihood of being realized on settlement. In 2022, the reserve for certain federal research and development credits of $1.7 million, which was recorded in 2021, was reversed.
The Registrants 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 federalFederal and state income tax benefits carrying into 2017, when the remaining federal net operating loss was utilized. State operating losses are being carried forward for utilization in future years. In addition togenerated during those years have been fully utilized, and the tax operating losses, the Company was unable to utilize therelated 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 anticipatesRegistrants anticipate future taxable income will be sufficient to utilize remaining losses andall credits before they begin to expire after 2020. 2022. The following table summarizespresents a summary of these carry forwards:
| | | | | | | | | | | OGE Energy | | | OG&E | | | |
| (In millions) | (In millions) | Carry Forward Amount | Deferred Tax Asset | Earliest Expiration Date | | Carry Forward Amount | | | Deferred Tax Asset | | | Carry Forward Amount | | | Deferred Tax Asset | | | Earliest Expiration Date |
| | State operating loss | $ | 371.6 | | $ | 16.6 | | 2030 | |
| Federal tax credits | $ | 238.0 | | $ | 238.0 | | 2032 | |
| State tax credits: | State tax credits: | | | | | | | | | | | | | | | |
| Oklahoma investment tax credits | Oklahoma investment tax credits | $ | 183.9 | | $ | 145.3 | | N/A | | $ | 242.8 | | | $ | 191.8 | | | $ | 226.7 | | | $ | 179.1 | | | N/A |
| Oklahoma capital investment board credits | Oklahoma capital investment board credits | $ | 12.4 | | $ | 12.4 | | N/A | | $ | 12.8 | | | $ | 12.8 | | | $ | 12.8 | | | $ | 12.8 | | | N/A |
| Oklahoma zero emission tax credits | Oklahoma zero emission tax credits | $ | 34.9 | | $ | 28.0 | | 2020 | | $ | 22.6 | | | $ | 16.6 | | | $ | 22.6 | | | $ | 16.6 | | | 2023 |
| Louisiana inventory credits | $ | 0.2 | | $ | 0.1 | | 2020 | |
N/A - not applicable
In connection with its investment in Energy Transfer during 2022, OGE Energy anticipates operating losses in various state jurisdictions. As discussed in Note 1, OGE Energy has fully disposed of its investment in Energy Transfer, and it does not expect future taxable income in these states. Therefore, as of December 31, 2022, OGE Energy has recorded a valuation allowance of $2.7 million, which eliminated the related deferred tax asset balance. OGE Energy did not record any valuation allowances as of December 31, 2021.
Automatic Dividend Reinvestment and Stock Purchase Plan
The Company
OGE Energy issued 0no new shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan in 2019. The Company may, from time to time, issue shares under its2022. Under the terms of the Automatic Dividend Reinvestment and Stock Purchase Plan, OGE Energy may, from time to time, issue new shares to satisfy purchases under the plan or purchasehave shares tradedpurchased on the open market. At December 31, 2019,2022, there were 4,774,4423,932,647 shares of unissued common stock reserved for issuance under the Company'sOGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan.
Earnings (Loss) Per Share
Basic earnings (loss) per share is calculated by dividing net income (loss) attributable to the CompanyOGE Energy by the weighted average number of the Company'sOGE Energy's common shares outstanding during the period. In the calculation of diluted earnings (loss) 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 CompanyOGE Energy consist of performance units and restricted stock units. The following table calculatespresents the calculation of basic and diluted earnings (loss) per share for the Company.OGE Energy.
| | (In millions except per share data) | (In millions except per share data) | 2019 | 2018 | 2017 | | 2022 | | | 2021 | | | 2020 | |
| Net income | $ | 433.6 | | $ | 425.5 | | $ | 619.0 | | |
Net income (loss) | | | $ | 665.7 | | | $ | 737.3 | | | $ | (173.7 | ) |
| Average common shares outstanding: | Average common shares outstanding: | | | | | | | | | | | | |
| Basic average common shares outstanding | Basic average common shares outstanding | 200.1 | | 199.7 | | 199.7 | | | | 200.2 | | | | 200.1 | | | | 200.1 | |
| Effect of dilutive securities: | Effect of dilutive securities: | | | | | | | | | | |
| Contingently issuable shares (performance and restricted stock units) | Contingently issuable shares (performance and restricted stock units) | 0.6 | | 0.8 | | 0.3 | | | | 0.6 | | | | 0.2 | | | | — | |
| Diluted average common shares outstanding | Diluted average common shares outstanding | 200.7 | | 200.5 | | 200.0 | | | | 200.8 | | | | 200.3 | | | | 200.1 | |
| Basic earnings per average common share | $ | 2.17 | | $ | 2.13 | | $ | 3.10 | | |
| Diluted earnings per average common share | $ | 2.16 | | $ | 2.12 | | $ | 3.10 | | |
Basic earnings (loss) per average common share | | | $ | 3.33 | | | $ | 3.68 | | | $ | (0.87 | ) |
Diluted earnings (loss) per average common share | | | $ | 3.32 | | | $ | 3.68 | | | $ | (0.87 | ) |
| Anti-dilutive shares excluded from earnings per share calculation | Anti-dilutive shares excluded from earnings per share calculation | | — | | — | �� | — | | | | — | | | | — | | | | 0.3 | |
The Company'sOGE Energy's Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Before the CompanyOGE Energy can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. As there is 0no preferred stock outstanding, that restriction did not place any effective limit on the Company'sOGE Energy's ability to pay dividends to its shareholders.
The Company OGE Energy 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.
PursuantOn December 19, 2022, OGE Energy entered into an amendment to the leverage restriction in the Company'sits revolving credit agreement,facility that increased the Company must maintain a percentagepermitted leverage ratio (percentage of debt to total capitalization at a level that doescapitalization) for OGE Energy from an amount not to exceed 65 percent to an amount not to exceed 70 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 $661.4$816.9 million of the Company'sOGE Energy's retained earnings from being paid out in dividends. Accordingly, approximately $2.4$2.5 billion of the Company'sOGE Energy's retained earnings as of December 31, 20192022 are unrestricted for the payment of dividends.
There were no new shares of OG&E common stock issued in 2022, 2021 or 2020.
Dividend Restrictions
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 $694.9$579.3 million of OG&E's retained earnings from being paid out in dividends. Accordingly, approximately $2.2$2.9 billion of OG&E's retained earnings as of December 31, 20192022 are unrestricted for the payment of dividends.
A summary of the Company'sRegistrants' long-term debt is included in the Consolidated Statementsstatements of Capitalization. The Company has no long-term debt maturing in the next five years.capitalization. At December 31, 2019,2022, the Company wasRegistrants were in compliance with all of itstheir debt agreements.
Maturities of OGE Energy's consolidated long-term debt during the next five years consist of $1.0 billion in 2023, $129.4 million in 2025 and $181.0 million in 2027. Maturities of OG&E's long-term debt during the next five years consist of $500.0 million in 2023, $79.4 million in 2025 and $181.0 million in 2027. All other long-term debt of the Registrants matures after 2027.
The Company hasRegistrants have previously incurred costs related to debt refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset.Asset in the balance sheets. Unamortized debt expense and unamortized premium and discount on long-term debt are classified as Long-Term Debt in the Consolidated Balance Sheetsbalance sheets and are being amortized over the life of the respective debt.
In May 2022, OGE Energy entered into a $100.0 million floating rate unsecured three-year credit agreement, of which $50.0 million is considered a revolving loan and $50.0 million is considered a term loan, and borrowed the full $50.0
135.0 million and includes a maximum leverage ratio of 0.65 to 1.0. The other covenants under this credit agreement are substantially the same as OGE Energy's existing $550.0 million revolving credit agreement. The credit agreement is scheduled to terminate on May 24, 2025. At December 31, 2022, the weighted-average interest rate for the amount drawn on the term loan under this credit agreement was 3.48 percent during the year.
In January 2023, OG&E issued $450.0 million of 5.40% Senior Notes due January 15, 2033. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to help fund the repayment of its $500.0 million 0.553% Senior Notes, Series due May 26, 2023 and the funding of its capital investment program and working capital needs.
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
following table presents information about these bonds, which can be tendered at the option of the holder during the next 12
months, are as follows:months. | | | | | | | | |
Series | Date Due | Amount | |
| | | | | (In millions) | |
0.11% | | — | | 3.98% | Garfield Industrial Authority, January 1, 2025 | $ | 47.0 | |
0.11% | | — | | 3.95% | Muskogee Industrial Authority, January 1, 2025 | | 32.4 | |
0.11% | | — | | 3.98% | Muskogee Industrial Authority, June 1, 2027 | | 56.0 | |
Total (redeemable during next 12 months) | $ | 135.4 | |
| | | | | | | | | | | | | | |
| Series | | | Date Due | Amount |
| | | | | (In millions) |
| 1.20% | | - | 2.50% | | Garfield Industrial Authority, January 1, 2025 | $ | 47.0 | |
| 1.19% | | - | 2.35% | | Muskogee Industrial Authority, January 1, 2025 | 32.4 | |
| 1.20% | | - | 2.48% | | Muskogee Industrial Authority, June 1, 2027 | 56.0 | |
| Total (redeemable during next 12 months) | | | | $ | 135.4 | |
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.balance sheets. OG&E believes that it has sufficient liquidity to meet these obligations.
Issuance of Long-Term Debt
In June 2019, OG&E issued $300.0 million of 3.30 percent senior notes due March 15, 2030. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to repay short-term debt (including debt pertaining to the acquisition of the River Valley plant) and to fund ongoing capital expenditures and working capital.
12.Short-Term Debt and Credit Facilities
The
Company borrowsRegistrants borrow on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under
itstheir revolving credit
agreement.agreements. OGE Energy also borrows under term credit agreements maturing in one year or less, as necessary. As of December 31,
2019, the Company2022, OGE Energy had
$112.0 millionno short-term debt as compared to 0$486.9 million of short-term debt at December 31, 2018. 2021.
The following table providespresents information regarding the Company'sRegistrants' revolving credit agreements at December 31, 2019.
| | | | | | | | | | | | | | | | | |
| Aggregate | Amount | Weighted-Average | | |
| Entity | Commitment | Outstanding (A) | Interest Rate | | Expiration |
| (In millions) | | | | |
| OGE Energy (B) | $ | 450.0 | | $ | 112.0 | | 2.06 | % | (D) | March 8, 2023 |
| OG&E (C) | 450.0 | | 0.3 | | 1.00 | % | (D) | March 8, 2023 |
| Total | $ | 900.0 | | $ | 112.3 | | 2.06 | % | | |
| | | | | | | | | | | |
Entity | Aggregate Commitment | | Amount Outstanding (A) | | Weighted-Average Interest Rate | Expiration |
| (In millions) | | | | | |
OGE Energy (B) | $ | 550.0 | | $ | — | | | — | | (F) | December 17, 2027 (G) |
OGE Energy (C) | | 50.0 | | | — | | | — | | (F) | May 24, 2025 |
OG&E (D)(E) | | 550.0 | | | 0.4 | | | 1.15 | % | (F) | December 17, 2027 (G) |
Total | $ | 1,150.0 | | $ | 0.4 | | | 1.15 | % | | |
(A)Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2019.2022.
(B)This bank facility is available to back up the Company'sOGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.
(C)See Note 9 for further information about this revolving credit facility.
(D)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)(E)OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $450.0 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 17, 2027. At December 31, 2022, there were $84.1 million in intercompany borrowings under this agreement.
(F)Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
In December 2021, the Registrants entered into unsecured five-year revolving credit agreements totaling $1.1 billion. Each of the revolving credit facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. In December 2022, the Registrants each entered into an amendment to their credit facility that extends the term of each credit facility for one year, until December 2027. Further, each credit facility amendment gives each of the Registrants the option of extending such commitments for up to two additional one-year periods.
In December 2022, the Registrants each entered into an amendment to their revolving credit facilities that replaced the LIBOR rate with the SOFR rate. The Company andamendment to OGE Energy's credit facility also increased OGE Energy's maximum debt to capitalization ratio from 65 percent to 70 percent. OG&E's credit facilities each havefacility has a financial covenant requiring that the respective borrower maintainOG&E maintains a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E'sRegistrants' 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'sRegistrants' 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$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$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'sRegistrants' 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'sRegistrants' 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'sRegistrants' short-term borrowings, but a reduction in the Company'sRegistrants' 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 CompanyRegistrants 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$1.0 billion in short-term borrowings at any one time for a two-year period beginning January 1, 20192023 and ending December 31, 2020.2024.
13.Retirement Plans and Postretirement Benefit Plans
OGE Energy sponsors defined benefit pension plans, 401(k) savings plans and other postretirement plans covering certain employees of the Registrants.
Pension Plan and Restoration of Retirement Income Plan
It is the Company's policy
OGE Energy periodically makes contributions to fund the Pension Plan on a current basis based on theconsidering information such as net periodic pension expense as determined by the Company'sand funded status from OGE Energy'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 CompanyOGE Energy did not make a contribution to its Pension Plan in 2022 and made a $20.0 million and $15.0$40.0 million contribution to its Pension Plan in 2019 and 2018, respectively. The Company has2021, of which $30.0 million was attributed to OG&E in 2021. OGE Energy does not determined whetherexpect it will need to make any contributions to the Pension Plan in 2020.2023. Any contribution to the Pension Plan during 20202023 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 CompanyOGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.
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 the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During 2019, 20182022, 2021 and 2017,2020, the CompanyRegistrants 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, which resulted in the CompanyRegistrants recording pension plan settlement charges as presented in the Pension Plan net periodic benefit cost table below. The pension settlement charges did not require a cash outlay by the CompanyRegistrants and 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.
