UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20162018
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission File Number: 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter) |
| | |
| Oklahoma | | 73-0382390 |
| (State or other jurisdiction of | | (I.R.S. Employer |
| incorporation or organization) | | Identification No.) |
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
o Yes þ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer"filer," "smaller reporting company" and "smaller reporting"emerging growth company" in Rule 12b-2 of the Exchange Act.
|
| |
Large accelerated filer o | Accelerated filer o |
Non-accelerated filer þ (Do not check if a smaller reporting company) | Smaller reporting company o |
| Emerging growth company o |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No
At June 30, 201629, 2018, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $0. As of such date, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp.
At January 31, 20172019, there were 40,378,745 shares of common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.
DOCUMENTS INCORPORATED BY REFERENCE
None
Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
OKLAHOMA GAS AND ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 20162018
TABLE OF CONTENTS
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations that are found throughout this Form 10-K.
|
| |
| Abbreviation | Definition |
| 2017 Tax Act | Tax Cuts and Jobs Act of 2017 |
| 401(k) Plan | Qualified defined contribution retirement plan |
ALJAES | Administrative Law JudgeAES-Shady Point, Inc. |
| APSC | Arkansas Public Service Commission |
| ASC | Financial Accounting Standards BoardFASB Accounting Standards Codification |
| ASU | Financial Accounting Standards BoardFASB Accounting Standards Update |
AVEC | Arkansas Valley Electric Cooperative Corporation |
Bcf/dBcf | Billion cubic feet per day |
CSAPR | Cross-State Air Pollution Rule |
Code | Internal Revenue Code of 1986 |
CO2 | Carbon dioxide |
| Code | Internal Revenue Code of 1986 |
| CSAPR | Cross-State Air Pollution Rule |
Dry ScrubbersScrubber | Dry flue gas desulfurization unitsunit with spray dryer absorber |
| ECP | Environmental Compliance Plan |
| Enable | Enable Midstream Partners, LP, a midstream partnership formed between OGE Energy the ArcLight Group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint |
Enogex | Enogex Holdings LLC, collectively with its subsidiaries, a majority-owned subsidiary of OGE Energy |
| EPA | U.S. Environmental Protection Agency |
| FASB | Financial Accounting Standards Board |
| Federal Clean Water Act | Federal Water Pollution Control Act of 1972, as amended |
| FERC | Federal Energy Regulatory Commission |
| FIP | Federal implementation planImplementation Plan |
| GAAP | Accounting principles generally accepted in the United StatesU.S. |
| IRP | Integrated Resource Plan |
| kV | Kilovolt |
| MATS | Mercury and Air Toxics Standards |
| MMBtu | Million British thermal unit |
| Mustang Modernization Plan | OG&E's plan to replace the soon-to-be retired Mustang steam turbines with 400 MWThe construction of seven new, efficient combustion turbines at the Mustang site in 2017with generating capability of 462 MWs |
| MW | Megawatt |
| MWh | Megawatt-hour |
| NAAQS | National Ambient Air Quality Standards |
| NERC | North American Electric Reliability Corporation |
NOX | Nitrogen oxide |
| OCC | Oklahoma Corporation Commission |
ODEQ | Oklahoma Department of Environmental Quality |
| OG&E | Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy |
| OGE Energy | OGE Energy Corp., parent company of OG&E |
| OSHA | Federal Occupational Safety and Health Act of 1970 |
| Pension Plan | Qualified defined benefit retirement plan |
| Ppb | Parts per billion |
PUD | Public Utility Division of the Oklahoma Corporation Commission |
| QF | Qualified cogeneration facilitiesfacility |
| QF contracts | Contracts with QFs and small power production producers |
| Regional Haze Rule | The EPA's regional haze ruleRegional Haze Rule |
| Restoration of Retirement Income Plan | Supplemental retirement plan to the Pension Plan |
| SIP | State implementation planImplementation Plan |
SO2 | Sulfur dioxide |
| SPP | Southwest Power Pool |
| Stock Incentive Plan | 2013 Stock Incentive Plan |
| System sales | Sales to OG&E's customers |
| U.S. | United States of America |
FORWARD-LOOKING STATEMENTS
Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," areforward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document bythe words "anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and similar expressions. Actual results may vary materiallyfrom those expressed in forward-looking statements. statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factorsthat could causeactual results to differ materiallyfrom the forward-looking statementsinclude, but are not limited to:to:
general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
the ability of OG&E and OGE Energy to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;
prices and availability of electricity, coal and natural gas;
business conditions in the energy industry;
competitive factors, including the extent and timing of the entry of additional competition in the markets served by OG&E;
the impact on demand for our services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;
technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
availability and prices of raw materials for current and future construction projects;
the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
Federalfederal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters OG&E's markets;
environmental laws, safety laws or other regulations that may impact the cost of operations or restrict or change the way OG&E operates its facilities;
changes in accounting standards, rules or guidelines;
the discontinuance of accounting principles for certain types of rate-regulated activities;
the cost of protecting assets against, or damage due to, terrorism or cyberattacks and other catastrophic events;
creditworthiness of suppliers, customers and other contractual parties;
social attitudes regarding the utility industry;
identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;
increased pension and healthcare costs;
costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-K; and
other risk factors listed in the reports filed by OG&E with the Securities and Exchange Commission, including those listed in "Item 1A. Risk Factors."Factors" herein.
OG&E undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
PART I
Item 1. Business.
Introduction
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, ana holding company with investments in energy and energy services providerproviders offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.U.S.
OG&E's principal executive offices are located at321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; (telephone telephone405-553-3000405-553-3000). At December 31, 2018, OG&E had 1,803 employees. OGE Energy's website address is www.ogeenergy.com. Through OGE Energy's website under the heading "Investors," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. OGE 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.
OG&E Mission and Focus
OGE Energy'smission, through OG&E and itsOGE Energy'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.
OG&E is focused on:
Providingproviding exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.productivity;
Providingproviding safe, reliable energy to the communities and customers we serve. Aserve, with a particular focus is 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.investments;
Havinghaving strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members.members;
Continuingcontinuing to grow a zero-injury culture and deliver top-quartile safety results.results;
Complying with the EPA's MATS and Regional Haze Rule requirements.
Ensuringensuring we have the necessary mix of generation resources to meet the long-term needs of our customers.customers; and
Continuingcontinuing focus on operational excellence and efficiencies in order to protect the customer bill.
General
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. The service area covers 30,000square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state.Of the 267 communities that OG&E serves, 241 are located in Oklahoma, and 26 are in Arkansas. OG&E derived 92 percent of its total electric operating revenues in 20162018 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.
OG&E's system control area peak demand in 20162018 was 6,5386,863 MWs onAugust 11, 2016. July 20, 2018. OG&E's load responsibility peak demand was 6,0086,094 MWs onAugust 11, 2016 July 20, 2018. . As reflected in theThe following table below and in the operating statistics that follow, there were26.9 millionMWhshows system sales in2016, 27.2 millionMWh system sales in2015and28.0 millionMWh system sales in2014. Variations variations in system sales for the three years are reflected in the following table:2018, 2017 and 2016.
| | | Year ended December 31 | 2016 | 2016 vs. 2015 | 2015 | 2015 vs. 2014 | 2014 | |
| Year Ended December 31 | | 2018 | 2018 vs. 2017 | 2017 | 2017 vs. 2016 | 2016 |
System sales - (Millions of MWh) | 26.9 | (1.1)% | 27.2 | (2.9)% | 28.0 | 28.1 | 6.8% | 26.3 | (2.2)% | 26.9 |
OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators as well
as from consumers choosing appliances powered by other energy sources.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. Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinatedeterminant of our competitiveness.
| | OKLAHOMA GAS AND ELECTRIC COMPANY | CERTAIN OPERATING STATISTICS | | | | |
| Year ended December 31 | 2016 | 2015 | 2014 | |
| Year Ended December 31 | | 2018 | 2017 | 2016 |
ELECTRIC ENERGY (Millions of MWh) | | |
| Generation (exclusive of station use) | 21.4 |
| 20.9 |
| 22.8 |
| 18.2 |
| 18.5 |
| 21.4 |
|
| Purchased | 9.6 |
| 9.2 |
| 8.8 |
| 12.6 |
| 11.0 |
| 9.6 |
|
| Total generated and purchased | 31.0 |
| 30.1 |
| 31.6 |
| 30.8 |
| 29.5 |
| 31.0 |
|
| OG&E use, free service and losses | (1.1 | ) | (1.2 | ) | (1.4 | ) | (1.3 | ) | (1.4 | ) | (1.1 | ) |
| Electric energy sold | 29.9 |
| 28.9 |
| 30.2 |
| 29.5 |
| 28.1 |
| 29.9 |
|
ELECTRIC ENERGY SOLD (Millions of MWh) | | |
| Residential | 9.3 |
| 9.2 |
| 9.4 |
| 9.7 |
| 8.8 |
| 9.3 |
|
| Commercial | 7.6 |
| 7.4 |
| 7.2 |
| 8.1 |
| 7.6 |
| 7.6 |
|
| Industrial | 3.6 |
| 3.6 |
| 3.8 |
| 3.8 |
| 3.6 |
| 3.6 |
|
| Oilfield | 3.2 |
| 3.4 |
| 3.4 |
| 3.4 |
| 3.2 |
| 3.2 |
|
| Public authorities and street light | 3.2 |
| 3.1 |
| 3.2 |
| 3.1 |
| 3.1 |
| 3.2 |
|
| Sales for resale | — |
| 0.5 |
| 1.0 |
| |
| System sales | 26.9 |
| 27.2 |
| 28.0 |
| 28.1 |
| 26.3 |
| 26.9 |
|
| Integrated market | 3.0 |
| 1.7 |
| 2.2 |
| 1.4 |
| 1.8 |
| 3.0 |
|
| Total sales | 29.9 |
| 28.9 |
| 30.2 |
| 29.5 |
| 28.1 |
| 29.9 |
|
ELECTRIC OPERATING REVENUES (In millions) | | |
| Residential | $ | 951.9 |
| $ | 896.5 |
| $ | 925.5 |
| $ | 901.0 |
| $ | 884.1 |
| $ | 951.9 |
|
| Commercial | 573.7 |
| 535.0 |
| 583.3 |
| 598.0 |
| 588.3 |
| 573.7 |
|
| Industrial | 194.6 |
| 190.6 |
| 224.5 |
| 196.7 |
| 200.6 |
| 194.6 |
|
| Oilfield | 156.9 |
| 162.8 |
| 188.3 |
| 153.2 |
| 159.5 |
| 156.9 |
|
| Public authorities and street light | 204.3 |
| 194.2 |
| 220.3 |
| 204.0 |
| 208.0 |
| 204.3 |
|
| Sales for resale | 0.3 |
| 21.7 |
| 52.9 |
| 0.2 |
| 0.2 |
| 0.3 |
|
| System sales revenues | 2,081.7 |
| 2,000.8 |
| 2,194.8 |
| 2,053.1 |
| 2,040.7 |
| 2,081.7 |
|
| Provision for rate refund | (33.6 | ) | — |
| — |
| (6.0 | ) | 26.8 |
| (33.6 | ) |
| Integrated market | 49.3 |
| 48.6 |
| 94.1 |
| 48.7 |
| 23.5 |
| 49.3 |
|
| Transmission | | 147.4 |
| 151.2 |
| 143.0 |
|
| Other | 161.8 |
| 147.5 |
| 164.2 |
| 27.1 |
| 18.9 |
| 18.8 |
|
| Total operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
| $ | 2,270.3 |
| $ | 2,261.1 |
| $ | 2,259.2 |
|
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) | | |
| Residential | 712,467 |
| 705,294 |
| 697,048 |
| 725,440 |
| 719,441 |
| 712,467 |
|
| Commercial | 94,790 |
| 93,401 |
| 91,966 |
| 97,685 |
| 96,098 |
| 94,790 |
|
| Industrial | 2,831 |
| 2,872 |
| 2,901 |
| 2,771 |
| 2,795 |
| 2,831 |
|
| Oilfield | 6,469 |
| 6,328 |
| 6,460 |
| 6,386 |
| 6,415 |
| 6,469 |
|
| Public authorities and street light | 17,025 |
| 16,880 |
| 16,581 |
| 17,090 |
| 17,081 |
| 17,025 |
|
| Sales for resale | — |
| 1 |
| 26 |
| |
| Total customers | 833,582 |
| 824,776 |
| 814,982 |
| 849,372 |
| 841,830 |
| 833,582 |
|
| AVERAGE RESIDENTIAL CUSTOMER SALES | | |
| Average annual revenue | $ | 1,342.88 |
| $ | 1,278.51 |
| $ | 1,334.05 |
| $ | 1,247.22 |
| $ | 1,234.92 |
| $ | 1,342.88 |
|
| Average annual use (kilowatt-hour) | 13,105 |
| 13,062 |
| 13,540 |
| 13,466 |
| 12,324 |
| 13,105 |
|
| Average price per kilowatt-hour (cents) | 10.25 |
| 9.79 |
| 9.85 |
| 9.26 |
| 10.02 |
| 10.25 |
|
Regulation and Rates
OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations.In2016, 2018, 86 percentof OG&E's electric revenue was subject to the jurisdiction of the OCC,eight percentto the APSC andsix percentto the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E,&E; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customerscustomers; and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities.
The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement.
On July 1, 2016, the Court upheld the FERC's decision requiring removal of the "right of first refusal" for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the "right of first refusal" in the SPP Membership Agreement to be anticompetitive.
OG&E does not believe the Court’s ruling will have any impact on existing transmission projects for which OG&E has already received a notice to construct from the SPP. OG&E intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV.
Fuel Adjustment Clause Review for Calendar Year 2014
On July 28, 2015, the OCC Staff filed an application to reviewFor information concerning OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.
Oklahoma Demand Program Rider Review - SmartHours Program
In July 2012, OG&E filed an application with the OCC to recover certain costs associated with demand programs through the Oklahoma Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off-peak hours during the months of May through October, by offering lower rates to those customers in the off-peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.
In December 2012, the OCC issued an order approving the recovery of costs associated with the demand programs, including the lost revenues associated with the SmartHours program, subject to the PUD Staff's review.
In March 2014, the PUD Staff began their review of the demand program costs, including the lost revenues associated with the SmartHours program.
On August 9, 2016, OG&E entered into a settlement agreement with the PUD Staff to resolve the recoverable amount of lost revenues associated with the SmartHours program. The settlement provides for recovery of $10.1 million per year for 2013, 2014 and 2015, for a total of $30.3 million. OG&E had recorded $36.6 million of lost revenues for 2013, 2014 and 2015. On August 16, 2016, the OCC issued an order adopting the settlement agreement. Accordingly, OG&E reduced lost revenues and the Oklahoma Demand Program Rider regulatory asset by $6.3 million.
Mustang Modernization Plan - Arkansas
On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas. The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings. In July 2016, OG&E filed a motion to dismiss this proceeding and in August, the APSC approved the dismissal. OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service.
Pending Regulatory Matters
Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.
Environmental Compliance Plan
On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 400 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs.
On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.
On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project isrecently completed and OG&E seeks recoverycurrently pending regulatory proceedings, see Note 14 in its rates. On April 28, 2016, the OCC approved the Dry Scrubber project.
Two parties appealed the OCC's decision to the Oklahoma Supreme Court. OG&E is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.
OG&E anticipates the total cost of Dry Scrubbers will be $547.5 million, including allowance for funds used during construction"Item 8. Financial Statements and capitalized ad valorem taxes. As of December 31, 2016, OG&E had invested $208.7 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $424.9 million and expects the project to be completed in late 2017. As of December 31, 2016, OG&E had invested $187.8 million on the Mustang Modernization Plan. Supplementary Data."
Integrated Resource Plans
In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Arkansas by October 1, 2017 and in Oklahoma by October 1, 2018.
Oklahoma Rate Case Filing
On December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53 percent. The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million. Each 0.25 percent change in the requested return on equity affects the requested rate increase by approximately $9.0 million.
In late March 2016, the PUD Staff and other intervenors filed testimony in the case. The PUD Staff recommended a $6.1 million annual rate increase based on a return on equity of 9.25 percent and a common equity percentage of 53.0 percent. Included in the PUD Staff's recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement.
The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent, as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent. Included in the Oklahoma Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement.
The Oklahoma Industrial Energy Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent. Included in the Oklahoma Industrial Energy Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement.
On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million which is subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case. As of December 31, 2016, OG&E has recorded $39.0 million of revenues from the interim rate increase and has reserved $33.7 million of that revenue.
In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations include, among other things, the use of OG&E's actual capital structure of 53 percent equity and 47 percent long-term debt and a return on equity of 9.87 percent resulting in an annual increase in OG&E's revenues of $40.7 million. The parties provided comments on the ALJ's report in early January 2017, and the OCC held hearings in early February 2017. OG&E is unable to predict what action the OCC will take, or the timing of such action.
Arkansas Rate Case Filing
On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management costs, and increased recovery of depreciation and dismantlement costs. A hearing in this matter is scheduled for the second quarter of 2017.
Fuel Adjustment Clause Review for Calendar Year 2015
On September 8, 2016, the OCC Staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. A hearing in this Cause will be held on March 30, 2017.
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.
At December 31, 2016and2015, OG&E had regulatory assets of$526.6 millionand$448.7 million, respectively, and regulatory liabilities of$312.0 millionand$342.4 million, respectively.See Note 1 for a further discussion.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects.See Note 1 in "Item 8. Financial Statements and Supplementary Data" for further discussion of OG&E's regulatory assets and liabilities.
Rate Structures
Oklahoma
OG&E's standard tariff rates include a cost-of-servicecost 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 alternatealternative customer programs and rate options. options, as described below.
Under OG&E's Smart Grid enabledGrid-enabled SmartHours programs, "time-of-use" and "variable peak pricing" rates offer customers the ability to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity and costs are at their lowest.
The guaranteed flat bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year. Another tariff
The Renewable Energy Credit purchase program, a rate option that provides a "renewable energy" resource, to OG&E's Oklahoma retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. Another program being offered to OG&E's commercial and industrial customers
Load Reduction is a voluntary load curtailment program called Load Reduction. This programthat provides OG&E's commercial and industrial customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days but may not be able to curtail every time that a curtailment event is required.
OG&E also offers certain qualifying customers "day-ahead price" and "flex price" rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price" and "flex price" rate options are based on OG&E's projected next day hourly operating costs.
OG&E also has the Public Schools-Demand and Public Schools Non-Demand rate classes that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to our military partners.
The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because
customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.
Arkansas
OG&E's standard tariff rates include a cost-ofcost of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. In May 2017, the APSC approved a settlement requiring OG&E to be regulated under a formula rate rider. The formula rate rider provides for an annual adjustment to rates approved by the APSC in the May 2017 settlement if the earned rate of return falls outside of a plus or minus 50 basis point dead-band around the allowed return on equity. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC.
OG&E offers several alternatealternative customer programs and rate options. options, as described below.
The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest. A second
The Renewable Energy Credit purchase program, a tariff rate option that provides a "renewable energy" resource, to OG&E's Arkansas retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. OG&E offers its commercial and industrial customers
Load Reduction is a voluntary load curtailment program called Load Reduction. This programthat 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" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The day-ahead price"day-ahead price" is based on OG&E's projected next day hourly operating costs.
Fuel Supply and Generation
In2016, 48.0 percentofThe OG&E-generated energy was produced by coal-fired units,45.3 percentby natural gas-fired units and6.7 percentby wind-powered units.Of OG&E's6,667total MWs of generation capability reflected in the table under Item 2. Properties,3,650MWs, or54.7 percent, are from natural gas generation,2,568MWs, or38.5 percent, are from coal generation and449MWs, or6.8 percent, are from wind generation. Over the last five years, the weighted average cost of fuel used, by type, was as follows:for the last three years is presented below.
| | Year ended December 31 (In cents/Kilowatt-Hour) | 2016 | 2015 | 2014 | 2013 | 2012 | |
| | | Fuel Mix (A) | Fuel Cost
(In cents/Kilowatt-Hour) |
| Fuel | | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 |
| Natural gas | 2.488 | 2.529 | 4.506 | 3.905 | 2.930 | 48% | 39% | 45% | 2.517 | 2.821 | 2.488 |
| Coal | 2.213 | 2.187 | 2.152 | 2.273 | 2.310 | 45% | 54% | 48% | 2.025 | 2.069 | 2.213 |
| Weighted average | 2.199 | 2.196 | 2.752 | 2.784 | 2.437 | |
| Renewable | | 7% | 7% | — | — |
| Total fuel | | 100% | 100% | 2.122 | 2.211 | 2.199 |
The increase in the weighted average cost(A)Fuel mix calculated as a percent of fuel in 2016 as compared to 2015 was primarily due to higher coal prices. net MWhs generated.
The decrease in the weighted average cost of fuel in 2015 as2018 compared to 20142017 was primarily due to lower natural gas prices. The decrease in the weighted average cost of fuel in 2014 as compared to 2013 was primarily due to less natural gas used, partially offset by higher natural gas prices. The increase in the weighted average cost of fuel in 20132017 as compared to 20122016 was primarily due to higher natural gas prices. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.
OG&E participates in the SPP Integrated Marketplace. As part of the Integrated Marketplace, the SPP has balancing authority responsibilities for its market participants. The SPP Integrated Marketplace functions as a centralized dispatch, where market participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers. The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations and to determine which generating units will run at any given time for maximum cost-effectiveness.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 recovered through fuel adjustment clauses.
Of OG&E's 6,616 total MWs of generation capability reflected in the table in "Item 2. Properties," 3,631 MWs, or 54.9 percent, are from natural gas generation, 2,524 MWs, or 38.1 percent, are from coal generation, 449 MWs, or 6.8 percent, are from wind generation and 12 MWs, or 0.2 percent, are from solar generation.
Coal
OG&E's coal-fired units with an aggregate capability of 2,568 MWs, are designed to burn low sulfur western sub-bituminous coal. The combination of all 2018 coal hashad a weighted average sulfur content of 0.240.23 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.5 lbslbs. of SO2 per MMBtu.
For 2017,the first quarter of 2019, OG&E has acquiredpurchased 100 percent of its forecasted annual coal usage viarequirements. OG&E plans to fill the remainder of its 2019 coal needs through spot purchases and use of existing inventory andinventory. OG&E has no coal purchase contracts that expire inbeyond December 2017.2019. In 2016,2018, OG&E purchased 5.54.6 million tons of coal from various Wyoming suppliers. See "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations"Operations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
Natural Gas
As a participant in the SPP Integrated Marketplace, OG&E now purchases a relatively small percentage of its natural gas supply through long-termshort-term agreements. Alternatively, OG&E relies on a combination of call natural gas call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.
Wind
OG&E's current wind power portfolio includes the following, in addition to&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms owned byfarms. OG&E:(i) access to up to 50 MWs of electricity generated at a&E's current wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expirespower portfolio also includes purchased power contracts as listed in 2018, (ii) access to up to 152 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to 130 MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2031 and (iv) access to up to 60 MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032.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 |
Solar
In 2015, OG&E placed its first solar plant ininto service. The plant consists of two separate solar farms and is located in Oklahoma City on the site of the Mustang generating facility. The Mustang solar plant has a maximum capacity of 2.5 MWs and consists of almost 10,000 photovoltaic panels.
In the first quarter of 2018, OG&E expects to begin construction on 10placed its second solar plant, which is located near Covington, Oklahoma, into service. The Covington solar plant has a maximum capacity of 9.7 MWs and consists of new solar farms in 2017. almost 38,000 photovoltaic panels.
OG&E will continue to evaluate the need to build additionaladd solar plants to its generation portfolio based on customer demand, cost and reliability.
Safety and Health Regulation
OG&E is subject to a number of Federalfederal and state laws and regulations, including OSHA, the EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.
In addition, the OSHA Hazard Communication Standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
ENVIRONMENTAL MATTERSEnvironmental Matters
General
The activities of OG&E are subject to numerous stringent and complex Federal,federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current Federal,federal, state and local environmental standards.
UnderIn the Obama administration,past, environmental regulation caused OG&E to incur significant costs because the trend in environmental regulation was to place more and more restrictions and limitations on activities that may affect the environment.OG&E'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, OG&E is unablecontinues to predict what changes the Trump administration may have on proposedobligations to take or existingcomplete action under previously adopted environmental regulations.rules, and OG&E cannot assure that future events, such as changes in existing laws, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause it to incur significant costs. costs for environmental matters.
It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 20172019 will be $241.350.0 million, of which $221.925.5 million is for capital expenditures. The amounts include capital expenditures for the Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 20182020 will be approximately $180.822.6 million, of which $161.6
0.2 million is for capital expenditures.The amountsabove include capital expenditures for low NOX burners, Dry Scrubbers and gas conversions. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
For a further discussion of environmental matters and capital expenditures related to environmental factors that may affect OG&E, see "2018 Capital Requirements, Sources of Financing and Financing Activities," "Future Capital Requirements" and "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations" in this Form 10-K.Operations."
FINANCE AND CONSTRUCTION
Future Capital Requirements and Financing Activities
Capital Requirements
OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for a discussion of OG&E's capital requirements.
Capital Expenditures
OG&E's estimates of capital expenditures for the years2017through 2021 are shown in the following table.These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operateOG&E's business) plus capital expenditures for known and committed projects.
|
| | | | | | | | | | | | | | | |
| (In millions) | 2017 | 2018 | 2019 | 2020 | 2021 |
| Base Transmission | $ | 35 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
|
| Base Distribution | 195 |
| 175 |
| 175 |
| 175 |
| 175 |
|
| Base Generation | 40 |
| 75 |
| 75 |
| 75 |
| 75 |
|
| Other | 35 |
| 25 |
| 25 |
| 25 |
| 25 |
|
| Total Base Transmission, Distribution, Generation and Other | 305 |
| 305 |
| 305 |
| 305 |
| 305 |
|
| Known and Committed Non-Base Projects: | | | | | |
| Transmission Projects: | | | | | |
| Other Regionally Allocated Projects (A) | 50 |
| 20 |
| 20 |
| 20 |
| 20 |
|
| Large SPP Integrated Transmission Projects (B) (C) | 155 |
| 20 |
| — |
| — |
| — |
|
| Total Transmission Projects | 205 |
| 40 |
| 20 |
| 20 |
| 20 |
|
| Other Projects: | | | | | |
| Solar | 20 |
| — |
| — |
| — |
| — |
|
Environmental - low NOX burners (D) | 15 |
| — |
| — |
| — |
| — |
|
| Environmental - Dry Scrubbers (D) | 160 |
| 95 |
| 15 |
| — |
| — |
|
| Combustion turbines - Mustang | 170 |
| 35 |
| — |
| — |
| — |
|
| Environmental - natural gas conversion (D) | 20 |
| 25 |
| 25 |
| — |
| — |
|
| Allowance of funds used during construction and ad valorem taxes | 55 |
| 40 |
| 5 |
| — |
| — |
|
| Total Other Projects | 440 |
| 195 |
| 45 |
| — |
| — |
|
| Total Known and Committed Non-Base Projects | 645 |
| 235 |
| 65 |
| 20 |
| 20 |
|
| Total | $ | 950 |
| $ | 540 |
| $ | 370 |
| $ | 325 |
| $ | 325 |
|
| |
(A) | Typically 100kV to 299kV projects. Approximately 30 percent of revenue requirement allocated to SPP members other than OG&E. |
| |
(B) | Typically 300kV and above projects. Approximately 85 percent of revenue requirement allocated to SPP members other than OG&E. |
|
| | | | |
(C) | Project Type | Project Description | Estimated Cost
(In millions) | Projected In-Service Date |
| Integrated Transmission Project | 30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation. $5.0 million of the estimated cost has been spent prior to 2017. | $45 | Late 2017 |
| Integrated Transmission Project | 126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation and construction of the Mathewson substation on this transmission line. $50.0 million of the estimated cost associated with the Mathewson to Cimarron line and substations went into service in 2016; $55.0 million has been spent prior to 2017. | $185 | Mid 2018 |
| |
(D) | Represent capital costs associated with OG&E’s ECP to comply with the EPA’s MATS and Regional Haze Rule. More detailed discussion regarding Regional Haze Rule and OG&E’s ECP can be found in Note 12 and under "Environmental Laws and Regulations" within "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Part II, Item 7 of this Form 10-K.
|
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 achievingOG&E'sfinancial objectives.
Pension and Postretirement Benefit Plans
During 2016, OGE Energy made a $20.0 million contribution to its Pension Plan, of which none related to OG&E. During 2015, OGE Energy did not make any contributions to its Pension Plan. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2017. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a discussion of OGE Energy's pension and postretirement benefit plans.
Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (proceeds fromOGE Energy'sofferings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities.OG&Eutilizes short-term borrowings (through a combination of bank borrowings, commercial paperand borrowings from OGE Energy)to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
Short-term borrowings generally are used to meet working capital requirements. OG&E borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. At December 31, 2016, there were $49.9 million in advances from OGE Energy compared to $333.6 million in advances to OGE Energy at December 31, 2015. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to$400.0 millionof OGE Energy's revolving credit amount.This agreement has a termination date of December 13, 2018. OG&E has a $400.0 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.AtDecember 31, 2016, there was$1.8 millionsupporting letters of credit at a weighted-average interest rate of0.945 percent. There werenooutstanding borrowings under this revolving credit agreement andnooutstanding commercial paper borrowings atDecember 31, 2016. AtDecember 31, 2016, OG&E had$398.2 millionof net available liquidity under its revolving credit agreement.OG&E has the necessary regulatory approvals to incur up to$800.0 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2017 and ending December 31, 2018.See Note 10 for a discussion of OG&E's short-term debt activity.
In December 2011, OG&E entered into an unsecured revolving credit agreement for $400.0 million which expires in December 2018. OG&E expects to replace the existing agreement with a new revolving credit agreement during 2017, under terms and conditions generally similar to the existing agreement.
Expected Issuance of Long-Term Debt
OG&E expects to issue $300.0 million of long-term debt during the first half of 2017, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.
EMPLOYEES
OG&E had1,865employees atDecember 31, 2016.
EXECUTIVE OFFICERSExecutive Officers
The followingtable below includes the names, titles and business experience for the most recent five years for those persons wereserving as Executive Officers of the Registrant as of February 22, 201720, 2019:
|
| | | |
| Name | Age | Current Title |
Sean Trauschke | 49 | Chairman of the Board, President and Chief Executive Officer |
E. Keith Mitchell | 54 | Chief Operating Officer |
Stephen E. Merrill | 52 | Chief Financial Officer |
Scott Forbes | 59 | Controller and Chief Accounting Officer |
Patricia D. Horn | 58 | Vice President - Governance and Corporate Secretary |
Jean C. Leger, Jr. | 58 | Vice President - Utility Operations |
Kenneth R. Grant | 51 | Vice President- Sales and Marketing |
Cristina F. McQuistion | 52 | Vice President - Chief Information Officer |
Jerry A. Peace | 54 | Vice President - Integrated Resource Planning and Development |
Paul L. Renfrow | 60 | Vice President - Public Affairs and Corporate Administration |
William H. Sultemeier | 49 | General Counsel |
Charles B. Walworth | 42 | Treasurer |
No family relationship exists between any of the Executive Officers of the Registrant.Messrs. Trauschke, Merrill, Forbes, Renfrow, Sultemeier, Walworth and Ms. Horn are also officers of OGE Energy. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareholders of OGE Energy, currently scheduled for May 18, 2017.
Mr. Trauschke is a member of the Board of Directors of Enable GP, LLC, the general partner of Enable. Mr. Merrill will become a member of the Board of Directors of Enable GP, LLC on March 1, 2017.