The Company
OGE Energy provides a Restoration of Retirement Income Plan to those participants in the Company'sOGE Energy'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'sOGE Energy'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 presentsdetails of the funded status of the Company'sOGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the balance sheets for 20192022 and 2018.2021 are included in the following tables. 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.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 Statementsstatements of Incomeincome in future periods. The benefit obligation for the Company'sOGE Energy'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'sOGE Energy'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
OGE Energy's seconded employee contract with Enable was terminated on December 2, 2021. OGE Energy retains the obligations to the balances and accrued benefits of these former employees as of the termination of the contract.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
| | Pension Plan | | | Restoration of Retirement
Income Plan | | | Pension Plan | | | Restoration of Retirement
Income Plan | |
December 31 (In millions) | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
Change in benefit obligation | | | | | | | | | | | | | | | | | | | | | | | | |
Beginning obligations | | $ | 502.9 | | | $ | 654.6 | | | $ | 5.9 | | | $ | 7.8 | | | $ | 363.2 | | | $ | 484.1 | | | $ | 0.5 | | | $ | 3.0 | |
Service cost | | | 7.6 | | | | 11.2 | | | | 1.1 | | | | 0.8 | | | | 6.2 | | | | 7.7 | | | | — | | | | — | |
Interest cost | | | 15.7 | | | | 13.3 | | | | 0.2 | | | | 0.1 | | | | 12.1 | | | | 9.7 | | | | — | | | | — | |
Plan settlements | | | (95.8 | ) | | | (158.6 | ) | | | (1.5 | ) | | | (4.6 | ) | | | (38.8 | ) | | | (120.4 | ) | | | — | | | | (2.9 | ) |
Plan amendments | | | — | | | | — | | | | — | | | | 1.4 | | | | — | | | | — | | | | — | | | | — | |
Plan curtailments | | | — | | | | — | | | | — | | | | (0.1 | ) | | | — | | | | — | | | | — | | | | — | |
Actuarial (gains) losses | | | (56.9 | ) | | | (3.5 | ) | | | 0.1 | | | | 0.5 | | | | (41.3 | ) | | | (6.0 | ) | | | — | | | | 0.4 | |
Benefits paid | | | (15.0 | ) | | | (14.1 | ) | | | — | | | | — | | | | (12.9 | ) | | | (11.9 | ) | | | — | | | | — | |
Ending obligations | | $ | 358.5 | | | $ | 502.9 | | | $ | 5.8 | | | $ | 5.9 | | | $ | 288.5 | | | $ | 363.2 | | | $ | 0.5 | | | $ | 0.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in plans' assets | | | | | | | | | | | | | | | | | | | | | | | | |
Beginning fair value | | $ | 486.0 | | | $ | 570.3 | | | $ | — | | | $ | — | | | $ | 353.0 | | | $ | 420.3 | | | $ | — | | | $ | — | |
Actual return on plans' assets | | | (82.2 | ) | | | 48.4 | | | | — | | | | — | | | | (62.4 | ) | | | 35.0 | | | | — | | | | — | |
Employer contributions | | | — | | | | 40.0 | | | | 0.2 | | | | 4.6 | | | | — | | | | 30.0 | | | | — | | | | 2.9 | |
Plan settlements | | | (95.8 | ) | | | (158.6 | ) | | | (0.2 | ) | | | (4.6 | ) | | | (38.8 | ) | | | (120.4 | ) | | | — | | | | (2.9 | ) |
Benefits paid | | | (15.0 | ) | | | (14.1 | ) | | | — | | | | — | | | | (12.9 | ) | | | (11.9 | ) | | | — | | | | — | |
Ending fair value | | $ | 293.0 | | | $ | 486.0 | | | $ | — | | | $ | — | | | $ | 238.9 | | | $ | 353.0 | | | $ | — | | | $ | — | |
Funded status at end of year | | $ | (65.5 | ) | | $ | (16.9 | ) | | $ | (5.8 | ) | | $ | (5.9 | ) | | $ | (49.6 | ) | | $ | (10.2 | ) | | $ | (0.5 | ) | | $ | (0.5 | ) |
Accumulated postretirement benefit obligation | | $ | 342.7 | | | $ | 475.2 | | | $ | 4.8 | | | $ | 5.4 | | | $ | 275.2 | | | $ | 341.0 | | | $ | 0.4 | | | $ | 0.4 | |
For the year ended December 31, 2022, Pension Plan actuarial gains were primarily due to significantly higher discount rates, partially offset by demographic experience and a larger than expected amount of early 2023 lump sum payouts. For the year ended December 31, 2021, Pension Plan actuarial gains were primarily due to favorable demographic experience and a higher discount rate. These gains were partially offset by a difference in lump sum interest rates and the long-term assumption for Enable seconded employee terminations and more retirements and terminations than expected with lump sum payouts.
| | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
| | Postretirement Benefit Plans | | | Postretirement Benefit Plans | |
December 31 (In millions) | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
Change in benefit obligation | | | | | | | | | | | | |
Beginning obligations | | $ | 137.3 | | | $ | 144.5 | | | $ | 102.4 | | | $ | 109.5 | |
Service cost | | | 0.2 | | | | 0.2 | | | | 0.1 | | | | 0.1 | |
Interest cost | | | 3.5 | | | | 3.4 | | | | 2.7 | | | | 2.6 | |
Plan curtailments | | | — | | | | 1.9 | | | | — | | | | — | |
Participants' contributions | | | 3.5 | | | | 3.5 | | | | 2.4 | | | | 2.6 | |
Actuarial (gains) losses | | | (29.1 | ) | | | (3.7 | ) | | | (21.0 | ) | | | (2.5 | ) |
Benefits paid | | | (13.5 | ) | | | (12.5 | ) | | | (10.2 | ) | | | (9.9 | ) |
Ending obligations | | $ | 101.9 | | | $ | 137.3 | | | $ | 76.4 | | | $ | 102.4 | |
| | | | | | | | | | | | |
Change in plans' assets | | | | | | | | | | | | |
Beginning fair value | | $ | 44.3 | | | $ | 47.6 | | | $ | 39.9 | | | $ | 42.7 | |
Actual return on plans' assets | | | (8.2 | ) | | | (0.5 | ) | | | (7.4 | ) | | | (0.5 | ) |
Employer contributions | | | 6.7 | | | | 6.2 | | | | 5.1 | | | | 5.0 | |
Participants' contributions | | | 3.5 | | | | 3.5 | | | | 2.4 | | | | 2.6 | |
Benefits paid | | | (13.5 | ) | | | (12.5 | ) | | | (10.2 | ) | | | (9.9 | ) |
Ending fair value | | $ | 32.8 | | | $ | 44.3 | | | $ | 29.8 | | | $ | 39.9 | |
Funded status at end of year | | $ | (69.1 | ) | | $ | (93.0 | ) | | $ | (46.6 | ) | | $ | (62.5 | ) |
Curtailment loss for the Pension Plan and the Restoration of Retirement Income Plan atyear ended December 31, 2019 was $563.3 million and $8.1 million, respectively. The accumulated postretirement benefit obligation for2021 is related to Enable seconded employees who terminated employment as a result of the Pension Plan andmerger with Energy Transfer. This reduction in future service of the Restorationactive participants triggered curtailment accounting as of Retirement Income Plan at December 31, 2018 was $561.9 million and $7.8 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 included in the following table.
| | | | | | | | | | | | | | | | | | | | |
| Pension Plan | | Restoration of Retirement
Income Plan | | Postretirement
Benefit Plans | |
December 31 (In millions) | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 |
| Change in benefit obligation | | | | | | |
| Beginning obligations | $ | 615.9 | | $ | 687.5 | | $ | 9.6 | | $ | 8.1 | | $ | 135.8 | | $ | 149.4 | |
| Service cost | 12.9 | | 14.9 | | 0.5 | | 0.4 | | 0.2 | | 0.3 | |
| Interest cost | 20.7 | | 23.8 | | 0.4 | | 0.3 | | 5.6 | | 5.4 | |
| | | | | | |
| Plan settlements | (83.1) | | (73.7) | | (1.2) | | (2.0) | | — | | — | |
| Plan amendments | — | | — | | 0.3 | | — | | — | | — | |
| Participants' contributions | — | | — | | — | | — | | 4.1 | | 3.8 | |
| | | | | | |
| Actuarial losses (gains) | 64.3 | | (22.0) | | 0.7 | | 2.8 | | 2.9 | | (9.6) | |
| Benefits paid | (14.6) | | (14.6) | | — | | — | | (12.1) | | (13.5) | |
| Ending obligations | $ | 616.1 | | $ | 615.9 | | $ | 10.3 | | $ | 9.6 | | $ | 136.5 | | $ | 135.8 | |
| | | | | | |
| Change in plans' assets | | | | | | |
| Beginning fair value | $ | 522.8 | | $ | 635.3 | | $ | — | | $ | — | | $ | 45.3 | | $ | 50.2 | |
| Actual return on plans' assets | 85.2 | | (39.2) | | — | | — | | 4.6 | | (0.6) | |
| Employer contributions | 20.0 | | 15.0 | | 1.2 | | 2.0 | | 5.1 | | 5.4 | |
| Plan settlements | (83.1) | | (73.7) | | (1.2) | | (2.0) | | — | | — | |
| Participants' contributions | — | | — | | — | | — | | 4.1 | | 3.8 | |
| | | | | | |
| Benefits paid | (14.6) | | (14.6) | | — | | — | | (12.1) | | (13.5) | |
| Ending fair value | $ | 530.3 | | $ | 522.8 | | $ | — | | $ | — | | $ | 47.0 | | $ | 45.3 | |
| Funded status at end of year | $ | (85.8) | | $ | (93.1) | | $ | (10.3) | | $ | (9.6) | | $ | (89.5) | | $ | (90.5) | |
Net Periodic Benefit Cost
The following
table presentstables present the net periodic benefit cost components, before consideration of capitalized amounts, of
the Company'sOGE Energy's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the
Consolidated Financial Statements.financial statements. Service cost is presented within Other Operation and Maintenance
Expense, and
interestthe remaining net period benefit cost
expected return on plan assets, amortization of net loss, amortization of unrecognized prior service cost and settlement costcomponents as listed in the following tables are presented within Other Net Periodic Benefit
ExpenseIncome (Expense) in the
Company's Consolidated Statementsstatements of
Income.income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. 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 review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit
ExpenseIncome (Expense) in the
Company's Consolidated Statementsstatements of
Income.income. | | | | | | | | | | | | | | | | | | | | | | | | |
OGE Energy | | Pension Plan | | | Restoration of Retirement
Income Plan | |
Year Ended December 31
(In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Service cost | | $ | 7.6 | | | $ | 11.2 | | | $ | 13.2 | | | $ | 1.1 | | | $ | 0.8 | | | $ | 0.8 | |
Interest cost | | | 15.7 | | | | 13.3 | | | | 17.0 | | | | 0.2 | | | | 0.1 | | | | 0.2 | |
Expected return on plan assets | | | (25.4 | ) | | | (34.1 | ) | | | (37.6 | ) | | | — | | | | — | | | | — | |
Amortization of net loss | | | 8.9 | | | | 9.4 | | | | 17.1 | | | | 0.2 | | | | 0.2 | | | | 0.5 | |
Plan curtailments | | | — | | | | — | | | | — | | | | — | | | | — | | | | 0.2 | |
Special termination benefits | | | — | | | | — | | | | 7.6 | | | | — | | | | — | | | | — | |
Amortization of unrecognized prior service cost (A) | | | — | | | | — | | | | — | | | | 0.2 | | | | 0.1 | | | | — | |
Settlement cost | | | 30.6 | | | | 41.3 | | | | 14.1 | | | | 0.3 | | | | 2.1 | | | | 2.7 | |
Total net periodic benefit cost | | | 37.4 | | | | 41.1 | | | | 31.4 | | | | 2.0 | | | | 3.3 | | | | 4.4 | |
Less: Amount paid by unconsolidated affiliates | | | — | | | | (0.2 | ) | | | 2.0 | | | | — | | | | 0.1 | | | | 0.1 | |
Net periodic benefit cost | | $ | 37.4 | | | $ | 41.3 | | | $ | 29.4 | | | $ | 2.0 | | | $ | 3.2 | | | $ | 4.3 | |
(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.
| | Pension Plan | | Restoration of Retirement
Income Plan | | Postretirement Benefit Plans | | |
OG&E | | | Pension Plan | | | Restoration of Retirement
Income Plan | |
Year Ended December 31 (In millions) | Year Ended December 31 (In millions) | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
| Service cost | Service cost | $ | 12.9 | | $ | 14.9 | | $ | 15.5 | | $ | 0.5 | | $ | 0.4 | | $ | 0.3 | | $ | 0.2 | | $ | 0.3 | | $ | 0.6 | | | $ | 6.2 | | | $ | 7.7 | | | $ | 9.2 | | | $ | — | | | $ | — | | | $ | 0.1 | |
| Interest cost | 20.7 | | 23.8 | | 26.2 | | 0.4 | | 0.3 | | 0.3 | | 5.6 | | 5.4 | | 7.2 | | |
Interest cost | | | | 12.1 | | | | 9.7 | | | | 12.6 | | | | — | | | | — | | | | 0.1 | |
| Expected return on plan assets | Expected return on plan assets | (36.1) | | (44.1) | | (42.6) | | — | | — | | — | | (1.9) | | (2.0) | | (2.2) | | | | (19.6 | ) | | | (24.7 | ) | | | (27.9 | ) | | | — | | | | — | | | | — | |
| | Amortization of net loss | Amortization of net loss | 17.3 | | 16.2 | | 17.4 | | 0.5 | | 0.7 | | 0.4 | | 2.0 | | 3.8 | | 2.0 | | | | 7.4 | | | | 7.0 | | | | 12.1 | | | | — | | | | 0.1 | | | | 0.4 | |
| Amortization of unrecognized prior service cost (A) | — | | — | | (0.1) | | — | | 0.1 | | 0.1 | | (8.4) | | (8.4) | | (3.5) | | |
| Special termination benefits | | | | — | | | | — | | | | 5.1 | | | | — | | | | — | | | | — | |
| Settlement cost | Settlement cost | 27.6 | | 25.1 | | 15.3 | | 0.5 | | 1.0 | | — | | — | | — | | 0.6 | | | | 12.9 | | | | 33.1 | | | | 11.4 | | | | — | | | | 1.6 | | | | 2.4 | |
| Total net periodic benefit cost | Total net periodic benefit cost | 42.4 | | 35.9 | | 31.7 | | 1.9 | | 2.5 | | 1.1 | | (2.5) | | (0.9) | | 4.7 | | | | 19.0 | | | | 32.8 | | | | 22.5 | | | | — | | | | 1.7 | | | | 3.0 | |
| Less: Amount paid by unconsolidated affiliates | 2.9 | | 2.5 | | 4.3 | | 0.1 | | 0.1 | | — | | (0.6) | | (0.5) | | 0.3 | | |
Plus: Amount allocated from OGE Energy | | | | 5.2 | | | | 6.5 | | | | 5.9 | | | | 1.5 | | | | 1.5 | | | | 1.3 | |
| Net periodic benefit cost | Net periodic benefit cost | $ | 39.5 | | $ | 33.4 | | $ | 27.4 | | $ | 1.8 | | $ | 2.4 | | $ | 1.1 | | $ | (1.9) | | $ | (0.4) | | $ | 4.4 | | | $ | 24.2 | | | $ | 39.3 | | | $ | 28.4 | | | $ | 1.5 | | | $ | 3.2 | | | $ | 4.3 | |
In addition to the net periodic benefit cost amounts recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2022, 2021 and 2020, the Registrants recognized the following:
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
Increase of regulatory asset related to pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A) | | $ | 15.2 | | | $ | 23.0 | | | $ | 13.8 | |
Deferral of pension expense related to pension settlement, curtailment and special termination benefits charges included in the above line item: | | | | | | | | | |
Oklahoma jurisdiction (A) | | $ | 15.4 | | | $ | 37.9 | | | $ | 21.6 | |
Arkansas jurisdiction (A) | | $ | 1.4 | | | $ | 3.5 | | | $ | 2.0 | |
(A)Included in the pension regulatory asset in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
| | Postretirement Benefit Plans | | | Postretirement Benefit Plans | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Service cost | | $ | 0.2 | | | $ | 0.2 | | | $ | 0.2 | | | $ | 0.1 | | | $ | 0.1 | | | $ | 0.2 | |
Interest cost | | | 3.5 | | | | 3.4 | | | | 4.2 | | | | 2.7 | | | | 2.6 | | | | 3.2 | |
Expected return on plan assets | | | (1.8 | ) | | | (1.8 | ) | | | (1.8 | ) | | | (1.6 | ) | | | (1.7 | ) | | | (1.7 | ) |
Amortization of net loss | | | 1.5 | | | | 2.8 | | | | 2.0 | | | | 1.5 | | | | 2.7 | | | | 2.1 | |
Plan curtailments | | | — | | | | — | | | | 1.5 | | | | — | | | | — | | | | 1.3 | |
Amortization of unrecognized prior service cost (A) | | | (3.8 | ) | | | (6.9 | ) | | | (8.4 | ) | | | (3.6 | ) | | | (5.0 | ) | | | (6.1 | ) |
Total net periodic benefit income | | | (0.4 | ) | | | (2.3 | ) | | | (2.3 | ) | | | (0.9 | ) | | | (1.3 | ) | | | (1.0 | ) |
Less: Amount paid by unconsolidated affiliates (B) | | | — | | | | (0.5 | ) | | | (0.7 | ) | | | | | | | | | |
Plus: Amount allocated from OGE Energy (B) | | | | | | | | | | | | — | | | | (0.5 | ) | | | (0.5 | ) |
Net periodic benefit income | | $ | (0.4 | ) | | $ | (1.8 | ) | | $ | (1.6 | ) | | $ | (0.9 | ) | | $ | (1.8 | ) | | $ | (1.5 | ) |
(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.
"Amount paid by unconsolidated affiliates" is only applicable to OGE Energy. "Amount allocated from OGE Energy" is only applicable to OG&E.