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
|
| | |
Name | Business Experience |
| Sean Trauschke | 51 | 2015 - Present: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. |
| | | 2014 - 2015: | President of OGE Energy Corp. |
| | 2012 - | 2014: | Vice President and Chief Financial Officer of OGE Energy Corp. |
| E. Keith Mitchell | 56 | 2015 - Present: | Chief Operating Officer of OG&E |
| | 2013 | 2014 - 2015: | Executive Vice President and Chief Operating Officer of Enable Midstream Partners, LP |
| 2012 - 2013: | President and Chief Operating Officer of Enogex Holdings; President of Enogex LLC |
| Stephen E. Merrill | 54 | 2014 - Present: | Chief Financial Officer of OGE Energy Corp. |
| | 2013 - | 2014: | Executive Vice President of Finance and Chief Administrative Officer of Enable Midstream Partners, LP |
| Sarah R. Stafford | 2012 - 2013:37 | Chief Operating Officer of Enogex LLC |
Scott Forbes | 20122018 - Present: | Controller and Chief Accounting Officer of OGE Energy Corp. |
| | 2016 - 2018: | Accounting Research Officer of OGE Energy Corp. |
| | 2014 - 2016: | Senior Manager - Ernst & Young, LLP |
| Patricia D. Horn | 60 | 2014 - Present: | Vice President - Governance and Corporate Secretary of OGE Energy Corp. |
| | 2012 - | 2014: | Vice President - Governance, Environmental and Corporate Secretary of OGE Energy Corp. |
| 2012: | Vice President - Governance, Environmental, Health & Safety; Corporate Secretary of OGE Energy Corp. |
| Jean C. Leger, Jr. | 201260 | 2014 - Present: | Vice President - Utility Operations of OG&E |
| Kenneth R. Grant | 54 | 2016 - Present: | Vice President - Sales and Marketing of OG&E |
| | | 2015: | Vice President Marketing and Product Development of OG&E |
| | 2013 | 2014 - 2015: | Managing Director Tech Solutions & Ops of OG&E |
| 2012 - 2013: | Managing Director Customer Solutions of OG&E |
| Cristina F. McQuistion | 54 | 2017 - Present: | Vice President - Chief Information Officer of OG&E |
| | 2016 - 2017: | Vice President - Chief Information Officer and Utility Strategy of OG&E |
| | 2014 - 2015: | Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OG&E |
| 2013 - | 2014: | Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OGE Energy Corp. and OG&E |
Kenneth A. Miller | 201252 | 2019 - 2013:Present: | Vice President - StrategyRegulatory and Performance ImprovementState Government Affairs of OGE Energy Corp. and OG&E |
| | 2014 - 2018: | State Treasurer of Oklahoma |
| Jerry A. Peace | 56 | 2016 - Present: | Vice President - Integrated Resource Planning and Development of OG&E |
| | 2014 - 20152015: | Chief Generation Planning and Procurement Officer of OG&E |
| 2012 - | 2014: | Chief Risk Officer of OGE Energy Corp. |
Paul L. Renfrow | 2014 - Present: | Vice President - Public Affairs and Corporate Administration of OGE Energy Corp. |
| 2012 - 2014: | Vice President - Public Affairs, Human Resources and Health & Safety of OGE Energy Corp. |
| William H. Sultemeier | 51 | 2017 - Present: | General Counsel of OGE Energy Corp. |
| | | 2016: | Partner - Jones Day |
| | 2012-2015: | 2014-2015: | Shareholder - Greenberg Traurig, LLP |
| Charles B. Walworth | 44 | 2014 - Present: | Treasurer of OGE Energy Corp. |
| | 2012 - | 2014: | Assistant Treasurer of OGE Energy Corp. |
| 2012: | Senior Manager Finance of OGE Energy Corp. |
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
OGE Energy's website address iswww.oge.com. Through OGE Energy's website under the heading "Investors," "Investor Relations," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K.
Item 1A. Risk Factors.
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us"refer to OG&E. In addition to the other information in this Form 10-K and other documents filed by uswith the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OG&E. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. us. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.
REGULATORY RISKS
OG&E's profitability depends to a large extent on the ability to fully recover its costs from its customers in a timely manner, and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.
OG&E is subject to comprehensive regulation by several Federalfederal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers in a timely manner. Any failure to obtain utility commission approval to increase rates to fully recover costs, or a delay in the receipt of such approval, could have an adverse impact on OG&E's results of operations. In addition, OG&E's jurisdictions have fuel adjustment clauses that permit OG&E to recover fuel costs through rates without a general rate case, subject to a later determination that such fuel costs were prudently incurred. If the state regulatory commissions determine that the fuel costs were not prudently incurred, recovery could be disallowed.
In recent years, the regulatory environments in which OG&E operates have received an increased amount of attention. It is possible that there could be changes in the regulatory environment that would impair OG&E's ability to fully recover costs historically paid by OG&E's customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. OG&E cannot assure that the OCC, APSC and the FERC will grant rate increases in the future or in the amounts requested, and they could instead lower OG&E's rates.
OG&E is unable to predict the impact on its operating results from future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations or the imposition of additional regulations could have an adverse impact on OG&E's results of operations.
OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a Federalfederal agency, whose regulatory paradigms and goals may not be consistent.
OG&E is currently a vertically integrated electric utility. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission.
OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to FERC regulation of its transmission activities and any wholesale sales. Exposure to inconsistent state and Federalfederal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate, including a change in our authorized return on equity, may harm our financial position and results of operations.
Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position or liquidity.
We are subject to extensive Federal,federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.
In response to recent regulatory and judicial decisions and international accords, emissions of greenhouse gases including, most significantly, CO2 could be restricted in the future as a result of Federalfederal or state legal requirements or litigation relating to greenhouse gas emissions. Additionally, international treaties or protocols could resultNo rules are currently in future additional reductions in the United States. In October 2015, the EPA issued standards for stateseffect that require us to implement to controlreduce our greenhouse gas emissions, from existing electric generating units. A number of states, including Oklahoma, filed lawsuits against the EPA standards. In February 2016, the U.S. Supreme Court entered an order staying the implementation of these EPA standards. If the standards survive judicial review and are implemented as written,but if such rules
were to become effective, they could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of these standards on our operations cannot be determined with certainty at this time.
There is growing effort to initiate nuisance claims against power generators. The impact of these efforts on OG&E cannot be determined with certainty as this time.
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,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.insurance or other regulatory mechanisms. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
For a further discussion of environmental matters that may affect OG&E, see "Environmental Laws and Regulations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations.Operations."
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
OG&E has recently made substantial investments in capital improvements and additions, including the installation of environmental upgrades and retrofits. OG&E's business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment. This could adversely affect OG&E's financial position and results of operations. While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
As of December 31, 2016,2018, OG&E had incurred $208.7invested $504.3 million of construction work in progress on the Dry Scrubbers.Scrubbers at Sooner Units 1 and 2 and is currently seeking recovery of its investment with the OCC.
The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.
OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. The SPP has implemented regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for
any speculative trading activities. OG&E records the SPP Integrated Marketplace transactions as sales or purchases with results reported as Operating Revenues or Cost of Goods SoldSales in its Financial Statements. OG&E's revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP.
Increased competition resulting from restructuring efforts could have a significant financial impact on OG&E and consequently decrease our revenue.
We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows.
Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business,financial position, results of operations, cash flows and access to capital.
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business,financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our financial position, results of operations and cash flows.
We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
We are subject to substantial regulation from Federal,federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain permits, approvals and certifications from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
In compliance with the Energy Policy Act of 2005, the FERC approved the NERC as the national energy reliability organization. The NERC is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. One of OG&E's regulators, 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 beyond our control.
We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal and natural gas for much of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short and long-term contracts. We have certain supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal and natural gas to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm, or generator or transmission facility outage on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E's electric generating facilitiesgeneration, transmission and distribution assets are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, and increased purchase power costs.costs, accidents and third-party liability.
OG&E owns and operates coal-fired, natural gas-fired, wind-powered and solar-powered generating facilities.assets. Operation of electric generating facilitiesgeneration, transmission and distribution assets involves risks that can adversely affect energy output and efficiency levels.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 as existing contracts expire;
facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
operator error or safety related stoppages;
disruptions in the delivery of electricity; and
catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.
WhenThe occurrence of any of these events, if not fully covered by insurance, could have a material effect on our 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, and regulatory policies and customer electricity consumption may cause our generating facilitiesassets to be less competitive.competitive and impact our results of operations.
OG&E primarily generates electricity at large central facilities. This method typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations. OG&E's widespread use of Smart Grid technology allowing for two-way communications between the utility and its customers could enable the entry of technology companies into the interface between OG&E and its customers, resulting in unpredictable effects on our current business.
IncreasedReductions in customer electricity consumption, thereby reducing utility electric sales, could result from increased deployment of renewable energy technologies could reduce utility electric sales, butas well as increased efficiency of household appliances, among other general efficiency gains in technology. However, this potential reduction in load would not reduce our need for ongoing investments in our infrastructure to reliably serve our customers. Continued utility infrastructure investment without increased electricity sales could cause increased rates for customers, potentially resulting in further reductions in electricity sales and reduced profitability.
Economic conditions could negatively impact our business and our results of operations.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity
markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.
Current economicEconomic conditions may be exacerbatedimpacted 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,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 financial risks associated with climate change.
Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to OG&E. In addition, to the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory imposed costs, CO2 taxes or costs associated with additional regulatory requirements, OG&E may be adversely impacted. A declining economy could adversely impact the overall financial health of OG&E due to a lack of load growth and decreased sales opportunities. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We are subject to cybersecurity risks and increased reliance on processes automated by technology.
In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems which may result in a loss of service to customers and also subjects OG&E to financial harm due to the significant expense to repair security breaches or system damage. The implementation of OG&E's Smart Grid program further increases potential risks associated with cybersecurity attacks. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’providers' operations, could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on its financial position, results of operations and cash flows.
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 financial position, results of operations and cash flows.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities or sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products,
and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, earthquakes, and prolonged droughts and the occurrence of wildfires, as well as seasonal temperature variations may adversely affect our financial position, results of operations and cash flows.
Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms, wind storms, earthquakes, and prolonged droughts 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 climate change exacerbates physical changes in weather, operations may be impacted as discussed above.
FINANCIAL RISKS
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our financial position, results of operations or cash flow.flows.
OGE Energy has a Pension Plan that covers a significant amount of our employees hired before December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. Based on our assumptions at December 31, 20162018, OGE Energy expects to make future contributions to maintain required funding levels.It has been OGE Energy's practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. OGE Energy may continue to make voluntary contributions in the future. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our financial position and results of operations. Those factors are outside of our control.
In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees, will continue to rise. The increasing costs and funding requirements with our Pension Plan, health care plans and other employee benefits may adversely affect our financial position, results of operations or liquidity.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years,34 32 percentof our current employees will meet the eligibility requirements to retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.
We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
The terms of the indentures governing our debt securities do not fully prohibit us from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreement and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we and they now face may intensify.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
We cannot assure you that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have a revolving credit agreement for working capital, capital expenditures, acquisitions and other corporate purposes. The levels of our debt could have important consequences, including the following:
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
our debt levels may limit our flexibility in responding to changing business and economic conditions.
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
We are exposed to credit risks in our generation and retail distributionoperations. Credit risk includes the risk that counterparties who owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 1011 generating stations with an aggregate capability of 6,6676,616 MWs at December 31, 20162018. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
| | | | | 2016 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) | | 2018 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) |
| | | Year Installed | | Fuel Capability | | | Year Installed | | Fuel Capability | |
| Station & Unit | | Unit Design Type | 2016 Capacity Factor (A) | | Unit Design Type | 2018 Capacity Factor (A) |
| Seminole | 1 | 1971 | Steam-Turbine | Gas | 9.4 | % | 448 |
| | 1 | 1971 | Steam-Turbine | Gas | 9.9 | % | 426 |
| |
| | 2 | 1973 | Steam-Turbine | Gas | 14.7 | % | 426 |
| | 2 | 1973 | Steam-Turbine | Gas | 4.9 | % | 425 |
| |
| | 3 | 1975 | Steam-Turbine | Gas/Oil | 22.3 | % | | 471 |
| 1,345 |
| 3 | 1975 | Steam-Turbine | Gas/Oil | 15.9 | % | | 464 |
| 1,315 |
|
| Muskogee | 4 | 1977 | Steam-Turbine | Coal | 52.4 | % | | 508 |
| | 4 | 1977 | Steam-Turbine | Coal | 16.5 | % | | 479 |
| |
| | 5 | 1978 | Steam-Turbine | Coal | 43.5 | % | | 497 |
| | 5 | 1978 | Steam-Turbine | Coal | 29.2 | % | | 501 |
| |
| | 6 | 1984 | Steam-Turbine | Coal | 39.8 | % | | 522 |
| 1,527 |
| 6 | 1984 | Steam-Turbine | Coal | 38.0 | % | | 503 |
| 1,483 |
|
| Sooner | 1 | 1979 | Steam-Turbine | Coal | 44.8 | % | | 521 |
| | 1 | 1979 | Steam-Turbine | Coal | 51.2 | % | | 520 |
| |
| | 2 | 1980 | Steam-Turbine | Coal | 42.4 | % | | 520 |
| 1,041 |
| 2 | 1980 | Steam-Turbine | Coal | 44.5 | % | | 521 |
| 1,041 |
|
| Horseshoe Lake | 6 | 1958 | Steam-Turbine | Gas/Oil | 10.5 | % | | 167 |
| | 6 | 1958 | Steam-Turbine | Gas/Oil | 13.2 | % | | 163 |
| |
| | 7 | 1963 | Combined Cycle | Gas/Oil | 8.4 | % | | 214 |
| | 7 | 1963 | Combined Cycle | Gas/Oil | 12.4 | % | | 211 |
| |
| | 8 | 1969 | Steam-Turbine | Gas | 7.4 | % | | 405 |
| | 8 | 1969 | Steam-Turbine | Gas | 5.3 | % | | 403 |
| |
| | 9 | 2000 | Combustion-Turbine | Gas | 18.6 | % |
| 46 |
| | 9 | 2000 | Combustion-Turbine | Gas | 17.6 | % |
| 43 |
| |
| | 10 | 2000 | Combustion-Turbine | Gas | 13.1 | % |
| 46 |
| 878 |
| 10 | 2000 | Combustion-Turbine | Gas | 16.2 | % |
| 42 |
| 862 |
|
| Redbud (B) | 1 | 2003 | Combined Cycle | Gas | 66.9 | % | | 155 |
| | 1 | 2003 | Combined Cycle | Gas | 51.2 | % | | 154 |
| |
| | 2 | 2003 | Combined Cycle | Gas | 65.0 | % | | 154 |
| | 2 | 2003 | Combined Cycle | Gas | 51.9 | % | | 154 |
| |
| | 3 | 2003 | Combined Cycle | Gas | 61.8 | % | | 155 |
| | 3 | 2003 | Combined Cycle | Gas | 47.9 | % | | 153 |
| |
| | 4 | 2003 | Combined Cycle | Gas | 66.7 | % | | 152 |
| 616 |
| 4 | 2003 | Combined Cycle | Gas | 49.7 | % | | 153 |
| 614 |
|
| Mustang | 3 | 1955 | Steam-Turbine | Gas | 6.6 | % | | 120 |
| | 5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | 0.8 | % | | 33 |
| |
| | 4 | 1959 | Steam-Turbine | Gas | 12.6 | % | | 252 |
| | 5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | 0.8 | % | | 31 |
| |
| | 5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | 1.0 | % |
| 28 |
| | 6 | 2018 | Combustion-Turbine | Gas | 23.0 | % | | 57 |
| |
| | 5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | 1.1 | % |
| 32 |
| 432 |
| 7 | 2018 | Combustion-Turbine | Gas | 25.1 | % | | 57 |
| |
| | | 8 | 2017 | Combustion-Turbine | Gas | 24.8 | % |
| 58 |
|
|
| | | 9 | 2018 | Combustion-Turbine | Gas | 27.3 | % | | 58 |
| |
| | | 10 | 2018 | Combustion-Turbine | Gas | 26.8 | % | | 57 |
| |
| | | 11 | 2018 | Combustion-Turbine | Gas | 27.0 | % | | 57 |
| |
| | | 12 | 2018 | Combustion-Turbine | Gas | 23.4 | % | | 57 |
| 465 |
|
| McClain (C) | 1 | 2001 | Combined Cycle | Gas | 78.1 | % | | 379 |
| 379 |
| 1 | 2001 | Combined Cycle | Gas | 76.3 | % | | 375 |
| 375 |
|
| Total Generating Capability (all stations, excluding wind stations) | 6,218 |
| |
| Total Generating Capability (all stations, excluding renewable) | | Total Generating Capability (all stations, excluding renewable) | 6,155 |
|
| | | | | |
| Renewable | | | 2016 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) | | | 2018 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) |
| | | Year Installed | | Number of Units | Fuel Capability | | Year Installed | | Number of Units | Fuel Capability |
| Station | | Location | | Location |
| Crossroads | | 2011 | Canton, OK | 98 | Wind | 38.7 | % | 2.3 |
| 228 |
| | 2011 | Canton, OK | 98 | Wind | 36.9 | % | 2.3 |
| 228 |
|
| Centennial | | 2007 | Laverne, OK | 80 | Wind | 31.9 | % | 1.5 |
| 120 |
| | 2007 | Laverne, OK | 80 | Wind | 27.9 | % | 1.5 |
| 120 |
|
| OU Spirit | | 2009 | Woodward, OK | 44 | Wind | 36.0 | % | 2.3 |
| 101 |
| | 2009 | Woodward, OK | 44 | Wind | 33.8 | % | 2.3 |
| 101 |
|
| Total Generating Capability (wind stations) | 449 |
| |
| Mustang | | | 2015 | Oklahoma City, OK | 90 | Solar | 20.1 | % | — |
| 2 |
|
| Covington | | | 2018 | Covington, OK | 4 | Solar | 25.3 | % | 2.4 |
| 10 |
|
| Total Generating Capability (renewable) | | Total Generating Capability (renewable) | 461 |
|
| |
| (A) | 20162018 Capacity Factor = 20162018 Net Actual Generation / (2016(2018 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)) |
| |
| (B) | Represents OG&E's 51 percent ownership interest in the Redbud Plant. |
| |
| (C) | Represents OG&E's 77 percent ownership interest in the McClain Plant. |
During 2017, OG&E anticipates retiring units 3 and 4 located at the Mustang station.
AtDecember 31, 2016, 2018, OG&E's transmission system included: (i)52substations with a total capacity of13.3 13.2 millionkV-amps and4,911 5,100 structure miles of lines in Oklahoma and (ii)seven substations with a total capacity of 2.9 million kV-amps and 277 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 345 substations with a total capacity of2.5
10.2 millionkV-amps, and277structure miles of lines in Arkansas.OG&E's distribution system included: (i)342substations with a total capacity of9.7 millionkV-amps,29,27829,345 structure miles of overhead lines,2,690 2,940 miles of underground conduit and10,817 10,932 miles of underground conductors in Oklahoma and (ii)30substations with a total capacity of0.9 1.0 millionkV-amps,2,782 2,786 structure miles of overhead lines,270 297 miles of underground conduit and692 685 miles of underground conductors in Arkansas.
Arkansas.
OG&E owns 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73102. In addition to its executive offices, OG&E owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, service centers, fleet and equipment service facilities, operation support and other properties.
During the three years ended December 31, 20162018, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $1.82.0 billion, and gross retirements were $259.8295.1 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paperand borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to 17.116.6 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 20162018.
Item 3. Legal Proceedings.
In the normal course of business,OG&Eis confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion,OG&Ehas incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected inOG&E'sFinancial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.
Item 4. Mine Safety Disclosures.
Not Applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.
In2016, 2015and2014, OG&E declared dividends to OGE Energy of$190.0 million, $120.0 million and $120.0 million, respectively.
Item 6. Selected Financial DataData.
HISTORICAL DATA
| | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | 2013 | 2012 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 | 2015 | 2014 |
| SELECTED FINANCIAL DATA | | |
| Results of Operations Data: | | |
| Results of Operations Data | | |
| Operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
| $ | 2,262.2 |
| $ | 2,141.2 |
| $ | 2,270.3 |
| $ | 2,261.1 |
| $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
| Cost of sales | 880.1 |
| 865.0 |
| 1,106.6 |
| 965.9 |
| 879.1 |
| 892.5 |
| 897.6 |
| 880.1 |
| 865.0 |
| 1,106.6 |
|
| Operating expenses | 870.2 |
| 831.5 |
| 808.5 |
| 771.0 |
| 772.7 |
| 883.6 |
| 835.5 |
| 851.6 |
| 814.5 |
| 789.0 |
|
| Operating income | 508.9 |
| 500.4 |
| 538.0 |
| 525.3 |
| 489.4 |
| 494.2 |
| 528.0 |
| 527.5 |
| 517.4 |
| 557.5 |
|
| Allowance for equity funds used during construction | 14.2 |
| 8.3 |
| 4.2 |
| 6.6 |
| 6.2 |
| 23.8 |
| 39.7 |
| 14.2 |
| 8.3 |
| 4.2 |
|
| Other net periodic benefit expense | | 8.9 |
| 16.3 |
| 18.6 |
| 17.0 |
| 19.5 |
|
| Other income | 16.4 |
| 13.3 |
| 4.8 |
| 8.1 |
| 8.2 |
| 14.1 |
| 36.6 |
| 16.4 |
| 13.3 |
| 4.8 |
|
| Other expense | 2.9 |
| 1.6 |
| 1.9 |
| 4.6 |
| 4.3 |
| 3.4 |
| 2.3 |
| 2.9 |
| 1.6 |
| 1.9 |
|
| Interest expense | 138.1 |
| 146.7 |
| 141.5 |
| 129.3 |
| 124.6 |
| 151.8 |
| 138.4 |
| 138.1 |
| 146.7 |
| 141.5 |
|
| Income tax expense | 114.4 |
| 104.8 |
| 111.6 |
| 113.5 |
| 94.6 |
| 40.0 |
| 141.8 |
| 114.4 |
| 104.8 |
| 111.6 |
|
| Net income | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
| $ | 292.6 |
| $ | 280.3 |
| $ | 328.0 |
| $ | 305.5 |
| $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
| Balance Sheet Data (at period end): | | |
| Balance Sheet Data (at period end) | | |
| Property, plant and equipment, net | $ | 7,681.8 |
| $ | 7,296.1 |
| $ | 6,941.5 |
| $ | 6,634.6 |
| $ | 6,044.1 |
| $ | 8,637.7 |
| $ | 8,333.8 |
| $ | 7,681.8 |
| $ | 7,296.1 |
| $ | 6,941.5 |
|
| Total assets (A) | $ | 8,669.4 |
| $ | 8,525.5 |
| $ | 8,248.9 |
| $ | 7,680.7 |
| $ | 7,209.7 |
| |
| Long-term debt (A) | $ | 2,530.8 |
| $ | 2,639.3 |
| $ | 2,638.0 |
| $ | 2,286.0 |
| $ | 2,037.6 |
| |
| Total assets | | $ | 9,704.5 |
| $ | 9,255.6 |
| $ | 8,669.4 |
| $ | 8,525.5 |
| $ | 8,248.9 |
|
| Long-term debt (including Long-term debt due within one year) | | $ | 3,146.9 |
| $ | 2,999.4 |
| $ | 2,530.8 |
| $ | 2,639.3 |
| $ | 2,638.0 |
|
| Total stockholder's equity | $ | 3,252.1 |
| $ | 3,155.7 |
| $ | 3,004.2 |
| $ | 2,829.3 |
| $ | 2,703.1 |
| $ | 3,603.3 |
| $ | 3,455.7 |
| $ | 3,252.1 |
| $ | 3,155.7 |
| $ | 3,004.2 |
|
| Capitalization Ratios (B) | | |
| Capitalization Ratios (A) | | |
| Stockholder's equity | 56.2 | % | 54.3 | % | 53.1 | % | 55.2 | % | 56.9 | % | 53.4 | % | 53.5 | % | 56.2 | % | 54.3 | % | 53.1 | % |
| Long-term debt | 43.8 | % | 45.7 | % | 46.9 | % | 44.8 | % | 43.1 | % | 46.6 | % | 46.5 | % | 43.8 | % | 45.7 | % | 46.9 | % |
| Ratio of Earnings to Fixed Charges (C) | | |
| Ratio of earnings to fixed charges | 3.64 |
| 3.40 |
| 3.73 |
| 3.96 |
| 3.87 |
| |
| |
| (A) | The amounts for 2015, 2014, 2013 and 2012 have been adjusted for the reclassification of $16.3, $17.3, $14.2 and $12.7, respectively, of debt issuance costs from Total Deferred Charges and Other Assets to Long-Term Debt to be consistent with the 2016 presentation due to the adoption of ASU 2015-03.
|
| |
(B) | Capitalization ratios = [Total stockholder's equity / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)]. |
| |
(C) | For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction and (ii) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.
|
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory.Territory. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, ana holding company with investments in energy and energy services providerproviders offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.U.S.
Overview
OG&E Mission and Focus
OGE Energy'smission, through OG&E and itsOGE Energy'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.
OG&E is focused on:
Providingproviding exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.productivity;
Providingproviding safe, reliable energy to the communities and customers we serve. Aserve, with a particular focus is 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.investments;
Havinghaving strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members.members;
Continuingcontinuing to grow a zero-injury culture and deliver top-quartile safety results.
results;Complying with the EPA's MATS and Regional Haze Rule requirements.
Ensuringensuring we have the necessary mix of generation resources to meet the long-term needs of our customers.customers; and
Continuingcontinuing focus on operational excellence and efficiencies in order to protect the customer bill.
Summary of Operating Results
20162018 compared to 2017.2015. OG&E reported net income of $284.1328.0 million and $268.9305.5 million, respectively, in 20162018 and 20152017, an. The increase of $15.222.5 million, or 5.77.4 percent, was primarily due to an increase inhigher gross margin relateddue to warmer summerfavorable weather (reduced by lower customer rates which were offset by lower income tax expense). This increase was partially offset by higher depreciation and increased wholesale transmission revenues and an increase in other income. Partially offsetting these items was an increase in other operation and maintenanceamortization expense, an increaseprimarily due to a reduction in depreciation expense duerecorded in March 2017 for the period from July 1, 2016 to additional assets being placed in serviceDecember 31, 2016 resulting from the March 2017 OCC rate order, and an increase in income tax expense.higher interest expense driven by increased debt outstanding during 2018 and decreased allowance for borrowed funds used during construction as environmental and large capital projects have been completed.
20152017 compared to 2016. 2014. OG&E reported net income of $268.9$305.5 million and $292.0$284.1 million, respectively, in 20152017 and 2014, a decrease2016. The increase of $23.1$21.4 million, or 7.97.5 percent, was primarily due to an increase in depreciation expense due to additional assets being placed in service in 2015, a decrease in gross margin related to milder weather and decreased wholesale transmission revenues. Partially offsetting these items was an increase in customer growth, an increase inhigher net other income and an increase indriven by increased allowance for equity funds used during construction.construction, as environmental and large capital projects were in progress during the year, and lower depreciation and amortization expense as a result of the March 2017 OCC rate order mandating a reduction in depreciation rates. These increases were partially offset by higher income tax expense, higher operation and maintenance expense as a result of increased spending on vegetation management and lower gross margin primarily due to milder weather.
Recent Developments and Regulatory Matters
As a result of the 2017 Tax Act, in early January 2018: (i) the OCC ordered OG&E to record a reserve, including accrued interest, to reflect the reduced federal corporate tax rate, among other tax implications, on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings; (ii) the APSC ordered OG&E to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act until the resulting benefits, including carrying charges, are returned to customers; and (iii) through a Section 206 filing with the FERC, modifications were requested to be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act.
For Oklahoma jurisdictional revenues, OG&E reserved the excess income taxes collected in current rates, plus interest, from January 2018 through June 2018, and any amortization of excess accumulated deferred income taxes associated with the
2017 Tax Act, which was refunded to Oklahoma customers, as approved by the OCC, during the July 2018 billing cycle. For Arkansas jurisdictional revenues, OG&E reserved the excess income taxes collected in current rates, plus carrying charges, from January 2018 through September 2018, as the Tax Adjustment Rider became effective on October 1, 2018. For FERC jurisdictional revenues, based on an order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice. Further, for Arkansas and FERC jurisdictional revenues, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act.
In January 2018, OG&E filed a general rate review in Oklahoma, seeking recovery of the seven combustion turbines that were part of the Mustang Modernization Plan, requesting an increase in depreciation rates to levels similar with rates in existence prior to the March 2017 OCC rate order and crediting customers for the impacts of the 2017 Tax Act. In June 2018, the OCC approved a Joint Stipulation and Settlement Agreement. As a result of the settlement, new rates were implemented on July 1, 2018.
In December 2018, OG&E filed a general rate review with the OCC, requesting a rate increase to recover its investments in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas to comply with the Regional Haze Rule. The filing also seeks to align OG&E's return on equity more closely to the industry average and to align OG&E's depreciation rates to more realistically reflect its assets' lifespans.
In December 2018, OG&E filed an application for pre-approval from the OCC to acquire a coal- and natural gas-fired plant from AES and a natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC in 2019. The purchase of these assets is intended to replace capacity currently provided by power purchase contracts set to expire in 2019 and to help OG&E satisfy its customers' energy needs and load obligations to the SPP.
Further discussion can be found in Note 14 within "Item 8. Financial Statements and Supplementary Data."
2019 Outlook
OG&E projects to earn approximately $316$311 million to $340$325 million or $1.58 to $1.70 per average diluted share in 20172019 and is based on the following assumptions:
normal weather patterns are experienced for the remainder of the year;
new rates take effect in Oklahoma and Arkansas in 2017;
gross margin on revenues of approximately $1.470$1.416 billion to $1.485$1.421 billion based on sales growth of approximately one percent on a weather-adjusted basis;
approximately $110 million of gross margin is primarily attributed to regionally allocated transmission projects;
operating expenses of approximately $896$941 million to $917$949 million, with operation and maintenance expenses comprising 54approximately 50 percent of the total;
interest expense of approximately $147$143 million to $145 million which assumes a $15$1.4 million allowance for borrowed funds used during construction reduction to interest expense and assumes a debt issuance of $300 million in the firstsecond half of 2017;2019;
other income of approximately $60$3.5 million including approximately $34$3.3 million of allowance for equity funds used during construction;
recovery of $8 million of expiring production tax credits or $0.04 per average diluted share;
an effective tax rate of approximately 324.4 percent;
assumes revenue of approximately $23 million or net income of approximately $14 million or $0.07 per average diluted share fornew rates implemented ontake effect in Oklahoma by July 1, 2016 through December 31, 2016 based on the findings in the ALJ's report associated with the Oklahoma General Rate Case and based on 9.87 percent return on equity;2019; and
every 1025 basis point change in the allowed Oklahoma return on equity equates to a change of approximately $3.6$9.4 million in revenue.
OG&E has significant seasonality in its earnings. OG&E typically shows minimalthe majority of its earnings in the firstsecond and fourththird quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.
Non-GAAP Financial Measures
Gross margin is defined by OG&E as operating revenues less 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, 2018, 2017 and 2016, 2015 and 2014, see OG&E (Electric Utility) Results"Results of OperationsOperations" below.