In addition to the net periodic benefit costincome amounts recognized, as presented in the table above, for the Pensionpostretirement benefit plans in 2022, 2021 and Restoration of Retirement Income Plans in 2019, 2018 and 2017,2020, the CompanyRegistrants recognized the following:
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
Increase (decrease) of regulatory liability related to postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A) | | $ | (0.6 | ) | | $ | 0.4 | | | $ | 1.6 | |
Deferral of postretirement expense related to postretirement plan curtailment charges included in the above line item: | | | | | | | | | |
Oklahoma jurisdiction (A) | | $ | — | | | $ | — | | | $ | (1.4 | ) |
Arkansas jurisdiction (A) | | $ | — | | | $ | — | | | $ | (0.1 | ) |
| | | | | | | | | | | |
| Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Decrease of pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A) | $ | (16.1) | | $ | (14.1) | | $ | (2.3) | |
| Deferral of pension expense related to pension settlement charges: | | | |
| Oklahoma jurisdiction (A) | $ | 17.9 | | $ | 22.1 | | $ | 13.2 | |
| Arkansas jurisdiction (A) | $ | 1.7 | | $ | 2.1 | | $ | 1.1 | |
(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.
In addition toThe following table presents the amount of net periodic benefit incomecost capitalized and cost amounts recognized, as presented inattributable to each of the table above,Registrants for theOGE Energy's Pension Plan and postretirement benefit plans in 2019, 20182022, 2021 and 2017, the Company recognized the following:2020.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | OGE Energy | | | OG&E | |
(In millions) | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Capitalized portion of net periodic pension benefit cost | | $ | 3.0 | | | $ | 3.4 | | | $ | 3.8 | | | $ | 2.5 | | | $ | 2.9 | | | $ | 3.1 | |
Capitalized portion of net periodic postretirement benefit cost | | $ | 0.2 | | | $ | 0.2 | | | $ | 0.2 | | | $ | 0.1 | | | $ | 0.1 | | | $ | 0.1 | |
| | | | | | | | | | | |
| Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Increase of postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A) | $ | 1.0 | | $ | 4.4 | | $ | 6.2 | |
(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.
| | | | | | | | | | | |
| (In millions) | 2019 | 2018 | 2017 |
| Capitalized portion of net periodic pension benefit cost | $ | 3.6 | | $ | 3.8 | | $ | 4.4 | |
| Capitalized portion of net periodic postretirement benefit cost | $ | 0.2 | | $ | 0.2 | | $ | 1.2 | |
Rate Assumptions
| | | | | | | | | | | | | | | | | | | | |
| Pension Plan and
Restoration of Retirement Income Plan | | | Postretirement
Benefit Plans | | |
| Year Ended December 31 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 |
| Assumptions to determine benefit obligations: | | | | | | | | | | | | |
| Discount rate | 3.15 | % | 4.20 | % | 3.60 | % | 3.25 | % | 4.30 | % | 3.70 | % |
| Rate of compensation increase | 4.20 | % | 4.20 | % | 4.20 | % | N/A | N/A | N/A | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Assumptions to determine net periodic benefit cost: | | | | | | |
| Discount rate | 3.63 | % | 3.73 | % | 4.00 | % | 4.30 | % | 3.70 | % | 4.20 | % |
| Expected return on plan assets | 7.50 | % | 7.50 | % | 7.50 | % | 4.00 | % | 4.00 | % | 4.00 | % |
| Rate of compensation increase | 4.20 | % | 4.20 | % | 4.20 | % | N/A | N/A | | 4.20 | % |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plan and
Restoration of Retirement Income Plan | | | Postretirement
Benefit Plans | |
Year Ended December 31 | | 2022 | | | 2021 | | | 2020 | | | 2022 | | | 2021 | | | 2020 | |
Assumptions to determine benefit obligations: | | | | | | | | | | | | | | | | | | |
Discount rate | | | 5.45 | % | | | 2.75 | % | | | 2.30 | % | | | 5.40 | % | | | 2.80 | % | | | 2.45 | % |
Rate of compensation increase | | | 4.20 | % | | | 4.20 | % | | | 4.20 | % | | N/A | | | N/A | | | N/A | |
Interest crediting rate | | | 3.50 | % | | | 3.50 | % | | | 3.50 | % | | N/A | | | N/A | | | N/A | |
Assumptions to determine net periodic benefit cost: | | | | | | | | | | | | | | | | | | |
Discount rate | | | 4.01 | % | | | 2.63 | % | | | 2.88 | % | | | 2.80 | % | | | 2.45 | % | | | 3.25 | % |
Expected return on plan assets | | | 7.00 | % | | | 7.00 | % | | | 7.50 | % | | | 4.00 | % | | | 4.00 | % | | | 4.00 | % |
Rate of compensation increase | | | 4.20 | % | | | 4.20 | % | | | 4.20 | % | | N/A | | | N/A | | | N/A | |
Interest crediting rate | | | 3.50 | % | | | 3.50 | % | | | 4.00 | % | | N/A | | | N/A | | | N/A | |
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 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, unless a plan settlement occurs during the current year that requires an updated discount rate for net periodic cost measurement. For 20192022 and 2018,2021, the Pension Plan discount rates used to determine net periodic benefit cost are disclosed on a weighted-average basis.
The overall expected rate of return on plan assets assumption was 7.50 percent in both 2019 and 2018, which wasis used in determining net periodic benefit cost due to recent returns on the Company's long-term investment portfolio.cost. 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 7.006.25 percent in 20202023 with the rates trending downward to 4.50 percent by 2030. The effects of a one-percentage point change in the assumed health care cost trend rate are presented in the following tables.
| | | | | | | | | | | |
| ONE-PERCENTAGE POINT INCREASE | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Effect on aggregate of the service and interest cost components | $ | — | | $ | — | | $ | — | |
| Effect on accumulated postretirement benefit obligations | $ | 0.1 | | $ | 0.1 | | $ | 0.1 | |
| | | | | | | | | | | |
| ONE-PERCENTAGE POINT DECREASE | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| Effect on aggregate of the service and interest cost components | $ | — | | $ | — | | $ | — | |
| Effect on accumulated postretirement benefit obligations | $ | 0.3 | | $ | 0.3 | | $ | 0.3 | |
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 following table below sets forthpresents 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.following table. | | | | | | |
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% |
| | | | | | | | | | | |
| 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
OGE Energy 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'sRegistrants' members and the Company'sOGE Energy'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.
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 threethree- to five yearfive-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
The following table presents a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:
against and the focus of the asset class. | | | | | |
Asset Class | Comparative Benchmark(s) | Focus of Asset Class |
Active Duration Fixed Income (A)(B) | Bloomberg Barclays Aggregate | - Maximize risk-adjusted performance while providing long bond exposure managed according to the manager's forecast on interest rates.
- All invested assets must reach at or above Baa3 or BBB- investment grade.
- Limited five percent exposure to any single issuer, except the U.S. Government or affiliates. |
| |
Long Duration Fixed Income (A)(B) | Duration blended Barclays Long Government/Credit & Barclays Universal | - Maximize risk-adjusted performance.
- At least 75 percent of invested assets much reach at or above Baaa3 or BBB- investment grade.
- Limited five percent exposure to any single issuer, except the U.S. Government or affiliates.
- May invest up to 10 percent of the market value in convertible bonds as long as quality guidelines are met.
- May invest up to 15 percent of the market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. |
Equity Index (B)(C) | Standard & Poor's 500 Index | - Focus on replicating the performance of the S&P 500 Index. |
| |
| |
Mid-Cap Equity (B)(C)
Small-Cap Equity (B)(C) | Russell Midcap Index |
|
Russell Midcap Value Index |
Small-Cap Equity |
Russell 2000 Index |
|
Russell 2000 Value Index | - Focus on undervalued stocks expected to earn average return and pay out higher than average dividends.
- Invest in companies with market capitalizations lower than average company on public exchanges:
- Price/earnings ratio at or near referenced
- Small dividend yield and return on equity at or near referenced index; and
- Earnings per share growth rate at or near referenced index. |
International Equity (D) | Morgan Stanley Capital International ACWI ex-U.S. | - Invest in non-dollar denominated equity securities. - Diversify the overall trust investments. |
The fixed income managers are expected to use discretion over the asset mix of the trust assets in their 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-Investment grades are by Moody's Investors Service, S&P's&P Global Ratings 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.
(B)The purchase of any of the Company'sOGE Energy's equity, debt or other securities is prohibited.
(C)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 from OGE Energy's Investment Committee is received. The purchase of securities on margin, securities lending, private placement purchases and venture capital purchases are prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.
(D)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 managerthis asset class 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.
Pension Plan Investments
The following tables summarizepresent the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 20192022 and 2018.2021. There were no Level 3 investments held by the Pension Plan at December 31, 20192022 and 2018.
| | | | | | | | | | | | | | |
| (In millions) | December 31, 2019 | Level 1 | Level 2 | Net Asset Value (A) |
| Common stocks | $ | 202.0 | | $ | 202.0 | | $ | — | | $ | — | |
| U.S. Treasury notes and bonds (B) | 134.8 | | 134.8 | | — | | — | |
| Mortgage- and asset-backed securities | 45.8 | | — | | 45.8 | | — | |
| Corporate fixed income and other securities | 130.5 | | — | | 130.5 | | — | |
| Commingled fund (C) | 23.9 | | — | | — | | 23.9 | |
| Foreign government bonds | 3.0 | | — | | 3.0 | | — | |
| U.S. municipal bonds | 1.1 | | — | | 1.1 | | — | |
| | | | |
| Money market fund | 7.5 | | — | | — | | 7.5 | |
| Mutual fund | 2.4 | | 2.4 | | — | | — | |
| Preferred stocks | 0.7 | | 0.7 | | — | | — | |
| Futures: | | | | |
| U.S. Treasury futures (receivable) | 22.9 | | — | | 22.9 | | — | |
| U.S. Treasury futures (payable) | (10.9) | | — | | (10.9) | | — | |
| Cash collateral | 0.6 | | 0.6 | | — | | — | |
| Forward contracts: | | | | |
| Receivable (foreign currency) | 0.1 | | — | | 0.1 | | — | |
| | | | |
| Total Pension Plan investments | 564.4 | | $ | 340.5 | | $ | 192.5 | | $ | 31.4 | |
| | | | |
| Interest and dividends receivable | 2.4 | | | | |
| Payable to broker for securities purchased | (36.5) | | | | |
| Total Pension Plan assets | $ | 530.3 | | | | |
| | | | | | | | | | | | | | | |
(In millions) | December 31, 2022 | | | Level 1 | | | Level 2 | | | Net Asset Value (A) | |
Common stocks | $ | 71.9 | | | $ | 71.9 | | | $ | — | | | $ | — | |
U.S. Treasury notes and bonds (B) | | 44.6 | | | | 44.6 | | | | — | | | | — | |
Mortgage- and asset-backed securities | | 26.2 | | | | — | | | | 26.2 | | | | — | |
Corporate fixed income and other securities | | 65.5 | | | | — | | | | 65.5 | | | | — | |
Commingled fund (C) | | 18.2 | | | | — | | | | — | | | | 18.2 | |
Foreign government bonds | | 0.5 | | | | — | | | | 0.5 | | | | — | |
U.S. municipal bonds | | 0.9 | | | | — | | | | 0.9 | | | | — | |
Money market fund | | 5.9 | | | | — | | | | — | | | | 5.9 | |
Mutual fund | | 60.4 | | | | 60.4 | | | | — | | | | — | |
Preferred stocks | | 1.5 | | | | 1.5 | | | | — | | | | — | |
U.S. Treasury futures: | | | | | | | | | | | |
Cash collateral | | 0.3 | | | | 0.3 | | | | — | | | | — | |
Forward contracts: | | | | | | | | | | | |
Receivable (foreign currency) | | 0.1 | | | | — | | | | 0.1 | | | | — | |
Total Pension Plan investments | | 296.0 | | | $ | 178.7 | | | $ | 93.2 | | | $ | 24.1 | |
Interest and dividends receivable | | 1.6 | | | | | | | | | | |
Receivable from broker for securities sold | | 20.6 | | | | | | | | | | |
Payable to broker for securities purchased | | (25.2 | ) | | | | | | | | | |
Total OGE Energy Pension Plan assets | $ | 293.0 | | | | | | | | | | |
Pension Plan investments attributable to affiliates | | (54.1 | ) | | | | | | | | | |
Total OG&E Pension Plan assets | $ | 238.9 | | | | | | | | | | |
| | | | | | | | | | | | | | | |
(In millions) | December 31, 2021 | | | Level 1 | | | Level 2 | | | Net Asset Value (A) | |
Common stocks | $ | 86.1 | | | $ | 86.1 | | | $ | — | | | $ | — | |
U.S. Treasury notes and bonds (B) | | 135.2 | | | | 135.2 | | | | — | | | | — | |
Mortgage- and asset-backed securities | | 24.6 | | | | — | | | | 24.6 | | | | — | |
Corporate fixed income and other securities | | 107.0 | | | | — | | | | 107.0 | | | | — | |
Commingled fund (C) | | 23.6 | | | | — | | | | — | | | | 23.6 | |
Foreign government bonds | | 0.9 | | | | — | | | | 0.9 | | | | — | |
U.S. municipal bonds | | 1.4 | | | | — | | | | 1.4 | | | | — | |
Money market fund | | 5.5 | | | | — | | | | — | | | | 5.5 | |
Mutual fund | | 99.8 | | | | 99.8 | | | | — | | | | — | |
Preferred stocks | | 1.1 | | | | 1.1 | | | | — | | | | — | |
U.S. Treasury futures: | | | | | | | | | | | |
Cash collateral | | 0.6 | | | | 0.6 | | | | — | | | | — | |
Forward contracts: | | | | | | | | | | | |
Receivable (foreign currency) | | 0.1 | | | | — | | | | 0.1 | | | | — | |
Total Pension Plan investments | | 485.9 | | | $ | 322.8 | | | $ | 134.0 | | | $ | 29.1 | |
Interest and dividends receivable | | 2.1 | | | | | | | | | | |
Payable to broker for securities purchased | | (2.0 | ) | | | | | | | | | |
Total OGE Energy Pension Plan assets | $ | 486.0 | | | | | | | | | | |
Pension Plan investments attributable to affiliates | | (133.0 | ) | | | | | | | | | |
Total OG&E Pension Plan assets | $ | 353.0 | | | | | | | | | | |
(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 Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service 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.
| | | | | | | | | | | | | | |
| (In millions) | December 31, 2018 | Level 1 | Level 2 | Net Asset Value (A) |
| | | | |
| Common stocks | $ | 169.3 | | $ | 169.3 | | $ | — | | $ | — | |
| | | | |
| | | | |
| U.S. Treasury notes and bonds (B) | 137.9 | | 137.9 | | — | | — | |
| Mortgage- and asset-backed securities | 65.9 | | — | | 65.9 | | — | |
| | | | |
| | | | |
| Corporate fixed income and other securities | 143.2 | | — | | 143.2 | | — | |
| | | | |
| Commingled fund (C) | 19.7 | | — | | — | | 19.7 | |
| Foreign government bonds | 4.4 | | — | | 4.4 | | — | |
| U.S. municipal bonds | 0.6 | | — | | 0.6 | | — | |
| | | | |
| Money market fund | 0.3 | | — | | — | | 0.3 | |
| | | | |
| Mutual fund | 8.0 | | 8.0 | | — | | — | |
| | | | |
| Futures: | | | | |
| U.S. Treasury futures (receivable) | 27.0 | | — | | 27.0 | | — | |
| U.S. Treasury futures (payable) | (20.4) | | — | | (20.4) | | — | |
| Cash collateral | 0.7 | | 0.7 | | — | | — | |
| Forward contracts: | | | | |
| Receivable (foreign currency) | 0.1 | | — | | 0.1 | | — | |
| | | | |
| Total Pension Plan investments | 556.7 | | $ | 315.9 | | $ | 220.8 | | $ | 20.0 | |
| | | | |
| Interest and dividends receivable | 3.0 | | | | |
| Payable to broker for securities purchased | (36.9) | | | | |
| Total Pension Plan assets | $ | 522.8 | | | | |
(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 Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service 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.