Detailed below is a reconciliation of gross margin to revenue included in the 20172019 Outlook.
| | | Reconciliation of Gross Margin to Revenue |
| |
| Year Ended December 31, (Dollars in Millions) | 2017
(A) | |
| (In millions) | | Twelve Months Ended December 31, 2019
(A) |
| Operating revenues | $ | 2,088 |
| $ | 1,820 |
|
| Cost of sales | 610 |
| 402 |
|
| Gross margin | $ | 1,478 |
| $ | 1,418 |
|
| |
| (A) | Based on the midpoint of OG&E earnings guidance for 2017.2019. |
Results of Operations
The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 20162018, 20152017 and 20142016 and OG&E's financial position at December 31, 20162018 and 20152017. The following information should be read in conjunction with the Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
| | Year ended December 31 (Dollars in millions) | 2016 | 2015 | 2014 | |
Year Ended December 31 (Dollars in millions) | | 2018 | 2017 | 2016 |
| Operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
| $ | 2,270.3 |
| $ | 2,261.1 |
| $ | 2,259.2 |
|
| Cost of sales | 880.1 |
| 865.0 |
| 1,106.6 |
| 892.5 |
| 897.6 |
| 880.1 |
|
| Other operation and maintenance | 469.8 |
| 444.5 |
| 453.2 |
| 473.8 |
| 469.8 |
| 451.2 |
|
| Depreciation and amortization | 316.4 |
| 299.9 |
| 270.8 |
| 321.6 |
| 280.9 |
| 316.4 |
|
| Taxes other than income | 84.0 |
| 87.1 |
| 84.5 |
| 88.2 |
| 84.8 |
| 84.0 |
|
| Operating income | 508.9 |
| 500.4 |
| 538.0 |
| 494.2 |
| 528.0 |
| 527.5 |
|
| Allowance for equity funds used during construction | 14.2 |
| 8.3 |
| 4.2 |
| 23.8 |
| 39.7 |
| 14.2 |
|
| Other net periodic benefit expense | | 8.9 |
| 16.3 |
| 18.6 |
|
| Other income | 16.4 |
| 13.3 |
| 4.8 |
| 14.1 |
| 36.6 |
| 16.4 |
|
| Other expense | 2.9 |
| 1.6 |
| 1.9 |
| 3.4 |
| 2.3 |
| 2.9 |
|
| Interest expense | 138.1 |
| 146.7 |
| 141.5 |
| 151.8 |
| 138.4 |
| 138.1 |
|
| Income tax expense | 114.4 |
| 104.8 |
| 111.6 |
| 40.0 |
| 141.8 |
| 114.4 |
|
| Net income | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
| $ | 328.0 |
| $ | 305.5 |
| $ | 284.1 |
|
| Operating revenues by classification | | |
| Operating revenues by classification: | | |
| Residential | $ | 951.9 |
| $ | 896.5 |
| $ | 925.5 |
| $ | 901.0 |
| $ | 884.1 |
| $ | 951.9 |
|
| Commercial | 573.7 |
| 535.0 |
| 583.3 |
| 598.0 |
| 588.3 |
| 573.7 |
|
| Industrial | 194.6 |
| 190.6 |
| 224.5 |
| 196.7 |
| 200.6 |
| 194.6 |
|
| Oilfield | 156.9 |
| 162.8 |
| 188.3 |
| 153.2 |
| 159.5 |
| 156.9 |
|
| Public authorities and street light | 204.3 |
| 194.2 |
| 220.3 |
| 204.0 |
| 208.0 |
| 204.3 |
|
| Sales for resale | 0.3 |
| 21.7 |
| 52.9 |
| 0.2 |
| 0.2 |
| 0.3 |
|
| System sales revenues | 2,081.7 |
| 2,000.8 |
| 2,194.8 |
| 2,053.1 |
| 2,040.7 |
| 2,081.7 |
|
| Provision for rate refund | (33.6 | ) | — |
| — |
| (6.0 | ) | 26.8 |
| (33.6 | ) |
| Integrated market | 49.3 |
| 48.6 |
| 94.1 |
| 48.7 |
| 23.5 |
| 49.3 |
|
| Transmission | | 147.4 |
| 151.2 |
| 143.0 |
|
| Other | 161.8 |
| 147.5 |
| 164.2 |
| 27.1 |
| 18.9 |
| 18.8 |
|
| Total operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
| $ | 2,270.3 |
| $ | 2,261.1 |
| $ | 2,259.2 |
|
| Reconciliation of gross margin to revenue: | | |
| Operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
| $ | 2,270.3 |
| $ | 2,261.1 |
| $ | 2,259.2 |
|
| Cost of sales | 880.1 |
| 865.0 |
| 1,106.6 |
| 892.5 |
| 897.6 |
| 880.1 |
|
| Gross margin | $ | 1,379.1 |
| $ | 1,331.9 |
| $ | 1,346.5 |
| $ | 1,377.8 |
| $ | 1,363.5 |
| $ | 1,379.1 |
|
MWh sales by classification (In millions) | | |
| Residential | 9.3 |
| 9.2 |
| 9.4 |
| 9.7 |
| 8.8 |
| 9.3 |
|
| Commercial | 7.6 |
| 7.4 |
| 7.2 |
| 8.1 |
| 7.6 |
| 7.6 |
|
| Industrial | 3.6 |
| 3.6 |
| 3.8 |
| 3.8 |
| 3.6 |
| 3.6 |
|
| Oilfield | 3.2 |
| 3.4 |
| 3.4 |
| 3.4 |
| 3.2 |
| 3.2 |
|
| Public authorities and street light | 3.2 |
| 3.1 |
| 3.2 |
| 3.1 |
| 3.1 |
| 3.2 |
|
| Sales for resale | — |
| 0.5 |
| 1.0 |
| |
| System sales | 26.9 |
| 27.2 |
| 28.0 |
| 28.1 |
| 26.3 |
| 26.9 |
|
| Integrated market | 3.0 |
| 1.7 |
| 2.2 |
| 1.4 |
| 1.8 |
| 3.0 |
|
| Total sales | 29.9 |
| 28.9 |
| 30.2 |
| 29.5 |
| 28.1 |
| 29.9 |
|
| Number of customers | 833,582 |
| 824,776 |
| 814,982 |
| 849,372 |
| 841,830 |
| 833,582 |
|
| Weighted-average cost of energy per kilowatt-hour - cents | | |
Weighted-average cost of energy per kilowatt-hour (In cents) | | |
| Natural gas | 2.488 |
| 2.529 |
| 4.506 |
| 2.517 |
| 2.821 |
| 2.488 |
|
| Coal | 2.213 |
| 2.187 |
| 2.152 |
| 2.025 |
| 2.069 |
| 2.213 |
|
| Total fuel | 2.199 |
| 2.196 |
| 2.752 |
| 2.122 |
| 2.211 |
| 2.199 |
|
| Total fuel and purchased power | 2.842 |
| 2.874 |
| 3.493 |
| 2.900 |
| 3.049 |
| 2.842 |
|
| Degree days (A) | | |
| Heating - Actual | 2,800 |
| 3,038 |
| 3,569 |
| 3,776 |
| 2,877 |
| 2,800 |
|
| Heating - Normal | 3,349 |
| 3,349 |
| 3,349 |
| 3,349 |
| 3,349 |
| 3,349 |
|
| Cooling - Actual | 2,247 |
| 2,071 |
| 2,114 |
| 2,123 |
| 1,944 |
| 2,247 |
|
| Cooling - Normal | 2,092 |
| 2,092 |
| 2,092 |
| 2,092 |
| 2,092 |
| 2,092 |
|
| |
| (A) | Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated |
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.
20162018 compared to 2015.2017. OG&E's net income increased $15.2$22.5 million, or 5.77.4 percent, in 20162018 as compared to 20152017, primarily due to an increase inhigher gross margin related to warmer summer weather and increased transmission revenues and an increase in other(reduced by lower customer rates which were offset by lower income tax expense), partially offset by increaseshigher depreciation and amortization expense, primarily due to a reduction in other operation and maintenance expense, depreciation expense recorded in March 2017 for the period from July 1, 2016 to December 31, 2016 resulting from the March 2017 OCC rate order, lower other income and income taxhigher interest expense.
Operating revenues were$2,259.2 millionin2016as compared to$2,196.9 millionin2015, an increaseof$62.3 million, or2.8 percent. Cost of sales were$880.1 millionin2016as compared to$865.0 millionin2015, an increaseof$15.1 million, or1.7 percent. Gross margin was $1,379.1 million in2016as compared to $1,331.9 million in2015, an increase of $47.2increased $14.3 million, or 3.5 percent.1.0 percent, in 2018 as compared to 2017. The below factors contributed to the change in gross margin:margin.
|
| | | |
| (In millions) | $ Change |
| Interim rate increase - Oklahoma (A) | $ | 39.0 |
|
| Reserve for rate refund (A) | (33.7 | ) |
| Wholesale transmission revenue (B) | 20.3 |
|
| Price variance (C) | 18.1 |
|
| Quantity variance (primarily weather) | 13.1 |
|
| New customer growth | 3.2 |
|
| Non-residential demand and related revenues | 0.6 |
|
| Other | (3.7 | ) |
| Expiration of AVEC contract (D) | (9.7 | ) |
| Change in gross margin | $ | 47.2 |
|
|
| | | |
| (In millions) | $ Change |
| Weather (price and quantity) (A) | $ | 43.0 |
|
| New customer growth | 7.8 |
|
| Non-residential demand and related revenue | 6.9 |
|
| Industrial and oilfield sales | 5.7 |
|
| Price variance (B) | (36.4 | ) |
| Reserve for tax refund (C) | (15.4 | ) |
| Wholesale transmission revenue (D) | (7.1 | ) |
| Other | 9.8 |
|
| Change in gross margin | $ | 14.3 |
|
| |
| (A) | As discussedCooling and heating degree days increased nine percent and 31 percent, respectively, during the year ended December 31, 2018, as compared to the same periods in Note 13, on July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million. Interim rates are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the general rate case.2017. |
| |
| (B) | IncreasedDecreased during the year ended December 31, 2018 primarily due to new Oklahoma rates being implemented on July 1, 2018 and new rates being implemented for Arkansas customers in October 2018, both of which reflected the SPP's settlementlower corporate federal tax rate as a result of revenue credits relatedthe 2017 Tax Act, as well as the Oklahoma and Arkansas tax refunds to customers during the July 2018 and October 2018 billing cycles, respectively, for amounts reserved in previous months during 2018 prior to the Windspeed Transmission line for the years 2008 through August 2016. Other increases include a recoveryimplementation of the base plan projects in the SPP formula rate for 2015 and 2016.new rates. |
| |
| (C) | Increased primarily due to the reversalFurther discussion of aOG&E's reserve for gas transportation chargestax refund in additionresponse to the pricing impact of weather related sales.OCC, APSC and FERC proceedings can be found in Notes 8 and 14 in "Item 8. Financial Statements and Supplementary Data."
|
| |
| (D) | On June 30, 2015,Beginning with the wholesale power contract with AVEC expired.July 2018 invoice, billings reflected the lower corporate federal tax rate enacted by the 2017 Tax Act, as discussed in Note 14 in "Item 8. Financial Statements and Supplementary Data."
|
Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission relatedtransmission-related charges. Fuel expense was$470.7 millionin2016as compared to$458.5 millionin2015, an increaseof$12.2 million, or2.7 percent, primarily due to higher volumes of natural gas used partially offset by lower natural gas prices.In2016, OG&E's fuel mix was48.0 percentcoal,45.3 percentnatural gas and6.7 percentwind. In2015, OG&E's fuel mix was49.0 percentcoal,44.0 percentnatural gas andseven percentwind. Purchased power costs were$350.3 millionin2016as compared to$362.6 millionin2015, a decreaseof$12.3 million, or3.4 percent, primarily due to a decrease in purchases from the SPP. Transmission related charges were$59.1 millionin2016as compared to$43.9 millionin2015, an increaseof$15.2 million, or34.6 percent, primarily due to higher SPP charges for the base plan projects of other utilities and SPP charges for the Windspeed Transmission line for the years 2008 through August 2016.
The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. OG&E's cost of sales decreased $5.1 million, or 0.6 percent, in 2018 as compared to 2017. The OCC andbelow factors contributed to the APSC have the authority to review the appropriatenesschange in cost of gas transportation charges or other fees OG&E pays to its affiliate, Enable.sales.
|
| | | | | |
| (In millions) | $ Change | % Change |
| Fuel expense (A) | $ | (22.3 | ) | (5.5 | )% |
| Purchased power costs: | | |
| Purchases from SPP (B) | 23.8 |
| 10.3 | % |
| Wind | (3.6 | ) | (5.7 | )% |
| Cogeneration | (2.8 | ) | (2.4 | )% |
| Transmission expense (C) | (0.9 | ) | (1.3 | )% |
| Curtailment expense | 0.7 |
| 9.3 | % |
| Change in cost of sales | $ | (5.1 | ) | |
| |
| (A) | Decrease in fuel expense during the year ended 2018 was primarily due to lower fuel prices and decreased utilization of company-owned generation. |
| |
| (B) | Increase in the cost of purchases from the SPP for the year ended 2018 was due to a 21.1 percent increase in MWhs purchased, partially offset by a 9.0 percent decrease in cost per MWhs purchased due to a decrease in fuel prices. |
| |
| (C) | Decrease in transmission-related charges was primarily due to lower SPP charges driven by lower rates charged to OG&E for transmission service as a result of lower tax rates due to the 2017 Tax Act. |
Operating Expenses
Other operation and maintenance expense wasincreased $469.8 millionin2016as compared to$444.5 millionin2015, an increaseof$25.34.0 million, or 5.70.9 percent., in 2018 as compared to 2017. The below factors contributed to the change in other operation and maintenance expense:expense.
| | | (In millions) | $ Change | $ Change | % Change |
| Salaries and wages (A) | $ | 10.4 |
| |
| Contract professional services (B) | 8.7 |
| |
| Corporate allocations and overheads (C) | 8.1 |
| |
| Payroll and benefits (A) | | $ | 13.6 |
| 5.8 | % |
| Contract technical and construction services and materials and supplies (B) | | (5.9 | ) | (8.2 | )% |
| Other | (1.9 | ) | (3.7 | ) | (2.3 | )% |
| Change in other operation and maintenance expense | $ | 25.3 |
| $ | 4.0 |
| |
| |
| (A) | Increased primarily due to annual salary increases and an increase in incentive compensation, pension expense, annual salaries and medical/dental expense partially offset by a decrease in overtime.compensation. |
| |
| (B) | IncreasedChanges are primarily due to increased consulting costs associated with demand side management programs.
|
| |
(C) | Increased primarily due to additional direct support in information technology, facility direct support, strategy and marketing support.
the timing of normal plant maintenance. |
Depreciation and amortization expense wasincreased $316.4 millionin2016as compared to$299.9 millionin2015, an increaseof$16.540.7 million, or 5.514.5 percent, primarily due to a reduction in depreciation expense of approximately $20.0 million recorded in March 2017 for the period from July 1, 2016 to December 31, 2016 resulting from the March 2017 OCC rate order, and additional assets being placed in service and amortization of deferred storm costs. into service.
Taxes other than income taxes was $84.0 million in 2016 as compared to $87.1 million in 2015, a decrease of $3.1 million, or 3.6 percent, due to increased capitalization of ad valorem taxes primarily associated with environmental projects.
Additional Information
Allowance for Equity Funds Used During Construction.Allowance for equity funds used during construction was $14.2 million in 2016 as compared to $8.3 million in 2015, an increase of $5.9decreased $15.9 million, or 71.140.1 percent, primarily due to higherlower construction work in progress balances resulting from increased spending forcertain environmental projects.projects being completed and placed into service.
Other Income. Other income was $16.4 million in 2016 as compared to $13.3 million in 2015, an increase of $3.1net periodic benefit expense decreased $7.4 million, or 23.345.4 percent, primarily due to amortization of unrecognized prior service cost.
Other income decreased $22.5 million, or 61.5 percent, primarily due to a decrease in the tax gross-up related to lower allowance for funds used during construction and a change in the presentation of guaranteed flat bill margins, which are now included in gross margin due to the adoption of the new revenue recognition standard (ASC 606).
Allowance for borrowed funds used during construction decreased $6.3 million, or 35.0 percent, primarily due to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.
Income tax expense decreased $101.8 million, or 71.8 percent, primarily due to a reduction in the corporate federal tax rate, an increase in the amortization of net unfunded deferred taxes, an increase in state tax gross up relatedcredit generation and lower pre-tax income.
2017 compared to 2016.OG&E's net income increased $21.4 million, or 7.5 percent, in 2017 as compared to 2016, primarily due to lower depreciation and amortization expense as a result of the March 2017 OCC rate order mandating a reduction in depreciation rates, higher allowance for equity funds used during construction, higher other income and an increase in interest income related to riders partially offset by decreased guaranteed flat bill margins.
Other Expense. Other expense was $2.9 million in 2016 as compared to $1.6 million in 2015, an increase of $1.3 million, or 81.3 percent, primarily due to increased other miscellaneous expenses, increased charitable donations during 2016 and an increase in consulting services.
Interest Expense. Interest expense was $138.1 million in 2016 compared to $146.7 million in 2015, a decrease of $8.6 million, or 5.9 percent, primarily due to the retirement of senior notes in January 2016, partially offset by increasedhigher allowance for borrowed funds used during construction, primarily associated with environmental projects.
Income Tax Expense. Income tax expense was $114.4 million in 2016 as compared to $104.8 million in 2015, an increase of $9.6 million, or 9.2 percent, primarily due to higher pre-tax operating income in addition to lower renewable energy credits.
2015 compared to 2014. OG&E's net income decreased $23.1 million, or 7.9 percent, in 2015 as compared to 2014 primarily due to higher depreciation expense and lower gross margin partially offset by higher other income tax expense, higher operation and an increase in allowance for equity funds used in construction.maintenance expense, lower gross margin and higher interest on long-term debt.
Operating revenues were $2,196.9Gross margin decreased $15.6 million, or 1.1 percent, in 20152017 as compared to $2,453.1 million in 2014, a decrease of $256.2 million, or 10.4 percent. Cost of sales were $865.0 million in 2015 as compared to $1,106.6 million in 2014, a decrease of $241.6 million, or 21.8 percent. Gross margin was $1,331.9 million in 2015 as compared to $1,346.5 million in 2014, a decrease of $14.6 million, or 1.1 percent.2016. The below factors contributed to the change in gross margin:margin.
| | | (In millions) | $ Change | $ Change |
| Quantity variance (primarily weather) (A) | $ | (25.8 | ) | |
| Wholesale transmission revenue (B) | (19.8 | ) | |
| Expiration of AVEC contract (C) | (11.5 | ) | |
| Weather (price and quantity) (A) | | $ | (15.1 | ) |
| Price variance (B) | | (13.9 | ) |
| Wholesale transmission revenue | | (8.1 | ) |
| New customer growth | | 14.2 |
|
| Non-residential demand and related revenues | | 5.0 |
|
| Industrial and oilfield sales | (4.5 | ) | 2.2 |
|
| Other | 2.1 |
| 0.1 |
|
| Non-residential demand and related revenues | 3.7 |
| |
| Price Variance (D) | 19.8 |
| |
| New customer growth | 21.4 |
| |
| Change in gross margin | $ | (14.6 | ) | $ | (15.6 | ) |
| |
| (A) | The overall coolingCooling degree days decreased twoapproximately 13 percent in 2015 compared to 2014 with August decreasing by 14.0 percent.2017. |
| |
| (B) | Decreased primarily due to a true upadditional reserves for the base plan projectsrate refunds in the SPP formula rate for 2014both Oklahoma and 2015Arkansas, as well as a reductionriders moving to base rates in the point-to-point credits shared with retail customers.March 2017 OCC rate order. |
OG&E's cost of sales increased $17.5 million, or 2.0 percent, in 2017 as compared to 2016. The below factors contributed to the change in cost of sales.
|
| | | | | |
| (In millions) | $ Change | % Change |
| Fuel expense (A) | $ | (61.5 | ) | (13.1 | )% |
| Purchased power costs: | | |
| Purchases from SPP (B) | 74.4 |
| 47.2 | % |
| Wind | 0.2 |
| 0.4 | % |
| Cogeneration | (9.5 | ) | (7.6 | )% |
| Transmission expense (C) | 13.9 |
| 23.5 | % |
| Change in cost of sales | $ | 17.5 |
| |
| |
| (A) | Decrease in fuel expense was primarily due to decreased utilization of company-owned generation. |
| |
| (B) | Increase in the cost of purchases from the SPP was due to an increase of 26.8 percent in MWh purchased and an increase of 16.2 percent in cost per MWhs purchased. The increase in cost per MWh purchased was due to an increase in fuel prices and higher grid congestion costs during 2017. |
| |
| (C) | On June 30, 2015, the wholesale power contract with AVEC expired.
|
| |
(D) | IncreasedIncrease in transmission-related charges was primarily due to sales and customer mix.
higher SPP charges for the base plan projects of other utilities. |
Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $458.5 million in 2015 as compared to $627.5 million in 2014, a decrease of $169.0 million, or 26.9 percent, primarily due to lower natural gas prices offset by higher natural gas used. In 2015, OG&E's fuel mix was 49.0 percent coal, 44.0 percent natural gas and seven percent wind. In 2014, OG&E's fuel mix was 61.0 percent coal, 32.0 percent natural gas and seven percent wind. Purchased power costs were $362.6 million in 2015 as compared to $444.1 million in 2014, a decrease of $81.5 million, or 18.4 percent, primarily due to a decrease in purchases from the SPP, reflecting the impact of OG&E's participation in the SPP Integrated Marketplace, which began on March 1, 2014. Transmission related charges were $43.9 million in 2015 as compared to $35.0 million in 2014, an increase of $8.9 million, or 25.4 percent, primarily due to higher SPP charges for the base plan projects of other utilities.
The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.
Operating Expenses
Other operation and maintenance expense was $444.5increased $18.6 million, or 4.1 percent, in 20152017 as compared to $453.2 million in 2014, a decrease of $8.7 million, or 1.9 percent.2016. The below factors contributed to the change in other operation and maintenance expense:expense.
|
| | | |
| (In millions) | $ Change |
| Additional capitalized labor (A) | $ | (9.2 | ) |
| Maintenance at power plants (B) | (7.0 | ) |
| Professional service contracts (C) | (2.1 | ) |
| Other | (1.0 | ) |
| Employee benefits (D) | 1.0 |
|
| Other marketing, sales and commercial (E) | 2.8 |
|
| Salaries and wages (F) | 6.8 |
|
| Change in other operation and maintenance expense | $ | (8.7 | ) |
|
| | | | | |
| (In millions) | $ Change | % Change |
| Vegetation management | $ | 14.5 |
| 68.7 | % |
| Other | 11.5 |
| 2.2 | % |
| Capitalized labor (A) | (7.4 | ) | (7.9 | )% |
| Change in other operation and maintenance expense | $ | 18.6 |
| |
| |
| (A) | DecreasedIncreased during 2017 primarily due to more capital projects and storm costs exceeding the $2.7 million OCC-allowed threshold, which were moved to a regulatory asset.
|
| |
(B) | Decreased primarily due to less work atasset, as well as mutual assistance, which was provided in the power plants.
|
| |
(C) | Decreased primarily due to decreased engineering services.
|
| |
(D) | Increased primarily due to higher medical costs incurred partially offset by lower pension costs.
|
| |
(E) | Increased primarily due to higher demand side management customer payments.
|
| |
(F) | Increased primarily due to annual salary increasesaftermath of Hurricanes Harvey and increased overtime related to storms.Irma.
|
Depreciation and amortization expense was $299.9 million in 2015 as compared to $270.8 million in 2014, an increase of $29.1decreased $35.5 million, or 10.711.2 percent, primarily due to lower depreciation expense related to the reduction in depreciation rates approved in the March 2017 OCC rate order, partially offset by additional assets being placed in service, along with an increase resulting from the amortization of deferred pension credits and post-retirement medical regulatory liabilities which were fully amortized in July 2014 and amortization of deferred storm costs.into service.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $8.3increased $25.5 million, in 2015 as compared to $4.2 million in 2014, an increase of $4.1 million or 97.6 percent, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.
Other Income. Other income was $13.3 million in 2015 as compared to $4.8 million in 2014, an increase of $8.5increased $20.2 million, primarily due to increased guaranteed flat bill margins and an increase in the tax gross upgross-up related to higher allowance for funds used during construction.construction and an increase in gains on guaranteed flat bill margins.
Income Tax Expense. Allowance for borrowed funds used during construction increased $10.5 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.
Income tax expense was $104.8 million in 2015 as compared to $111.6 million in 2014, a decrease of $6.8increased $27.4 million, or 6.124.0 percent, primarily due to higher pre-tax operating income and lower pretax income partially offset by a reduction in Federal tax credits.credits generated.
Off-Balance Sheet Arrangement
Railcar Lease Agreement
As of December 31, 2018, OG&E has a noncancellable operating lease with a purchase option, covering approximately 1,2501,093 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's tariffs and fuel adjustment clauses.
On January 11, 2012,At the end of the lease term, which was February 1, 2019, OG&E executedhad the option to either purchase the railcars at a five-yearstipulated fair market value or renew the lease. If OG&E chose not to purchase the railcars or renew the lease agreement for 135and the actual fair value of the railcars to replace railcars thatwas less than the stipulated fair market value, OG&E would have been taken out of service or destroyed.responsible for the difference
On October 14, 2014,
in those values up to a maximum of $16.2 million. OG&E signed a separate three-year lease effective December 2014 for 131was also required to maintain all of the railcars to replace railcars that have been taken out of service or destroyed.it had under the operating lease.
On December 17, 2015,February 1, 2019, OG&E renewed the lease agreement effective February 1, 2016.2019, under similar terms and conditions, for a fleet of 780 railcars, expiring February 1, 2024. The number of railcars was reduced due to the conversion of Muskogee Units 4 and 5 to natural gas. At the end of the new lease term, which is February 1, 2019, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is
less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $18.3$6.8 million.
The railcar lease was recorded on OG&E is also required to maintain all&E's 2019 Balance Sheet upon adoption of the railcars it has under the operating lease.new leases standard (ASC 842).
Liquidity and Capital Resources
Working Capital
Working capital is defined as the difference in current assets and current liabilities. OG&E's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to and the timing of collections from customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.
Accounts Receivable and Accrued Unbilled Revenues. The balance of Accounts Receivable and Accrued Unbilled Revenues was $232.7$235.5 million and $226.6$255.0 million at December 31, 20162018 and 2015,2017, respectively, a decrease of $19.5 million, or 7.6 percent, primarily due to a decrease in billings to OG&E's retail customers.
Advances to Parent. The balance in Advances to Parent was $319.5 million and $112.5 million at December 31, 2018 and 2017, respectively, an increase of $6.1$207.0 million, or 2.7 percent, primarily due to an increase in billings to OG&E's retailof cash from customers reflecting higher usage in December 2016 compared to December 2015.and proceeds from long-term debt, partially offset by daily operational expenses, capital expenditures, payment of long-term debt and dividends paid on common stock.
Fuel Inventories.The balance ofin Fuel Inventories was $79.8$57.6 million and $113.8$84.3 million at December 31, 20162018 and 2015,2017, respectively, a decrease of $34.0$26.7 million, or 29.931.7 percent, primarily due to lowerdecreased coal inventory balances resulting from increased production from coal plants in 2016 and lower average prices.gas inventory.
Fuel Clause Recoveries.Materials and Supplies, at Average Cost. The Fuel Clause balance of Materials and Supplies, at Average Cost was an under recovery of $51.3$126.7 million and $80.8 million at December 31, 2016 compared to2018 and 2017, respectively, an over recoveryincrease of $61.3$45.9 million, at December 31, 2015,or 56.8 percent, primarily due to lower amounts billedincreased inventory related to OG&E retail customers as compared to the actual cost of fuel and purchased power.long-term service agreements.
Other Current Assets. The balance of Other Current Assets was $78.3$25.5 million and $51.6$48.6 million at December 31, 20162018 and 2015,2017, respectively, an increasea decrease of $26.7$23.1 million, or 51.747.5 percent, primarily due to lower revenueincreased collections from customers associated with various rate riders.
Accounts Payable. The balance of Accounts Payable was $196.4 million and $238.2 million at December 31, 2016 and 2015, respectively, a decrease of $41.8 million, or 17.5 percent, primarily due to a decrease in accruals and the timing of vendor payments partially offset by an increase in fuel and purchased power expense.
Advances from Parent/Advances to Parent. The balance of Advances from Parent was $49.9 million and at December 31, 2016 compared to an Advances to Parent balance of $333.6 million at December 31, 2015. The changes in Advances with Parent are primarily due to additional capital expenditures during 2016, payment of long-term debt in January of 2016 and customer refunds of over-recovered fuel.
Accrued Taxes. The balance of Accrued Taxes was $40.8 million and $45.7 million at December 31, 2016 and 2015, respectively, a decrease of $4.9 million, or 10.7 percent, primarily resulting from ad valorem tax accruals of approximately $76.8 million partially offset by payments of approximately $82.4 million.
Accrued Compensation. The balance of Accrued Compensation was $31.3$33.8 million and $23.8$25.6 million at December 31, 20162018 and 2015,2017, respectively, an increase of $7.5$8.2 million, or 31.532.0 percent, primarily due to an increase in accruedhigher accruals for incentive compensation, andpartially offset by a decrease in laborlower amount of accrued but not paid and forfeited vacation.
Long-Term Debt Due Within One Year. The balance of Long-Term Debt Due Within One Year was $125.0 million and $110.0 million at December 31, 2016 and December 31, 2015, respectively, an increase of $15.0 million, or 13.6 percent, primarily due to long-term debt that matured in January 2016 and the reclassification of long-term debt that will mature July 2017.
Other Current Liabilities. The balance of Other Current Liabilities was $95.8$86.8 million and $43.6$28.5 million at December 31, 20162018 and 2015,2017, respectively, an increase of $52.2$58.3 million, primarily due to revenue that has been collected fromamounts owed to customers, but is reserved and subject toincluding the reserve for tax refund until OG&E receives a rate case orderof $15.4 million resulting from the OCC2017 Tax Act, SPP reserves of $29.9 million and over recovery of the SPP credits that will be returned to customers.cost tracker of $16.8 million.
Cash Flows
| | | | | 2016 vs. 2015 | 2015 vs. 2014 | | 2018 vs. 2017 | 2017 vs. 2016 |
Year ended December 31 (In millions) | 2016 |
| 2015 |
| 2014 |
| $
Change | %
Change | $
Change | %
Change | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 | $
Change | %
Change | $
Change | %
Change |
| Net cash provided from operating activities | $ | 572.9 |
| $ | 770.5 |
| $ | 587.7 |
| $ | (197.6 | ) | (25.6 | )% | $ | 182.8 |
| 31.1 | % | $ | 804.0 |
| $ | 715.7 |
| $ | 572.9 |
| $ | 88.3 |
| 12.3 | % | $ | 142.8 |
| 24.9 | % |
| Net cash used in investing activities | (659.2 | ) | (549.0 | ) | (564.7 | ) | (110.2 | ) | 20.1 | % | 15.7 |
| (2.8 | )% | $ | (573.5 | ) | $ | (823.4 | ) | $ | (659.2 | ) | $ | 249.9 |
| (30.3 | )% | $ | (164.2 | ) | 24.9 | % |
| Net cash provided from (used in) financing activities | 86.3 |
| (221.5 | ) | (23.0 | ) | 307.8 |
| * |
| (198.5 | ) | * |
| |
| Net cash (used in) provided from financing activities | | $ | (230.5 | ) | $ | 107.7 |
| $ | 86.3 |
| $ | (338.2 | ) | * |
| $ | 21.4 |
| 24.8 | % |
* Greater than a 100 percent variance.
Operating Activities
The decrease increase of $197.6$88.3 million, or 25.612.3 percent, in net cash provided from operating activities in 2016 2018 as compared to 2015 2017 was primarily due to a returndecrease in vendor payments and an increase in amounts received from customers, partially offset by an increase in income taxes, net of cash from fuel over recoveries to customers.income tax refunds.
The increase of $182.8142.8 million, or 31.124.9 percent, in net cash provided from operating activities in 20152017 as compared to 20142016was primarily due to increased amounts received from customers, primarily due to recovery of fuel costs, partially offset by an increase in cash received from fuel recoveries and a decrease in payments to vendors.vendor payments.
Investing Activities
The increasedecrease of $110.2$249.9 million, or 20.130.3 percent, in net cash used in investing activities in 20162018 as compared to 20152017 was primarily due to a decrease in capital expenditures primarily related to environmental and large capital projects.
The increase of $164.2 million, or 24.9 percent, in net cash used in investing activities in 2017 as compared to 2016 was primarily due to an increase in capital expenditures related to multiple environmental projects.
The decrease of $15.7 million, or 2.8 percent, in net cash used in investing activities in 2015 as compared to 2014 was primarily due to a decrease inand large capital expenditures related to transmission projects partially offset by an increase in capital expenditures related to environmental projects.
Financing Activities
The increase of $307.8 million in net cash provided from financing activitiesin 2016 as compared to 2015 was primarily due to an increase in net advances with OGE Energy partially offset by the payment of $110.0 million in long-term debt during the first quarter of 2016 and an increase in dividend payments.
The increase of $198.5$338.2 million in net cash used in financing activitiesin 20152018 as compared to 20142017 was primarily due to the issuance of less long-term debt during 2014 partially offset by:in 2018 and additional long-term debt paid off in 2018.
•The increase of $21.4 million, or 24.8 percent, in net cash provided from financing activities in 2017 as compared to 2016 was primarily due to the paymentissuance of $140.0$300.0 million in long-term debt during 2014;in each March 2017 and August 2017, partially offset by changes in cash advances with parent.
2018Capital Requirements, Sources of Financingand Financing Activities
•Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were$823.7 millionan increase, and contractual obligations, net of recoveries through fuel adjustment clauses, were$75.6 million, resulting in total net capital requirements and contractual obligations of$899.3 millionin2018, of which$139.8 millionwas to comply with environmental regulations. This compares to net capital requirements of$949.2 millionand net contractual obligations of$78.0 milliontotaling$1,027.2 millionin2017, of which$213.9 millionwas to comply with environmental regulations.