As defined in the fair value hierarchy, 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. 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 Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
Expected Benefit Payments
The following table
summarizespresents the benefit payments the
Company expectsRegistrants expect to pay related to
OGE Energy'sthe Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure
the Company'sOGE Energy's benefit obligation at the end of the year and include benefits attributable to estimated future employee service.
| | | | | | | | |
(In millions) | | OGE Energy | | | OG&E | |
2023 | | $ | 92.0 | | | $ | 80.1 | |
2024 | | $ | 29.4 | | | $ | 23.1 | |
2025 | | $ | 27.7 | | | $ | 21.8 | |
2026 | | $ | 28.9 | | | $ | 23.0 | |
2027 | | $ | 35.1 | | | $ | 21.3 | |
2028-2032 | | $ | 128.6 | | | $ | 99.7 | |
| | | | | |
(In millions) | Projected Benefit Payments |
| 2020 | $ | 58.4 | |
| 2021 | $ | 56.8 | |
| 2022 | $ | 56.2 | |
| 2023 | $ | 55.7 | |
| 2024 | $ | 56.6 | |
| After 2024 | $ | 249.4 | |
Postretirement Benefit Plans
In addition to providing pension benefits, the CompanyOGE Energy 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 CompanyOGE Energy 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 postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.
The Company'sOGE Energy's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and the CompanyOGE Energy 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 CompanyOGE Energy provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to a Company-sponsoredan OGE Energy-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.
Postretirement Plans Investments
The following tables summarizepresent the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 20192022 and 2018.2021. There were no Level 2 investments held by the postretirement benefit plans at December 31, 20192022 and 2018.2021.
| | | | | | | | | | | | |
(In millions) | | December 31, 2022 | | | Level 1 | | | Level 3 | |
Group retiree medical insurance contract | | $ | 21.6 | | | $ | — | | | $ | 21.6 | |
Mutual funds | | | 11.2 | | | | 11.2 | | | | — | |
Total OGE Energy plan investments | | $ | 32.8 | | | $ | 11.2 | | | $ | 21.6 | |
Plan investments attributable to affiliates | | | (3.0 | ) | | | | | | |
Total OG&E plan investments | | $ | 29.8 | | | | | | | |
| | | | | | | | | | | | |
(In millions) | | December 31, 2021 | | | Level 1 | | | Level 3 | |
Group retiree medical insurance contract | | $ | 28.1 | | | $ | — | | | $ | 28.1 | |
Mutual funds | | | 16.2 | | | | 16.2 | | | | — | |
Total OGE Energy plan investments | | $ | 44.3 | | | $ | 16.2 | | | $ | 28.1 | |
Plan investments attributable to affiliates | | | (4.4 | ) | | | | | | |
Total OG&E plan investments | | $ | 39.9 | | | | | | | |
| | | | | | | | | | | |
| (In millions) | December 31, 2019 | Level 1 | Level 3 |
| Group retiree medical insurance contract | $ | 34.8 | | $ | — | | $ | 34.8 | |
| | | |
| Mutual funds | 10.9 | | 10.9 | | — | |
| Money market fund | 1.2 | | 1.2 | | — | |
| | | |
| Total plan investments | $ | 46.9 | | $ | 12.1 | | $ | 34.8 | |
| | | | | | | | | | | |
| (In millions) | December 31, 2018 | Level 1 | Level 3 |
| Group retiree medical insurance contract | $ | 36.0 | | $ | — | | $ | 36.0 | |
| | | |
| Mutual funds | 8.9 | | 8.9 | | — | |
| | | |
| Cash | 0.9 | | 0.9 | | — | |
| Total plan investments | $ | 45.8 | | $ | 9.8 | | $ | 36.0 | |
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.
The following table summarizespresents a reconciliation of 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) | | 2022 | |
Group retiree medical insurance contract: | | | |
Beginning balance | | $ | 28.1 | |
Claims paid | | | (4.8 | ) |
Net unrealized losses related to instruments held at the reporting date | | | (1.8 | ) |
Investment fees | | | (0.1 | ) |
Realized losses | | | (0.6 | ) |
Interest income | | | 0.7 | |
Dividend income | | | 0.1 | |
Ending balance | | $ | 21.6 | |
| | | | | |
Year Ended December 31 (In millions)
| 2019 |
Group retiree medical insurance contract: | |
Beginning balance | $ | 36.0 | |
Claims paid | (3.8) | |
Investment fees | (0.1) | |
Net unrealized gains related to instruments held at the reporting date | 1.4 | |
Interest income | 0.8 | |
Dividend income | 0.5 | |
| |
Ending balance | $ | 34.8 | |
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 summarizespresents the gross benefit payments the Company expectsRegistrants expect to pay related to itsthe postretirement benefit plans, including prescription drug benefits.
| | | | | | | | |
(In millions) | | OGE Energy | | | OG&E | |
2023 | | $ | 12.0 | | | $ | 9.1 | |
2024 | | $ | 11.7 | | | $ | 8.9 | |
2025 | | $ | 10.0 | | | $ | 7.5 | |
2026 | | $ | 9.5 | | | $ | 7.1 | |
2027 | | $ | 8.9 | | | $ | 6.7 | |
After 2027 | | $ | 37.0 | | | $ | 27.8 | |
| | | | | |
(In millions) | Gross Projected
Postretirement
Benefit
Payments |
| 2020 | $ | 11.2 | |
| 2021 | $ | 11.2 | |
| 2022 | $ | 11.1 | |
| 2023 | $ | 9.5 | |
| 2024 | $ | 9.4 | |
| After 2024 | $ | 42.3 | |
Post-Employment Benefit Plan
Disabled employees receiving benefits from the Company'sOGE Energy's Group Long-Term Disability Plan are entitled to continue participating in the Company'sOGE Energy'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'sOGE Energy'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 are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company'sOGE Energy's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits. The Company'sOGE Energy's post-employment benefit obligation was $2.1$1.8 million and $1.9$2.0 million at December 31, 20192022 and 2018, respectively.
2021, respectively, of which $1.3 million and $1.5 million, respectively, was OG&E's portion of the obligation.
401(k) Plan
The Company
OGE Energy provides a 401(k) Plan, and each regular full-time employee of the CompanyOGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately.immediately upon hire. All other employees of the CompanyOGE Energy 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 1975 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 their 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 CompanyOGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to 5five percent of compensation.
No CompanyOGE Energy 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'sOGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. The CompanyOGE Energy match
contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their CompanyOGE Energy 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 CompanyOGE Energy or its affiliates. The CompanyOGE Energy contributed $14.4$17.1 million, $13.2$15.4 million and $13.2$18.2 million in 2019, 20182022, 2021 and 2017,2020, respectively, to the 401(k) Plan.
Plan, of which $13.9 million, $12.0 million and $14.3 million, respectively, related to OG&E.
Deferred Compensation Plan
The Company
OGE Energy 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 theOGE Energy's 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 CompanyOGE Energy 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 CompanyOGE Energy or termination of the plan. Deferrals, plus any CompanyOGE Energy 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 2019,2022, those investment options included a Companyan OGE Energy Common Stock fund, whose value was determined based on the stock price of the Company's common stock. The CompanyOGE Energy's Common Stock. OGE Energy accounts for the contributions related to the Company'sits executive officers in this plan as Accrued Benefit Obligations and the Company accounts for the contributions related to the Company'sOGE Energy's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.balance sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets.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 Statementsstatements of Income.
Supplemental Executive Retirement Plan
The CompanyOGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of the Company'sOGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under the Company'sOGE Energy's Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code. For the actuarial equivalence calculations, the supplemental executive retirement plan provides that (i) mortality rates shall be based on the unisex mortality table issued under Internal Revenue Service Notice 2018-02 for purposes of determining the minimum present value under Code Section 417(e)(3) for distributions with annuity starting dates that occur during stability periods beginning in the 2019 calendar year and (ii) the interest rate shall be five percent.
14.Report of Business Segments
The CompanyOGE Energy reports its operations in two business segments: (i) the electric utilitycompany segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) natural gas midstream operations segment. Prior to the Enable and Energy Transfer merger closing on December 2, 2021, OGE Energy's natural gas midstream operations segment included its equity method investment in Enable. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment included OGE Energy's investment in Energy Transfer's equity securities acquired in the merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. 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 summarizepresent the results of the Company'sOGE Energy's business segments for the years ended December 31, 2019, 20182022, 2021 and 2017.2020.
| | 2019 | Electric Utility | Natural Gas Midstream Operations | Other
Operations | Eliminations | Total | |
2022 | | | Electric Company | | | Natural Gas Midstream Operations | | | Other
Operations | | | Eliminations | | | Total | |
| (In millions) | (In millions) | | | | | | | | | | | | | | | | |
| Operating revenues | Operating revenues | $ | 2,231.6 | | $ | — | | $ | — | | $ | — | | $ | 2,231.6 | | | $ | 3,375.7 | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,375.7 | |
| Cost of sales | 786.9 | | — | | — | | — | | 786.9 | | |
Fuel, purchased power and direct transmission expense | | | | 1,662.4 | | | | — | | | | — | | | | — | | | | 1,662.4 | |
| Other operation and maintenance | Other operation and maintenance | 492.5 | | 2.8 | | (3.5) | | — | | 491.8 | | | | 491.9 | | | | 12.6 | | | | (3.1 | ) | | | — | | | | 501.4 | |
| Depreciation and amortization | Depreciation and amortization | 355.0 | | — | | — | | — | | 355.0 | | | | 460.9 | | | | — | | | | — | | | | — | | | | 460.9 | |
| | Taxes other than income | Taxes other than income | 89.5 | | 0.4 | | 3.7 | | — | | 93.6 | | | | 98.0 | | | | 0.1 | | | | 3.4 | | | | — | | | | 101.5 | |
| Operating income (loss) | Operating income (loss) | 507.7 | | (3.2) | | (0.2) | | — | | 504.3 | | | | 662.5 | | | | (12.7 | ) | | | (0.3 | ) | | | — | | | | 649.5 | |
| Equity in earnings of unconsolidated affiliates | — | | 113.9 | | — | | — | | 113.9 | | |
Gain on equity securities | | | | — | | | | 282.1 | | | | — | | | | — | | | | 282.1 | |
| Other income (expense) | Other income (expense) | 3.1 | | (8.6) | | 2.2 | | (3.6) | | (6.9) | | | | 11.2 | | | | 10.0 | | | | 4.9 | | | | (2.1 | ) | | | 24.0 | |
| Interest expense | Interest expense | 140.5 | | — | | 11.0 | | (3.6) | | 147.9 | | | | 157.8 | | | | — | | | | 10.6 | | | | (2.1 | ) | | | 166.3 | |
| Income tax expense (benefit) | Income tax expense (benefit) | 20.1 | | 20.7 | | (11.0) | | — | | 29.8 | | | | 76.4 | | | | 48.1 | | | | (0.9 | ) | | | — | | | | 123.6 | |
| Net income | $ | 350.2 | | $ | 81.4 | | $ | 2.0 | | $ | — | | $ | 433.6 | | |
| Investment in unconsolidated affiliates | $ | — | | $ | 1,132.9 | | $ | 18.6 | | $ | — | | $ | 1,151.5 | | |
Net income (loss) | | | $ | 439.5 | | | $ | 231.3 | | | $ | (5.1 | ) | | $ | — | | | $ | 665.7 | |
| Total assets | Total assets | $ | 10,076.6 | | $ | 1,135.4 | | $ | 107.0 | | $ | (294.7) | | $ | 11,024.3 | | | $ | 12,410.5 | | | $ | 1.2 | | | $ | 683.7 | | | $ | (550.7 | ) | | $ | 12,544.7 | |
| Capital expenditures | Capital expenditures | $ | 635.5 | | $ | — | | $ | — | | $ | — | | $ | 635.5 | | | $ | 1,050.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,050.9 | |
| | | | | | | | | | | | | | | | | | | | |
2021 | | Electric Company | | | Natural Gas Midstream Operations | | | Other
Operations | | | Eliminations | | | Total | |
(In millions) | | | | | | | | | | | | | | | |
Operating revenues | | $ | 3,653.7 | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,653.7 | |
Fuel, purchased power and direct transmission expense | | | 2,127.6 | | | | — | | | | — | | | | — | | | | 2,127.6 | |
Other operation and maintenance | | | 464.7 | | | | 1.6 | | | | (3.2 | ) | | | — | | | | 463.1 | |
Depreciation and amortization | | | 416.0 | | | | — | | | | — | | | | — | | | | 416.0 | |
Taxes other than income | | | 99.3 | | | | 0.2 | | | | 3.3 | | | | — | | | | 102.8 | |
Operating income (loss) | | | 546.1 | | | | (1.8 | ) | | | (0.1 | ) | | | — | | | | 544.2 | |
Equity in earnings of unconsolidated affiliates | | | — | | | | 169.8 | | | | — | | | | — | | | | 169.8 | |
Gain on Enable/Energy Transfer transaction, net | | | — | | | | 344.4 | | | | — | | | | — | | | | 344.4 | |
Other income (expense) | | | 7.7 | | | | (26.4 | ) | | | (2.0 | ) | | | (0.9 | ) | | | (21.6 | ) |
Interest expense | | | 152.0 | | | | — | | | | 7.2 | | | | (0.9 | ) | | | 158.3 | |
Income tax expense (benefit) | | | 41.8 | | | | 101.0 | | | | (1.6 | ) | | | — | | | | 141.2 | |
Net income (loss) | | $ | 360.0 | | | $ | 385.0 | | | $ | (7.7 | ) | | $ | — | | | $ | 737.3 | |
Total assets | | $ | 11,688.0 | | | $ | 786.6 | | | $ | 350.3 | | | $ | (218.5 | ) | | $ | 12,606.4 | |
Capital expenditures | | $ | 778.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 778.5 | |
| | | | | | | | | | | | | | | | | | | | |
2020 | | Electric Company | | | Natural Gas Midstream Operations | | | Other
Operations | | | Eliminations | | | Total | |
(In millions) | | | | | | | | | | | | | | | |
Operating revenues | | $ | 2,122.3 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,122.3 | |
Fuel, purchased power and direct transmission expense | | | 644.6 | | | | — | | | | — | | | | — | | | | 644.6 | |
Other operation and maintenance | | | 464.4 | | | | 1.7 | | | | (3.3 | ) | | | — | | | | 462.8 | |
Depreciation and amortization | | | 391.3 | | | | — | | | | — | | | | — | | | | 391.3 | |
Taxes other than income | | | 97.2 | | | | 0.4 | | | | 3.8 | | | | — | | | | 101.4 | |
Operating income (loss) | | | 524.8 | | | | (2.1 | ) | | | (0.5 | ) | | | — | | | | 522.2 | |
Equity in losses of unconsolidated affiliates (A) | | | — | | | | (668.0 | ) | | | — | | | | — | | | | (668.0 | ) |
Other income (expense) | | | 4.1 | | | | (2.9 | ) | | | 3.6 | | | | (1.6 | ) | | | 3.2 | |
Interest expense | | | 154.8 | | | | — | | | | 5.3 | | | | (1.6 | ) | | | 158.5 | |
Income tax expense (benefit) | | | 34.7 | | | | (158.0 | ) | | | (4.1 | ) | | | — | | | | (127.4 | ) |
Net income (loss) | | $ | 339.4 | | | $ | (515.0 | ) | | $ | 1.9 | | | $ | — | | | $ | (173.7 | ) |
Investment in unconsolidated affiliates | | $ | — | | | $ | 374.3 | | | $ | — | | | $ | — | | | $ | 374.3 | |
Total assets | | $ | 10,489.0 | | | $ | 378.1 | | | $ | 116.4 | | | $ | (264.7 | ) | | $ | 10,718.8 | |
Capital expenditures | | $ | 650.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 650.5 | |
In March 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable.