In2018, OG&E's primary sources of capital were cash generated from operations and proceeds from the issuance oflong- and short-term debt. Changes in working capital reflect the seasonal nature of OG&E's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net advances with OGE Energy during 2015;working capital requirements as it pertains to operating cash flow and liquidity.
a decrease in dividend payments in 2015.
The Dodd-Frank Act
Derivative instruments have been used at times in managing OG&E's commodity price exposure. The Dodd-Frank Act, among other things, provides for regulation by the Commodity Futures Trading Commission of certain commodity-related contracts. Although OG&E qualifies for an end-user exception from mandatory clearing of commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and could add additional regulatory oversight over its contracting activities.
Future Capital Requirements and Financing Activities
OG&E'sprimary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes.OG&Egenerally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paperand borrowings from OGE Energy)and permanent financings.
Capital Expenditures
OG&E'sestimates of capital expenditures for the years 20172019 through 20212023 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operateOG&E's business) plus capital expenditures for known and committed projects.
|
| | | | | | | | | | | | | | | |
| (In millions) | 2017 | 2018 | 2019 | 2020 | 2021 |
| Base Transmission | $ | 35 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
|
| Base Distribution | 195 |
| 175 |
| 175 |
| 175 |
| 175 |
|
| Base Generation | 40 |
| 75 |
| 75 |
| 75 |
| 75 |
|
| Other | 35 |
| 25 |
| 25 |
| 25 |
| 25 |
|
| Total Base Transmission, Distribution, Generation and Other | 305 |
| 305 |
| 305 |
| 305 |
| 305 |
|
| Known and Committed Non-Base Projects: | | | | | |
| Transmission Projects: | | | | | |
| Other Regionally Allocated Projects (A) | 50 |
| 20 |
| 20 |
| 20 |
| 20 |
|
| Large SPP Integrated Transmission Projects (B) (C) | 155 |
| 20 |
| — |
| — |
| — |
|
| Total Transmission Projects | 205 |
| 40 |
| 20 |
| 20 |
| 20 |
|
| Other Projects: | | | | | |
| Solar | 20 |
| — |
| — |
| — |
| — |
|
Environmental - low NOX burners (D) | 15 |
| — |
| — |
| — |
| — |
|
| Environmental - Dry Scrubbers (D) | 160 |
| 95 |
| 15 |
| — |
| — |
|
| Combustion turbines - Mustang | 170 |
| 35 |
| — |
| — |
| — |
|
| Environmental - natural gas conversion (D) | 20 |
| 25 |
| 25 |
| — |
| — |
|
| Allowance of funds used during construction and ad valorem taxes | 55 |
| 40 |
| 5 |
| — |
| — |
|
| Total Other Projects | 440 |
| 195 |
| 45 |
| — |
| — |
|
| Total Known and Committed Non-Base Projects | 645 |
| 235 |
| 65 |
| 20 |
| 20 |
|
| Total | $ | 950 |
| $ | 540 |
| $ | 370 |
| $ | 325 |
| $ | 325 |
|
|
| | | | | | | | | | | | | | | |
| (In millions) | 2019 | 2020 | 2021 | 2022 | 2023 |
| Transmission | $ | 40 |
| $ | 35 |
| $ | 35 |
| $ | 35 |
| $ | 35 |
|
| Distribution: | | | | | |
| Oklahoma | 195 |
| 205 |
| 225 |
| 225 |
| 225 |
|
| Arkansas | 55 |
| 30 |
| 15 |
| 15 |
| 15 |
|
| Generation | 145 |
| 75 |
| 60 |
| 60 |
| 90 |
|
| Other | 50 |
| 40 |
| 40 |
| 40 |
| 30 |
|
| Total transmission, distribution, generation and other | 485 |
| 385 |
| 375 |
| 375 |
| 395 |
|
| Projects: | | | | | |
| Environmental - Dry Scrubbers (A) | 15 |
| — |
| — |
| — |
| — |
|
| Environmental - natural gas conversion (A) | 10 |
| — |
| — |
| — |
| — |
|
| Grid modernization, reliability, resiliency, technology and other | 115 |
| 190 |
| 225 |
| 210 |
| 185 |
|
| Total projects | 140 |
| 190 |
| 225 |
| 210 |
| 185 |
|
| Total | $ | 625 |
| $ | 575 |
| $ | 600 |
| $ | 585 |
| $ | 580 |
|
| |
| (A) | Typically 100kV to 299kV projects. Approximately 30 percent of revenue requirement allocated to SPP members other than OG&E. |
| |
(B) | Typically 300kV and above projects. Approximately 85 percent of revenue requirement allocated to SPP members other than OG&E. |
|
| | | | |
(C) | Project Type | Project Description | Estimated Cost
(In millions) | Projected In-Service Date |
| Integrated Transmission Project | 30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation. $5.0 million of the estimated cost has been spent prior to 2017. | $45 | Late 2017 |
| Integrated Transmission Project | 126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation and construction of the Mathewson substation on this transmission line. $50.0 million of the estimated cost associated with the Mathewson to Cimarron line and substations went into service in 2016; $55.0 million has been spent prior to 2017. | $185 | Mid 2018 |
| |
(D) | Represent capital costs associated with OG&E’s&E's ECP to comply with the EPA’s MATS andEPA's Regional Haze Rule. More detailed discussion regarding the Regional Haze Rule and OG&E’s&E's ECP can be found in NoteNotes 1213 and under14 in "Item 8. Financial Statements and Supplementary Data" and in "Environmental Laws and Regulations" within "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Part II, Item 7 of this Form 10-K.below. |
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 achievingOG&E'sfinancial objectives.
Contractual Obligations
The following table summarizes OG&E's contractual obligations at December 31, 20162018. See OG&E's Statements of Capitalization and Note 1213 in "Item 8. Financial Statements and Supplementary Data" for additional information.
| | | (In millions) | 2017 | 2018-2019 | 2020-2021 | After 2021 | Total | 2019 | 2020-2021 | 2022-2023 | After 2023 | Total |
| Maturities of long-term debt (A) | $ | 125.2 |
| $ | 500.2 |
| $ | 0.2 |
| $ | 1,929.7 |
| $ | 2,555.3 |
| $ | 250.1 |
| $ | 0.2 |
| $ | 0.2 |
| $ | 2,929.5 |
| $ | 3,180.0 |
|
| Operating lease obligations | | | |
| Operating lease obligations: | | | |
| Railcars | 2.7 |
| 22.7 |
| — |
| — |
| 25.4 |
| 18.6 |
| — |
| — |
| — |
| 18.6 |
|
| Wind farm land leases | 2.5 |
| 5.0 |
| 5.8 |
| 43.5 |
| 56.8 |
| 2.5 |
| 5.8 |
| 5.8 |
| 37.6 |
| 51.7 |
|
| Total operating lease obligations | 5.2 |
| 27.7 |
| 5.8 |
| 43.5 |
| 82.2 |
| 21.1 |
| 5.8 |
| 5.8 |
| 37.6 |
| 70.3 |
|
| Other purchase obligations and commitments | | |
| Other purchase obligations and commitments: | | |
Cogeneration capacity and fixed operation and maintenance payments | 77.1 |
| 140.4 |
| 105.7 |
| 48.8 |
| 372.0 |
| 10.9 |
| — |
| — |
| — |
| 10.9 |
|
Expected cogeneration energy payments | 37.7 |
| 76.4 |
| 85.1 |
| 49.9 |
| 249.1 |
| 2.4 |
| — |
| — |
| — |
| 2.4 |
|
| Minimum fuel purchase commitments | 236.2 |
| 85.5 |
| 49.2 |
| 407.2 |
| 778.1 |
| |
| Minimum purchase commitments | | 75.8 |
| 89.2 |
| 89.2 |
| 370.4 |
| 624.6 |
|
| Expected wind purchase commitments | 59.0 |
| 114.5 |
| 114.6 |
| 583.5 |
| 871.6 |
| 56.3 |
| 114.0 |
| 115.5 |
| 448.0 |
| 733.8 |
|
| Long-term service agreement commitments | 2.2 |
| 50.6 |
| 4.8 |
| 120.6 |
| 178.2 |
| 46.8 |
| 4.8 |
| 16.8 |
| 108.9 |
| 177.3 |
|
| Mustang Modernization expenditures | 130.4 |
| 21.9 |
| — |
| — |
| 152.3 |
| |
| Environmental compliance plan expenditures | 169.2 |
| 71.9 |
| 0.2 |
| — |
| 241.3 |
| 5.8 |
| 0.2 |
| — |
| — |
| 6.0 |
|
| Total other purchase obligations and commitments | 711.8 |
| 561.2 |
| 359.6 |
| 1,210.0 |
| 2,842.6 |
| 198.0 |
| 208.2 |
| 221.5 |
| 927.3 |
| 1,555.0 |
|
| Total contractual obligations | 842.2 |
| 1,089.1 |
| 365.6 |
| 3,183.2 |
| 5,480.1 |
| 469.2 |
| 214.2 |
| 227.5 |
| 3,894.4 |
| 4,805.3 |
|
| Amounts recoverable through fuel adjustment clause (B) | (335.6 | ) | (299.1 | ) | (248.9 | ) | (1,040.6 | ) | (1,924.2 | ) | |
| Amounts recoverable through fuel adjustment clause (C) | | (153.1 | ) | (203.2 | ) | (204.7 | ) | (818.4 | ) | (1,379.4 | ) |
| Total contractual obligations, net | $ | 506.6 |
| $ | 790.0 |
| $ | 116.7 |
| $ | 2,142.6 |
| $ | 3,555.9 |
| $ | 316.1 |
| $ | 11.0 |
| $ | 22.8 |
| $ | 3,076.0 |
| $ | 3,425.9 |
|
| |
| (A) | Maturities of OG&E's long-term debt during the next five years consist of $125.2 million, $250.1 million, $250.1$0.1 million, $0.1 million, $0.1 million and $0.1 million in years2017, 2018, 2019, 2020, 2021, 2022 and 2021,2023, respectively. |
| |
| (B) | Cogeneration capacity, fixed operation and maintenance and energy payments will end in 2019, as a result of contract expiration. As described below, OG&E intends to acquire the AES and Oklahoma Cogeneration LLC power plants, pending regulatory approval. |
| |
| (C) | Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's expected cogeneration energy payments, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments. |
As of December 31, 2018, OG&E also has440MWs of QF contracts with AES and Oklahoma Cogeneration LLC to meet its current and future expected customer needs. The QF contract with AES expired on January 15, 2019, and the QF contract with Oklahoma Cogeneration LLC expires on August 31, 2019. On December 20, 2018, OG&E will continue reviewing all of the supply alternativesannounced its plan to these QF contracts that minimize the total cost of generationacquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.meet customers' energy needs. Further discussion can be found in Notes 13 and 14 in "Item 8. Financial Statements and Supplementary Data."
The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed throughon to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.
Pension and Postretirement Benefit Plans
At December 31, 20162018, 39.832.4 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income, other securities and U.S. treasuryTreasury notes and bonds as presented in Note 11.12 in "Item 8. Financial Statements and Supplementary Data." During 20162018, actual returnslosses on the Pension Plan were $48.0$29.2 million, slightly higher than thecompared to expected return on plan assets of $41.5$33.1 million. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, remained unchangeddecreased. The level of funding isFunding levels are dependent on returns on plan assets and future discount rates. During 2016, OGE Energy made a $15.0 million and $20.0 million contribution to its Pension Plan in 2018 and 2017, respectively, of which none$5.0 million is related to OG&E. During 2015, OGE Energy did not make any contributions&E in 2018 compared to its Pension Plan.$4.0 million related to OG&E in 2017. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2017.2019. 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 OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 20162018 and 20152017. These amounts have been recorded in Accrued
Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance SheetSheets as discussed in Note 1.1 in "Item 8. Financial Statements and Supplementary Data." The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
| | | | Pension Plan | Restoration of Retirement
Income Plan | Postretirement
Benefit Plans | Pension Plan | Restoration of Retirement
Income Plan | Postretirement
Benefit Plans |
December 31 (In millions) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Benefit obligations | $ | 500.5 |
| $ | 514.4 |
| $ | 4.0 |
| $ | 2.7 |
| $ | 166.4 |
| $ | 176.1 |
| $ | 453.6 |
| $ | 510.6 |
| $ | 6.0 |
| $ | 4.2 |
| $ | 104.8 |
| $ | 115.8 |
|
| Fair value of plan assets | 457.3 |
| 464.2 |
| — |
| — |
| 47.8 |
| 50.0 |
| 387.6 |
| 477.2 |
| — |
| — |
| 40.6 |
| 45.2 |
|
| Funded status at end of year | $ | (43.2 | ) | $ | (50.2 | ) | $ | (4.0 | ) | $ | (2.7 | ) | $ | (118.6 | ) | $ | (126.1 | ) | $ | (66.0 | ) | $ | (33.4 | ) | $ | (6.0 | ) | $ | (4.2 | ) | $ | (64.2 | ) | $ | (70.6 | ) |
Financing Activities and Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long- and short-term debt and funds received from OGE Energy (from proceeds from the sales of OGE Energy's common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
Short-term borrowings generally are used to meet working capital requirements. OG&E borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. At December 31, 2018, there were $319.5 million in advances to OGE Energy compared to $112.5 million at December 31, 2017. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $350.0 million of OGE Energy's revolving credit amount. This agreement has a termination date of March 8, 2023. OG&E has a $450.0 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. The following table highlights OG&E's short-term debt activity as of December 31, 2018.
|
| | | |
| (Dollars in millions) | December 31, 2018 |
| Balance of outstanding supporting letters of credit | $ | 0.3 |
|
| Weighted-average interest rate of outstanding supporting letters of credit | 1.05 | % |
| Balance of outstanding commercial paper borrowings | $ | — |
|
| Net available liquidity under revolving credit agreements | $ | 449.7 |
|
| Balance of outstanding intercompany borrowings with OGE Energy | $ | — |
|
In accordance with ASC Topic 715, "Compensation - Retirement Benefits,"March 2017, OG&E entered into an unsecured five-year $450.0 million revolving credit agreement. The facility contained an option, which could be exercised up to two times, to extend the term of the facility for an additional year. Effective March 9, 2018, OG&E utilized one of those extensions to extend the maturity of its credit facility from March 8, 2022 to March 8, 2023.
OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a one-time settlement charge is requiredtwo-year period beginning January 1, 2019 and ending December 31, 2020. See Note 11 in "Item 8. Financial Statements and Supplementary Data" for further discussion of OG&E's short-term debt activity.
Issuance of Long-Term Debt
In August 2018, OG&E issued $400.0 million of 3.80 percent senior notes due August 15, 2028. The proceeds from the issuance were added to OG&E's general funds to be recorded by an organization when lump sum payments or other settlementsused for general corporate purposes, including to fund the payment of OG&E's $250.0 million of 6.35 percent senior notes that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service costmatured on September 1, 2018, to repay short-term debt and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, OG&E experienced a settlement of its non-qualified Restoration of Retirement Income Plan. As a result, OG&E recorded pension settlement charges of $0.4 million during 2016, of which $0.4 million related to OG&E's Oklahoma jurisdictionfund ongoing capital expenditures and has been included in the pension tracker. During 2015, OG&E experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, OG&E recorded pension settlement charges of $10.0 million in the third quarter of 2015 and $4.2 million in the fourth quarter of 2015, of which $12.5 million related to OG&E's Oklahoma jurisdiction and has been included in the pension tracker. The pension settlement charges did not increase OG&E’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.working capital.
Security Ratings
|
| | | |
| | Moody’sMoody's Investors ServicesService | Standard & Poor'sS&P's Global Ratings Services | Fitch Ratings |
| Senior Notes | A1A2 | A-BBB+ | A+A |
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 OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy's and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E 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 March 5, 2018, S&P's Global Ratings revised the rating outlooks on OGE Energy and OG&E from stable to negative. S&P's Global Ratings indicated that the revised outlooks reflect the limited cushion in company financial measures, which incorporate higher capital spending plans and the effects of the 2017 Tax Act, and uncertainty regarding regulatory risk. The revised outlooks did not trigger any collateral requirements or change fees under the revolving credit agreements.
On June 18, 2018, S&P's Global Ratings lowered its issuer credit ratings for OGE Energy and OG&E from A- to BBB+ and revised their rating outlooks from negative to stable. S&P's Global Ratings also lowered its rating on OG&E's senior unsecured notes from A- to BBB+. S&P's Global Ratings indicated that the changes in ratings are a result of the $64.0 million rate decrease in the June 19, 2018 OCC settlement, the existing level of depreciation expense and continued capital spending, which places OGE Energy and OG&E at a higher level of financial risk in S&P's Global Ratings' risk profile. Furthermore, S&P's Global Ratings indicated that OGE Energy's change in credit rating was impacted by Enable's business risk, due to the volatility of the oil and gas industry. However, S&P's Global Ratings indicated that the stable outlook reflects its expectation that OGE Energy and OG&E will be able to manage future regulatory risk in Oklahoma.
On July 11, 2018, Moody's Investors Service lowered its rating from A3 to Baa1 for OGE Energy and from A1 to A2 for OG&E with both companies having negative outlooks. The Oklahoma regulatory environment and the 2017 Tax Act were both cited by Moody's Investors Service as contributing factors to the credit downgrade. Moody's Investors Service indicated that the negative outlook for OG&E is a reflection of current capital expenditures relating to environmental projects, upcoming debt maturities over the next year and decreased cash flow as a result of the 2017 Tax Act. In addition to the OG&E impacts, Moody's Investors Service indicated that the negative outlook for OGE Energy is a reflection of Enable's business risk, due to the volatility of the oil and gas industry, which Moody's Investors Service indicated could lead to decreased distributions.
On August 1, 2018, Fitch Ratings lowered its senior unsecured debt rating from A- to BBB+ for OGE Energy and from A+ to A for OG&E with both companies having stable outlooks. Fitch Ratings cited the regulatory environment in Oklahoma, underscored by the unfavorable rate review outcomes in 2017 and 2018 and uncertainty surrounding regulatory treatment for OG&E's investment in the Dry Scrubbers at Sooner Units 1 and 2, as a key contributing factor to the credit downgrade. Fitch Ratings also indicated that OGE Energy's credit profile reflects Enable's higher operating risks.
OGE Energy's and OG&E's borrowing costs under the credit agreements will increase immaterially as a result of these recent credit downgrades.
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.
2016Capital Requirements, Sources of Financingand Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were$770.3 millionand contractual obligations, net of recoveries through fuel adjustment clauses, were$81.8 millionresulting in total net capital requirements and contractual obligations of$852.1 millionin2016, of which$137.9 millionwas to comply with environmental regulations. This compares to net capital requirements of$551.8 millionand net contractual obligations of$84.8 milliontotaling$636.6 millionin2015, of which$130.6 millionwas to comply with environmental regulations.
In2016, OG&E's sources of capital were cash generated from operations and proceeds from the issuance ofshort-term debt. Changes in working capital reflect the seasonal nature of OG&E's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.
The Dodd-Frank Act
Derivative instruments have been used at times in managing OG&E's commodity price exposure. The Dodd-Frank Act, among other things, provides for regulation by the Commodity Futures Trading Commission of certain commodity-related contracts. Although OG&E qualifies for an end-user exception from mandatory clearing of commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and could add additional regulatory oversight over its contracting activities.
Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (proceeds fromOGE Energy'sofferings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities.OG&Eutilizes short-term borrowings (through a combination of bank borrowings, commercial paperand borrowings from OGE Energy)to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
At December 31, 2016, there were $49.9 million in advances from OGE Energy compared to $333.6 million in advances to OGE Energy at December 31, 2015. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400.0 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 13, 2018. OG&E has a $400.0 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2016, there was $1.8 million supporting letters of credit at a weighted-average interest rate of 0.95 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2016. At December 31, 2016, OG&E had $398.2 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to$800.0 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2017 and ending December 31, 2018. See Note 10 for a discussion of OG&E's short-term debt activity.
Expected Issuance of Long-Term Debt
OG&E expects to issue $300.0 million of long-term debt during the first half of 2017, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.
Critical Accounting Policies and Estimates
The Financial Statements and Notes to Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the 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 Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, and depreciable lives of property, plant and equipment, the determination of regulatory assets and liabilities and unbilled revenues.revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Audit Committee ofOGE Energy's Audit Committee.Board of Directors. OG&E discusses its significant accounting policies, including those that do not require management to make difficult, subjective or complex judgments or estimates, in Note 1.1 in "Item 8. Financial Statements and Supplementary Data."
Pension and Postretirement Benefit Plans
OGE Energy has a Pension Plan that covers a significant amount of OG&E's employees hired before December 1, 2009. Effective December 1, 2009, OGE Energy's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of its employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The Pension Plan rate assumptions are shown in Note 11. 12 in "Item 8. Financial Statements and Supplementary Data." The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding isFunding levels are dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan. The following table indicates the sensitivity of theOGE Energy's Pension Plan funded status to these variables.
|
| | |
| | Change | Impact on Funded Status |
| Actual plan asset returns | +/- 1 percent | +/- $6.0$5.2 million |
| Discount rate | +/- 0.25 percent | +/- $14.8$11.4 million |
| Contributions | +/- $10 million | +/- $10.0 million |
Income Taxes
OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Accordingly, it is necessary to make judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts OG&E recognized in itsfinancial statements.Tax positions taken by OG&E on its income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information. See Note 8 in "Item 8. Financial Statements and Supplementary Data" for discussion of the effects of the 2017 Tax Act and other tax policies.
Asset Retirement Obligations
OG&Ehas previously recorded asset retirement obligations that are being accreted over their respective lives ranging fromthree two to74years.The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost.
Unbilled Revenues
OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on theBalance Sheets and in Operating Revenues on theStatements of Income based on estimates of usage and prices during the period.At December 31, 20162018, 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. $0.4 million. At December 31, 20162018 and 20152017, Accrued Unbilled Revenues were $59.762.6 million and $53.566.5 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate, which is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 20162018, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of$0.1 million. $0.2 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Balance Sheets and is included in the Other Operation and Maintenance Expense on the Statements of Income. The allowance for uncollectible accounts receivable was $1.7 million and $1.5 million $1.5 millionand$1.4 millionat December 31, 20162018 and 2015, 2017, respectively.
Accounting Pronouncements
See Note 2 in "Item 8. Financial Statements and Supplementary Data" for discussion of current accounting pronouncements that are applicable to OG&E.
Commitments and Contingencies
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows. See
Notes 12 and 13 and Item 3 of Part I14 in this Form 10-K"Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" for a discussion of OG&E's commitments and contingencies.
Environmental Laws and Regulations
The activities of OG&E are subject to numerous stringent and complex Federal,federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current Federal,federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to itsfinancial position or results of operations.OG&Ebelieves, however, that it is likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 20172019 will be $241.350.0 million, of which $221.925.5 million is for capital expenditures. The amounts include capital expenditures for the Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. It is estimated that OG&E's total expenditures
to comply with environmental laws, regulations and requirements for 20182020 will be approximately $180.822.6 million, of which $161.60.2 million is for capital expenditures.The amountsabove include capital expenditures for low NOX burners, Dry Scrubbers and gas conversions.
Air
Federal Clean Air Act Overview
OG&E’s&E's operations are subject to the Federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.
Regional Haze Control Measures
The EPA's 2005 Regional Haze Rule is intended to protect visibility in certain national parks and wilderness areas throughout the United StatesU.S. that may be impacted by air pollutant emissions. On December 28, 2011, the EPA issued a final Regional Haze Rule for Oklahoma which adopted a FIP for SO2 emissions at Sooner Units 1 and 2 and Muskogee Units 4 and 5. The FIP compliance date is nowwas January 4, 2019 as a result of thean appeal filed by OG&E and others.
OG&E's current strategy for satisfyingTo satisfy the FIP, includes installingOG&E installed Dry Scrubbers at Sooner Units 1 and 2 and the conversion ofis converting Muskogee Units 4 and 5 to natural gas. As described in Note 13, the OCC has approved OG&E's decision to install Dry Scrubbers at the Sooner units. As of December 31, 2016,2018, OG&E has incurred $208.7invested $504.3 million of construction work in progress on the Dry Scrubbers.Scrubbers and $50.5 million in the Muskogee natural gas conversion.
Cross-State Air Pollution Rule
In August 2011, the EPA finalized its CSAPR that required several27 states in the eastern half of the United StatesU.S. (including Oklahoma) to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. Litigation challenging the rule prevented it from entering into effectdelayed the effective date until 2014. Several parties to that litigation, including OG&E, have petitions for review that remain pending although the rule is now effective. Compliance with the CSAPR began in 2015 using the amount of allowances originally scheduled to be available in 2012. As of December 31, 2016, OG&E has installed sixseven low NOX burner systems on two Muskogee units, two Sooner units and twothree Seminole units and is in compliance. Installation of the final low NOX burner system is scheduled during the first quarter of 2017 on the remaining Seminole unit.
On September 7, 2016, the EPA finalized an update to the 2011 CSAPR. The new rule applies to ozone-season NOX in 22 eastern states (including Oklahoma), utilizes a cap and trade program for NOX emissions and will takewent into effect on May 1, 2017. The rule reduces the 2016 CSAPR emissions cap for all seven of OG&E’s&E's coal and gas facilities by 47 percent combined. On December 23, 2016, OG&E
and numerous other parties filed a petition for reconsideration of the 2016 rule with the EPA. OG&E is asking the agency to reconsider the methodology used to calculate state ozone-season emissions budgets. OG&E's petition, along with petitions for reconsideration filed by various other parties, is currently pending. Also on December 23, 2016, OG&E filed a petition forjudicial and administrative review of the 2016 rule inrule. Oral argument before the Unites StatesD.C. Circuit U.S. Court of Appeals for the District of Columbia Circuit, asking the court to set aside the rulewas held on the grounds that it is arbitrary, capricious, an abuse of the EPA's discretion and not otherwise in accordance with the law. OG&E's case has been consolidated with several other petitions for review, all of which are currently pending.October 3, 2018.
Due to the pending litigation and administrative proceedings, the ultimate timing and impact of the 2016 CSAPR update rule on our operations cannot be determined with certainty at this time. However, OG&E does not anticipate additional capital expenditures beyond what has already been disclosed and does not expect that the reduced emissions cap, if upheld, will have a material impact on OG&E's financial position, results of operations or cash flows.
Hazardous Air Pollutants Emission Standards
On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units, which became effective April 16, 2012. OG&E believes that it complied with the MATS rule by the April 16, 2016 deadline that applied to OG&E.&E by installing activated carbon injection for all five coal units. Nonetheless, there is continuing litigation, to which OG&E is not a party, challenging whether 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 rule in response to lengthy litigation in the D.C. Circuit Court. The proposed rule will be available for public comment when it is published in the Federal Register. OG&E cannot predict the outcome of this litigation or regulatory proposal or how it will affect OG&E.
National Ambient Air Quality Standards
The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, OG&E could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of the end of 2016,December 31, 2018, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect OG&E's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS. OG&E is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to OG&E's financial results.
The EPA proposed to designate part of Muskogee County, in which OG&E's Muskogee Power Plant is located, as non-attainment for the 2010 SO2 NAAQS on March 1, 2016, even though nearby monitors indicate compliance with the NAAQS. The proposed designation is based on modeling that does not reflect the planned conversion of two of the coal units at Muskogee to natural gas. OG&E commented that the EPA should defer a designation of the area to allow time for additional monitoring. The State of Oklahoma's revised monitoring plan was approved by the EPA, and the required monitoring commenced at the beginning of 2017 and will continue through the end of 2019. Nonetheless, the EPA has a deadline for making a decision on the designation pursuant to a consent decree entered by the U.S. District Court for the Northern District of California to resolve a citizen suit. The deadline has been extended several times, with the current deadline being February 27, 2017.August 26, 2017, but a decision has yet to be reached. It is unclear what impact, if any, the consent decree deadline will have on the monitoring plan. At this time, OG&E cannot determine with any certainty whether the proposed designation of Muskogee County will cause a material impact to OG&E's financial results. The EPA has published final decisions on all other areas of Oklahoma. In this decision, Noble County, in which the Sooner plant is located, was deemed to be in attainment with the 2010 standard. At this time, OG&E cannot determine with any certainty whether this determination will cause a material impact to its financial results.
On September 30, 2015, the EPA finalized a NAAQS for ozone at 70 ppb, which is more stringent than the previous standard of 75 ppb set in 2008. In September 2016, Governor Mary FallinOklahoma submitted to the EPA the recommendation of "attainment/unclassifiable" for all 77 counties in Oklahoma. This recommendation is subject to approval byOn June 4, 2018, the EPA.EPA published its final determination that there are no nonattainment areas in Oklahoma. Based on this assessment, no material impacts are anticipated at this time.
OG&E is monitoring thosecontinues 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 OG&E'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 contributing to the warming of the earth's atmosphere. In December 2015, as part ofOn June 1, 2017, President Trump announced that the 21st Conference ofU.S. will withdraw from the PartiesParis Climate Accord and begin negotiations to re-enter the United Nations Framework Convention on Climate Change, the United States committed to reduce economy wide emissions by 26 percent to 28 percent below 2005 emission levels. This multinational agreement became open for signing on April 22, 2016 and will require countries to review and "represent a progression" every five years beginning in 2020. Thewith different terms. A new agreement couldmay result in future additional emissions reductions in the United States,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 under the December 2015 Paris Agreement will be implemented through the Clean Air Act or any other than existing statutes and new legislation.
If legislation or regulations are passed at the Federalfederal or state levels in the future requiring mandatory reductions of CO2 and other greenhouse gases on OG&E's facilities, this could result in significant additional compliance costs that would affect OG&E's future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Several states outside the area where OG&E operates have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.
On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO2 emissions from existing fossil-fuel-fired power plants along with state-specific CO2 reduction standards expressed as both rate-based (lbs/(lbs./MWh) and mass-based (tons/yr)yr.) goals. The 2030 rate-based reduction requirement for all existing generating unitsHowever, the rule was challenged in
Oklahoma has decreased from a proposed 43 percent reduction to 32 percent in the final rule. The mass-based approach for existing units calls for a 24 percent reduction by 2030 in Oklahoma.
A number of states, including Oklahoma, filed lawsuits against the Clean Power Plan. On February 9, 2016, court when it was issued, and the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan on February 9, 2016 pending resolution of challengesthe court challenges. The EPA published a proposal on October 16, 2017 to repeal the rule. OG&E is unable to determine what impactClean Power Plan. On August 31, 2018, without acting on the lawsuits will ultimately have onproposed repeal of the Clean Power Plan, or what impact the stay in implementation will have; however, ifEPA published the Affordable Clean Energy Rule, a proposed rule to replace the Clean Power Plan survives judicial reviewPlan. The ultimate timing and is implemented as written, itimpact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect ourOG&E's future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of these standards on our operations cannot be determined with certainty at this time.
Nonetheless, OG&E’s&E's current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in Note 14 in "Item 8. Financial Statements and Supplementary Data" under "Pending Regulatory Matters," OG&E has filed an application with the OCC for approval of its&E's plan to comply with the EPA’sEPA's MATS rule and Regional Haze Rule FIP byincludes converting two coal-fired generating units at the Muskogee Station to natural gas, among other measures. OG&E’s&E's deployment of Smart Grid technology helps to reduce the peak load demand. OG&E is also seeks to utilizedeploying more renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas.areas, and OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource areaareas in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.
EPA Startup, Shutdown and Malfunction Policy
On May 22, 2015, the EPA issued a final rule to address the outdated provisions in the SIPSIPs of 36 states including Oklahoma,(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 PolicyPolicy. Although judicial challenges to assure consistency with the Clean Air Act and other recent court decisions. The ODEQrule 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. Although the extent of impact is not known, thisThis rule will impacthas resulted in permit modifications for certain OG&E units. OG&E does not anticipate capital expenditures or a material impact to its financial position, results of operations or cash flows, as a result of adoption of this rule.
Air Quality Control System
The Dry Scrubber system on Sooner Unit 1 completed certain emission testing in October 2018 and was placed into service. The Dry Scrubber system on Sooner Unit 2 completed certain emission testing in January 2019 and was placed into service. More detail regarding the ECP can be found under "Pending Regulatory Matters" in Note 14 in "Item 8. Financial Statements and Supplementary Data."
Endangered Species
Certain Federalfederal 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 OG&E conducts operations, or if additional species in those areas become subject to protection, OG&E’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or OG&E could be required to implement expensive mitigation measures.
In 2014, OG&E enrolled in the Western Association of Fish and Wildlife Agencies range-wide conservation plan which consists of industry-specific conservation practices that apply to projects and activities in the impacted area. The range-wide conservation plan was approved by the U.S. Fish and Wildlife Service and incorporated as part of the agency’s final decision on March 27, 2014 to list the lesser prairie chicken as a threatened species. On September 1, 2015, the U.S. District Court Western District of Texas vacated federal protections for the lesser prairie chicken based on the U.S. Fish and Wildlife Service's failure to thoroughly consider the active conservation efforts in making the listing decision. On July 19, 2016, the U.S. Fish and Wildlife Service issued a final rule to amend its regulations to remove the lesser prairie chicken from the list of threatened species under the Endangered Species Act. On September 8, 2016, WildEarth Guardians, Defenders of Wildlife and the Center for Biological Diversity filed a petition with the U.S. Fish and Wildlife Services to list the lesser prairie chicken as "endangered" under the Endangered Species Act. On November 30, 2016, the U.S. Fish and Wildlife Services published a notice in the Federal Register announcing its finding that the September 2016 petition presents information indicating that listing of the lesser prairie-chicken may be warranted. The agency has initiated a 12-month status review. OG&E will continue to monitor the progress of the petition.
Air Quality Control System
On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015, to install the
Dry Scrubber systems. The Dry Scrubbers are scheduled to be completed by 2019. More detail regarding the ECP can be found under the "Pending Regulatory Matters" section of "Notes to Financial Statements" of Part II, Item 8 of this Form 10-K.
Waste
OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.
On December 19, 2014,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 final rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. The final rule is currently being appealedRecent litigation decisions at the D.C. Circuit Court of Appeals.Appeals indicate that the EPA will be required to revise certain aspects of this rule. OG&E manages one regulated inactive coal ash impoundment that is expected to be clean-closed in 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 lieu of the federal coal ash program promulgated under the Federal Resource Conservation and Recovery Act. The EPA approval of the State of Oklahoma permitting program is currently under litigation. OG&E 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.
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 20162018, OG&E obtained refunds of $1.9 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.
Water
OG&E's operations are subject to the Federal Clean Water Act and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federalfederal 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 submitted compliance plans todid not incur any material costs associated with the state in April 2015.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 the permits from the state.State of Oklahoma.
On September 30,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 occurs between 2018 and 2023.will occur by 2023; however, on April 12, 2017, the EPA granted a Petition for Reconsideration of the 2015 Rule. OG&E is evaluating what, if any, compliance actions are needed but is not able to quantify with any certainty what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the state.State of Oklahoma.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generategenerates wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.
For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12.13 in "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. OG&E's exposure to
changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. OG&E is exposed to commodity prices in its operations.
Risk Oversight Committee
Management monitors market risks using a risk committee structure. OG&E's Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and
policies for all market risk management activities of OG&E. This committee's emphasis is a holistic perspective of risk measurement and policies targeting OG&E's overall financial performance. On a quarterly basis, the Risk Oversight Committee reports to the Audit Committee of OGE Energy's Board of Directors on OGE Energy's risk profile affecting anticipated financial results, including any significant risk issues.
OG&E also has a Corporate Risk Management Department. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing OG&E's risk policies.
Risk Policies
Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of OGE Energy's Board of Directors and senior executives of OG&E with confidence that the risks taken on by OG&E's 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.
Interest Rate Risk
OG&E's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. OG&E manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. OG&E 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 OG&E has no intent at this time to utilize interest rate derivativesderivatives.
The fair value of OG&E's 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 OG&E's current borrowing rate. The following table shows OG&E's long-term debt maturities and the weighted-average interest rates by maturity date.
| | Year ended December 31 (Dollars in millions) | 2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total | 12/31/16 Fair Value | |
| Fixed-rate debt (A) | | |
Year Ended December 31 (Dollars in millions) | | 2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | Total | 12/31/18 Fair Value |
| Fixed-rate debt (A): | | |
| Principal amount | $ | 125.2 |
| $ | 250.1 |
| $ | 250.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 1,794.3 |
| $ | 2,419.9 |
| $ | 2,668.5 |
| $ | 250.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 2,794.1 |
| $ | 3,044.6 |
| $ | 3,186.9 |
|
| Weighted-average interest rate | 6.50 | % | 6.35 | % | 8.25 | % | 3.01 | % | 3.01 | % | 5.19 | % | 5.70 | % | | 8.25 | % | 4.48 | % | 4.48 | % | 4.48 | % | 4.48 | % | 4.74 | % | 5.03 | % | |
| Variable-rate debt (B) | | |
| Variable-rate debt (B): | | |
| Principal amount | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 135.4 |
| $ | 135.4 |
| $ | 135.4 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 135.4 |
| $ | 135.4 |
| $ | 135.4 |
|
| Weighted-average interest rate | — | % | — | % | — | % | — | % | — | % | 0.76 | % | 0.76 | % | | — | % | — | % | — | % | — | % | — | % | 1.79 | % | 1.79 | % | |
| |
| (A) | Prior to or when these debt obligations mature, OG&E 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 OG&E would change interest expense by $1.4 million annually. |
Item 8. Financial Statements and Supplementary Data.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
|
| | | | | | | | | |
Year ended December 31 (In millions) | 2016 | 2015 | 2014 |
| OPERATING REVENUES | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
| COST OF SALES | 880.1 |
| 865.0 |
| 1,106.6 |
|
| OPERATING EXPENSES | | |
|
| Other operation and maintenance | 469.8 |
| 444.5 |
| 453.2 |
|
| Depreciation and amortization | 316.4 |
| 299.9 |
| 270.8 |
|
| Taxes other than income | 84.0 |
| 87.1 |
| 84.5 |
|
| Total operating expenses | 870.2 |
| 831.5 |
| 808.5 |
|
| OPERATING INCOME | 508.9 |
| 500.4 |
| 538.0 |
|
| OTHER INCOME (EXPENSE) | | |
|
| Allowance for equity funds used during construction | 14.2 |
| 8.3 |
| 4.2 |
|
| Other income | 16.4 |
| 13.3 |
| 4.8 |
|
| Other expense | (2.9 | ) | (1.6 | ) | (1.9 | ) |
| Net other income | 27.7 |
| 20.0 |
| 7.1 |
|
| INTEREST EXPENSE | | |
|
| Interest on long-term debt | 141.7 |
| 146.8 |
| 139.7 |
|
| Allowance for borrowed funds used during construction | (7.5 | ) | (4.2 | ) | (2.4 | ) |
| Interest on short-term debt and other interest charges | 3.9 |
| 4.1 |
| 4.2 |
|
| Interest expense | 138.1 |
| 146.7 |
| 141.5 |
|
| INCOME BEFORE TAXES | 398.5 |
| 373.7 |
| 403.6 |
|
| INCOME TAX EXPENSE | 114.4 |
| 104.8 |
| 111.6 |
|
| NET INCOME | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
|
| COMPREHENSIVE INCOME | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
|
| | | | | | | | | |
Year Ended December 31 (In millions) | 2018 | 2017 | 2016 |
| OPERATING REVENUES | | | |
| Revenues from contracts with customers | $ | 2,211.7 |
| $ | — |
| $ | — |
|
| Other revenues | 58.6 |
| — |
| — |
|
| Operating revenues | 2,270.3 |
| 2,261.1 |
| 2,259.2 |
|
| COST OF SALES | 892.5 |
| 897.6 |
| 880.1 |
|
| OPERATING EXPENSES | | |
|
| Other operation and maintenance | 473.8 |
| 469.8 |
| 451.2 |
|
| Depreciation and amortization | 321.6 |
| 280.9 |
| 316.4 |
|
| Taxes other than income | 88.2 |
| 84.8 |
| 84.0 |
|
| Operating expenses | 883.6 |
| 835.5 |
| 851.6 |
|
| OPERATING INCOME | 494.2 |
| 528.0 |
| 527.5 |
|
| OTHER INCOME (EXPENSE) | | |
|
| Allowance for equity funds used during construction | 23.8 |
| 39.7 |
| 14.2 |
|
| Other net periodic benefit expense | (8.9 | ) | (16.3 | ) | (18.6 | ) |
| Other income | 14.1 |
| 36.6 |
| 16.4 |
|
| Other expense | (3.4 | ) | (2.3 | ) | (2.9 | ) |
| Net other income | 25.6 |
| 57.7 |
| 9.1 |
|
| INTEREST EXPENSE | | |
|
| Interest on long-term debt | 157.4 |
| 151.9 |
| 141.7 |
|
| Allowance for borrowed funds used during construction | (11.7 | ) | (18.0 | ) | (7.5 | ) |
| Interest on short-term debt and other interest charges | 6.1 |
| 4.5 |
| 3.9 |
|
| Interest expense | 151.8 |
| 138.4 |
| 138.1 |
|
| INCOME BEFORE TAXES | 368.0 |
| 447.3 |
| 398.5 |
|
| INCOME TAX EXPENSE | 40.0 |
| 141.8 |
| 114.4 |
|
| NET INCOME | 328.0 |
| 305.5 |
| 284.1 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
|
| COMPREHENSIVE INCOME | $ | 328.0 |
| $ | 305.5 |
| $ | 284.1 |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
| | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | |
| | |
|
| Net income | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
| $ | 328.0 |
| $ | 305.5 |
| $ | 284.1 |
|
| Adjustments to reconcile net income to net cash provided from operating activities | | |
| |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | |
|
| Depreciation and amortization | 316.4 |
| 299.9 |
| 270.8 |
| 321.6 |
| 280.9 |
| 316.4 |
|
| Deferred income taxes and investment tax credits | 116.8 |
| 127.6 |
| 161.4 |
| |
| Deferred income taxes and investment tax credits, net | | 56.6 |
| 119.8 |
| 116.8 |
|
| Allowance for equity funds used during construction | (14.2 | ) | (8.3 | ) | (4.2 | ) | (23.8 | ) | (39.7 | ) | (14.2 | ) |
| Stock-based compensation expense | 2.3 |
| 2.6 |
| 2.9 |
| 4.6 |
| 3.1 |
| 2.3 |
|
| Regulatory assets | (21.4 | ) | (9.1 | ) | 4.6 |
| (10.8 | ) | 3.7 |
| (21.4 | ) |
| Regulatory liabilities | (11.8 | ) | (27.5 | ) | (4.4 | ) | (16.5 | ) | (3.7 | ) | (11.8 | ) |
| Other assets | 13.7 |
| 10.1 |
| (1.2 | ) | 1.9 |
| 1.6 |
| 13.7 |
|
| Other liabilities | (20.1 | ) | 22.2 |
| 14.0 |
| — |
| (59.9 | ) | (20.1 | ) |
| Change in certain current assets and liabilities | | |
| |
| Accounts receivable, net | 0.1 |
| 15.7 |
| (9.4 | ) | |
| Accrued unbilled revenues | (6.2 | ) | 2.0 |
| 3.2 |
| |
| Change in certain current assets and liabilities: | | | |
|
| Accounts receivable and accrued unbilled revenues, net | | 19.5 |
| (22.2 | ) | (6.1 | ) |
| Fuel, materials and supplies inventories | 32.5 |
| (56.2 | ) | 20.1 |
| 27.3 |
| (5.0 | ) | 32.5 |
|
| Fuel clause under recoveries | (51.3 | ) | 68.3 |
| (42.1 | ) | |
| Fuel recoveries | | (3.4 | ) | 53.0 |
| (112.6 | ) |
| Other current assets | (26.7 | ) | (16.0 | ) | (2.6 | ) | 23.1 |
| 29.7 |
| (26.7 | ) |
| Accounts payable | (27.7 | ) | 20.4 |
| (66.4 | ) | 19.0 |
| 22.5 |
| (29.8 | ) |
| Accounts payable - affiliates | (2.1 | ) | 1.9 |
| (1.5 | ) | |
| Income taxes payable - parent | (3.1 | ) | (16.7 | ) | (50.2 | ) | (15.6 | ) | 92.0 |
| (3.1 | ) |
| Fuel clause over recoveries | (61.3 | ) | 61.3 |
| (0.4 | ) | |
| Other current liabilities | 52.9 |
| 3.4 |
| 1.1 |
| 72.5 |
| (65.6 | ) | 52.9 |
|
| Net Cash Provided from Operating Activities | 572.9 |
| 770.5 |
| 587.7 |
| |
| Net cash provided from operating activities | | 804.0 |
| 715.7 |
| 572.9 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | |
| | |
|
| Capital expenditures (less allowance for equity funds used during construction) | (660.1 | ) | (551.6 | ) | (565.4 | ) | (573.6 | ) | (824.1 | ) | (660.1 | ) |
| Proceeds from sale of assets | 0.9 |
| 2.6 |
| 0.7 |
| 0.1 |
| 0.7 |
| 0.9 |
|
| Net Cash Used in Investing Activities | (659.2 | ) | (549.0 | ) | (564.7 | ) | |
| Net cash used in investing activities | | (573.5 | ) | (823.4 | ) | (659.2 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | |
| | |
|
| Dividends paid on common stock | | (185.0 | ) | (170.0 | ) | (155.0 | ) |
| Proceeds from long-term debt | — |
| — |
| 489.6 |
| 396.0 |
| 592.1 |
| — |
|
| Dividends paid on common stock | (155.0 | ) | (120.0 | ) | (140.0 | ) | |
| Payment of long-term debt | | (250.1 | ) | (125.1 | ) | (110.2 | ) |
| Changes in advances with parent | 351.5 |
| (101.3 | ) | (232.4 | ) | (191.4 | ) | (189.3 | ) | 351.5 |
|
| Payment of long-term debt | (110.2 | ) | (0.2 | ) | (140.2 | ) | |
| Net Cash Provided from (Used in) Financing Activities | 86.3 |
| (221.5 | ) | (23.0 | ) | |
| Net cash (used in) provided from financing activities | | (230.5 | ) | 107.7 |
| 86.3 |
|
| NET CHANGE IN CASH AND CASH EQUIVALENTS | — |
| — |
| — |
| — |
| — |
| — |
|
| CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | — |
| — |
| — |
| — |
| — |
| — |
|
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
| | December 31 (In millions) | 2016 | 2015 | 2018 | 2017 |
| ASSETS | | |
| CURRENT ASSETS | | |
| Accounts receivable, less reserve of $1.5 and $1.4, respectively | $ | 173.0 |
| $ | 173.1 |
| |
| Accounts receivable, less reserve of $1.7 and $1.5, respectively | | $ | 172.9 |
| $ | 188.5 |
|
| Accrued unbilled revenues | 59.7 |
| 53.5 |
| 62.6 |
| 66.5 |
|
| Advances to parent | — |
| 333.6 |
| 319.5 |
| 112.5 |
|
| Fuel inventories | 79.8 |
| 113.8 |
| 57.6 |
| 84.3 |
|
| Materials and supplies, at average cost | 80.3 |
| 78.8 |
| 126.7 |
| 80.8 |
|
| Fuel clause under recoveries | 51.3 |
| — |
| 2.0 |
| — |
|
| Other | 78.3 |
| 51.6 |
| 25.5 |
| 48.6 |
|
| Total current assets | 522.4 |
| 804.4 |
| 766.8 |
| 581.2 |
|
| OTHER PROPERTY AND INVESTMENTS | 6.6 |
| 5.6 |
| 5.0 |
| 5.9 |
|
| PROPERTY, PLANT AND EQUIPMENT | | |
| In service | 10,572.3 |
| 10,179.3 |
| 11,988.7 |
| 11,035.1 |
|
| Construction work in progress | 495.1 |
| 278.5 |
| 376.4 |
| 867.5 |
|
| Total property, plant and equipment | 11,067.4 |
| 10,457.8 |
| 12,365.1 |
| 11,902.6 |
|
| Less accumulated depreciation | 3,385.6 |
| 3,161.7 |
| 3,727.4 |
| 3,568.8 |
|
| Net property, plant and equipment | 7,681.8 |
| 7,296.1 |
| 8,637.7 |
| 8,333.8 |
|
| DEFERRED CHARGES AND OTHER ASSETS | | |
| Regulatory assets | 404.8 |
| 402.2 |
| 285.8 |
| 283.0 |
|
| Other | 53.8 |
| 17.2 |
| 9.2 |
| 51.7 |
|
| Total deferred charges and other assets | 458.6 |
| 419.4 |
| 295.0 |
| 334.7 |
|
| TOTAL ASSETS | $ | 8,669.4 |
| $ | 8,525.5 |
| $ | 9,704.5 |
| $ | 9,255.6 |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
| | December 31 (In millions) | 2016 | 2015 | 2018 | 2017 |
| LIABILITIES AND STOCKHOLDER'S EQUITY | | |
| CURRENT LIABILITIES | | |
| Accounts payable - affiliates | $ | 0.1 |
| $ | 2.2 |
| |
| Accounts payable - other | 196.3 |
| 236.0 |
| |
| Advances from parent | 49.9 |
| — |
| |
| Accounts payable | | $ | 215.0 |
| $ | 216.8 |
|
| Customer deposits | 77.7 |
| 77.0 |
| 83.6 |
| 80.7 |
|
| Accrued taxes | 40.8 |
| 45.7 |
| 44.0 |
| 41.5 |
|
| Accrued interest | 40.2 |
| 42.8 |
| 44.5 |
| 44.0 |
|
| Accrued compensation | 31.3 |
| 23.8 |
| 33.8 |
| 25.6 |
|
| Long-term debt due within one year | 125.0 |
| 110.0 |
| 250.0 |
| 249.8 |
|
| Fuel clause over recoveries | — |
| 61.3 |
| 0.3 |
| 1.7 |
|
| Other | 95.8 |
| 43.6 |
| 86.8 |
| 28.5 |
|
| Total current liabilities | 657.1 |
| 642.4 |
| 758.0 |
| 688.6 |
|
| LONG-TERM DEBT | 2,405.8 |
| 2,529.3 |
| 2,896.9 |
| 2,749.6 |
|
| DEFERRED CREDITS AND OTHER LIABILITIES | | |
| Accrued benefit obligations | 167.7 |
| 179.9 |
| 137.9 |
| 110.3 |
|
| Deferred income taxes | 1,752.3 |
| 1,637.8 |
| 892.7 |
| 832.2 |
|
| Regulatory liabilities | 299.7 |
| 273.6 |
| 1,270.7 |
| 1,283.4 |
|
| Other | 134.7 |
| 106.8 |
| 145.0 |
| 135.8 |
|
| Total deferred credits and other liabilities | 2,354.4 |
| 2,198.1 |
| 2,446.3 |
| 2,361.7 |
|
| Total liabilities | 5,417.3 |
| 5,369.8 |
| 6,101.2 |
| 5,799.9 |
|
| COMMITMENTS AND CONTINGENCIES (NOTE 12) |
|
|
|
| |
| COMMITMENTS AND CONTINGENCIES (NOTE 13) | |
|
|
|
|
| STOCKHOLDER'S EQUITY | | |
| Common stockholder's equity | 1,024.1 |
| 1,021.8 |
| 1,031.8 |
| 1,027.2 |
|
| Retained earnings | 2,228.0 |
| 2,133.9 |
| 2,571.5 |
| 2,428.5 |
|
| Total stockholder's equity | 3,252.1 |
| 3,155.7 |
| 3,603.3 |
| 3,455.7 |
|
| TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | $ | 8,669.4 |
| $ | 8,525.5 |
| $ | 9,704.5 |
| $ | 9,255.6 |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
| | December 31 (In millions) | 2016 | 2015 | |
December 31 (In millions except per share data) | | December 31 (In millions except per share data) | 2018 | 2017 |
| STOCKHOLDER'S EQUITY | STOCKHOLDER'S EQUITY | | 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 | 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 |
| 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 | Premium on common stock | 923.2 |
| 920.9 |
| Premium on common stock | 930.9 |
| 926.3 |
|
| Retained earnings | Retained earnings | 2,228.0 |
| 2,133.9 |
| Retained earnings | 2,571.5 |
| 2,428.5 |
|
| Total stockholder's equity | Total stockholder's equity | 3,252.1 |
| 3,155.7 |
| Total stockholder's equity | 3,603.3 |
| 3,455.7 |
|
| | | | | |
| LONG-TERM DEBT | | | | |
| SERIES | DUE DATE | | DUE DATE | |
| Senior Notes | | | | |
| 5.15% | Senior Notes, Series Due January 15, 2016 | — |
| 110.0 |
| |
| 6.50% | Senior Notes, Series Due July 15, 2017 | 125.0 |
| 125.0 |
| |
| 6.35% | Senior Notes, Series Due September 1, 2018 | 250.0 |
| 250.0 |
| Senior Notes, Series Due September 1, 2018 | — |
| 250.0 |
|
| 8.25% | Senior Notes, Series Due January 15, 2019 | 250.0 |
| 250.0 |
| Senior Notes, Series Due January 15, 2019 | 250.0 |
| 250.0 |
|
| 6.65% | Senior Notes, Series Due July 15, 2027 | 125.0 |
| 125.0 |
| Senior Notes, Series Due July 15, 2027 | 125.0 |
| 125.0 |
|
| 6.50% | Senior Notes, Series Due April 15, 2028 | 100.0 |
| 100.0 |
| Senior Notes, Series Due April 15, 2028 | 100.0 |
| 100.0 |
|
| 3.80% | | Senior Notes, Series Due August 15, 2028 | 400.0 |
| — |
|
| 5.75% | Senior Notes, Series Due January 15, 2036 | 110.0 |
| 110.0 |
| Senior Notes, Series Due January 15, 2036 | 110.0 |
| 110.0 |
|
| 6.45% | Senior Notes, Series Due February 1, 2038 | 200.0 |
| 200.0 |
| Senior Notes, Series Due February 1, 2038 | 200.0 |
| 200.0 |
|
| 5.85% | Senior Notes, Series Due June 1, 2040 | 250.0 |
| 250.0 |
| Senior Notes, Series Due June 1, 2040 | 250.0 |
| 250.0 |
|
| 5.25% | Senior Notes, Series Due May 15, 2041 | 250.0 |
| 250.0 |
| Senior Notes, Series Due May 15, 2041 | 250.0 |
| 250.0 |
|
| 3.90% | Senior Notes, Series Due May 1, 2043 | 250.0 |
| 250.0 |
| Senior Notes, Series Due May 1, 2043 | 250.0 |
| 250.0 |
|
| 4.55% | Senior Notes, Series Due March 15, 2044 | 250.0 |
| 250.0 |
| Senior Notes, Series Due March 15, 2044 | 250.0 |
| 250.0 |
|
| 4.00% | Senior Notes, Series Due December 15, 2044 | 250.0 |
| 250.0 |
| Senior Notes, Series Due December 15, 2044 | 250.0 |
| 250.0 |
|
| 3.70% | Tinker Debt, Due August 31, 2062 | 9.9 |
| 10.0 |
| |
| 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 | 9.6 |
| 9.7 |
|
| | | | | |
| Other Bonds | | | | |
| 0.05% - 0.90% | Garfield Industrial Authority, January 1, 2025 | 47.0 |
| 47.0 |
| |
| 0.07% - 0.83% | Muskogee Industrial Authority, January 1, 2025 | 32.4 |
| 32.4 |
| |
| 0.05% - 0.86% | Muskogee Industrial Authority, June 1, 2027 | 56.0 |
| 56.0 |
| |
| | | | |
| 1.01% - 2.00% | | Garfield Industrial Authority, January 1, 2025 | 47.0 |
| 47.0 |
|
| 1.01% - 1.83% | | Muskogee Industrial Authority, January 1, 2025 | 32.4 |
| 32.4 |
|
| 1.03% - 1.86% | | Muskogee Industrial Authority, June 1, 2027 | 56.0 |
| 56.0 |
|
| Unamortized debt expense | Unamortized debt expense | (15.2 | ) | (16.3 | ) | Unamortized debt expense | (22.9 | ) | (20.8 | ) |
| Unamortized discount | Unamortized discount | (9.3 | ) | (9.8 | ) | Unamortized discount | (10.2 | ) | (9.9 | ) |
| Total long-term debt | Total long-term debt | 2,530.8 |
| 2,639.3 |
| Total long-term debt | 3,146.9 |
| 2,999.4 |
|
| Less long-term debt due within one year | (125.0 | ) | (110.0 | ) | |
| Total long-term debt (excluding debt due within one year) | 2,405.8 |
| 2,529.3 |
| |
| Total Capitalization (including long-term debt due within one year) | $ | 5,782.9 |
| $ | 5,795.0 |
| |
| Less: long-term debt due within one year | | Less: long-term debt due within one year | (250.0 | ) | (249.8 | ) |
| Total long-term debt (excluding long-term debt due within one year) | | Total long-term debt (excluding long-term debt due within one year) | 2,896.9 |
| 2,749.6 |
|
| Total capitalization (including long-term debt due within one year) | | Total capitalization (including long-term debt due within one year) | $ | 6,750.2 |
| $ | 6,455.1 |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
| | | (In millions) | Common Stock | Premium on Common Stock | Retained Earnings | Total | Shares Outstanding | Common Stock | Premium on Common Stock | Retained Earnings | Total |
| Balance at December 31, 2013 | $ | 100.9 |
| $ | 915.4 |
| $ | 1,813.0 |
| $ | 2,829.3 |
| |
| Net income | — |
| — |
| 292.0 |
| 292.0 |
| |
| Dividends declared on common stock | — |
| — |
| (120.0 | ) | (120.0 | ) | |
| Stock-based compensation | — |
| 2.9 |
| — |
| 2.9 |
| |
| Balance at December 31, 2014 | $ | 100.9 |
| $ | 918.3 |
| $ | 1,985.0 |
| $ | 3,004.2 |
| |
| Net income | — |
| — |
| 268.9 |
| 268.9 |
| |
| Dividends declared on common stock | — |
| — |
| (120.0 | ) | (120.0 | ) | |
| Stock-based compensation | — |
| 2.6 |
| — |
| 2.6 |
| |
| Balance at December 31, 2015 | $ | 100.9 |
| $ | 920.9 |
| $ | 2,133.9 |
| $ | 3,155.7 |
| 40.4 |
| $ | 100.9 |
| $ | 920.9 |
| $ | 2,133.9 |
| $ | 3,155.7 |
|
| Net income | — |
| — |
| 284.1 |
| 284.1 |
| — |
| — |
| — |
| 284.1 |
| 284.1 |
|
| Dividends declared on common stock | — |
| — |
| (190.0 | ) | (190.0 | ) | — |
| — |
| — |
| (190.0 | ) | (190.0 | ) |
| Stock-based compensation | — |
| 2.3 |
| — |
| 2.3 |
| — |
| — |
| 2.3 |
| — |
| 2.3 |
|
| Balance at December 31, 2016 | $ | 100.9 |
| $ | 923.2 |
| $ | 2,228.0 |
| $ | 3,252.1 |
| 40.4 |
| $ | 100.9 |
| $ | 923.2 |
| $ | 2,228.0 |
| $ | 3,252.1 |
|
| Net income | | — |
| — |
| — |
| 305.5 |
| 305.5 |
|
| Dividends declared on common stock | | — |
| — |
| — |
| (105.0 | ) | (105.0 | ) |
| Stock-based compensation | | — |
| — |
| 3.1 |
| — |
| 3.1 |
|
| Balance at December 31, 2017 | | 40.4 |
| $ | 100.9 |
| $ | 926.3 |
| $ | 2,428.5 |
| $ | 3,455.7 |
|
| Net income | | — |
| — |
| — |
| 328.0 |
| 328.0 |
|
| Dividends declared on common stock | | — |
| — |
| — |
| (185.0 | ) | (185.0 | ) |
| Stock-based compensation | | — |
| — |
| 4.6 |
| — |
| 4.6 |
|
| Balance at December 31, 2018 | | 40.4 |
| $ | 100.9 |
| $ | 930.9 |
| $ | 2,571.5 |
| $ | 3,603.3 |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
| |
| 1. | Summary of Significant Accounting Policies |
Organization
OG&Egenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, ana holding company with investments in energy and energy services providerproviders offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.U.S.
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 is a summary of OG&E's regulatory assets and liabilities at:liabilities:
| | December 31 (In millions) | 2016 | 2015 | 2018 | 2017 |
| Regulatory Assets | | |
| Current | | |
| REGULATORY ASSETS | | |
| Current: | | |
| Production tax credit rider under recovery (A) | | $ | 6.9 |
| $ | — |
|
| Oklahoma demand program rider under recovery (A) | | 6.4 |
| 31.6 |
|
| Fuel clause under recoveries | $ | 51.3 |
| $ | — |
| 2.0 |
| — |
|
| Oklahoma demand program rider under recovery (A) | 51.0 |
| 36.6 |
| |
| SPP cost tracker under recovery (A) | 10.0 |
| 4.5 |
| — |
| 7.7 |
|
| Other (A) | 9.5 |
| 5.4 |
| 3.2 |
| 1.5 |
|
| Total Current Regulatory Assets | $ | 121.8 |
| $ | 46.5 |
| |
| Non-Current | | |
| Total current regulatory assets | | $ | 18.5 |
| $ | 40.8 |
|
| Non-current: | | |
| Benefit obligations regulatory asset | $ | 232.6 |
| $ | 242.2 |
| $ | 188.2 |
| $ | 177.2 |
|
| Income taxes recoverable from customers, net | 62.3 |
| 56.7 |
| |
| Deferred storm expenses | | 36.5 |
| 42.2 |
|
| Smart Grid | 43.2 |
| 43.6 |
| 25.6 |
| 32.8 |
|
| Deferred storm expenses | 35.7 |
| 27.6 |
| |
| Unamortized loss on reacquired debt | 13.4 |
| 14.8 |
| 11.4 |
| 12.3 |
|
| Arkansas deferred pension expenses | | 6.8 |
| 5.1 |
|
| Sooner Dry Scrubbers | | 4.5 |
| — |
|
| Other | 17.6 |
| 17.3 |
| 12.8 |
| 13.4 |
|
| Total Non-Current Regulatory Assets | $ | 404.8 |
| $ | 402.2 |
| |
| Regulatory Liabilities | | |
| Current | | |
| Total non-current regulatory assets | | $ | 285.8 |
| $ | 283.0 |
|
| REGULATORY LIABILITIES | | |
| Current: | | |
| SPP cost tracker over recovery (B) | | $ | 16.8 |
| $ | — |
|
| Reserve for tax refund (B) | | 15.4 |
| — |
|
| Transmission cost recovery rider over recovery (B) | | 2.7 |
| 0.2 |
|
| Fuel clause over recoveries | $ | — |
| $ | 61.3 |
| 0.3 |
| 1.7 |
|
| Other (B) | 12.3 |
| 7.5 |
| |
| Total Current Regulatory Liabilities | $ | 12.3 |
| $ | 68.8 |
| |
| Non-Current | | |
Other (C)(B) | | 1.4 |
| 2.0 |
|
| Total current regulatory liabilities | | $ | 36.6 |
| $ | 3.9 |
|
| Non-current: | | |
| Income taxes refundable to customers, net | | $ | 937.1 |
| $ | 955.5 |
|
| Accrued removal obligations, net | $ | 262.8 |
| $ | 254.9 |
| 308.1 |
| 288.4 |
|
| Pension tracker | 35.5 |
| 17.7 |
| 18.7 |
| 32.3 |
|
Other (C)(B) | 1.4 |
| 1.0 |
| |
| Total Non-Current Regulatory Liabilities | $ | 299.7 |
| $ | 273.6 |
| |
| Other | | 6.8 |
| 7.2 |
|
| Total non-current regulatory liabilities | | $ | 1,270.7 |
| $ | 1,283.4 |
|
| |
| (A) | Included in Other Current Assets on the Balance Sheets. |
| |
| (B) | Included in Other Current Liabilities on the Balance Sheets. |
| |
(C) | Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities. |
As discussed in Note 14 under "Oklahoma Rate Review Filing - January 2018," as a result of the settlement agreement reached in the most recent Oklahoma rate review, OG&E removed production tax credits from base rates and now utilizes a separate rider to credit customers for production tax credits, which can either result in a regulatory asset or regulatory liability based on the differential between estimated and actual production tax credits included in the rider.
OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand Program Rider, which operates on a three year program cycle. The most recently concluded cycle allowed for recovery through December 2018 of energy efficiency program costs as well as associated lost revenues for achieved energy efficiency and demand savings and performance-based incentives. As discussed in Note 14 under "Demand Program Portfolio Filing," in December 2018, the OCC approved OG&E's 2019 through 2021 program cycle demand portfolio programs, which includes (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.
Fuel clause under recoveries are generated from under recoveries from OG&E's customers when OG&E's cost of fuel either exceeds or is less than the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E's customers when the amount billed to its customers exceeds OG&E's cost of fuel. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.