| | | | | | | | | | | | | | | | | |
| 2018 | Electric Utility | Natural Gas Midstream Operations | Other
Operations | Eliminations | Total |
| (In millions) | | | | | |
| Operating revenues | $ | 2,270.3 | | $ | — | | $ | — | | $ | — | | $ | 2,270.3 | |
| Cost of sales | 892.5 | | — | | — | | — | | 892.5 | |
| Other operation and maintenance | 473.8 | | 1.4 | | (0.6) | | — | | 474.6 | |
| Depreciation and amortization | 321.6 | | — | | — | | — | | 321.6 | |
| | | | | |
| | | | | |
| Taxes other than income | 88.2 | | 0.6 | | 3.2 | | — | | 92.0 | |
| Operating income (loss) | 494.2 | | (2.0) | | (2.6) | | — | | 489.6 | |
| Equity in earnings of unconsolidated affiliates | — | | 152.8 | | — | | — | | 152.8 | |
| Other income (expense) | 25.6 | | (4.9) | | (3.4) | | (6.0) | | 11.3 | |
| Interest expense | 151.8 | | — | | 10.2 | | (6.0) | | 156.0 | |
| Income tax expense (benefit) | 40.0 | | 37.1 | | (4.9) | | — | | 72.2 | |
| Net income (loss) | $ | 328.0 | | $ | 108.8 | | $ | (11.3) | | $ | — | | $ | 425.5 | |
| | | | | |
| | | | | |
| Investment in unconsolidated affiliates | $ | — | | $ | 1,166.6 | | $ | 10.9 | | $ | — | | $ | 1,177.5 | |
| Total assets | $ | 9,704.5 | | $ | 1,169.8 | | $ | 184.8 | | $ | (310.5) | | $ | 10,748.6 | |
| Capital expenditures | $ | 573.6 | | $ | — | | $ | — | | $ | — | | $ | 573.6 | |
| | | | | | | | | | | | | | | | | |
| 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 | 469.8 | | (0.8) | | (10.3) | | — | | 458.7 | |
| Depreciation and amortization | 280.9 | | — | | 2.6 | | — | | 283.5 | |
| | | | | |
| | | | | |
| Taxes other than income | 84.8 | | 1.0 | | 3.6 | | — | | 89.4 | |
| Operating income (loss) | 528.0 | | (0.2) | | 4.1 | | — | | 531.9 | |
| Equity in earnings of unconsolidated affiliates | — | | 131.2 | | — | | — | | 131.2 | |
| Other income (expense) | 57.7 | | (1.0) | | (5.4) | | (0.9) | | 50.4 | |
| 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.
15.Commitments and Contingencies
Public Utility Regulatory Policy Act of 1978
OG&E had a QF contract with AES which expired on January 15, 2019 and a QF contract with Oklahoma Cogeneration LLC which expired on August 31, 2019. For the 320 MW AES QF contract and the 120 MW Oklahoma Cogeneration LLC QF contract, OG&E purchased 100 percent of the electricity generated by the QFs.
In December 2018, OG&E announced its plan to acquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to meet customers' energy needs. In May 2019, OG&E received the necessary approval from the OCC and the FERC and conditional approval from the APSC to acquire both plants. In May 2019, OG&E acquired the power plant from AES, and in August 2019, OG&E acquired the power plant from Oklahoma Cogeneration LLC. In August 2019, OG&E received final approval from the APSC to acquire both plants. Further discussion can be found in Note 16.
For the years ended December 31, 2019, 2018 and 2017, OG&E made total payments to cogenerators of $14.7 million, $112.4 million and $115.2 million, respectively, of which $7.4 million, $60.0 million and $63.0 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Sales.
Purchase Obligations and Commitments
The Company'sfollowing table presents the Registrants' future purchase obligations and commitments estimated for the next five years are as follows:
| | | | | | | | | | | | | | | | | | | | |
| (In millions) | 2020 | 2021 | 2022 | 2023 | 2024 | Total |
| Purchase obligations and commitments: | | | | | | |
| Minimum purchase commitments | $ | 82.6 | | $ | 55.1 | | $ | 50.4 | | $ | 50.4 | | $ | 32.9 | | $ | 271.4 | |
| Expected wind purchase commitments | 55.7 | | 56.0 | | 56.4 | | 56.8 | | 57.5 | | 282.4 | |
| Long-term service agreement commitments | 2.4 | | 2.4 | | 2.4 | | 13.8 | | 32.1 | | 53.1 | |
| | | | | | |
| Environmental compliance plan expenditures | 0.4 | | — | | — | | — | | — | | 0.4 | |
| Total purchase obligations and commitments | $ | 141.1 | | $ | 113.5 | | $ | 109.2 | | $ | 121.0 | | $ | 122.5 | | $ | 607.3 | |
109 | | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | | 2023 | | | 2024 | | | 2025 | | | 2026 | | | 2027 | | | Total | |
Purchase obligations and commitments: | | | | | | | | | | | | | | | | | | |
Minimum purchase commitments | | $ | 110.0 | | | $ | 92.2 | | | $ | 66.4 | | | $ | 24.6 | | | $ | 24.6 | | | $ | 317.8 | |
Expected wind purchase commitments | | | 56.0 | | | | 56.6 | | | | 56.9 | | | | 57.3 | | | | 57.7 | | | | 284.5 | |
Long-term service agreement commitments | | | 2.7 | | | | 14.5 | | | | 2.8 | | | | 17.1 | | | | 23.8 | | | | 60.9 | |
Total purchase obligations and commitments | | $ | 168.7 | | | $ | 163.3 | | | $ | 126.1 | | | $ | 99.0 | | | $ | 106.1 | | | $ | 663.2 | |
OG&E Minimum Purchase Commitments
OG&E has coal contracts for purchases through June 30, 2020 and MayDecember 31, 2021, whereby2025. OG&E has the right but not the obligation tomay also purchase a defined quantity of coal. OG&E purchases its coal through spot purchases on an as-needed basis. As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and 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.
OG&E has natural gas transportation service contracts with Enable andEnergy Transfer, ONEOK, Inc. and Southern Star. The contractcontracts with Enable endsEnergy Transfer end in MayDecember 2024 and December 2038; the contracts with ONEOK, Inc. end in March 2024 and August 2037; and the contract with ONEOK, Inc.Southern Star ends in August 2037.June 2024. These transportation contracts grant EnableEnergy Transfer, ONEOK, Inc. and ONEOK, Inc.Southern Star the responsibility of delivering natural gas to OG&E's generating facilities.
OG&E Wind Power Purchase Commitments
The following table summarizespresents OG&E's wind purchased power purchase contracts.
| | | | | | | | | | | | | | |
| Company | Location | Original 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 | |
| | | | |
| | | | | | |
Company | Location | Original 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 | |
The following table summarizespresents a summary of OG&E's wind power purchases for the years ended December 31, 2019, 20182022, 2021 and 2017.
| | | | | | | | | | | |
Year Ended December 31 (In millions) | 2019 | 2018 | 2017 |
| CPV Keenan | $ | 27.2 | | $ | 27.0 | | $ | 29.0 | |
| Edison Mission Energy | 23.1 | | 21.7 | | 22.1 | |
| NextEra Energy | 7.4 | | 6.8 | | 7.4 | |
| FPL Energy (A) | — | | 2.1 | | 2.6 | |
| Total wind power purchased | $ | 57.7 | | $ | 57.6 | | $ | 61.1 | |
(A)2020.OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018. | | | | | | | | | | | | |
Year Ended December 31 (In millions) | | 2022 | | | 2021 | | | 2020 | |
CPV Keenan | | $ | 25.8 | | | $ | 27.3 | | | $ | 27.5 | |
Edison Mission Energy | | | 24.9 | | | | 21.7 | | | | 22.8 | |
NextEra Energy | | | 7.3 | | | | 6.8 | | | | 7.0 | |
Total wind power purchased | | $ | 58.0 | | | $ | 55.8 | | | $ | 57.3 | |
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. In December 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 2033.2035. 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 2030.2032. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.
Environmental Laws and Regulations
The activities of the CompanyOG&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 the Company'sRegistrants' 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 or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of itsthe Registrants' 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. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
Affordable Clean Energy Rule
CO2 Emission Limits for Existing Generating Units
On July 8, 2019, the EPA published the Affordable Clean Energy rule. Numerous parties, not including OG&E, have filed petitions for judicial review of the Affordable Clean Energy rule inJanuary 19, 2021, the U.S. Court of Appeals forvacated the District of Columbia Circuit. The Affordable Clean Energy rule requires states, including Oklahoma,EPA's latest effort to develop emission limitationsadopt CO2 emissions standards for carbon dioxide for each existing coal-fired utility boiler within the state, including all of OG&E's coalelectric generating units, and submit a compliance and implementation planthe court remanded the matter to the EPA by July 2022.for further consideration. The EPA will approve or disapprovehas indicated that administrative proceedings to respond to the proposed state plan within 18 monthsU.S. Court of submittalAppeals' remand in a new rulemaking action are ongoing but has not announced rulemaking details. The decision was based on the court's conclusion that the Clean Air Act does not require the EPA to limit the standards to measures that can be applied at and develop a federal implementation plan ifto an existing unit. On October 29, 2021, the proposed state plan is disapproved. The ultimate timingU.S. Supreme Court granted petitions to review the decision and impact of these standardsheard oral arguments on OG&E's operations cannotFebruary 28, 2022. On June 22, 2022, the U.S. Supreme Court ruled that the approach the EPA took in the rule exceeded the powers granted by Congress and remanded greenhouse gas regulation for existing units to the EPA. With the ruling and remand by the U.S. Supreme Court, there continues to be determined with certainty at this time,no applicable greenhouse gas regulation for existing power plants, 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'sRegistrants' 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 isRegistrants are 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 hasRegistrants have 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.financial statements. At the present time, based on currently available information, the Company believesRegistrants believe 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 itstheir financial statements and would not have a material adverse effect on the Company's consolidatedtheir financial position, results of operations or cash flows.
16.Rate Matters and Regulation
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 2019, 862022, 88 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, 8eight percent to the APSC and 6four percent to the FERC.
The OCC and the APSC require that, among other things, (i) the CompanyOGE Energy permits the OCC and the APSC access to the books and records of the CompanyOGE Energy and its affiliates relating to transactions with OG&E; (ii) the CompanyOGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) the CompanyOGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of the CompanyOGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
APSC Proceedings
Arkansas 20182021 Formula Rate Plan Filing
Per OG&E's settlement in its last general rate review,In October 2021, OG&E filed anits fourth evaluation report under its Formula Rate Plan, in October 2018.and on February 1, 2022, OG&E, the APSC General Staff and the Office of the Arkansas Attorney General filed a non-unanimous joint settlement agreement, which included an annual electric revenue increase of $4.2 million. The only non-signatory to the settlement agreement agreed not to oppose the settlement. On March 6, 2019,4, 2022, the APSC approvedissued a final order approving the non-unanimous settlement agreement, for a $3.3 million revenue increase, and new rates werebecame effective as of April 1, 2019.
2022.Approval
Winter Storm Uri
In February 2021, Winter Storm Uri resulted in record winter peak demand for Acquisition of Existing Power Plants
In December 2018,electricity and extremely high natural gas and purchased power prices in OG&E's service territory. On April 1, 2021, OG&E filed an application for pre-approval from the OCC to acquire a 360 MW capacity coal- and natural gas-fired plant from AES and a 146 MW capacity natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC for $53.5 million. The purchase of these assets replaces capacity provided by purchased power contracts that expired in 2019 and helps OG&E satisfy its customers' energy needs and load obligations to the SPP. In addition, the filing sought approval of a rider mechanism to collect costs associated with the purchase of these generating facilities. On May 13, 2019, the OCC approved OG&E's acquisition of both plants, the requested rider mechanism for the AES plant and regulatory asset treatment for the Oklahoma Cogeneration LLC plant that will defer non-fuel operation and maintenance expenses, depreciation and ad valorem taxes.
On January 23, 2019, OG&E filed an application for Federal Power Act Section 203 approval with a request for expedited consideration. This application requested FERC's prior authorization to acquire the AES and Oklahoma Cogeneration LLC plants. On May 22, 2019, OG&E received authorization from the FERC to acquire both plants.
On April 24, 2019, OG&E filed an application with the APSC
requestinga motion seeking approval
to defer, amortize and recover the extraordinary fuel costs over a 10-year period with a carrying charge of OG&E's pre-tax rate of return of 6.60 percent, through a special factor within OG&E's Energy Cost Recovery Rider beginning with the acquisition, as well as depreciation rates,first billing cycle of the AES and Oklahoma Cogeneration LLC plants, and on May 8, 2019, OG&E received conditional approval for the purchase of the generating facilities.2021. On August 30, 2019,April 13, 2021, the APSC issued an order finding thatallowing OG&E interim recovery at an interest rate equal to the plantscustomer deposit interest rate over a period of 10 years beginning with the first billing cycle of May 2021, subject to true-up.
On July 5, 2022, OG&E filed a motion to request recovery of the regulatory asset balance over 10 years using a weighted average cost of capital. A hearing on the merits was scheduled to be acquired were usedheld on December 2, 2022 but was cancelled after all interested parties agreed to waive the hearing and usefulhave the APSC decide the matter based on the established record. In January 2023, the APSC issued an order approving OG&E's requested relief and thatauthorizing OG&E to amortize the acquisitionregulatory asset balance over 10 years using a pre-tax weighted average cost of capital of 6.49 percent as a carrying charge beginning March 2021. The impact of this order will be recorded beginning in the first quarter of 2023, as the order was received from the APSC in January 2023.
Arkansas 2021 Formula Rate Plan Filing - Extension
On May 18, 2022, the APSC issued an order granting OG&E's request for a five-year extension of the plants was in the public interest. The APSC also approved the depreciation ratesFormula Rate Plan Rider with certain terms and conditions, including continuation of OG&E's current return on equity of 9.5 percent and a change to be appliedOG&E's current debt-to-equity ratio of 50/50 percent to the acquired plants. The cost55/45 percent. On June 17, 2022, OG&E paidfiled a request for the acquired plants was reviewedrehearing seeking reconsideration by the APSC in OG&E's 2019of their decision to alter the Formula Rate Plan filing,Rider's capital structure. On September 19, 2022, the APSC issued an order reversing its May 18, 2022 order and parties reacheddenying the extension of OG&E's Formula Rate Plan Rider. On September 20, 2022, the APSC Staff filed a motion for clarification for the extension denial, and OG&E, the Arkansas Attorney General and Arkansas River Valley Energy Consumers filed responses to the clarification. On September 30, 2022, the APSC issued an order clarifying that OG&E is authorized to file its 2022 and 2023 evaluation reports under the Formula Rate Plan Rider to true-up prior projected year rate adjustments. On October 28, 2022, Arkansas River Valley Energy Consumers and Walmart Inc. filed a request for rehearing of the APSC's September 30, 2022 order and asked the APSC to reverse its position and prohibit OG&E from making any further filings under its current Formula Rate Plan. On November 1, 2022, OG&E submitted its opposition to the request for rehearing. On November 28, 2022, the APSC granted the application for rehearing solely for the purpose of further consideration. On January 20, 2023, the APSC issued an order denying the request for rehearing of the September 30, 2022 order and ruling that OG&E is able to undertake two more true-up updates to its Formula Rate Plan Rider with adjustments to rates occurring in April 2023 and April 2024. Despite the denial of OG&E's extension request, the Formula Rate Plan Rider will continue until new rates are set in a future general rate review.
OCC Proceedings
Winter Storm Uri
In December 2021, the OCC approved a settlement agreement requestingin a final financing order authorizing the APSCissuance of securitization bonds in an amount up to approve$760.0 million, which included estimated finance costs and was subject to change for carrying costs, any updates from the costSPP settlement process and actual securitization issuance costs. On July 20, 2022, the ODFA issued the securitization bonds consistent with the OCC's order.