OG&E recovers program costs related to the Demand and Energy Efficiency Program. An extension of the demand program rider was approved in January 2016, which allows for the recovery through December 2018 of (i) demand program costs; (ii) lost revenues associated with certain achieved energy efficiency and demand savings; (iii) performance-based incentives; and (iv) costs associated with research and development investments.
OG&E recovers certain SPP costs related to base plan charges from its customers in Oklahoma through the SPP cost tracker.
The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost.These expenses are recorded as a regulatory asset as OG&E had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to accumulated other comprehensive income.
The following table is a summary of the components of the benefit obligations regulatory asset at:asset:
| | December 31 (In millions) | 2016 | 2015 | 2018 | 2017 |
| Pension Plan and Restoration of Retirement Income Plan | | |
| Pension Plan and Restoration of Retirement Income Plan: | | |
| Net loss | $ | 199.9 |
| $ | 214.1 |
| $ | 185.3 |
| $ | 172.4 |
|
| Postretirement Benefit Plans | | | |
| Postretirement Benefit Plans: | | | |
| Net loss | 32.7 |
| 34.2 |
| 25.6 |
| 33.6 |
|
| Prior service cost | — |
| (6.1 | ) | (22.7 | ) | (28.8 | ) |
| Total | $ | 232.6 |
| $ | 242.2 |
| $ | 188.2 |
| $ | 177.2 |
|
The following amounts in the benefit obligations regulatory asset at December 31, 20162018 are expected to be recognized as components of net periodic benefit cost in 20172019:
|
| | | |
| (In millions) | |
| Pension Plan and Restoration of Retirement Income Plan | |
| Net loss | $ | 12.4 |
|
| Postretirement Benefit Plans | |
| Net loss | 2.3 |
|
| Total | $ | 14.7 |
|
Income taxes recoverable from customers, which represents income tax benefits previously used to reduce OG&E's revenues, are treated as regulatory assets and are being amortized over the estimated remaining life of the assets to which they relate. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The income tax related regulatory assets and liabilities are netted in income taxes recoverable from customers, net in the regulatory assets and liabilities table above.
OG&E recovers the cost of system-wide deployment of smart grid technology and implementing the smart grid pilot program, the incremental costs for web portal access, education and providing home energy reports. These amounts are currently being recovered through a rate rider. Following a final order in the current Oklahoma general rate case, and review by the OCC Staff, the Oklahoma jurisdictional balance of the regulatory asset will be included in the fuel adjustment clause for final recovery. Costs not included in the rider are the incremental costs for web portal access, education and home energy reports, which are capped at $6.9 million, and the stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters and were accumulated during the smart grid deployment and have been included in the Smart Grid asset in the regulatory assets and liabilities table above. These costs are expected to be recovered in base rates upon final orders in the current general rate cases. |
| | | |
| (In millions) | |
| Pension Plan and Restoration of Retirement Income Plan: | |
| Net loss | $ | 13.8 |
|
| Postretirement Benefit Plans: | |
| Net loss | 2.7 |
|
| Prior service cost | (6.1 | ) |
| Total | $ | 10.4 |
|
OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to$2.7 $2.7 million annually and defers to a regulatory asset any additional expenses incurred over $2.7 million. OG&E expects to recover the amounts deferred each year over afive-year period in accordance with historical practice.
OG&E deferred to a regulatory asset the incremental 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. These costs have been included in the Smart Grid asset in the table above, and as approved in recent rate reviews in Oklahoma and Arkansas, these costs are now being recovered over a six year period.
Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expensesexpense 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.
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 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 now being recovered in current rates, and additional amounts will be requested as additional settlements occur. For additional information related to settlements, see Note 12.
As discussed in Note 14 under "Oklahoma Rate Review Filing - January 2018," as the result of a settlement agreement reached in the most recent Oklahoma rate review, OG&E began deferring 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. Recovery of these costs was requested in OG&E's December 2018 rate review filing. For additional information on the Dry Scrubber project, see Note 14 under "Environmental Compliance Plan."
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.
Further discussion of OG&E's reserve for tax refund in response to OCC, APSC and FERC proceedings can be found in Notes 8 and 14.
Income taxes refundable to customers, net, represents the reduction in accumulated deferred income taxes resulting from the reduction in the federal income tax rate as part of the 2017 Tax Act and includes income taxes recoverable from customers that represent income tax benefits previously used to reduce OG&E's revenues (treated as regulatory assets). These 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 representrepresents asset retirement costs previously recovered from ratepayers for other than legal obligations.
OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases.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 casereview as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory liability in the regulatory assets and liabilities table above.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to
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.
Use of Estimates
In preparing the 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 Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, and depreciable lives of property, plant and equipment, the determination of regulatory assets and liabilities and unbilled revenues.revenues.
Cash and Cash Equivalents
For purposes of the Financial Statements, OG&E considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate, which is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Balance Sheets and is included in the Other Operation and Maintenance Expense on the Statements of Income. The allowance for uncollectible accounts receivable was $1.5$1.7 million and $1.4 $1.5 million at December 31, 20162018 and 2015, 2017, 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 and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was$82.4 $57.6 millionand$119.3 $84.3 millionatDecember 31, 20162018 and2015, 2017, respectively. Effective May 1, 2014, the gas storage services agreement with Enable was terminated. As a result of this contract termination, approximately 5.3 Bcf of cushion gas owned by OG&E and stored on the Enable system iswas being directed to OG&E's power plants over a five yearfive-year period during peak time of June 1 to August 31 at a rate of 11,500 MMBtu/day for a total of 1.06 Bcf per year. In 2014, approximately $11.0 million of cushion gas was reclassified from Plant-in-Service to Other Deferred Assets, representing natural gas in storage that willto be removed from storage over four years. As of December 31, 2016, the balance of2018, all cushion gas in Fuel Inventories is $3.0 million and the balance in Other Deferred Assets is $2.7 million.had been withdrawn from storage.
Property, Plant and Equipment
All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Statements of Income as Other Operation and Maintenance Expense.
The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Statements of Income.
| | December 31, 2016 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2018 (In millions) | | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| McClain Plant (A) | 77 | % | $ | 234.2 |
| $ | 72.3 |
| $ | 161.9 |
| 77 | % | $ | 227.2 |
| $ | 78.2 |
| $ | 149.0 |
|
| Redbud Plant (A)(B) | 51 | % | $ | 489.0 |
| $ | 121.0 |
| $ | 368.0 |
| 51 | % | $ | 493.9 |
| $ | 145.3 |
| $ | 348.6 |
|
| |
| (A) | Construction work in progress was $0.2 million and $1.8$0.9 million for the McClain and Redbud Plants, respectively. |
| |
| (B) | This amount includes a plant acquisition adjustment of$148.3 $148.3 millionand accumulated amortization of$45.3 million. $56.3 million. |
| | December 31, 2015 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2017 (In millions) | | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| McClain Plant (A) | 77 | % | $ | 220.4 |
| $ | 62.8 |
| $ | 157.6 |
| 77 | % | $ | 226.8 |
| $ | 71.4 |
| $ | 155.4 |
|
| Redbud Plant (A)(B) | 51 | % | $ | 487.5 |
| $ | 101.2 |
| $ | 386.3 |
| 51 | % | $ | 496.6 |
| $ | 136.0 |
| $ | 360.6 |
|
| |
| (A) | Construction work in progress was $1.6$0.4 million and $1.3$7.8 million for the McClain and Redbud Plants, respectively. |
| |
| (B) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8$50.8 million. |
OG&E's property, plant and equipment and related accumulated depreciation are divided into the following major classes at:classes:
| | December 31, 2016 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2018 (In millions) | | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| Distribution assets | $ | 3,896.2 |
| $ | 1,221.5 |
| $ | 2,674.7 |
| $ | 4,229.4 |
| $ | 1,324.5 |
| $ | 2,904.9 |
|
| Electric generation assets (A) | 4,155.9 |
| 1,493.3 |
| 2,662.6 |
| 4,657.2 |
| 1,572.8 |
| 3,084.4 |
|
| Transmission assets (B) | 2,548.8 |
| 481.3 |
| 2,067.5 |
| 2,846.7 |
| 534.2 |
| 2,312.5 |
|
| Intangible plant | 85.0 |
| 43.9 |
| 41.1 |
| 187.6 |
| 135.1 |
| 52.5 |
|
| Other property and equipment | 381.5 |
| 145.6 |
| 235.9 |
| 444.2 |
| 160.8 |
| 283.4 |
|
| Total property, plant and equipment | $ | 11,067.4 |
| $ | 3,385.6 |
| $ | 7,681.8 |
| $ | 12,365.1 |
| $ | 3,727.4 |
| $ | 8,637.7 |
|
| |
| (A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3$56.3 million. |
| |
| (B) | This amount includes a plant acquisition adjustment of$3.3 $3.3 millionand accumulated amortization of$0.6 million. $0.7 million. |
| | December 31, 2015 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2017 (In millions) | | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| Distribution assets | $ | 3,728.8 |
| $ | 1,152.8 |
| $ | 2,576.0 |
| $ | 4,057.1 |
| $ | 1,259.1 |
| $ | 2,798.0 |
|
| Electric generation assets (A) | 3,837.4 |
| 1,407.0 |
| 2,430.4 |
| 4,475.0 |
| 1,493.5 |
| 2,981.5 |
|
| Transmission assets (B) | 2,454.2 |
| 440.7 |
| 2,013.5 |
| 2,767.7 |
| 506.5 |
| 2,261.2 |
|
| Intangible plant | 81.0 |
| 38.0 |
| 43.0 |
| 181.8 |
| 135.8 |
| 46.0 |
|
| Other property and equipment | 356.4 |
| 123.2 |
| 233.2 |
| 421.0 |
| 173.9 |
| 247.1 |
|
| Total property, plant and equipment | $ | 10,457.8 |
| $ | 3,161.7 |
| $ | 7,296.1 |
| $ | 11,902.6 |
| $ | 3,568.8 |
| $ | 8,333.8 |
|
| |
| (A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of$39.8 million. $50.8 million. |
| |
| (B) | This amount includes a plant acquisition adjustment of$3.3 $3.3 millionand accumulated amortization of$0.5 million. $0.6 million. |
OG&E's unamortized computer software costs, included in intangible plant above, were$36.544.3 millionand$34.337.5 millionatDecember 31, 20162018and20152017, respectively. In 2018, respectively. In2017 and 2016, 2015and2014, amortization expense for computer software costs was $8.09.6 million, $6.98.8 million and $5.28.0 million, respectively.
Depreciation and Amortization
The provision for depreciation, which was 3.02.7 percent and 2.92.5 percent of the average depreciable utility plant for 20162018 and 20152017, respectively, is provided on acalculated 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 2017,2019, the provision for depreciation is projected to be 3.12.7 percent of the average depreciable utility plant.
Amortization of intangible assets is computedcalculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2016, 97.02018, 98.7 percentwill be amortized over 16 10.4 years with the remaining3.0 1.3 percent of the intangible plant balance at December 31, 2016 2018 being amortized over23.7years.
Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset. Plant acquisition adjustments include $148.3 million $148.3 millionfor the Redbud Plant, which is being amortized over a27 year life and$3.3 $3.3 millionfor certain transmission substation facilities in OG&E's service territory, which are being amortized over a37to59year period.
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. OG&E has previously recorded asset retirement obligations that are being accreted over their respective lives ranging fromthree two to74years.
The following table summarizes changes to OG&E's asset retirement obligations during the years ended December 31, 20162018 and 20152017.
| | | (In millions) | 2016 | 2015 | 2018 | 2017 |
| Balance at January 1 | $ | 63.3 |
| $ | 58.6 |
| $ | 75.1 |
| $ | 69.6 |
|
| Accretion expense | 2.8 |
| 2.6 |
| 3.4 |
| 3.1 |
|
| Revisions in estimated cash flows (A) | 3.6 |
| 1.6 |
| 6.8 |
| 2.4 |
|
| Additions | — |
| 0.9 |
| |
| Liabilities settled | (0.1 | ) | (0.4 | ) | (1.4 | ) | — |
|
| Balance at December 31 | $ | 69.6 |
| $ | 63.3 |
| $ | 83.9 |
| $ | 75.1 |
|
| |
| (A) | Assumptions changed related to the estimated timing and estimated cost of asbestos abatement.ash pond removal at one of OG&E's generating facilities. |
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 expenseor 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 insuranceor raterecovery, 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 whereOG&E has been designated as one of several potentially responsible parties, the amount accrued representsOG&E'sestimated share of the cost. OG&E had$23.4 millionand$17.1 millioninaccrued environmental liabilities atDecember 31, 2018and2017, respectively, which are included in OG&E's asset retirement obligations.
Allowance for Funds Used During Construction
Allowance for funds used during construction, is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction, a non-cash item, is reflected as an increase to netNet Other Income and a reduction to Interest Expense in the Statements of Income and as an increase to Construction Work in Progress in the Balance Sheets. Allowance for funds used during construction is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 8.27.6 percent, 8.18.2 percent and 6.98.2 percent for the years ended December 31, 20162018, 20152017 and 20142016, respectively. Theincreasein the allowance for funds used during construction rates in 2016 was primarily due to short-term debt being used to finance construction projects, which caused the debt portion of allowance for funds used during construction to increase.
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
General
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 reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on theBalance Sheets and in Operating Revenues from Contracts with Customers on theStatements of Income based on estimates of usage and prices during the period.The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Integrated Market and Transmission
SPP Purchases and Sales
OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the
SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities.
OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. 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 Operating Revenues from Contracts with Customers or Cost of Goods SoldSales in itsthe Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.
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 on the Statements of Income 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 to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. The OCC and the APSC have the authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.
Income Taxes
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federalfederal jurisdiction and various state jurisdictions. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. OG&E recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Statements of Income.
Accrued Vacation
OG&E accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned but not taken.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expenseor 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 insuranceor raterecovery, 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 whereOG&E has been designated as one of several potentially responsible parties, the amount accrued representsOG&E'sestimated share of the cost. OG&E had$13.9 millionand$10.0 millioninaccrued environmental liabilities atDecember 31, 2016and2015, respectively, which are included in the asset retirement obligations table.
Reclassifications
Certain prior-year amounts have been reclassified to conform to the current year presentation.
The
Amounts for the years ended December 31, 2015 Balance Sheet has2017 and 2016 have been adjusted for the reclassification of $16.3 million of debt issuance costs from Total Deferred Chargesnet periodic benefit cost components and the regulatory Pension tracker mechanism between Other Operation and Maintenance and Other Assets to Long-Term DebtNet Periodic Benefit Expense in OG&E's Statements of Income to be consistent with the 20162018 presentation due to theOG&E's adoption of ASU 2015-03, "Simplifying2017-07, "Improving the Presentation of Debt Issuance Costs,Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." Further discussion can be found in 2016.
Note 12.
| |
| 2. | Accounting Pronouncements |
Recently Adopted Accounting Standards
Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenueOG&E adopted this standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. The deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. OG&E currently expects to applyfirst quarter of 2018 utilizing the modified retrospective transition method but will ultimately determine its transition approach once various industry issues have been resolved. Currently, OG&E is not aware of any issues that would have a material impact on the timing of revenue recognition. OG&E is assessing the impact of this new guidance on its tariff-based sales, contributions in aid of construction, bundled arrangements and alternative revenue programs. At this time, OG&E is evaluating the impact ofapplied the new standard on its resultsonly to contracts that were not completed at the date of operations and financial position, but believes thatinitial application. OG&E determined it willwas not necessary to change the incometiming or amounts of revenue recognized based on the adoption of Topic 606. Therefore, financial statement amounts in the period of adoption have not changed under Topic 606 as compared with the guidance that was in effect before the adoption of Topic 606. The adoption did change financial statement presentation as Operating Revenues are now separated between Revenues from Contracts with Customers and Other Revenues in the 2018 Statements of Income. In addition, gains and losses associated with OG&E's guaranteed flat bill program that were previously included in Net Other Income in the Statements of Income are now presented as Revenues from Contracts with Customers since the gains and losses are included within the transaction price in the contract under Topic 606. Operating Revenues presented in the 2017 Statements of Income did not change from prior year. Alternative revenue programs are scoped out of Topic 606, as these programs are considered agreements between an entity and a regulator, not contracts between an entity and a customer; therefore, OG&E now presents revenues from alternative revenue programs separately from revenues from contracts with customers. Further discussion regarding OG&E's revenue recognition as well as additional disclosures resulting from the adoption of Topic 606 can be found in Notes 1 and will require new disclosures.3.
ConsolidationImproving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost..In February 2015,May 2017, the FASB issued ASU 2015-02, "Consolidation2017-07, "Compensation-Retirement Benefits (Topic 810).715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." The amendments in ASU 2015-02 affectnew guidance is designed to improve the reporting entitiesof pension and other postretirement benefit costs by bifurcating the components of net benefit cost between those that are attributed to compensation for service and those that are not. The service cost component of benefit cost continues to be presented within operating income, but entities are now required to evaluate whether they should consolidate certain legal entities.present the other components of benefit cost as non-operating within the income statement. Additionally, the new guidance only permits the capitalization of the service cost component of net benefit cost. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs. OG&E adopted the new standard modifiesguidance beginning in the evaluationfirst quarter of whether limited partnerships2018. The presentation and similar legal entities are variable interest entities or voting interest entities along with eliminating the presumption that a general partner should consolidate a limited partnership. The new standard is effective for fiscal years beginning after December 15, 2015. Therecognition impacts of OG&E's adoption of this new standard did not resultASU 2017-07 are further discussed in the consolidation of any non-consolidated entities. Note 12.
Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between currentprior lease accounting and Topic 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under currentprior accounting guidance. Lessees, such as OG&E, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment for items such as for initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to currentprior capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in currentprior lease guidance but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 15, 2018. The new guidance must be adopted using a modified retrospective transition method and provides for certain practical expedients. Transition will requiremethod options include application of the new guidance at the beginning of the earliest comparative period presented.presented or at the adoption date, with a cumulative-effect adjustment to retained earnings in the period of adoption. OG&E has started evaluatingevaluated its current lease contracts.contracts and applied the 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. OG&E has not determined the amountrecognized approximately $38.0 million of impact onlease liabilities in its Financial Statements, but it anticipates an increase in the recognition of right-of-use assetsBalance Sheet at January 1, 2019 for railcar, wind farm land and lease liabilities.office space leases.
Investments. In March 2016,January 2018, the FASB issued ASU 2016-07, "Investments-Equity Method and Joint Ventures; Simplifying the2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842," which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the Equity Method of Accounting (Topic 323)." The amendments in ASU 2016-07 eliminate the requirementright to retroactively adopt the equity method of accountinguse, access or cross another entity's land for a qualifying equity method investment. ASU 2016-07 requires equity method investors to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendments in this ASU are effective for the fiscal years and interim periods within those fiscal years, beginning after December 15, 2016. OG&E does not believe this ASU will have any effect on its Financial Statements.
Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends ASC Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements. Thespecified purpose. This new guidance among other requirements will require all of the tax effects relatedpermits an entity to share based payments at settlement (or expiration) to be recorded through the income statement. Currently, tax benefits in excess of compensation cost ("windfalls") are recorded in equity, and tax deficiencies ("shortfalls") are recorded in equity to the extent of previous windfalls, and then to the income statement. This change is requiredelect a transitional practical expedient, to be applied prospectivelyconsistently, to all excess tax benefits and tax deficiencies resulting from settlements afternot evaluate land easements under Topic 842 that exist or expired before the date ofentity's adoption of the ASU 2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reportedTopic 842 and that were not previously accounted for as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. OG&E will prospectively adopt this standard in the first quarter of 2017. Going forward, tax benefits in excess of compensation cost previously recorded in equityleases under ASC 840, "Leases." Once
willTopic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be recorded within the income statement and all tax related cash flows resulting from share based payments will be recorded as an operating activity within the statement of cash flows.
Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, "Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments." The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accountingaccounted for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. OG&E does not believe this ASU will have any effect on its Financial Statements.
Simplifying the Presentation of Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." The amendments in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability consistent with debt discounts. OG&E adopted this standard and adjusted the December 31, 2015 Balance Sheet for the reclassification of debt issuance costs from Total Deferred Charges and Other Assets to Long-Term Debt to be consistent with the December 31, 2016 presentation.
Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issuedlease. ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." This standard addresses the classification of seven specific types of cash flows as follows: debt prepayment or extinguishment costs, payments for the extinguishment of zero coupon debt, payments to settle contingent consideration liabilities incurred in a business combination, proceeds from insurance claims, payments to purchase and proceeds from the settlement of company-owned life insurance, distributions from equity method investees, and cash flows related to beneficial interests retained in securitization transactions. In addition to these seven specific issues, the ASU also provides additional guidance on the application of the predominance principle when cash receipts and payments have aspects of more than one class of cash flows. The standard2018-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017,2018. OG&E elected this practical expedient during its adoption of Topic 842 and interimdid not evaluate existing easement contracts under Topic 842, if these contracts had not previously been accounted for under Topic 840.
In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which provides the following additional amendments to ASU 2016-02: (i) entities can elect to initially apply ASU 2016-02 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and (ii) lessors can elect a practical expedient, by class of underlying asset, to account for nonlease components and the associated lease component as a single component, if the nonlease component otherwise would be accounted for under Topic 606 and certain conditions, as described in ASU 2018-11, are met. If an entity elects the additional (and optional) transition method, the entity will provide the required Topic 840 disclosures for all periods within thosethat continue to be reported under Topic 840. ASU 2018-11 is effective for fiscal years beginning after December 2018. OG&E elected the transition method provided by the guidance allowing for initial application at January 1, 2019.
Issued Accounting Standards Not Yet Adopted
Fair Value Measurement Disclosure Framework. In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement." The new guidance removes, adds or modifies disclosure requirements that impact all levels of the fair value hierarchy, as well as investments measured using the net asset value practical expedient. ASU 2018-13 is effective for fiscal years beginning after December 2019 and retrospective application is required.required to be applied both retrospectively and prospectively, depending on the specific disclosure change. Early adoption is permitted. OG&E does not believe this ASU will have a material effectsignificant impact on its Statements of Cash Flows.financial statement disclosures.
Going Concern.Defined Benefit Plans Disclosure Framework. In August 2014, the FASB defined management’s responsibility to evaluate whether substantial doubt exists about an entity’s ability to continue as a going concern. Professional auditing standards require auditors to evaluate the going concern presumption, but previously there was a lack of guidance in GAAP for financial statement preparers. ASU 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern," requires management to perform a going concern evaluation effective for annual periods ending after December 15, 2016, and annual and interim periods thereafter. OG&E adopted this standard in 2016 and management does not believe there is substantial doubt about the entity’s ability to continue as a going concern.
Fair Value Measurement. In May 2015,2018, the FASB issued ASU 2015-07, "Fair Value Measurement (Topic 820)2018-14, "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): DisclosuresDisclosure Framework - Changes to the Disclosure Requirements for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent.Defined Benefit Plans." The new guidance removes, adds or clarifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. ASU 2015-07 removes the requirement2018-14 is effective for fiscal years ending after December 2020 and is required to categorize within the fair value hierarchy all investments for which fair valuebe applied on a retrospective basis. Early adoption is measured using the net asset value per share practical expedient and eliminates certain disclosures for those investments.permitted. OG&E adopteddoes not believe this standardASU will have a significant impact on its financial statement disclosures.
Accounting for Implementation Costs Incurred in 2016 which minimally impacted disclosures withina Cloud Computing Arrangement That Is a Service Contract. In August 2018, the Retirement PlansFASB issued ASU 2018-15, "Intangibles - Goodwill and Postretirement Benefit Plans footnote includedOther - 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 2018-15 is effective for fiscal years beginning after December 2019 and can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. OG&E is currently evaluating the impact of this filing.ASU on its Financial Statements.
The following table disaggregates OG&E's revenues from contracts with customers by customer classification. OG&E's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
|
| | | |
| (In millions) | Year Ended
December 31, 2018 |
| Residential | $ | 877.8 |
|
| Commercial | 578.0 |
|
| Industrial | 191.1 |
|
| Oilfield | 150.2 |
|
| Public authorities and street light | 197.4 |
|
| System sales revenues | 1,994.5 |
|
| Provision for rate refund | (6.0 | ) |
| Integrated market | 48.7 |
|
| Transmission | 147.4 |
|
| Other | 27.1 |
|
| Revenues from contracts with customers | $ | 2,211.7 |
|
| |
3.4. | Related Party Transactions |
OGE Energy charged operating costs to OG&E of $131.5140.9 million, $123.0134.4 million and $120.3131.5 million in 20162018, 20152017 and 20142016, respectively. OGE Energy charges operating costs to OG&E based on several factors. 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.
In 2018, 2017 and 2016, OG&E declared dividends to OGE Energy of $185.0 million, $105.0 million and $190.0 million, respectively.
OG&E entered into a contract with Enable to provideprovides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. In October 2018, OG&E and Enable agreed to a new contract that will be effective as of April 2019 for a five year period ending May 1, 2014.2024. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s&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’sEnable's deliveries exceed OG&E’s&E's pipeline receipts. Enable purchases gas from OG&E when OG&E’s&E's pipeline receipts exceed Enable’sEnable's deliveries. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will bethat became effective uponin December 2018 related to the conversion of unitsproject to convert Muskogee Units 4 and 5 at Muskogee from coal to natural gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2016, 20152018, 2017 and 2014.2016.
|
| | | | | | | | | |
Year Ended December 31, (In millions) | 2016 | 2015 | 2014 |
| Operating Revenues: | | | |
| Electricity to power electric compression assets | $ | 11.5 |
| $ | 13.8 |
| $ | 13.3 |
|
| Cost of Sales: | | | |
| Natural gas transportation services | $ | 35.0 |
| $ | 35.0 |
| $ | 34.9 |
|
| Natural gas storage services | — |
| — |
| 4.4 |
|
| Natural gas purchases/(sales) | 11.2 |
| 7.6 |
| 8.7 |
|
|
| | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2018 | 2017 | 2016 |
| Operating revenues: | | | |
| Electricity to power electric compression assets | $ | 16.3 |
| $ | 14.0 |
| $ | 11.5 |
|
| Cost of sales: | | | |
| Natural gas transportation services | $ | 37.9 |
| $ | 35.0 |
| $ | 35.0 |
|
| Natural gas (sales) purchases | $ | (3.2 | ) | $ | (2.1 | ) | $ | 11.2 |
|
In2016, 2015and2014, OG&E declared dividends to OGE Energy of$190.0 million, $120.0 million and $120.0 million, respectively.
| |
4.5. | Fair Value Measurements |
The classification of OG&E's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.
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).
OG&E had no financial instruments measured at fair value on a recurring basis at December 31, 20162018 and 2015.
2017. The fair value of OG&E's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt whose fair value is based on calculating the net present value of the monthly payments discounted by OG&E's current borrowing rate and is classified as Level 3 in the fair value hierarchy. The following table summarizes the fair value and carrying amount of OG&E's financial instruments at December 31, 20162018 and 2015.2017.
| | Year Ended December 31 (In millions) | 2016 | 2015 | |
| | Carrying Amount | Fair Value | Carrying Amount | Fair Value | 2018 | 2017 |
| Long-Term Debt (including Long-Term Debt due within one year) | | |
December 31 (In millions) | | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
| Long-term Debt (including Long-term Debt due within one year): | | |
| Senior Notes | $ | 2,385.5 |
| $ | 2,657.2 |
| $ | 2,493.9 |
| $ | 2,754.6 |
| $ | 3,001.9 |
| $ | 3,178.2 |
| $ | 2,854.3 |
| $ | 3,242.8 |
|
| Industrial Authority Bonds | 135.4 |
| 135.4 |
| 135.4 |
| 135.4 |
| $ | 135.4 |
| $ | 135.4 |
| $ | 135.4 |
| $ | 135.4 |
|
| Tinker Debt | 9.9 |
| 11.3 |
| 10.0 |
| 9.2 |
| $ | 9.6 |
| $ | 8.7 |
| $ | 9.7 |
| $ | 9.8 |
|
| |
5.6. | Stock-Based Compensation |
In 2013,OGE Energyadopted, and its shareholders approved, the Stock Incentive Plan. Under the Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to7,400,000shares under the Stock Incentive Plan.
The following table summarizes OG&E's pre-tax compensation expense and related income tax benefit for the years ended December 31, 20162018, 20152017 and 20142016 related to performance units and restricted stock for OG&E employees.
| | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
| Performance units | | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| Performance units: | | |
| Total shareholder return | $ | 2.1 |
| $ | 2.4 |
| $ | 2.0 |
| $ | 2.8 |
| $ | 2.5 |
| $ | 2.1 |
|
| Earnings per share | 0.1 |
| 0.4 |
| 0.8 |
| 1.8 |
| 0.5 |
| 0.1 |
|
| Total performance units | 2.2 |
| 2.8 |
| 2.8 |
| 4.6 |
| 3.0 |
| 2.2 |
|
| Restricted stock | — |
| 0.1 |
| 0.1 |
| — |
| — |
| — |
|
| Net compensation expense | $ | 2.2 |
| $ | 2.9 |
| $ | 2.9 |
| |
| Total compensation expense | | $ | 4.6 |
| $ | 3.0 |
| $ | 2.2 |
|
| Income tax benefit | $ | 0.9 |
| $ | 1.1 |
| $ | 1.1 |
| $ | 1.2 |
| $ | 1.2 |
| $ | 0.9 |
|
OGE Energy has issued new shares to satisfy restricted stock grants and payouts of earned performance units. In 20162018, 20152017 and 20142016, there were 1,1318,599 shares, 18,820965 shares and 100,6401,131 shares, respectively, of new common stock issued to OG&E's employees pursuant to OGE Energy's Stock Incentive Plan related to restricted stock grants (net of forfeitures) and payouts of earned performance units. In2016, there were658shares of restricted stockreturned toOGE Energyto satisfy tax liabilities.
Performance Units
Under the Stock Incentive Plan,OGE Energyhas issued performance units which represent the value of one share ofOGE Energy'scommon stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment withOGE Energyor 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. OG&E estimates 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 OGE 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 OGE 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 OGE Energy's common stock based on OGE Energy'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 OGE Energy's Board of Directors. All of these performance units are classified as equity
in OGE Energy's Consolidated Balance Sheet.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 OGE 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 were not accrued or paid for awards prior to February 2014, and were therefore not included in the fair value calculation. Beginning with the February 2014 performance unit awards, dividends are accrued on a quarterly basis pending achievement of payout criteria and were thereforeare included in the fair value calculations. Expected price volatility is based on the historical volatility of OGE Energy's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to OGE Energy's performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.
| | | | 2016 | 2015 | 2014 | 2018 | 2017 | 2016 |
| Number of units granted to OG&E employees | 105,076 |
| 90,098 |
| 67,773 |
| 91,940 |
| 85,501 |
| 105,076 |
|
| Fair value of units granted | $ | 20.84 |
| $ | 31.02 |
| $ | 34.73 |
| $ | 36.86 |
| $ | 41.76 |
| $ | 20.84 |
|
| Expected dividend yield | 3.5 | % | 2.6 | % | 2.5 | % | 3.6 | % | 3.8 | % | 3.5 | % |
| Expected price volatility | 19.8 | % | 16.9 | % | 20.0 | % | 19.0 | % | 19.8 | % | 19.8 | % |
| Risk-free interest rate | 0.88 | % | 0.91 | % | 0.67 | % | 2.38 | % | 1.46 | % | 0.88 | % |
| Expected life of units (in years) | 2.85 |
| 2.85 |
| 2.88 |
| 2.86 |
| 2.86 |
| 2.85 |
|
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 OGE Energy'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.OGE Energyreassesses 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 OGE Energy's performance units based on earnings per share. The number of performance units granted based on earnings per share and the grant date fair value are shown in the following table.
| | | | 2016 | 2015 | 2014 | 2018 | 2017 | 2016 |
| Number of units granted to OG&E employees | 35,025 |
| 30,034 |
| 22,592 |
| 30,649 |
| 28,499 |
| 35,025 |
|
| Fair value of units granted | $ | 26.59 |
| $ | 33.99 |
| $ | 34.74 |
| $ | 31.03 |
| $ | 34.83 |
| $ | 26.59 |
|
Restricted Stock
Under the Stock Incentive Plan,OGE Energyissued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests primarily in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services toOGE Energyor a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.
The fair value of the restricted stock was based on the closing market price ofOGE Energy'scommon stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, OG&E treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is
recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period on restricted stock granted prior to July 2014, and therefore dividends are included in the fair value calculation for such restricted stock granted prior to July 2014.
For restricted stock granted after July 2014, dividendsDividends will only be paid on restricted stock awards that vest. Accordingly, for restricted stock granted after July 2014,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 is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to OGE Energy's restricted stock. The number of shares of restricted stock granted and the grant date fair value are shown in the following table. There were no restricted stock grants made to OG&E employees during 2018, 2017 or 2016.
|
| | | | | | | | | |
| | 2016 | 2015 | 2014 |
| Shares of restricted stock granted to OG&E employees | — |
| — |
| 6,204 |
|
| Fair value of restricted stock granted | $ | — |
| $ | — |
| $ | 35.66 |
|
A summary of the activity for OGE Energy's performance units and restricted stock applicable to OG&E's employees at December 31, 20162018 and changes in 20162018 are shown in the following table.
| | | | Performance Units | | | Performance Units | | |
| | Total Shareholder Return | Earnings Per Share | Restricted Stock | Total Shareholder Return | Earnings Per Share | Restricted Stock |
| (Dollars in millions) | Number
of Units | | Aggregate Intrinsic Value | Number
of Units | | Aggregate Intrinsic Value | Number
of Shares | Aggregate Intrinsic Value | Number
of Units | | Aggregate Intrinsic Value | Number
of Units | | Aggregate Intrinsic Value | Number
of Shares | Aggregate Intrinsic Value |
| Units/Shares Outstanding at 12/31/15 | 214,652 |
| | | 71,555 |
| | | 5,715 |
| | |
| Units/shares outstanding at 12/31/17 | | 252,250 |
| | | 84,083 |
| | | 625 |
| |
| Granted | 105,076 |
| (A) | | 35,025 |
| (A) | | — |
| | 91,940 |
| (A) | | 30,649 |
| (A) | | — |
| |
| Converted | (80,581 | ) | (B) | $ | — |
| (26,862 | ) | (B) | $ | — |
| N/A |
| | (73,092 | ) | (B) | $ | — |
| (24,366 | ) | (B) | $ | 0.4 |
| N/A |
| |
| Vested | N/A |
| | | N/A |
| | | (3,651 | ) | $ | 0.1 |
| N/A |
| | | N/A |
| | | (313 | ) | $ | — |
|
| Forfeited | (7,172 | ) | | | (2,388 | ) | | | (268 | ) | | (10,000 | ) | | | (3,333 | ) | | | — |
| |
| Employee migration | 4,606 |
| (C) | | 1,534 |
| (C) | | — |
| | 325 |
| (C) | | 110 |
| (C) | | — |
| |
| Units/Shares Outstanding at 12/31/16 | 236,581 |
| | $ | 6.5 |
| 78,864 |
| | $ | 0.7 |
| 1,796 |
| $ | 0.1 |
| |
| Units/Shares Fully Vested at 12/31/16 | 57,484 |
| | $ | — |
| 19,164 |
| | $ | — |
| | | |
| Units/shares outstanding at 12/31/18 | | 261,423 |
| | $ | 18.5 |
| 87,143 |
| | $ | 4.9 |
| 312 |
| $ | — |
|
| Units/shares fully vested at 12/31/18 | | 95,593 |
| | $ | 7.0 |
| 31,865 |
| | $ | 2.5 |
| | |
| |
| (A) | For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. |
| |
| (B) | These amounts represent performance units that vested at December 31, 20152017 which were settled in February 2016.2018. |
| |
| (C) | Due to certain employees transferring between OG&E and its affiliates.OGE Energy. |
A summary of the activity forOGE Energy'snon-vested performance units and restricted stock applicable to OG&E's employees at December 31, 20162018 and changes in 20162018 are shown in the following table.
| | | | Performance Units | | | Performance Units | | |
| | Total Shareholder Return | Earnings Per Share | Restricted Stock | Total Shareholder Return | Earnings Per Share | Restricted Stock |
| | Number
of Units | | Weighted-Average
Grant Date
Fair Value | Number
of Units | | Weighted-Average
Grant Date
Fair Value | Number
of Shares | Weighted-Average
Grant Date
Fair Value | 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 12/31/15 | 134,071 |
| | $ | 32.62 |
| 44,693 |
| | $ | 34.22 |
| 5,715 |
| $ | 34.04 |
| |
| Units/shares non-vested at 12/31/17 | | 179,158 |
| | $ | 30.26 |
| 59,717 |
| | $ | 30.30 |
| 625 |
| $ | 31.92 |
|
| Granted | 105,076 |
| (A) | $ | 20.84 |
| 35,025 |
| (A) | $ | 26.59 |
| — |
| $ | — |
| 91,940 |
| (A) | $ | 36.86 |
| 30,649 |
| (A) | $ | 31.03 |
| — |
| $ | — |
|
| Converted | — |
|
| $ | — |
| — |
|
| $ | — |
| N/A |
| N/A |
| |
| Vested | (57,484 | ) | | $ | 34.73 |
| (19,164 | ) | | $ | 34.74 |
| (3,651 | ) | $ | 33.10 |
| (95,593 | ) | | $ | 20.84 |
| (31,865 | ) | | $ | 26.59 |
| (313 | ) | $ | 31.88 |
|
| Forfeited | (7,172 | ) | | $ | 26.45 |
| (2,388 | ) | | $ | 30.32 |
| (268 | ) | $ | 37.31 |
| (10,000 | ) | | $ | 36.71 |
| (3,333 | ) | | $ | 31.82 |
| — |
| $ | — |
|
| Employee migration | 4,606 |
| (B) | $ | 26.67 |
| 1,534 |
| (B) | $ | 30.34 |
| — |
| $ | — |
| 325 |
| (B) | $ | 139.59 |
| 110 |
| (B) | $ | 66.20 |
| — |
| $ | — |
|
| Units/Shares Non-Vested at 12/31/16 | 179,097 |
| | $ | 25.12 |
| 59,700 |
| | $ | 29.70 |
| 1,796 |
| $ | 35.45 |
| |
| Units/Shares Expected to Vest | 167,588 |
| (C) | | 55,863 |
| (C) | | 1,796 |
| | |
| Units/shares non-vested at 12/31/18 | | 165,830 |
| | $ | 39.17 |
| 55,278 |
| | $ | 32.82 |
| 312 |
| $ | 31.88 |
|
| Units/shares expected to vest | | 162,181 |
| (C) | | 54,061 |
| (C) | | 312 |
| |
| |
| (A) | For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. |
| |
| (B) | Due to certain employees transferring between OG&E and its affiliates.OGE Energy. |
| |
| (C) | The intrinsic value of the performance units based on total shareholder return and earnings per share is $5.8$11.2 million and $1.9$2.4 million, respectively. |
Fair Value of Vested Performance Units and Restricted Stock
A summary of OG&E's fair value for its vested performance units and restricted stock is shown in the following table.
| | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
| Performance units | | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| Performance units: | | |
| Total shareholder return | $ | 2.0 |
| $ | 2.1 |
| $ | 1.9 |
| $ | 2.1 |
| $ | 2.3 |
| $ | 2.0 |
|
| Earnings per share | — |
| — |
| 0.7 |
| $ | 1.7 |
| $ | 0.4 |
| $ | — |
|
| Restricted stock | 0.1 |
| 0.1 |
| 0.1 |
| $ | — |
| $ | 0.1 |
| $ | 0.1 |
|
Unrecognized Compensation Cost
A summary of OG&E's unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
| | | December 31, 2016 | Unrecognized Compensation Cost (in millions) | Weighted Average to be Recognized (in years) | |
| Performance units | | | |
| December 31, 2018 | | Unrecognized Compensation Cost (In millions) | Weighted Average to be Recognized (In years) |
| Performance units: | | | |
| Total shareholder return | $ | 2.2 |
| 1.66 | $ | 3.2 |
| 1.67 |
| Earnings per share | 0.9 |
| 1.70 | 0.9 |
| 1.68 |
| Total performance units | 3.1 |
|
| 4.1 |
|
|
| Restricted stock | — |
| 0.78 | — |
| 0.03 |
| Total | $ | 3.1 |
|
| |
| Total unrecognized compensation cost | | $ | 4.1 |
|
|
| |
6.7. | Supplemental Cash Flow Information |
The following table discloses information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments. Also disclosed in the table iscashCash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.refunds are also disclosed in the table.
| | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| NON-CASH INVESTING AND FINANCING ACTIVITIES | | |
| Power plant long-term service agreement | $ | 39.5 |
| $ | 2.3 |
| $ | — |
| $ | (9.2 | ) | $ | (2.6 | ) | $ | 39.5 |
|
| SUPPLEMENTAL CASH FLOW INFORMATION | | |
| Cash paid during the period for | | |
| Cash paid during the period for: | | |
| Interest (net of interest capitalized) (A) | $ | 138.3 |
| $ | 143.6 |
| $ | 143.6 |
| $ | 149.7 |
| $ | 133.1 |
| $ | 138.3 |
|
| Income taxes (net of income tax refunds) | — |
| (6.2 | ) | 0.2 |
| $ | 0.9 |
| $ | (71.5 | ) | $ | — |
|
| |
| (A) | Net of interest capitalized of $7.511.7 million, $4.218.0 million and $2.47.5 million in 20162018, 20152017 and 20142016, respectively. |
2017 Tax Act
In December 2017, the 2017 Tax Act was signed into law, reducing the corporate federal tax rate from 35 percent to 21 percent for tax years beginning in 2018. ASC 740, "Income Taxes," requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized and settled. Entities subject to ASC 980, "Accounting for Regulated Entities," such as OG&E, are required to recognize a regulatory liability for the decrease in taxes payable for the change in tax rates that are expected to be returned to customers through future rates and to recognize a regulatory asset for the increase in taxes receivable for the change in tax rates that are expected to be recovered from customers through future rates. At December 31, 2017, as a result of remeasuring existing deferred taxes at the lower 21 percent tax rate, OG&E reduced net deferred income tax liabilities and increased regulatory liabilities. As of December 31, 2018, OG&E's regulatory liability for income taxes refundable to customers, net was $1.022 billion, as a result of the change in the corporate federal tax rate.
As a result of the 2017 Tax Act, in early January 2018: (i) the OCC ordered OG&E to record a reserve, including accrued interest, to reflect the reduced federal corporate tax rate, among other tax implications, on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings; (ii) the APSC ordered OG&E to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act until the resulting benefits, including carrying charges, are returned to customers; and (iii) through a Section 206 filing with the FERC, modifications were requested to be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act. Further discussion regarding OG&E's response to OCC, APSC and FERC proceedings, including reserves to revenue for each jurisdiction, can be found in Note 14 under "Oklahoma Rate Review Filing - January 2018," "APSC Order - 2017 Tax Act," "FERC - Request for Waiver" and "FERC - Section 206 Filing." As of December 31, 2018, the total recorded reserve was $15.4 million, which is included in Other Current Liabilities in OG&E's Balance Sheets.
Staff Accounting Bulletin No. 118
Staff Accounting Bulletin No. 118 addresses the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the 2017 Tax Act. OG&E recognized the provisional tax impacts related to the revaluation of deferred tax assets and liabilities as of December 31, 2017, as OG&E had not completed its accounting for income tax effects of the 2017 Tax Act. As of December 31, 2018, OG&E has completed its accounting for the enactment-date income tax effects of the 2017 Tax Act. Upon further analysis of certain aspects of the 2017 Tax Act and refinement of the final calculations during the 12 months ended December 31, 2018, OG&E adjusted its provisional amount by an increase to regulatory liabilities of $7.4 million.
Income Tax Expense (Benefit)
The items comprising income tax expense (benefit) are as follows:
|
| | | | | | | | | |
Year ended December 31 (In millions) | 2016 | 2015 | 2014 |
| Provision (Benefit) for Current Income Taxes | | | |
| Federal | $ | 2.9 |
| $ | (17.5 | ) | $ | (43.4 | ) |
| State | (5.3 | ) | (5.3 | ) | (6.3 | ) |
| Total Provision (Benefit) for Current Income Taxes | (2.4 | ) | (22.8 | ) | (49.7 | ) |
| Provision for Deferred Income Taxes, net | | | |
| Federal | 99.8 |
| 117.0 |
| 146.8 |
|
| State | 17.2 |
| 11.3 |
| 15.4 |
|
| Total Provision for Deferred Income Taxes, net | 117.0 |
| 128.3 |
| 162.2 |
|
| Deferred Federal Investment Tax Credits, net | (0.2 | ) | (0.7 | ) | (0.9 | ) |
| Total Income Tax Expense | $ | 114.4 |
| $ | 104.8 |
| $ | 111.6 |
|
|
| | | | | | | | | |
Year Ended December 31 (In millions) | 2018 | 2017 | 2016 |
| Provision (benefit) for current income taxes: | | | |
| Federal | $ | (12.4 | ) | $ | 26.3 |
| $ | 2.9 |
|
| State | (4.1 | ) | (4.3 | ) | (5.3 | ) |
| Total provision (benefit) for current income taxes | (16.5 | ) | 22.0 |
| (2.4 | ) |
| Provision for deferred income taxes, net: | | | |
| Federal | 53.7 |
| 100.0 |
| 99.8 |
|
| State | 2.7 |
| 19.9 |
| 17.2 |
|
| Total provision for deferred income taxes, net | 56.4 |
| 119.9 |
| 117.0 |
|
| Deferred federal investment tax credits, net | 0.1 |
| (0.1 | ) | (0.2 | ) |
| Total income tax expense | $ | 40.0 |
| $ | 141.8 |
| $ | 114.4 |
|
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federalfederal jurisdiction and various state jurisdictions. With few exceptions, OG&E is no longer subject to U.S. Federalfederal tax examinations by tax authorities for years prior to 20132015 or state and local tax examinations by tax authorities for years prior to 20122014. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federalfederal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which reduce OG&E's effective tax rate.
The following schedule reconciles the statutory tax rates to the effective income tax rate:
| | | Year ended December 31 | 2016 | 2015 | 2014 | |
| Statutory Federal tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |
| Year Ended December 31 | | 2018 | 2017 | 2016 |
| Statutory federal tax rate | | 21.0 | % | 35.0 | % | 35.0 | % |
| Federal renewable energy credit (A) | | (6.9 | ) | (6.1 | ) | (8.2 | ) |
| Amortization of net unfunded deferred taxes | 0.8 |
| 0.9 |
| 0.8 |
| (2.9 | ) | 0.9 |
| 0.8 |
|
| State income taxes, net of federal income tax benefit | | (0.2 | ) | 2.2 |
| 1.8 |
|
| Other | | (0.1 | ) | (0.3 | ) | 0.1 |
|
| Uncertain tax positions | | — |
| — |
| 0.1 |
|
| Federal investment tax credits, net | (0.9 | ) | (0.2 | ) | (0.2 | ) | — |
| — |
| (0.9 | ) |
| State income taxes, net of Federal income tax benefit | 1.8 |
| 0.5 |
| 0.8 |
| |
| Federal renewable energy credit (A) | (8.2 | ) | (8.8 | ) | (9.4 | ) | |
| Uncertain tax positions | 0.1 |
| 0.7 |
| 0.7 |
| |
| Other | 0.1 |
| (0.1 | ) | — |
| |
| Effective income tax rate | 28.7 | % | 28.0 | % | 27.7 | % | 10.9 | % | 31.7 | % | 28.7 | % |
| |
| (A) | Represents credits associated with the production from OG&E's wind farms. |
The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 20162018 and 2015,2017 respectively, were as follows:
| | December 31 (In millions) | 2016 | 2015 | 2018 | 2017 |
| Non-Current Deferred Income Tax Liabilities, net | | |
| Deferred income tax liabilities, net: | | |
| Accelerated depreciation and other property related differences | $ | 2,101.4 |
| $ | 2,012.1 |
| $ | 1,605.3 |
| $ | 1,449.6 |
|
| OG&E pension plan | 48.0 |
| 55.1 |
| |
| Regulatory asset | 34.4 |
| 32.7 |
| |
| Income taxes refundable to customers, net | 24.1 |
| 22.0 |
| |
| OG&E Pension Plan | | 26.0 |
| 28.4 |
|
| Regulatory assets | | 17.4 |
| 18.9 |
|
| Bond redemption-unamortized costs | 4.3 |
| 4.8 |
| 2.4 |
| 2.6 |
|
| Income taxes recoverable from customers, net | | (239.6 | ) | (244.3 | ) |
| Federal tax credits | (209.3 | ) | (174.0 | ) | (237.5 | ) | (218.3 | ) |
| State tax credits | (102.6 | ) | (98.6 | ) | (142.3 | ) | (129.2 | ) |
| Postretirement medical and life insurance benefits | (34.3 | ) | (40.8 | ) | |
| Regulatory liabilities | (34.6 | ) | (46.3 | ) | (78.8 | ) | (16.8 | ) |
| Asset retirement obligations | (24.5 | ) | (22.5 | ) | (21.5 | ) | (19.2 | ) |
| Postretirement medical and life insurance benefits | | (16.2 | ) | (17.4 | ) |
| Net operating losses | (26.1 | ) | (89.7 | ) | (10.0 | ) | (11.2 | ) |
| Accrued liabilities | | (6.1 | ) | (3.8 | ) |
| Other | (16.7 | ) | (7.1 | ) | (2.4 | ) | (4.8 | ) |
| Accrued liabilities | (8.0 | ) | (5.9 | ) | |
| Deferred federal investment tax credits | | (1.9 | ) | (0.5 | ) |
| Accrued vacation | (2.4 | ) | (2.6 | ) | (1.7 | ) | (1.4 | ) |
| Deferred Federal investment tax credits | (0.8 | ) | (0.9 | ) | |
| Uncollectible accounts | (0.6 | ) | (0.5 | ) | (0.4 | ) | (0.4 | ) |
| Non-Current Deferred Income Tax Liabilities, net | $ | 1,752.3 |
| $ | 1,637.8 |
| |
| Total deferred income tax liabilities, net | | $ | 892.7 |
| $ | 832.2 |
|
As of December 31, 2016,2018, OG&E has classified $13.5$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 is a reconciliation of OG&E’s total gross unrecognized tax benefits as of the years ended December 31, 2016, 2015,2018, 2017 and 2014.2016.
| | | (In millions) | 2016 | 2015 | 2014 | 2018 | 2017 | 2016 |
| Balance at January 1 | $ | 20.2 |
| $ | 16.1 |
| $ | 12.0 |
| $ | 20.7 |
| $ | 20.7 |
| $ | 20.2 |
|
| Tax positions related to current year: | | |
| Additions | 0.5 |
| 4.1 |
| 4.1 |
| — |
| — |
| 0.5 |
|
| Balance at December 31 | $ | 20.7 |
| $ | 20.2 |
| $ | 16.1 |
| $ | 20.7 |
| $ | 20.7 |
| $ | 20.7 |
|
As of December 31, 2018, 2017 and 2016, 2015 and 2014, there are $13.5were $16.4 million, $13.2$16.4 million and $10.5$13.5 million of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.
OG&E has determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During 2016, OG&E recorded an additional reserve for this item of $0.5 million ($0.3 million after the federal tax benefit) related to the same Oklahoma investment tax credits generated in the current year but not yet utilized due to management's determination that it is more likely than not that it will be unable to utilize these credits.
Where applicable, OG&E classifies income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2016,2018, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions.
Other
OG&E sustained Federalfederal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. As a result, OG&E had accrued Federalfederal and state income tax benefits carrying into2016. As OG&E can no longer carry these losses back to prior periods, these 2017, when the remaining federal net operating loss was utilized. State operating losses are being carried forward for utilization in future years which began in 2013.years. In addition to the tax operating losses, OG&E was unable to utilize the various tax credits that were generated during these years.These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods.Under current law, OG&E anticipates future taxable income will be sufficient to utilize all of theremaining losses and remaining credits before they begin to expire. The following table summarizes these carry forwards:
| | | (In millions) | Carry Forward Amount | Deferred Tax Asset | Earliest Expiration Date | Carry Forward Amount | Deferred Tax Asset | Earliest Expiration Date |
| Net operating losses | | | |
| State operating loss | $ | 403.1 |
| $ | 14.8 |
| 2030 | $ | 223.7 |
| $ | 10.0 |
| 2030 |
| Federal operating loss | 32.2 |
| 11.3 |
| 2030 | |
| Federal tax credits | 209.3 |
| 209.3 |
| 2029 | $ | 237.5 |
| $ | 237.5 |
| 2032 |
| State tax credits | | | |
| State tax credits: | | | |
| Oklahoma investment tax credits | 121.7 |
| 79.1 |
| N/A | $ | 144.3 |
| $ | 114.0 |
| N/A |
| Oklahoma capital investment board credits | 7.3 |
| 7.3 |
| N/A | $ | 8.9 |
| $ | 8.9 |
| N/A |
| Oklahoma zero emission tax credits | 24.1 |
| 16.2 |
| 2020 | $ | 24.1 |
| $ | 19.4 |
| 2020 |
N/A - not applicable
| |
8.9. | Common Stock and Cumulative Preferred Stock |
There were no new shares of common stock issued in 20162018, 20152017 or 20142016.
A summary of OG&E's long-term debt is included in the Statements of Capitalization. At December 31, 20162018, OG&E was in compliance with all of its debt agreements.
Industrial Authority Bonds
OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:
|
| | | | | | |
| SERIES | DATE DUE | AMOUNT |
| | | | | (In millions) |
| 0.05% | - | 0.90% | Garfield Industrial Authority, January 1, 2025 | $ | 47.0 |
|
| 0.07% | - | 0.83% | Muskogee Industrial Authority, January 1, 2025 | 32.4 |
|
| 0.05% | - | 0.86% | Muskogee Industrial Authority, June 1, 2027 | 56.0 |
|
| Total (redeemable during next 12 months) | $ | 135.4 |
|
|
| | | | | | |
| SERIES | DATE DUE | AMOUNT |
| | | | | (In millions) |
| 1.01% | - | 2.00% | Garfield Industrial Authority, January 1, 2025 | $ | 47.0 |
|
| 1.01% | - | 1.83% | Muskogee Industrial Authority, January 1, 2025 | 32.4 |
|
| 1.03% | - | 1.86% | 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 OG&E's Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.
Long-Term Debt Maturities
Maturities of OG&E's long-term debt during the next five years consist of $125.2 million, $250.1 million, $250.1$0.1 million, $0.1 million, $0.1 million and $0.1 million in years2017, 2018, 2019, 2020, 2021, 2022 and 2021,2023, respectively.
OG&E has previously incurred costs related to debt refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset,Asset. unamortizedUnamortized debt expense and unamortized premium and discount on long-term debt isare classified as Long-Term Debt, in the Balance Sheets and are being amortized over the life of the respective debt.
Issuance of Long-Term Debt
In August 2018, OG&E issued $400.0 million of 3.80 percent senior notes due August 15, 2028. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to fund the payment of OG&E's $250.0 million of 6.35 percent senior notes that matured on September 1, 2018, to repay short-term debt and to fund ongoing capital expenditures and working capital.
| |
10.11. | Short-Term Debt and Credit Facility |
OG&E's credit facility has a financial covenant requiring that OG&E maintain a maximum debt to capitalization ratio of 65 percent, as defined in the facility. OG&E's new facility also contains covenants which restrict, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. OG&E's new facility is subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in the new facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.
At December 31, 2016,2018, there were $49.9 million in advances from OGE Energy compared to $333.6$319.5 million in advances to OGE Energy compared to $112.5 million at December 31, 2015.2017. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400.0$350.0 million of OGE Energy's revolving credit amount. Effective July 29, 2013, OG&E extended theThis agreement has a termination date of this agreement to December 13, 2018. OG&E has a $400.0 million unsecured five-year revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.March 8, 2023. At December 31, 2016,2018, there was $1.8were no intercompany borrowings under this agreement. At December 31, 2018, there were $0.3 million supporting letters of credit at a weighted-average interest rate of 0.951.05 percent. There wereno outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 20162018.
In March 2017, OG&E entered into an unsecured five-year $450.0 million revolving credit agreement. The facility contained an option, which could be exercised up to two times, to extend the term of the facility for an additional year. Effective March 9, 2018, OG&E utilized one of those extensions to extend the maturity of its credit facility from March 8, 2022 to March 8, 2023.
OGE Energy's and OG&E's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy's and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would requireOG&Eto post collateral or letters of credit.
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 20172019 and ending December 31, 2018.2020.
| |
11.12. | Retirement Plans and Postretirement Benefit Plans |
Pension Plan and Restoration of Retirement Income Plan
OG&E's employees participate inOGE Energy'sPension Plan and Restoration of Retirement Income Plan.
It is OGE Energy's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by 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. During 2016, OGE Energy made a $15.0 million and $20.0 million contribution to its Pension Plan in 2018 and 2017, of which none$5.0 million is related to OG&E. During 2015, OGE Energy did not make any contributions&E in 2018 compared to its Pension Plan.$4.0 million related to OG&E in 2017. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2017.2019. Any contribution to the Pension Plan during 20172019 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. 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.
In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s
organization's net periodic pension cost. During the quarter ended June 30, 2016, OG&E experienced a settlement of its non-qualified Restoration of Retirement Income Plan. As a result, OG&E recorded pension settlement charges of $0.4 million during 2016, of which $0.4 million related to OG&E's Oklahoma jurisdiction2018 and has been included in the pension tracker. During 2015,2017, OG&E experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, OG&E recorded pension plan settlement charges of $10.0$19.8 million in the third quarter of 2015during 2018 and $4.2$11.7 million in the fourth quarter of 2015,during 2017, of which $12.5$18.1 million and $10.8 million, respectively, related to OG&E's Oklahoma jurisdiction and has been included in the pensionPension tracker. The pension settlement charges did not increase OG&E’s&E's total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods. During 2016, OG&E experienced a settlement of its non-qualified Restoration Income Plan. As a result, OG&E recorded pension settlement charges of $0.4 million during 2016, of which $0.4 million related to OG&E's Oklahoma jurisdiction and has been included in the Pension tracker.
OGE Energy provides a Restoration of Retirement Income Plan to those participants in OGE 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 OGE Energy's Pension Plan in the absence of limitations imposed by the Federalfederal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.
Obligations and Funded Status
The following table presents the status of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 20162018 and 20152017. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheets as discussed in Note 1. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods. OG&E's portion of the benefit obligation for OGE 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 OG&E's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 20162018 was $458.1417.6 million and $3.45.0 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 20152017 was $470.6469.0 million and $2.23.9 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 Balance Sheets are as follows:included in the following table.
| | | | Pension Plan | Restoration of Retirement
Income Plan | Postretirement
Benefit Plans | Pension Plan | Restoration of Retirement
Income Plan | Postretirement
Benefit Plans |
December 31 (In millions) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Change in Benefit Obligation | | |
| Change in benefit obligation | | |
| Beginning obligations | $ | 514.4 |
| $ | 543.5 |
| $ | 2.7 |
| $ | 2.8 |
| $ | 176.1 |
| $ | 217.6 |
| $ | 510.6 |
| $ | 500.5 |
| $ | 4.2 |
| $ | 4.0 |
| $ | 115.8 |
| $ | 166.4 |
|
| Service cost | 10.3 |
| 10.3 |
| 0.1 |
| 0.1 |
| 0.6 |
| 1.0 |
| 9.8 |
| 10.1 |
| 0.2 |
| 0.1 |
| 0.2 |
| 0.4 |
|
| Interest cost | 19.2 |
| 19.8 |
| 0.1 |
| 0.1 |
| 7.4 |
| 7.9 |
| 17.6 |
| 19.5 |
| 0.2 |
| 0.2 |
| 4.2 |
| 5.6 |
|
| Plan settlements | — |
| (36.5 | ) | (1.0 | ) | — |
| — |
| — |
| (52.6 | ) | (35.2 | ) | (0.6 | ) | — |
| — |
| (21.1 | ) |
| Plan amendments | | — |
| — |
| — |
| — |
| — |
| (29.4 | ) |
| Participants' contributions | — |
| — |
| — |
| — |
| 2.9 |
| 2.6 |
| — |
| — |
| — |
| — |
| 2.9 |
| 2.7 |
|
| Actuarial (gains) losses | 1.2 |
| (8.6 | ) | 2.1 |
| (0.1 | ) | (7.2 | ) | (40.0 | ) | |
| Actuarial losses (gains) | | (19.0 | ) | 28.8 |
| 2.0 |
| 0.1 |
| (6.5 | ) | 4.6 |
|
| Benefits paid | (44.6 | ) | (14.1 | ) | — |
| (0.2 | ) | (13.4 | ) | (13.0 | ) | (12.8 | ) | (13.1 | ) | — |
| (0.2 | ) | (11.8 | ) | (13.4 | ) |
| Ending obligations | $ | 500.5 |
| $ | 514.4 |
| $ | 4.0 |
| $ | 2.7 |
| $ | 166.4 |
| $ | 176.1 |
| $ | 453.6 |
| $ | 510.6 |
| $ | 6.0 |
| $ | 4.2 |
| $ | 104.8 |
| $ | 115.8 |
|
| | | |
| Change in Plans' Assets | | |
| Change in plans' assets | | |
| Beginning fair value | $ | 464.2 |
| $ | 532.5 |
| $ | — |
| $ | — |
| $ | 50.0 |
| $ | 54.2 |
| $ | 477.2 |
| $ | 457.3 |
| $ | — |
| $ | — |
| $ | 45.2 |
| $ | 47.8 |
|
| Actual return on plans' assets | 37.7 |
| (17.7 | ) | — |
| — |
| 1.8 |
| (0.5 | ) | (29.2 | ) | 64.2 |
| — |
| — |
| (0.5 | ) | 2.5 |
|
| Employer contributions | — |
| — |
| 1.0 |
| 0.2 |
| 6.5 |
| 6.7 |
| 5.0 |
| 4.0 |
| 0.6 |
| 0.2 |
| 4.8 |
| 26.7 |
|
| Plan settlements | — |
| (36.5 | ) | (1.0 | ) | — |
| — |
| — |
| (52.6 | ) | (35.2 | ) | (0.6 | ) | — |
| — |
| (21.1 | ) |
| Participants' contributions | — |
| — |
| — |
| — |
| 2.9 |
| 2.6 |
| — |
| — |
| — |
| — |
| 2.9 |
| 2.7 |
|
| Benefits paid | (44.6 | ) | (14.1 | ) | — |
| (0.2 | ) | (13.4 | ) | (13.0 | ) | (12.8 | ) | (13.1 | ) | — |
| (0.2 | ) | (11.8 | ) | (13.4 | ) |
| Ending fair value | $ | 457.3 |
| $ | 464.2 |
| $ | — |
| $ | — |
| $ | 47.8 |
| $ | 50.0 |
| $ | 387.6 |
| $ | 477.2 |
| $ | — |
| $ | — |
| $ | 40.6 |
| $ | 45.2 |
|
| Funded status at end of year | $ | (43.2 | ) | $ | (50.2 | ) | $ | (4.0 | ) | $ | (2.7 | ) | $ | (118.6 | ) | $ | (126.1 | ) | $ | (66.0 | ) | $ | (33.4 | ) | $ | (6.0 | ) | $ | (4.2 | ) | $ | (64.2 | ) | $ | (70.6 | ) |
Net Periodic Benefit Cost
OG&E adopted ASU 2017-07 in the first quarter of 2018 and, as a result, presents the service cost component of net benefit cost in operating income and the other components of net benefit cost as non-operating within its Statements of Income. Further, as required by ASU 2017-07, OG&E adjusted prior year income statement presentation of the net benefit cost components, which were previously presented in total within Other Operation and Maintenance in OG&E's Statements of Income. OG&E elected the practical expedient allowed by ASU 2017-07 to utilize amounts disclosed in OG&E's retirement plans and postretirement benefit plans note for the prior comparative period as the estimation basis for applying the retrospective presentation requirements.