In connection with the securitization transaction, the ODFA and OG&E entered into an agreement on July 20, 2022 whereby the ODFA purchased, and OG&E sold, the securitization property that was created pursuant to legislation enacted by the State of Oklahoma in April 2021 and the financing order received from the OCC in December 2021. Such securitization property includes the right to assess, impose, adjust, collect and receive funds, in the form of the acquisitions.winter event securitization charge, from OG&E's existing and future Oklahoma customers in amounts intended to be sufficient to pay the principal and interest and financing charges on the
securitization bonds. On July 20, 2022, OG&E is awaiting a final decision fromreceived proceeds of approximately $750 million for the APSC.
In May 2019, OG&E completed the acquisitionsale of the power plant from AES and placed it into service,securitization property, which is now namedrepresented the River Valley power plant. In August 2019,amount of the securitization bonds sold less the issuance costs. OG&E completedused these proceeds to fund the acquisition ofOklahoma Winter Storm Uri regulatory asset by recovering the authorized extreme, extraordinary fuel and purchased power plantcosts incurred during Winter Storm Uri, as well as carrying costs. Beginning August 1, 2022, OG&E acts as a servicer for collecting the funds from Oklahoma Cogeneration LLC and placed it into service, which is now namedcustomers that are then submitted to the Frontier power plant.
Fuel Adjustment Clause Review for Calendar Year 2017ODFA to repay the securitization bonds over 28
In July 2018, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2017, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 1, 2019, the Administrative Law Judge recommended that OG&E's processes, costs, investments and decisions regarding fuel procurement for the 2017 calendar year be found prudent. On May 22, 2019, the OCC deemed OG&E's electric generation, purchased power and fuel procurement costs to be materially prudent.
2021 Oklahoma General Rate Review Filing - December 2018
In December
2018,2021, OG&E filed a general rate review
with the OCC, requestingin Oklahoma seeking a rate increase of
$77.6$163.5 million per year to recover its investment in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas, to align OG&E'sa 10.2 percent return on equity more closelybased on a common equity percentage of 53.37 percent. The rate review was based on a September 30, 2021 test year and included a request for recovery of $1.2 billion of capital investment since the last general rate review. OG&E had the right to implement interim rates subject to refund beginning July 1, 2022 (180 days after the industry averagefiling of its application on December 30, 2021). On July 1, 2022, OG&E implemented an annual interim rate increase of $30.0 million, subject to refund for amounts in excess of the rates approved by the OCC.
On September 8, 2022, the OCC approved a Joint Stipulation and to align OG&E's depreciation rates to more realistically reflect its assets' lifespans.
On May 24, 2019, OG&ESettlement Agreement that had been entered into
a non-unanimous joint stipulation and settlement agreement withby OG&E, the OCC
staff,Public Utility Division Staff, the
Oklahoma Attorney
General's Office of Oklahoma,General, the
OG&E Shareholders Association, Oklahoma Industrial Energy Consumers and
certain other
intervenors. Non-signatory parties
associated with the requested rate increase. The filing was further amended on May 30, 2019had agreed not to
include Oklahoma Association of Electric Cooperatives as a settling party. Under thecontest this agreement. Key terms of the
settlement agreement,
as approved by the OCC, include, among others:
•A base rate revenue increase of $30.0 million;
•OG&E would receive full recovery of its environmental investmentsissue a refund, over a 12-month period, for the tax expense savings arising from the reduction in the Dry Scrubbers project andOklahoma state corporate income tax rate from 6 percent to 4 percent for the period from January 1, 2022 through June 30, 2022, as well as amortize over five years the excess accumulated deferred income tax balance resulting from this corporate tax rate change;
•There would be no change in the conversion of Muskogee Units 4 and 5 to natural gas. Base rates would not change as a result of the settlement agreement due to the reduction of costs related to cogeneration contracts and the acceleration of unprotected deferred tax savings over a 10-year period. Further, OG&E's current depreciation rates and return on equity of 9.5 percent, for purposes of calculating the allowance for funds used during construction and OG&E's various recovery riders that includerequested capital structure based on a full return componentcommon equity percentage of 53.37 percent would remain unchanged.
On July 1, 2019, •OG&E implemented interimwould utilize depreciation rates which were subject to refund of any amount recovered in excessbased on the recommendations of the Oklahoma Attorney General with the exception of transmission and general plant accounts, which would be based on the depreciation rates ultimately approvedrecommended by the OCCOklahoma Industrial Energy Consumers;
•OG&E's Grid Enhancement Plan projects recorded as of March 31, 2022 would be considered prudent and be included in base rates;
•OG&E's Grid Enhancement Plan interim recovery would continue and updated terms include: (i) cost recovery through a rider mechanism will be limited to projects placed in service in 2022, 2023 and 2024, capped at a revenue requirement of $6.0 million for each annual investment plan and include communication, automation and technology systems projects, as well as certain weather hardening projects; and (ii) the rate review. On September 19, 2019,rider mechanism will terminate by the OCC issuedissuance of a final order whichin OG&E's first general rate review following completion of projects included in the 2024 annual investment plan or no later than July 1, 2025;
•OG&E would amend several of its rider tariffs to incorporate the agreements of the stipulating parties; and
•Regulatory accounting treatments approved include, among other things, the settlement agreement.
The Dry Scrubbersestablishment of a regulatory asset to defer operation and maintenance costs associated with OG&E's SAP S/4 HANA enterprise resource planning system project which includesfor consideration in future rate proceedings with the installationcarrying cost accruing at OG&E's short-term cost of two dry scrubbers atdebt, the Sooner plant,amortization of COVID-19 regulatory asset balance over five years and the conversionamortization of Muskogee Units 4 and 5 to natural gas were initiated in responseover/under-recovery balance of the pension tracker over 15 years, which is a change from the previous five-year recovery period.
Due to the EPA's MATS and Regional Haze Rule FIP. The Dry Scrubber systems on Sooner Unit 1 and Unit 2 were placed into service in October 2018 and January 2019, respectively. Muskogee Units 4 and 5 were placed into service in March 2019.
Fuel Adjustment Clause Review for Calendar Year 2018
In June 2019, theSeptember 8, 2022 OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2018, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On December 12, 2019, the OCC issued an order deeming OG&E's electric generation, purchased power and fuel procurement costs were prudent.
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 dateapproval of the complaint. 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 formularate increase of $30.0 million, no refund of interim rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. In May 2019, all parties agreed to a settlement which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. On November 21, 2019, the FERC approved the settlement agreement.was necessary.
Pending Regulatory Matters
Set forth below is a list of various
Various proceedings pending before state or federal regulatory agencies.agencies are described below. Unless stated otherwise, OG&Ethe Registrants cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E'sThe Registrants' financial results are dependent in part on timely and adequateconstructive decisions by the regulatory agencies that set OG&E's rates.
FERC
Proceedings
Order for Sponsored Transmission Upgrades within SPP
Under Attachment Z2 of the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff required the SPP to charge for these upgrades beginning in 2008, but the SPP haddid not beenbegin charging its customers for these upgrades until 2016 due to information system limitations. However,At that time, the SPP had informed participantssought a waiver of a time limitation in its tariff that otherwise would have prevented it from waiting until 2016 to bill for the market that these charges would be forthcoming. In July 2016, the2008 through 2015 period. The FERC granted SPP's request to recover the charges not billed since 2008.waiver, and the SPP subsequentlythen billed OG&E as a user for these Z2 charges and creditedwhile simultaneously crediting OG&E related toas a sponsor of Z2 transmission upgrades, that OG&E had sponsored, which resultedresulting in OG&E being a net receiverrecipient of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E.
Several companies that were net payers of Z2 charges sought rehearing of the FERC's July 2016 order; however, in November 2017,order approving the waiver and then appealed it. While that appeal was pending, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. In July 2018, that court grantedobtained a motion requested by the FERC that the case be remanded back to the FERC for further examinationremand and proceedings. In February 2019, the FERCthen reversed its July 2016 orderitself and November 2017 rehearing denial, ruled that SPP violated its tariff to charge for the 2008 - 2015 period in 2016, held that the SPP tariff provision that prohibited thosethe 2008 through 2015 charges could not be waived andwaived. It ordered the SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, onin April 1, 2019, OG&E filed a request for rehearing withat the FERC. The next month, it also filed a Complaint at the FERC and on May 24, 2019, OG&E filed a FERC 206 complaint against SPP, alleging that SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. OG&E's filing requested that the FERC rule that SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that SPP should not be held responsible for those payments if refunds are ordered. Further, SPP has requested the FERC to
negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.
OnSPP and not OG&E should bear the cost of any refunds resulting from the SPP's tariff violation and that SPP’s actions also violated its contracts with OG&E. In February 20, 2020, the FERC denied OG&E's request for rehearing of its February 28, 2019 order, denying the waiver and ruling that SPP must seek refunds from project sponsors for Z2 payments for the 2008 - 2015 period and pay them back to transmission owners. The FERC also denied SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERCbut did not rule on OG&E's complaint or the complaints of other project sponsors, or consider SPP's refund plan. The FERC thus has not set anyNo date for payment of refunds. Therefunds was established. In August 2021, the U.S. Court of Appeals for the District of Columbia Circuit denied OG&E's petition for review of the FERC's order denying the waiver and requiring refunds is now appealable, and OG&E intendsrefunds. After denying rehearing of its ruling, the court of appeals returned the matter in November 2021 to file a timely appeal.
the FERC for further proceedings in accordance with its opinion. The
Company cannot predict the outcome of this proceeding based on currently available information, and as of December 31, 2019 and at present time, the CompanyFERC has not
reserved an amount for a potential refund. acted on that remand.
If the reversal of the July 2016 FERC proceeds to order remains intact,refunds in full, OG&E estimates it would be required to refund $13.0$13.0 million, which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. IfThe SPP has stated in filings with the FERC both before and after the court of appeals decision that there are considerable complexities in implementing the refunds were required,that will have to be resolved before they can be paid. Payment of refunds would shift recovery of these upgrade credits would shift to future periods. The SPP filed a report on January 4, 2022 confirming that administering refunds would be complex and could take years unless the SPP is allowed to make certain simplifying assumptions. The SPP also urged that all pending complaint proceedings, including OG&E's complaint and three similar complaints against the SPP, be resolved before any refund process is ordered to begin. OG&E and other parties filed responses to the SPP report, and the matter remains pending at the FERC. Of the $13.0$13.0 million, the CompanyRegistrants would be impacted by $5.0$5.0 million in expense that initially benefited the CompanyRegistrants in 2016, and OG&E customers would incur a net impact of $8.0$8.0 million in expense through rider mechanisms or the FERC formula rate.
As of December 31, 2022, the Registrants have reserved $
million plus estimated interest for a potential refund.
In November 2022, the FERC issued an order denying OG&E's complaint against SPP. It also issued orders granting the other three complaints against the SPP has recently proposed eliminatingin part but awarded no relief. All four complainants timely sought rehearing of these orders. Those rehearing petitions remain pending, though OG&E and the other complainants can appeal them now if they choose to do so on the basis that they have been deemed denied by operation of law. The FERC, however, can continue to consider the rehearings on the merits, and the complainants will be able appeal any denial on the merits as well.
In June 2020, the FERC approved, effective July 1, 2020, an SPP proposal to eliminate Attachment Z2 revenue crediting and replacingreplace it with a different rate mechanism that would provide project sponsors, such as OG&E, the same level of recovery. This elimination of the Attachment Z2 revenue crediting would only prospectively impact OG&E and its recovery they wouldof any future upgrade costs that it may incur as a project sponsor subsequent to July 2020. All of the existing projects that are eligible to receive if payments continuedrevenue credits under Attachment Z2. Z2 will remain eligible, which includes the $13.0 million that is at issue in the remand from OG&E's appeal and in OG&E's complaint proceeding.
Incentive Adders for Transmission Rates
The FERC rejectedissued a NOPR in March 2020, and issued a supplemental NOPR in April 2021, proposing to update its transmission incentives policy. Among other things, the NOPR proposes (i) the current 50-basis point return on equity adder for RTO/ISO participation would be applicable only to transmitting utilities that proposal to the extent itjoin an RTO/ISO, and this incentive would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest, finding that providing the possibility of recovering greater than the cost of the investment could serve as an incentive for entities to build merchant transmission projects. The SPP can resubmit a proposal without that cap.
APSC - Environmental Compliance Plan Rider
On May 31, 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investmentonly apply for the environmentally mandated costs associated withfirst three years in which the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filingutility is an interim surcharge, subjectRTO/ISO member and (ii) transmitting utilities that have been members of an RTO/ISO for three years or more, such as OG&E, would be required to refund, that began withmake a compliance filing to remove the first billing cycleexisting return on equity adder from their rates. Currently, there is no specific deadline for the FERC to take further action, and it is unknown whether the FERC will address the RTO participation adder individually or as part of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending a larger order on transmission incentives.
APSC approval of OG&E's filing. A hearing on the merits was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.
Arkansas 20192022 Formula Rate Plan Filing
On October 3, 2022, OG&E filed its secondfifth evaluation report under its Formula Rate Plan, inincluding a request to increase its Arkansas retail revenues by $8.5 million, which reflects a cap of 4.0 percent of annualized filing year revenues as of June 2022. After utilizing an adjustment to annualized filing year revenues as of October 2019.2022, the capped revenue requirement increase rose to approximately $9.6 million. On JanuaryDecember 29, 2020,2022, intervening parties filed errors and objections to OG&E, the General Staff of the APSC and the Office of the&E's fifth evaluation report. The Arkansas Attorney General made no recommended adjustments to the revenue requirement, and the Arkansas Valley Electric Consumers reiterated legal arguments about the legal permissibility of the fifth evaluation report. The APSC Staff made certain minor adjustments but agreed that the overall revenue requirement adjustment should reflect the capped amount of $9.6 million. On February 1, 2023, OG&E and the APSC Staff filed a non-unanimous joint settlement agreement, requestingwhich includes an annual electric revenue increase of $9.6 million. The Arkansas Attorney General and the Arkansas Valley Electric Consumers have agreed not to oppose the settlement, and the settlement agreement is subject to approval by the APSC. OG&E and the APSC approveStaff have requested a $5.2 million revenue increase,final order from the APSC by early March 2023, with new rates to be effective April 1, 2020. The settling parties agreed that the Series I grid modernization projects are prudent in both action and cost and that the Series II grid modernization projects are prudent in action only and the determination of prudence of costs will be reserved until the actual historical costs are reviewed. The settling parties also agreed that OG&E will no longer use projections for the remaining initial term or extension of its current Formula Rate Plan and that all costs will be included for recovery for the first time in the historical year. A hearing was held on February 5, 2020, and OG&E is awaiting a final decision from the APSC.
2023.
Oklahoma Grid Enhancement Plan
Prudence Review - Winter Storm Uri Extraordinary Costs
On February 24, 2020,2, 2023, the APSC issued an order to initiate proceedings to address the prudence and appropriate allocation of the extraordinary costs incurred by Arkansas jurisdictional electric and natural gas utilities during Winter Storm Uri. As discussed above, in January 2023, the APSC issued an order approving OG&E filed an application with the OCC for approval of a mechanism that allows for interim&E's recovery of the costs associated with its grid enhancement plan.Winter Storm Uri regulatory asset balance, which included setting the carrying charges and term of recovery. The plan includes approximately $800 million of strategic, data-driven investments, over five years, covering grid resiliency, grid automation, communication systemsAPSC did not rule on prudence or cost allocation at that time. OG&E's direct testimony is due in April 2024, and technology platforms and applications. A procedural schedule has not been set bya hearing on the OCC.
merits is expected to begin in August 2024.
OCC Proceedings
Oklahoma Retail Electric Supplier Certified Territory Act Causes
CertainSeveral rural electric cooperative electricity suppliers have filed complaints with the OCC alleging that OG&E has violated the Oklahoma Retail Electric Supplier Certified Territory Act. OG&E believes it is lawfully serving customers specifically exempted from this act and has presented evidence and testimony to the OCC supporting its position. There have been five complaint cases initiated at the OCC, and the OCC has issued decisions on each of them. The OCC ruled in favor of the electric cooperatives in three of those cases and ruled in favor of OG&E in two of those cases. All five of those cases have been appealed to the Oklahoma Supreme Court, where they have been made companion cases but will be individually briefed and have individual final decisions.
If the OCCOklahoma Supreme Court ultimately were to ultimately find that some or all of the customers being served are not exempted thenfrom the Oklahoma Retail Electric Supplier Certified Territory Act, OG&E would have to evaluate the recoverability of some plant investmentinvestments made to serve these customers. The total amount of OG&E's plant investments made to serve the customers in all five cases is approximately$28.0 million, of which $11.7 million applies to the three cases where the OCC ruled in favor of the electric cooperatives. In addition to the evaluation of the recoverability of the investments, OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue.
17. The amount of such lost revenue would depend on how the OCC calculates the revenue requirement but could range from approximately $Quarterly Financial Data (Unaudited)16.2
Due63.9 million for all five cases, of which $4.4 million to $7.9 million would apply to the seasonal fluctuations and other factorsthree cases where the OCC ruled in favor of the Company's businesses,electric cooperatives.
2021 Oklahoma Fuel Prudency
On July 1, 2022, the operating results for interim periods are not necessarily indicativeOCC Public Utility Division Staff filed their application initiating the review of the results2021 fuel adjustment clause and prudence review. On February 21, 2023, a Joint Stipulation and Settlement Agreement was filed, and OG&E filed its testimony in support of such agreement. The stipulating parties, which include the OCC Public Utility Division Staff and the Oklahoma Attorney General, agree that: (i) OG&E's practices, policies and judgment for fuel procurement during 2021 were prudent; (ii) OG&E's power purchase costs and expenses, monthly fuel filings and processes and fuel-related investments and decisions for 2021 were fair, just and reasonable and (iii) OG&E exercised prudent judgement pertaining to all such matters and that maythe electric generation, purchased power and fuel procurement expenses were prudently incurred. Further, the stipulating parties agree to certain revisions of the fuel clause adjustment tariff, including a revised semi-annual fuel clause adjustment factor redetermination process which will be expectedsubject to the OCC Public Utility Division approval or denial. A hearing on the merits for the year. InJoint Stipulation and Settlement Agreement is scheduled for February 23, 2023.
Fuel Cost Adjustment Show Cause
On September 29, 2022, the Company's opinion,OCC Public Utility Division Staff initiated a cause to determine the following quarterly financial data includes all adjustments, consistingappropriate methodology to recover OG&E's fuel clause under recovery balance of normal recurring adjustments, necessary$424.0 million and how OG&E's fuel factors should be set going forward. The Staff requested that OG&E explain how it arrived at the noted under recovery balance, explain its fuel forecasting process, justify its
amortization period of 24 months and explain the adequacy of its resource mix and fuel supply plans. Updated fuel factors were implemented by OG&E on October 1, 2022 to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows:
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Quarter Ended (In millions, except per share data) | | March 31 | June 30 | September 30 | December 31 | Total |
| Operating revenues | 2019 | $ | 490.0 | | $ | 513.7 | | $ | 755.4 | | $ | 472.5 | | $ | 2,231.6 | |
| 2018 | $ | 492.7 | | $ | 567.0 | | $ | 698.8 | | $ | 511.8 | | $ | 2,270.3 | |
| Operating income | 2019 | $ | 49.7 | | $ | 110.0 | | $ | 274.3 | | $ | 70.3 | | $ | 504.3 | |
| 2018 | $ | 66.6 | | $ | 137.7 | | $ | 227.3 | | $ | 58.0 | | $ | 489.6 | |
| Net income | 2019 | $ | 47.1 | | $ | 100.2 | | $ | 250.9 | | $ | 35.4 | | $ | 433.6 | |
| 2018 | $ | 55.0 | | $ | 110.7 | | $ | 205.1 | | $ | 54.7 | | $ | 425.5 | |
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| Basic earnings per average common share (A) | 2019 | $ | 0.24 | | $ | 0.50 | | $ | 1.25 | | $ | 0.18 | | $ | 2.17 | |
| 2018 | $ | 0.28 | | $ | 0.55 | | $ | 1.03 | | $ | 0.27 | | $ | 2.13 | |
| Diluted earnings per average common share (A) | 2019 | $ | 0.24 | | $ | 0.50 | | $ | 1.25 | | $ | 0.18 | | $ | 2.16 | |
| 2018 | $ | 0.27 | | $ | 0.55 | | $ | 1.02 | | $ | 0.27 | | $ | 2.12 | |
(A)Duerecover the balance from customers over 24 months. The OCC Public Utility Division Staff did not oppose OG&E's implementation of updated fuel factors on an interim basis and subject to the impact of dilutionrefund. A hearing on the earnings per share calculation, quarterly earnings per share amounts maymerits was held on November 3 and 4, 2022. Despite several public deliberations, the OCC has not addissued a final order in this proceeding. On January 1, 2023, OG&E implemented its annual redetermination of its fuel factors, without further action or opposition from the OCC.
SPP Proceedings
Planning Reserve Margin and Performance Based Accreditation
On July 26, 2022, the SPP Board of Directors approved a planning reserve margin increase from 12 percent to 15 percent that each load serving entity, such as OG&E, must maintain. This change will be effective for the total.summer of 2023. At the same time, the SPP Board of Directors also approved a new unit accreditation methodology for conventional generation, effective 2024. As a result, OG&E is currently evaluating its plan to fill the incremental capacity needs brought about by these policy changes.
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, 20192022 and 2018,2021, 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, 2019,2022, and the related notes and financial statement schedule listed in the Index at Item 15(a)(collectively (collectively referred to as the "consolidated financial statements"). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as ofat December 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2022, 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 had a 25.5% interest atas of December 31, 2019. The2020. In the consolidated financial statements, the Company's investment in Enable constituted 10.3% and 10.9% of the Company's assetsis stated at $374.3 million as of December 31, 2019 and 2018, respectively,2020, and the Company's equity earnings in the net income of Enable constituted 24.6%, 30.7% and 23.0% of the Company's income before taxes for the years ended December 31, 2019, 2018, and 2017, respectively.is stated at $13.2 million in 2020. 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 for 2020, 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'sCompany’s internal control over financial reporting as of December 31, 2019,2022, 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 26, 2020,22, 2023, expressed an unqualified opinion thereon.
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 included 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.
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accountaccounts or disclosuredisclosures to which it relates.
Regulatory Assets and Liabilities
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Description of the Matter | As discussed in Note 1 to the consolidated financial statements, the Company conducts its electric utility operations through Oklahoma Gas & Electric Company (OG&E). OG&E is a regulated utility subject to accounting principles for rate-regulated activities. As such, certain incurred costs that would otherwise be charged to expense are 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 are deferred as regulatory liabilities, based on the expected refund to customers in future rates. OG&E records items 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. |
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How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of internal controls over the Company's accounting for regulatory assets and liabilities, including, among others, controls over management's assessment of the likelihood of approval by regulators for new matters and controls over the evaluation of filings with regulatory bodies on existing regulatory assets and liabilities, including factors that may affect the timing or nature of recoverability. |
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| We performed audit procedures that included, among others, reviewing evidence of correspondence with regulatory bodies to test that the Company appropriately evaluated new information obtained from regulatory rulings. For example, we assessed the recoverability, considering information obtained from regulatory rulings, of various regulatory assets. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the regulatory assets and liabilities were appropriately amortized through the Company's rates charged to customers based on rulings from regulatory bodies. |
/s/ Ernst & Young LLP
We have served as the Company's auditor since 2002.
Oklahoma City, Oklahoma
February 22, 2023
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder and the Board of Directors of Oklahoma Gas and Electric Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company (the Company) as of December 31, 2022 and 2021, the related statements of income and comprehensive income, changes in stockholder's equity and cash flows for each of the three years in the period ended December 31, 2022, 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, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.
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, 2022, 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 22, 2023, expressed an unqualified opinion thereon.
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 included 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.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities
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Description of the Matter | As discussed in Note 1 to the financial statements, OG&E is a regulated utility subject to accounting principles for rate-regulated activities. As such, certain incurred costs that would otherwise be charged to expense are 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 are deferred as regulatory liabilities, based on the expected refund to customers in future rates. OG&E records items 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. |
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| Auditing regulatory assets and liabilities is complex as it requires specialized knowledge of rate-regulated activities and judgments as to matters that could affect the recording or updating of regulatory assets and liabilities. |
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How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of internal controls over the Company’sCompany's accounting for regulatory assets and liabilities, including, among others, controls over management’smanagement's assessment of the likelihood of approval by regulators for new matters and controls over the evaluation of filings with regulatory bodies on existing regulatory assets and liabilities, including factors that may affect the timing or nature of recoverability. |
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| We performed audit procedures that included, among others, reviewing evidence of correspondence with regulatory bodies to test that the Company appropriately evaluated new information obtained from regulatory rulings. For example, we assessed the recoverability, considering information obtained from regulatory rulings, of various regulatory assets including deferred expenses, pensions and other regulatory assets. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the timing of customer refunds attributableregulatory assets and liabilities were appropriately amortized through the Company's rates charged to changes in the tax law were consistent with methods agreed to bycustomers based on rulings from regulatory bodies. |
We have served as the Company's auditor since 2002.
22, 2023
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9A. Controls and Procedures.
The Company maintainsRegistrants maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the CompanyRegistrants in reports that it filesthey file or submitssubmit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company'sRegistrants' management, including the chief executive officer and chief financial officer, of the effectiveness of the Company'sRegistrants' disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that the Company'sRegistrants' disclosure controls and procedures are effective.
No change in the Company'sRegistrants' internal control over financial reporting has occurred during the Company's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company'sRegistrants' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).
Management's Report on Internal Control Over Financial Reporting
The management of the CompanyRegistrants is responsible for establishing and maintaining adequate internal control over financial reporting. The Company'sRegistrants' internal control system wassystems were designed to provide reasonable assurance to the Company's management and OGE Energy's Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
The Company'sRegistrants' management assessed the effectiveness of the Company'stheir internal control over financial reporting as of December 31, 2019.2022. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2019,2022, the Company'sRegistrants' internal control over financial reporting is effective based on those criteria.
The Company'sRegistrants' independent auditors have issued an attestation report on the Company'sRegistrants' internal control over financial reporting. This report appears on the following page.
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/s/ Sean Trauschke |
| /s/ Sarah R. Stafford |
Sean Trauschke, Chairman of the Board, President |
| Sarah R. Stafford, Controller |
and Chief Executive Officer |
| and Chief Accounting Officer |
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/s/ Stephen E. MerrillW. Bryan Buckler |
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Stephen E. MerrillW. Bryan Buckler
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Chief Financial Officer |
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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, 2019,2022, 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, 2019,2022, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2019 consolidated financialbalance sheets and consolidated statements of capitalization of OGE Energy Corp. as of December 31, 2022 and 2021, the Companyrelated 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, 2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 26, 202022, 2023 expressed an unqualified opinion thereon.
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 overOver 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.
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/s/ Ernst & Young LLP
/s/ Ernst & Young LLP
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Oklahoma City, Oklahoma
22, 2023
To the Stockholder and the Board of Directors of Oklahoma Gas and Electric Company
Opinion on Internal Control over Financial Reporting
We have audited Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2022, 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, Oklahoma Gas and Electric Company (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheets and statements of capitalization of Oklahoma Gas & Electric Company as of December 31, 2022 and 2021, the related statements of income and comprehensive income, changes in stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 22, 2023 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 22, 2023
Item 9B. Other Information.
On February 22, 2023, the Board of Directors approved and adopted the OGE Energy Corp. 2023 Annual Executive Incentive Compensation Plan (the "Annual Plan"). The Annual Plan replaces the OGE Energy Corp. 2022 Annual Executive Incentive Compensation Plan (the "current annual plan"). The Annual Plan is very similar to the current annual plan, with the only difference being changing the annual incentive payout amounts from 0% - 150% to 0% - 200% of target based on peer review.
Officers, executives or other key employees of OGE Energy and its subsidiaries who are selected by the Compensation Committee are eligible to be granted awards under the Annual Plan, which provides for the payment of annual cash bonuses based on OGE Energy performance and individual performance relative to performance goals approved by the Compensation Committee. The level of achievement of the specified OGE Energy and individual performance goals at the end of the plan year will determine the amount of each participant's target company award and/or target individual award that such participant will receive, which may exceed 100 percent of the participant's target awards.
This summary of the Annual Plan is qualified in its entirety by reference to the Annual Plan filed as Exhibit 10.14 to this 2022 Form 10-K.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
None.
PARTT III
Item 10. Directors, Executive Officers and Corporate Governance.
The Company
OGE Energy maintains a code of ethics for our chief executive officer and senior financial officers, including the chief financial officer and chief accounting officer, which is available for public viewing on the Company'sOGE Energy's website address www.ogeenergy.com under the heading "Investors," "Governance."at www.oge.com/governance. The code of ethics will be provided, free of charge, upon request. The CompanyOGE Energy intends to satisfy the disclosure requirements under Section 5, Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the code of ethics by posting such information on its website at the location specified above. The CompanyOGE Energy will also include in its proxy statement information regarding the Audit Committee financial experts.
OGE Energy. Information regarding OGE Energy's executive officers is set forth in "Part I, Item 1. Business - Information About the Registrants' Executive Officers." As permitted by General Instruction G of Form 10-K, the information required by Item 10, other than information regarding the executive officers and the Code of Ethics, will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.
OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 for OG&E has been omitted.
Item 11. Executive Compensation.
OGE Energy. As permitted by General Instruction G of Form 10-K, the information required by Item 11 will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.
OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 11 for OG&E has been omitted.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 14. Principal Accountant Fees and Services.
Items 10 through 14 (other than Item 10 information regarding the Code of Ethics) are omitted pursuant toOGE Energy. As permitted by General Instruction G of Form 10-K, because the Companyinformation required by Item 12 will file copies of abe set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 6, 2020.3, 2023. Such proxy statement is incorporated herein by reference.
OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 12 for OG&E has been omitted.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
OGE Energy. As permitted by General Instruction G of Form 10-K, the information required by Item 13 will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.
OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 for OG&E has been omitted.
Item 14. Principal Accountant Fees and Services.
The following discussion relates to the audit fees paid by OGE Energy to its principal independent accountants for the services provided to OGE Energy and its subsidiaries, including OG&E.
Fees for Principal Independent Accountants
| | | | | | | | |
Year Ended December 31 | | 2022 | | | 2021 | |
Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting | | $ | 1,232,000 | | | $ | 1,209,000 | |
Services in support of debt and stock offerings | | | 59,000 | | | | 65,000 | |
Other (A) | | | 447,500 | | | | 361,000 | |
Total audit fees (B) | | | 1,738,500 | | | | 1,635,000 | |
Employee benefit plan audits | | | 138,000 | | | | 133,000 | |
Total audit-related fees | | | 138,000 | | | | 133,000 | |
Assistance with examinations and other return issues | | | 219,892 | | | | 237,481 | |
Review of federal and state tax returns | | | 34,000 | | | | 32,000 | |
Total tax preparation and compliance fees | | | 253,892 | | | | 269,481 | |
Total tax fees | | | 253,892 | | | | 269,481 | |
Total fees | | $ | 2,130,392 | | | $ | 2,037,481 | |
(A)Includes reviews of the financial statements included in the Registrants' Quarterly Reports on Form 10-Q, audits of OGE Energy's subsidiaries, preparation for Audit Committee meetings, agreed-upon procedures and fees for consulting with the Registrants' executives regarding accounting issues.
121The aggregate audit fees include fees billed for the audit of the Registrants' annual financial statements and for the reviews of the financial statements included in the Registrants' Quarterly Reports on Form 10-Q. For 2022, this amount includes estimated billings for the completion of the 2022 audit, which services were rendered after year-end.
All Other Fees
There were no other fees billed by the principal independent accountants to OGE Energy in 2022 and 2021 for other services.
Audit Committee Pre-Approval Procedures
Rules adopted by the Securities and Exchange Commission in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. OGE Energy's Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the principal independent accountants for additional services not contemplated in the original pre-approval. In those instances, OGE Energy will obtain the specific pre-approval of the Audit Committee before engaging the principal independent accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee's responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
For 2022, 100 percent of the audit fees, audit-related fees and tax fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority.
PART IV
Item 15. Exhibits,Exhibit and Financial Statement Schedules.
(a) 1. Financial Statements
(i)The following Consolidated Financial Statementsfinancial statements are included in Part II, Item 8 of this Annual Report:
•Consolidated Statements of Income for the years ended December 31, 2019, 20182022, 2021 and 20172020
•Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 20182022, 2021 and 20172020
•Consolidated Statements of Cash Flows for the years ended December 31, 2019, 20182022, 2021 and 20172020
•Consolidated Balance Sheets at December 31, 20192022 and 20182021
•Consolidated Statements of Capitalization at December 31, 20192022 and 20182021
•Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2019, 20182022, 2021 and 20172020
•Notes to Consolidated Financial Statements
•Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
•Management's Report on Internal Control Over Financial Reporting
•Report of Independent Registered Public Accounting Firm (Audit of Internal Control over Financial Reporting)
OG&E
•Statements of Income for the years ended December 31, 2022, 2021 and 2020
Statements of Comprehensive Income for the years ended December 31, 2022, 2021 and 2020
(i)•Statements of Cash Flows for the years ended December 31, 2022, 2021 and 2020
•Balance Sheets at December 31, 2022 and 2021
•Statements of Capitalization at December 31, 2022 and 2021
•Statements of Changes in Stockholder's Equity for the years ended December 31, 2022, 2021 and 2020
•Notes to Financial Statements
•Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
•Management's Report on Internal Control Over Financial Reporting
•Report of Independent Registered Public Accounting Firm (Audit of Internal Control over Financial Reporting)
The reports of the Registrants' independent registered public accounting firm (PCAOB ID:42) with respect to the above-referenced financial statements and their reports on internal control over financial reporting are included in Item 8 and Item 9A of this Form 10-K. Their consents for each Registrant appear as Exhibit 23.01 and Exhibit 23.02 of this Form 10-K.
(ii)The audited financial statements and Notes to Consolidated Financial Statements of Enable Midstream Partners, LP, for the year ending December 31, 2020 required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.01.99.03.
The report of the independent registered public accounting firm
The unaudited financial statements and Notes to Consolidated Financial Statements of Enable Midstream Partners, LP, for the nine month period ending September 30, 2021 required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.04.
2. Financial Statement Schedule (included in Part IV)
•Schedule II - Valuation and Qualifying Accounts
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective Consolidated Financial Statementsfinancial statements or Notesnotes thereto.
3. Exhibits
| | | | | | | | X |
4.18 |
| | X | | X |
4.19 |
| | X | | X |
4.20 | Supplemental Indenture No. 21 dated as of April 1, 2020, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed April 1, 2020 (File No. 1-1097) and incorporated by reference herein). | | X |
4.21 | Supplemental Indenture No. 22 dated as of May 27, 2021, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed May 27, 2021 (File No. 1-1097) and incorporated by reference herein). | X | X |
4.22 | Supplemental Indenture No. 23 dated as of January 5, 2023, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 5, 2023 (File No. 1-1097) and incorporated by reference herein). | X | X |
4.23 | Indenture dated as of November 1, 2004 between OGE Energy Corp. and UMB Bank, N.A., as trustee. (Filed as Exhibit 4.01 to OGE Energy's Form 8-K filed November 12, 2004 (File No. 1-12579) and incorporated by reference herein). | X | |
|
4.21 4.24
|
| | X | |
|
4.22 4.25
| | Supplemental Indenture No. 3 dated as of April 26, 2018, being a supplemental instrument to Exhibit 4.204.22 hereto. (Filed as Exhibit 4.04 to the Company'sOGE Energy's Registration Statement on Form S-3ASR filed May 18, 2018 (File No. 333-225030) and incorporated by reference herein). | X | |
|
4.23 4.26
| Supplemental Indenture No. 4 dated as of May 27, 2021, being a supplemental instrument to Exhibit 4.22 hereto. (Filed as Exhibit 4.01 to OGE Energy's Form 8-K filed May 27, 2021 (File No. 1-12579) and incorporated by reference herein). | X | |
4.27+ | | X | |
|
10.01 |
| | X | | X |
10.02 |
| | X | | X |
10.03 |
| | X | | X |
10.04* |
| | X | | X |
10.05 10.05*
|
| Credit Agreement dated as of March 8, 2017 by and among OGE Energy Corp. and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed March 8, 2017 (File No. 1-12579) and incorporated by reference herein). | | | |
10.06 | | Credit Agreement dated as of March 8, 2017 by and among Oklahoma Gas and Electric Company and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed March 8, 2017 (File No. 1-12579) and incorporated by reference herein). | | | |
| | | | |
10.07* | | | X | | X |
10.08* 10.06*
| Amendment No. 1 to the OGE Energy Corp. Supplemental Executive Retirement Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2021 (File No. 1-12579) and incorporated by reference herein). | | X |
10.07* | OGE Energy Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein). | X | X |
| | | | | | | | |
10.15 | | | | | |
10.16 | | | | | |
10.17 | | | | | |
10.18* | | | X | | X |
10.19* 10.13*
|
| | X | | X |
10.14*+ | OGE Energy's 2023 Annual Executive Incentive Compensation Plan. | X | | X |
10.15* | | | | |
10.20*
| | | | | |
10.21* | | | | | |
10.22* | | | | | |
| | | | |
| | | | |
| | | | |
| | | | |
10.23* | | | X | | X |
10.24* 10.16*
|
| | X | | X |
10.25* 10.17*+
| Form of Performance Unit Agreement under OGE Energy's 2022 Stock Incentive Plan. | | X |
10.18*+ | Form of Restricted Stock Unit Agreement under OGE Energy's 2022 Stock Incentive Plan. | X | X |
10.19* | OGE Energy Corp. Deferred Compensation Plan (As amended and restated effective October 1, 2016). (Filed as Exhibit 10.37 to OGE Energy's Form 10-K for the year ended December 31, 2016 (File No. 1-12579) and incorporated by reference herein). | X | | X |
10.26 10.20
|
| | X | | X |
10.27 10.21
|
| Letter of extensionAmended and Restated Credit Agreement dated as of March 9, 2018 for the Company's and OG&E's credit agreements dated as March 8, 2017,December 17, 2021 by and among OGE Energy Corp. and Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., Syndication Agent, and Mizuho Bank, Ltd., as Co-Syndication Agents, MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed December 21, 2021 (File No. 1-12579) and incorporated by reference herein). | X |
|
10.22 | First Amendment dated as of December 19, 2022, to Amended and Restated Credit Agreement dated as of December 17, 2021, by and among OGE Energy, the Lenders thereto, Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and the CompanyMizuho Bank, Ltd., as Co-Syndication Agents, and OG&E, for their respective credit facility.MUFG Bank, Ltd., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended March 31, 20188-K filed December 19, 2022 (File No. 1-12579) and incorporated by reference herein). | X |
|
10.23 | Amended and Restated Credit Agreement dated as of December 17, 2021 by and among Oklahoma Gas and Electric Company and Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and Mizuho Bank, Ltd., as Co-Syndication Agents, MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.02 to OG&E's Form 8-K filed December 21, 2021 (File No. 1-1097) and incorporated by reference herein). | X | X |
10.24 | First Amendment dated as of December 19, 2022, to Amended and Restated Credit Agreement dated as of December 17, 2021, by and among OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and Mizuho Bank, Ltd., as Co-Syndication Agents, and MUFG Bank, Ltd., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents. (Filed as Exhibit 10.02 to OG&E's Form 8-K filed December 19, 2022 (File No. 1-1097) and incorporated by reference herein). | X | X |
10.25 | Securitization Property Purchase and Sale Agreement dated as of July 20, 2022 by and between Oklahoma Development Finance Authority, as Issuer, and Oklahoma Gas and Electric Company, as Seller. (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed July 20, 2022 (File No. 1-12579) and incorporated by reference herein). |
| X |
21.01+ | Subsidiaries of OGE Energy. | X |
|
| | | |
21.01 23.01+
|
| | | | |
23.01 | | | X | |
|
23.02 23.02+
| Consent of Ernst & Young LLP. | | |
23.03+ | Consent of Deloitte & Touche LLP for the Financial Statements of Enable Midstream Partners, LP.LP as of and for the three years ended December 31, 2020 as listed at Exhibit 99.03. | X | |
|
24.01 24.01+
|
| | X | |
|
31.01 24.02+
| Power of Attorney. | | |
31.01+ | Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | |
|
32.01 31.02+
| Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | | |
32.01+ | Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | |
|
99.01 32.02+
| Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | | |
99.01 | Financial Statements of Enable Midstream Partners, LPCredit Agreement dated as of May 24, 2022 by and among OGE Energy Corp., the Lenders and BOKF NA, dba Bank of Oklahoma as Sole Administrative Agent, Sole Syndication Agent, Lead Arranger and Sole Bookrunner (Filed as Exhibit 99.01 to OGE Energy's Form 10-Q for the three yearsquarter ended December 31, 201June 30, 2022 (File No. 1-12579) and incorporated by reference herein).9.
| X | | X |
99.02 | | | | |
| | | | |
99.02
| | | X | | X |
99.03 99.03+
| Audited Financial Statements of Enable Midstream Partners, LP as of and for the three years ended December 31, 2020. | X | | | | | |
99.04+ | Financial Statements of Enable Midstream Partners, LP as of and for the nine months ended September 30, 2021 (unaudited). | X | |
|
101.INS | Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document. | X | | X |
101.SCH | Inline XBRL Taxonomy Schema Document. | X | | X |
101.PRE | Inline XBRL Taxonomy Presentation Linkbase Document. | X | | |
| | | | | | | | X |
101.LAB | Inline XBRL Taxonomy Label Linkbase Document. | X | | X |
101.CAL | Inline XBRL Taxonomy Calculation Linkbase Document. | X | | X |
101.DEF | Inline XBRL Definition Linkbase Document. | X | | X |
104 | Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101). | X | | X |
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* Represents executive compensation plans and arrangements. |
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+ Represents exhibits filed herewith. All exhibits not so designated are incorporated by reference to a prior filing, as indicated. |
|
|
OGE ENERGY CORP.
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
| | | | | | | | | | | | | | | | |
| | | | | Additions | | | | | | | |
Description | | Balance at Beginning of Period | | | Charged to Costs and Expenses | | | Deductions (A) | | | Balance at End of Period | |
(In millions) | |
Balance at December 31, 2020 | | | | | | | | | | | | |
Reserve for Uncollectible Accounts | | $ | 1.5 | | | $ | 3.0 | | | $ | 1.9 | | | $ | 2.6 | |
Balance at December 31, 2021 | | | | | | | | | | | | |
Reserve for Uncollectible Accounts | | $ | 2.6 | | | $ | 3.2 | | | $ | 3.4 | | | $ | 2.4 | |
Balance at December 31, 2022 | | | | | | | | | | | | |
Reserve for Uncollectible Accounts | | $ | 2.4 | | | $ | 2.8 | | | $ | 3.3 | | | $ | 1.9 | |
| | | | | | | | | | | | | | |
| | Additions | | |
| Description | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions (A) | Balance at End of Period |
| (In millions) | | | | |
| Balance at December 31, 2017 | | | | |
| Reserve for Uncollectible Accounts | $ | 1.5 | | $ | 2.6 | | $ | 2.6 | | $ | 1.5 | |
| Balance at December 31, 2018 | | | | |
| Reserve for Uncollectible Accounts | $ | 1.5 | | $ | 3.4 | | $ | 3.2 | | $ | 1.7 | |
| Balance at December 31, 2019 | | | | |
| Reserve for Uncollectible Accounts | $ | 1.7 | | $ | 2.2 | | $ | 2.4 | | $ | 1.5 | |
(A)Uncollectible accounts receivable written off, net of recoveries.
Item 16. Form 10-K Summary.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on February 26th, 2020.
22
, 2023. | | | | | | | | | | | |
| OGE ENERGY CORP. | | |
| (Registrant) | | |
| | | |
|
| By /s/ | Sean Trauschke | |
|
| Sean Trauschke | |
|
| Chairman of the Board, President | |
|
| and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
| | | | | | | | | | | |
Signature | | Title | Date |
| | | |
Signature |
| Title | Date |
|
|
|
|
/s/ Sean Trauschke | | | |
|
Sean Trauschke |
| Principal Executive | |
|
| Officer and Director; | February 26, 202022, 2023
|
|
|
|
|
/s/ W. Bryan Buckler |
|
|
|
W. Bryan Buckler |
| Principal Financial Officer; | February 22, 2023 |
|
|
|
|
/s/ Sarah R. Stafford |
|
|
|
Sarah R. Stafford |
| Principal Accounting Officer; | February 22, 2023 |
|
|
|
|
Frank A. Bozich |
| Director; |
|
Peter D. Clarke |
| Director; |
|
Cathy R. Gates |
| Director; |
|
David L. Hauser |
| Director; |
|
Luther C. Kissam, IV |
| Director; |
|
Judy R. McReynolds |
| Director; |
|
David E. Rainbolt |
| Director; |
|
J. Michael Sanner |
| Director; |
|
Sheila G. Talton |
| Director; |
|
| | | |
/s/ Stephen E. MerrillSean Trauschke |
|
|
|
Stephen E. MerrillBy Sean Trauschke (attorney-in-fact)
|
| Principal Financial Officer;
| February 26, 202022, 2023 |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on February 22nd, 2023.
| | | |
/s/ Sarah R. Stafford
| OKLAHOMA GAS AND ELECTRIC COMPANY | |
|
Sarah R. Stafford
| (Registrant) | Principal Accounting Officer.
|
| February 26, 2020
|
|
|
| By /s/ | Sean Trauschke |
|
|
| Sean Trauschke |
|
|
| Chairman of the Board, President |
|
|
| and Chief Executive Officer |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
| | | |
Signature |
| Title | Date |
|
|
|
|
/s/ Sean Trauschke |
|
|
|
Sean Trauschke |
| Principal Executive |
|
|
| Officer and Director; | February 22, 2023 |
|
|
|
|
/s/ W. Bryan Buckler |
|
|
|
W. Bryan Buckler |
| Principal Financial Officer; | February 22, 2023 |
|
|
|
|
/s/ Sarah R. Stafford |
|
|
|
Sarah R. Stafford |
| Principal Accounting Officer; | February 22, 2023 |
|
|
|
|
Frank A. Bozich |
| Director; | |
James H. Brandi | | Director; | |
Peter D. Clarke |
| Director; |
|
LukeCathy R. CorbettGates
|
| Director; | |
David L. Hauser |
| Director; | |
Luther C. Kissam, IV |
| Director; |
|
Judy R. McReynolds |
| Director; |
|
David E. Rainbolt |
| Director; |
|
J. Michael Sanner |
| Director; |
|
Sheila G. Talton |
| Director; |
|
| | | |
| | | |
Judy R. McReynolds | | Director; | |
David E. Rainbolt | | Director; | |
J. Michael Sanner | | Director; | |
Sheila G. Talton | | Director; | |
| | | | | | | | | | | |
/s/ Sean Trauschke | | | |
|
By Sean Trauschke (attorney-in-fact) |
|
| February 26, 202022, 2023 |