The following table presents the net periodic benefit cost components, before consideration of capitalized amounts, of OG&E's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in OG&E's Statements of 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 Expense in OG&E's Statements of Income.
| | | | Pension Plan | Restoration of Retirement
Income Plan | Postretirement Benefit Plans | Pension Plan | Restoration of Retirement
Income Plan | Postretirement Benefit Plans |
Year ended December 31 (In millions) | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 |
| Service cost | $ | 10.3 |
| $ | 10.3 |
| $ | 9.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | — |
| $ | 0.6 |
| $ | 1.0 |
| $ | 2.0 |
| $ | 9.8 |
| $ | 10.1 |
| $ | 10.3 |
| $ | 0.2 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 0.2 |
| $ | 0.4 |
| $ | 0.6 |
|
| Interest cost | 19.2 |
| 19.8 |
| 21.4 |
| 0.1 |
| 0.1 |
| 0.1 |
| 7.4 |
| 7.9 |
| 8.8 |
| 17.6 |
| 19.5 |
| 19.2 |
| 0.2 |
| 0.2 |
| 0.1 |
| 4.2 |
| 5.6 |
| 7.4 |
|
| Expected return on plan assets | (33.1 | ) | (36.5 | ) | (35.8 | ) | — |
| — |
| — |
| (2.1 | ) | (2.2 | ) | (2.2 | ) | (33.1 | ) | (32.8 | ) | (33.1 | ) | — |
| — |
| — |
| (1.8 | ) | (2.0 | ) | (2.1 | ) |
| Amortization of net loss | 12.4 |
| 13.8 |
| 11.4 |
| 0.1 |
| 0.1 |
| 0.1 |
| 2.5 |
| 11.9 |
| 11.0 |
| 12.1 |
| 13.0 |
| 12.4 |
| 0.5 |
| 0.4 |
| 0.1 |
| 3.8 |
| 1.9 |
| 2.5 |
|
| Amortization of unrecognized prior service cost (A) | — |
| 0.5 |
| 1.9 |
| — |
| — |
| 0.1 |
| (6.1 | ) | (13.6 | ) | (13.7 | ) | — |
| — |
| — |
| — |
| — |
| — |
| (6.1 | ) | (2.5 | ) | (6.1 | ) |
| Settlement | — |
| 14.2 |
| — |
| 0.4 |
| — |
| — |
| — |
| — |
| — |
| |
| Settlement cost | | 19.4 |
| 11.7 |
| — |
| 0.4 |
| — |
| 0.4 |
| — |
| 0.4 |
| — |
|
| Total net periodic benefit cost | | 25.8 |
| 21.5 |
| 8.8 |
| 1.3 |
| 0.7 |
| 0.7 |
| 0.3 |
| 3.8 |
| 2.3 |
|
| Plus: Amount allocated from OGE Energy | | 5.7 |
| — |
| — |
| 1.2 |
| — |
| — |
| (0.7 | ) | — |
| — |
|
| Net periodic benefit cost (B) | $ | 8.8 |
| $ | 22.1 |
| $ | 8.0 |
| $ | 0.7 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 2.3 |
| $ | 5.0 |
| $ | 5.9 |
| $ | 31.5 |
| $ | 21.5 |
| $ | 8.8 |
| $ | 2.5 |
| $ | 0.7 |
| $ | 0.7 |
| $ | (0.4 | ) | $ | 3.8 |
| $ | 2.3 |
|
| |
| (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. |
| |
| (B) | In addition to the $11.833.6 million, $27.426.0 million and $14.211.8 million of net periodic benefit cost recognized in 20162018, 20152017 and 20142016, respectively, OG&E recognized the following: |
a change in pension expense in 20162018, 20152017 and 20142016 of $9.9(14.1) million, $(3.1)(2.3) million and $11.29.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1);
an increase in postretirement medical expense in 20162018, 20152017 and 20142016 of $7.94.4 million, $5.86.2 million and $5.2$7.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and
a deferral of pension expense in 2018, 2017 and 2016 and 2015 of $0.1$1.7 million, $0.9 million and $1.9$0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $19.8 million, $11.7 million and $0.4 million, and $14.2 million, respectively.respectively, which are included in the Arkansas deferred pension expense regulatory asset (see Note 1).
As required by ASU 2017-07, OG&E only capitalizes the service cost component of net benefit cost, beginning in the first quarter of 2018. Prior year capitalized amounts were not adjusted, as this change was implemented on a prospective basis.
| | | (In millions) | 2016 | 2015 | 2014 | 2018 | 2017 | 2016 |
| Capitalized portion of net periodic pension benefit cost | $ | 2.9 |
| $ | 2.6 |
| $ | 2.6 |
| $ | 3.2 |
| $ | 3.4 |
| $ | 2.9 |
|
| Capitalized portion of net periodic postretirement benefit cost | 0.8 |
| 1.6 |
| 1.8 |
| $ | 0.1 |
| $ | 1.1 |
| $ | 0.8 |
|
Rate Assumptions
|
| | | | | | | | | | | | |
| | Pension Plan and
Restoration of Retirement Income Plan | Postretirement
Benefit Plans |
| Year ended December 31 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 |
| Discount rate | 4.00 | % | 4.00 | % | 3.80 | % | 4.20 | % | 4.25 | % | 3.80 | % |
| Rate of return on plans' assets | 7.50 | % | 7.50 | % | 7.50 | % | 4.00 | % | 4.00 | % | 4.00 | % |
| Compensation increases | 4.20 | % | 4.20 | % | 4.20 | % | N/A |
| N/A |
| N/A |
|
| Assumed health care cost trend: | |
| |
| |
| |
| |
| |
|
| Initial trend | N/A |
| N/A |
| N/A |
| 6.75 | % | 6.10 | % | 7.85 | % |
| Ultimate trend rate | N/A |
| N/A |
| N/A |
| 4.50 | % | 4.50 | % | 4.48 | % |
| Ultimate trend year | N/A |
| N/A |
| N/A |
| 2026 |
| 2026 |
| 2028 |
|
|
| | | | | | | | | | | | |
| | Pension Plan and
Restoration of Retirement Income Plan | Postretirement
Benefit Plans |
| Year Ended December 31 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 |
| Assumptions to determine benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
| Discount rate | 4.20 | % | 3.60 | % | 4.00 | % | 4.30 | % | 3.70 | % | 4.20 | % |
| Rate of compensation increase | 4.20 | % | 4.20 | % | 4.20 | % | N/A |
| N/A |
| 4.20 | % |
| Assumptions to determine net periodic benefit cost: | | | |
| |
| |
| |
|
| Discount rate | 3.73 | % | 4.00 | % | 4.00 | % | 3.70 | % | 4.20 | % | 4.25 | % |
| 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 |
| 4.20 | % | 4.20 | % |
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.
The overall expected rate of return on plan assets assumption was 7.50 percent in both 20162018 and 20152017, which was used in determining net periodic benefit cost due to recent returns on OGE Energy's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.
The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 6.757.25 percent in 20172019 with the rates trending downward to 4.50 percent by 2026.2030. A one-percentage point change in the assumed health care cost trend rate would have the following effects:
| | ONE-PERCENTAGE POINT INCREASE | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| Effect on aggregate of the service and interest cost components | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Effect on accumulated postretirement benefit obligations | 0.1 |
| 0.1 |
| 0.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 0.1 |
|
| | ONE-PERCENTAGE POINT DECREASE | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| Effect on aggregate of the service and interest cost components | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Effect on accumulated postretirement benefit obligations | 0.5 |
| 0.5 |
| 0.5 |
| $ | 0.2 |
| $ | 0.2 |
| $ | 0.5 |
|
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 drivenliability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.
|
| | | | | | | |
| Projected Benefit Obligation Funded Status Thresholds | <90% | 95% | 100% | 105% | 110% | 115% | 120% |
| Fixed income | 50% | 58% | 65% | 73% | 80% | 85% | 90% |
| Equity | 50% | 42% | 35% | 27% | 20% | 15% | 10% |
| Total | 100% | 100% | 100% | 100% | 100% | 100% | 100% |
Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below. |
| | | |
| Asset Class | Target Allocation | Minimum | Maximum |
| Domestic Large Cap Equity | 40% | 35% | 60% |
| Domestic Mid-Cap Equity | 15% | 5% | 25% |
| Domestic Small-Cap Equity | 25% | 5% | 30% |
| International Equity | 20% | 10% | 30% |
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 OG&E's members and OGE 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 three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:
|
| |
| Asset Class | Comparative Benchmark(s) |
| Active Duration Fixed Income | Bloomberg Barclays Aggregate |
| Long Duration Fixed Income | Duration blended Barclays Long Government/Credit & Barclays Universal |
| Equity Index | Standard & Poor's 500 Index |
| Mid-Cap Equity | Russell Midcap Index |
| | Russell Midcap Value Index |
| Small-Cap Equity | Russell 2000 Index |
| | Russell 2000 Value Index |
| International Equity | Morgan Stanley Capital InvestmentInternational ACWI ex-USex-U.S. |
The fixed income managers are expected to use discretion over the asset mix of the trust assets in itstheir 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 gradeinvestment-grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor'sService, S&P's Global Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of OGE Energy's equity, debt or other securities is prohibited.
The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global
equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including:including regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-USex-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-USex-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 United States.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 OGE Energy'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 OGE Energy'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 summarizeOG&E's portion of OGE Energy'sPension Plan's investments that are measured at fair value on a recurring basis atDecember 31, 20162018 and2015. 2017. There were no Level 3 investments held by the Pension Plan at December 31, 20162018 and 20152017.
|
| | | | | | | | | | | | |
| (In millions) | December 31, 2016 | Level 1 | Level 2 | NAV |
| Common stocks | $ | 237.1 |
| $ | 237.1 |
| $ | — |
| $ | — |
|
| U.S. treasury notes and bonds (A) | 122.3 |
| 122.3 |
| — |
| — |
|
| Mortgage and asset-backed securities | 59.2 |
| — |
| 59.2 |
| — |
|
| Corporate fixed income and other securities | 137.6 |
| — |
| 137.6 |
| — |
|
| Commingled fund (B) | 23.8 |
| — |
| — |
| 23.8 |
|
| Foreign government bonds | 5.2 |
| — |
| 5.2 |
| — |
|
| U.S. municipal bonds | 1.9 |
| — |
| 1.9 |
| — |
|
| Money market fund | 2.2 |
| — |
| — |
| 2.2 |
|
| Mutual fund | 9.0 |
| 9.0 |
| — |
| — |
|
| Futures | | | | |
| U.S. Treasury futures (receivable) | 10.7 |
| — |
| 10.7 |
| — |
|
| U.S. Treasury futures (payable) | (2.3 | ) | — |
| (2.3 | ) | — |
|
| Cash collateral | 0.3 |
| 0.3 |
| — |
| — |
|
| Forward contracts | | | | |
| Receivable (foreign currency) | 0.2 |
| — |
| 0.2 |
| — |
|
| Total Plan investments | $ | 607.2 |
| $ | 368.7 |
| $ | 212.5 |
| $ | 26.0 |
|
| Receivable from broker for securities sold | — |
| |
| |
| |
| Interest and dividends receivable | 3.0 |
| |
| |
| |
| Payable to broker for securities purchased | (14.3 | ) | |
| |
| |
| Plan investments attributable to affiliates | (138.6 | ) | | | |
| Total Plan assets | $ | 457.3 |
| |
| |
| |
| | | (In millions) | December 31, 2015 | Level 1 | Level 2 | NAV | December 31, 2018 | Level 1 | Level 2 | Net Asset Value (A) |
| Common stocks | $ | 208.2 |
| $ | 208.2 |
| $ | — |
| $ | — |
| $ | 169.3 |
| $ | 169.3 |
| $ | — |
| $ | — |
|
| U.S. treasury notes and bonds (A) | 158.9 |
| 158.9 |
| — |
| — |
| |
| Mortgage-backed securities | 14.5 |
| — |
| 14.5 |
| — |
| |
| 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 | 140.2 |
| — |
| 140.2 |
| — |
| 143.2 |
| — |
| 143.2 |
| — |
|
Commingled fund (B)(C) | 24.4 |
| — |
| — |
| 24.4 |
| 19.7 |
| — |
| — |
| 19.7 |
|
| Foreign government bonds | 5.6 |
| — |
| 5.6 |
| — |
| 4.4 |
| — |
| 4.4 |
| — |
|
| U.S. municipal bonds | 4.9 |
| — |
| 4.9 |
| — |
| 0.6 |
| — |
| 0.6 |
| — |
|
| Interest-bearing cash | 0.4 |
| 0.4 |
| — |
| — |
| |
| Money market fund | 11.7 |
| — |
| — |
| 11.7 |
| 0.3 |
| — |
| — |
| 0.3 |
|
| Index fund | 1.8 |
| 1.8 |
| — |
| — |
| |
| Mutual fund | 24.3 |
| 24.3 |
| — |
| — |
| 8.0 |
| 8.0 |
| — |
| — |
|
| Preferred stocks | 0.3 |
| 0.3 |
| — |
| — |
| |
| Futures | | |
| Futures: | | |
| U.S. Treasury futures (receivable) | 17.6 |
| — |
| 17.6 |
| — |
| 27.0 |
| — |
| 27.0 |
| — |
|
| U.S. Treasury futures (payable) | (12.4 | ) | — |
| (12.4 | ) | — |
| (20.4 | ) | — |
| (20.4 | ) | — |
|
| Forward contracts | | |
| Cash collateral | | 0.7 |
| 0.7 |
| — |
| — |
|
| Forward contracts: | | |
| Receivable (foreign currency) | 0.1 |
| — |
| 0.1 |
| — |
| 0.1 |
| — |
| 0.1 |
| — |
|
| Payable (foreign currency) | (0.1 | ) | — |
| (0.1 | ) | — |
| |
| Total Plan investments | $ | 600.4 |
| $ | 393.9 |
| $ | 170.4 |
| $ | 36.1 |
| |
| Total Pension Plan investments | | $ | 556.7 |
| $ | 315.9 |
| $ | 220.8 |
| $ | 20.0 |
|
| Receivable from broker for securities sold | — |
| |
| |
| | — |
| |
| |
| |
| Interest and dividends receivable | 3.5 |
| |
| |
| | 3.0 |
| |
| |
| |
| Payable to broker for securities purchased | (22.2 | ) | |
| |
| | (36.9 | ) | |
| |
| |
| Plan investments attributable to affiliates | (117.5 | ) | | |
| Total Plan assets | $ | 464.2 |
| | |
| | |
| Pension Plan investments attributable to affiliates | | (135.2 | ) | |
| Total Pension Plan assets | | $ | 387.6 |
| |
| |
| |
| |
| (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. treasuryTreasury notes and bonds with a Moody's Investors ServicesService rating of Aaa and Government Agency Bonds with a Moody's Investors ServicesService 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, 2017 | Level 1 | Level 2 | Net Asset Value (A) |
| Common stocks | $ | 225.9 |
| $ | 225.9 |
| $ | — |
| $ | — |
|
| U.S. Treasury notes and bonds (B) | 169.7 |
| 169.7 |
| — |
| — |
|
| Mortgage- and asset-backed securities | 43.4 |
| — |
| 43.4 |
| — |
|
| Corporate fixed income and other securities | 153.8 |
| — |
| 153.8 |
| — |
|
| Commingled fund (C) | 29.9 |
| — |
| — |
| 29.9 |
|
| Foreign government bonds | 4.0 |
| — |
| 4.0 |
| — |
|
| U.S. municipal bonds | 1.2 |
| — |
| 1.2 |
| — |
|
| Money market fund | 4.3 |
| — |
| — |
| 4.3 |
|
| Mutual fund | 7.8 |
| 7.8 |
| — |
| — |
|
| Futures: | | | | |
| U.S. Treasury futures (receivable) | 13.4 |
| — |
| 13.4 |
| — |
|
| U.S. Treasury futures (payable) | (11.4 | ) | — |
| (11.4 | ) | — |
|
| Cash collateral | 0.3 |
| 0.3 |
| — |
| — |
|
| Forward contracts: | | | | |
| Receivable (foreign currency) | 0.1 |
| — |
| 0.1 |
| — |
|
| Total Pension Plan investments | $ | 642.4 |
| $ | 403.7 |
| $ | 204.5 |
| $ | 34.2 |
|
| Receivable from broker for securities sold | — |
| |
| |
| |
| Interest and dividends receivable | 3.2 |
| |
| |
| |
| Payable to broker for securities purchased | (10.3 | ) | |
| |
| |
| Pension Plan investments attributable to affiliates | (158.1 | ) | | | |
| Total Pension Plan assets | $ | 477.2 |
| | |
| |
| |
| (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. |
The three levels defined in the fair value hierarchy and examples of each are as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common and preferred stocks, U.S. treasuryTreasury notes and bonds, mutual funds index funds and interest-bearing cash.cash collateral.
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include mortgage- and asset-backed securities, corporate fixed income and other securities, mortgage-backed securities, a commingled fund, a common/collective trust,foreign government bonds, U.S. municipal bonds, foreign government bonds, money market fund, treasuryU.S. Treasury futures contracts and forward contracts.
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
Postretirement Benefit Plans
In addition to providing pension benefits, OGE 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 OGE 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.
OGE Energy's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and OGE 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. OGE Energy provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to OGE Energy'ssponsoredhealth reimbursement arrangement. OGE Energy's 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.
PlanPostretirement Plans Investments
The following tables summarizeOG&E's portion of OGE Energy'spostretirement benefit plansplans' investments that are measured at fair value on a recurring basis atDecember 31, 20162018 and2015. 2017. There werenoLevel 2 investments held by the postretirement benefit plans atDecember 31, 20162018 and2015. 2017.
| | | (In millions) | December 31, 2016 | Level 1 | Level 3 | December 31, 2018 | Level 1 | Level 3 |
Group retiree medical insurance contract (A) | $ | 44.7 |
| $ | — |
| $ | 44.7 |
| $ | 36.0 |
| $ | — |
| $ | 36.0 |
|
| Mutual funds investment | | |
| U.S. equity investments | 8.1 |
| 8.1 |
| — |
| |
| Mutual funds | | 8.9 |
| 8.9 |
| — |
|
| Cash | 0.3 |
| 0.3 |
| — |
| 0.9 |
| 0.9 |
| — |
|
| Total Plan investments | $ | 53.1 |
| $ | 8.4 |
| $ | 44.7 |
| |
| Total plan investments | | $ | 45.8 |
| $ | 9.8 |
| $ | 36.0 |
|
| Plan investments attributable to affiliates | (5.3 | ) | | (5.2 | ) | |
| Total Plan assets | $ | 47.8 |
|
|
|
|
| |
| Total plan assets | | $ | 40.6 |
|
|
|
|
|
|
| | | | | | | | | |
| (In millions) | December 31, 2015 | Level 1 | Level 3 |
| Group retiree medical insurance contract (A) | $ | 46.8 |
| $ | — |
| $ | 46.8 |
|
| Mutual funds investment | | | |
| U.S. equity investments | 7.8 |
| 7.8 |
| — |
|
| Money market funds investment | 0.7 |
| 0.7 |
| — |
|
| Total Plan investments | $ | 55.3 |
| $ | 8.5 |
| $ | 46.8 |
|
| Plan investments attributable to affiliates | (5.3 | ) | | |
| Total Plan assets | $ | 50.0 |
|
|
|
|
|
|
| | | | | | | | | |
| (In millions) | December 31, 2017 | Level 1 | Level 3 |
| Group retiree medical insurance contract | $ | 40.2 |
| $ | — |
| $ | 40.2 |
|
| Mutual funds | 9.5 |
| 9.5 |
| — |
|
| Cash | 0.5 |
| 0.5 |
| — |
|
| Total plan investments | $ | 50.2 |
| $ | 10.0 |
| $ | 40.2 |
|
| Plan investments attributable to affiliates | (5.0 | ) | | |
| Total plan assets | $ | 45.2 |
|
|
|
|
|
| |
(A) | This category represents a
The group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. |
The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plansplans' pro-rata share of the total assets in the contract.
The following table summarizes the postretirement benefit plansplans' investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
| | Year ended December 31 (In millions) | 2016 | |
| Group retiree medical insurance contract | | |
Year Ended December 31 (In millions) | | 2018 |
| Group retiree medical insurance contract: | | |
| Beginning balance | $ | 46.8 |
| $ | 40.2 |
|
| Interest income | 0.9 |
| 0.7 |
|
| Dividend income | 0.6 |
| 0.5 |
|
| Net unrealized gains related to instruments held at the reporting date | 0.2 |
| |
| Claims paid | | (4.6 | ) |
| Net unrealized losses related to instruments held at the reporting date | | (0.5 | ) |
| Realized losses | (0.1 | ) | (0.2 | ) |
| Claims paid | (3.7 | ) | |
| Investment fees | | (0.1 | ) |
| Ending balance | $ | 44.7 |
| $ | 36.0 |
|
Medicare Prescription Drug, Improvement and Modernization Act of 2003
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments OG&E expects to pay related to its postretirement benefit plans, including prescription drug benefits.
| | (In millions) | Gross Projected
Postretirement
Benefit
Payments | Gross Projected
Postretirement
Benefit
Payments |
| 2017 | $ | 11.4 |
| |
| 2018 | 11.4 |
| |
| 2019 | 11.3 |
| $ | 9.3 |
|
| 2020 | 11.3 |
| $ | 9.4 |
|
| 2021 | 11.2 |
| $ | 9.3 |
|
| After 2021 | 53.8 |
| |
| 2022 | | $ | 9.2 |
|
| 2023 | | $ | 7.9 |
|
| After 2023 | | $ | 35.9 |
|
The following table summarizes the benefit payments OG&E expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure OGE Energy's benefit obligation at the end of the year and include benefits attributable to estimated future employee service.
| | (In millions) | Projected Benefit Payments | Projected Benefit Payments |
| 2017 | $ | 35.3 |
| |
| 2018 | 37.0 |
| |
| 2019 | 40.3 |
| $ | 48.0 |
|
| 2020 | 42.3 |
| $ | 45.1 |
|
| 2021 | 42.7 |
| $ | 45.0 |
|
| After 2021 | 210.0 |
| |
| 2022 | | $ | 43.3 |
|
| 2023 | | $ | 43.5 |
|
| After 2023 | | $ | 191.9 |
|
Post-Employment Benefit Plan
Disabled employees receiving benefits from OGE Energy's Group Long-Term Disability Plan are entitled to continue participating in OGE 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 OGE Energy's Group Long-Term Disability Plan and their dependents, as defined in OGE 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 OGE Energy's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical
benefits. OG&E's post-employment benefit obligation was $2.11.7 million and $1.12.2 million at December 31, 20162018 and 20152017, respectively.
401(k) Plan
OGE Energy provides a 401(k) Plan. EachPlan, and each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of OGE 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 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attainedreached 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;thereof, (ii) a contribution made on a non Rothnon-Roth after-tax basis;basis or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with
the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or hertheir 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, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.
No OGE 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, OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE 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 OGE Energy or its affiliates. OG&E contributed $8.89.8 million, $8.29.7 million and $8.28.8 million in 20162018, 20152017 and 20142016, respectively, to the 401(k) Plan.
Deferred Compensation Plan
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 the Board of Directors of OGE Energy 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. OGE 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 OGE Energy or termination of the plan. Deferrals, plus any OGE 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 20162018, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock.
| |
12.13. | Commitments and Contingencies |
Operating Lease Obligations
OG&E has operating lease obligations expiring at various dates, primarily for railcar leases and wind farm land leases. Future minimum payments for noncancellable operating leases are as follows:
| | Year ended December 31 (In millions) | 2017 | 2018 | 2019 | 2020 | 2021 | After 2021 | Total | |
| Operating lease obligations | | | | | | | | |
Year Ended December 31 (In millions) | | 2019 | 2020 | 2021 | 2022 | 2023 | After 2023 | Total |
| Operating lease obligations: | | | | | | | | |
| Railcars | $ | 2.7 |
| $ | 1.7 |
| $ | 21.0 |
| $ | — |
| $ | — |
| $ | — |
| $ | 25.4 |
| $ | 18.6 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 18.6 |
|
| Wind farm land leases | 2.5 |
| 2.5 |
| 2.5 |
| 2.9 |
| 2.9 |
| 43.5 |
| 56.8 |
| 2.5 |
| 2.9 |
| 2.9 |
| 2.9 |
| 2.9 |
| 37.6 |
| 51.7 |
|
| Total operating lease obligations | $ | 5.2 |
| $ | 4.2 |
| $ | 23.5 |
| $ | 2.9 |
| $ | 2.9 |
| $ | 43.5 |
| $ | 82.2 |
| $ | 21.1 |
| $ | 2.9 |
| $ | 2.9 |
| $ | 2.9 |
| $ | 2.9 |
| $ | 37.6 |
| $ | 70.3 |
|
Payments for operating lease obligations were $8.5$4.1 million, $6.9$5.4 million and $5.9$8.5 million for the years ended December 31, 2016, 20152018, 2017 and 2014,2016, respectively.
Railcar Lease Agreement
As of December 31, 2018, OG&E has a noncancellable operating lease with a purchase option, covering approximately 1,2501,093 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's tariffs and fuel adjustment clauses.
On January 11, 2012,
At the end of the lease term, which was February 1, 2019, OG&E executedhad the option to either purchase the railcars at a five-yearstipulated fair market value or renew the lease. If OG&E chose not to purchase the railcars or renew the lease agreement for 135and the actual fair value of the railcars to replace railcars thatwas less than the stipulated fair market value, OG&E would have been taken outresponsible for the difference in those values up to a maximum of service or destroyed.
On October 14, 2014,$16.2 million. OG&E signed a separate three-year lease effective December 2014 for 131was also required to maintain all of the railcars to replace railcars that have been taken out of service or destroyed.it had under the operating lease.
On December 17, 2015,February 1, 2019, OG&E renewed the lease agreement effective February 1, 2016.2019, under similar terms and conditions, for a fleet of 780 railcars, expiring February 1, 2024. The number of railcars was reduced due to the conversion of Muskogee Units 4 and 5 to natural gas. At the end of the new lease term, which is February 1, 2019, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $18.3$6.8 million. OG&EThe railcar lease effective February 1, 2019 is also required to maintain all of the railcars it has undernot included in the operating lease.lease obligations table above.
Wind Farm Land Lease Agreements
OG&E has operating leases related to land for its Centennial, OU Spirit and Crossroads wind farms expiring at various dates. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their useful life.
Other Purchase Obligations and Commitments
OG&E's other future purchase obligations and commitments estimated for the next five years are as follows:
| | | (In millions) | 2017 | 2018 | 2019 | 2020 | 2021 | Total | 2019 | 2020 | 2021 | 2022 | 2023 | Total |
| Other purchase obligations and commitments | | |
| Other purchase obligations and commitments: | | |
Cogeneration capacity and fixed operation and maintenance payments | $ | 77.1 |
| $ | 73.9 |
| $ | 66.5 |
| $ | 54.7 |
| $ | 51.0 |
| $ | 323.2 |
| $ | 10.9 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 10.9 |
|
Expected cogeneration energy payments | 37.7 |
| 37.5 |
| 38.9 |
| 40.7 |
| 44.4 |
| 199.2 |
| 2.4 |
| — |
| — |
| — |
| — |
| 2.4 |
|
| Minimum fuel purchase commitments | 236.2 |
| 49.3 |
| 36.2 |
| 24.6 |
| 24.6 |
| 370.9 |
| |
| Minimum purchase commitments | | 75.8 |
| 44.6 |
| 44.6 |
| 44.6 |
| 44.6 |
| 254.2 |
|
| Expected wind purchase commitments | 59.0 |
| 57.9 |
| 56.6 |
| 57.1 |
| 57.5 |
| 288.1 |
| 56.3 |
| 56.9 |
| 57.1 |
| 57.5 |
| 58.0 |
| 285.8 |
|
| Long-term service agreement commitments | 2.2 |
| 28.4 |
| 22.2 |
| 2.4 |
| 2.4 |
| 57.6 |
| 46.8 |
| 2.4 |
| 2.4 |
| 2.4 |
| 14.4 |
| 68.4 |
|
| Mustang Modernization expenditures | 130.4 |
| 21.9 |
| — |
| — |
| — |
| 152.3 |
| |
| Environmental compliance plan expenditures | 169.2 |
| 63.0 |
| 8.9 |
| 0.2 |
| — |
| 241.3 |
| 5.8 |
| 0.2 |
| — |
| — |
| — |
| 6.0 |
|
| Total other purchase obligations and commitments | $ | 711.8 |
| $ | 331.9 |
| $ | 229.3 |
| $ | 179.7 |
| $ | 179.9 |
| $ | 1,632.6 |
| $ | 198.0 |
| $ | 104.1 |
| $ | 104.1 |
| $ | 104.5 |
| $ | 117.0 |
| $ | 627.7 |
|
| |
| (A) | Cogeneration capacity, fixed operation and maintenance and energy payments will end in 2019, as a result of contract expiration. As described below, OG&E intends to acquire the AES and Oklahoma Cogeneration LLC power plants, pending regulatory approval. |
Public Utility Regulatory Policy Act of 1978
At December 31, 20162018, OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019 and a QF contract with AES-Shady Point, Inc.AES which expiresexpired on January 15, 2023.2019. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978. Stated generally, the Public Utility Regulatory Policy Act of 1978 and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a QF. The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E;&E, and the other is a capacity charge, which OG&E must pay the QF for having the capacity available. However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E's obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. For the 320 MWs AES-Shady Point, Inc.AES QF contract and the 120 MWs Oklahoma Cogeneration LLC QF contract, OG&E purchases 100 percent of the electricity generated by the QFs.
As part of the QF contract with AES, OG&E had the option to provide notice to AES to terminate the contract, and on August 24, 2018, OG&E notified AES that OG&E was exercising this option to terminate the contract, effective January 15, 2019. OG&E subsequently issued a request for proposals to fill the capacity need created by the termination of this QF contract. On
December 20, 2018, OG&E announced its plan to acquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to meet customers' energy needs. Further discussion can be found in Note 14.
For the years ended December 31, 20162018, 20152017 and 20142016, OG&E made total payments to cogenerators of $124.8112.4 million, $124.0115.2 million and $129.4124.8 million, respectively, of which $66.360.0 million, $69.563.0 million and $72.366.3 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as Cost of Sales.
Minimum Fuel Purchase Commitments
OG&E has coal contracts for purchases through December 2017.March 31, 2019, whereby OG&E has the right but not the obligation to 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 now purchases a relatively small percentage of its natural gas supply through long-termshort-term agreements. Alternatively, OG&E relies on a combination of call natural gas call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.
OG&E has natural gas transportation service contracts with Enable and ONEOK, Inc. The contract with Enable expires in April 2019, and in October 2018, OG&E and Enable agreed to a new contract that will be effective as of April 2019 for a five year period ending May 2024. The contracts with ONEOK, Inc. end in March 2019 and August 2037. These transportation contracts grant Enable and ONEOK, Inc. the responsibility of delivering natural gas to OG&E's generating facilities.
Wind Purchase Commitments
OG&E's current wind power portfolio includes the following, in addition to&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms owned byfarms. OG&E:(i) access to up to50MWs of electricity generated at a&E's current wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expirespower portfolio also includes purchased power contracts as listed in 2018, (ii) access to up to152MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to130MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2031 and (iv) access to up to60MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032.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 |
The following table summarizes OG&E's wind power purchases for the years ended December 31, 20162018, 20152017 and 20142016.
| | Year ended December 31 (In millions) | 2016 | 2015 | 2014 | |
Year Ended December 31 (In millions) | | 2018 | 2017 | 2016 |
| CPV Keenan | $ | 29.2 |
| $ | 26.7 |
| $ | 28.1 |
| $ | 27.0 |
| $ | 29.0 |
| $ | 29.2 |
|
| Edison Mission Energy | 21.1 |
| 19.7 |
| 21.3 |
| 21.7 |
| 22.1 |
| 21.1 |
|
| FPL Energy | 3.4 |
| 3.2 |
| 3.6 |
| |
| NextEra Energy | 7.3 |
| 7.0 |
| 7.8 |
| 6.8 |
| 7.4 |
| 7.3 |
|
| FPL Energy (A) | | 2.1 |
| 2.6 |
| 3.4 |
|
| Total wind power purchased | $ | 61.0 |
| $ | 56.6 |
| $ | 60.8 |
| $ | 57.6 |
| $ | 61.1 |
| $ | 61.0 |
|
| |
| (A) | OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018. |
Long-Term Service Agreement Commitments
OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 4,800 factored-fired starts. On December 30, 2015, the McClain LTSALong-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 2030.2031. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.
OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2028.2029. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.
Enable Gas Transportation Agreement
OG&E contracts with Enable for firm non-notice load following gas transportation services, under a five year contract. The contract will expire in April 2019. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will be effective upon the conversion of units 4 and 5 at Muskogee from coal to gas.
Environmental Laws and Regulations
The activities of OG&E are subject to numerous stringent and complex Federal,federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current Federal,federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to itsfinancial position or results of operations.OG&Ebelieves, however, that it is likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court.OG&E is unable to predict the financial impact of these matters with certainty at this time.
Air Quality Control System
On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulatingThe Dry Scrubber systems to be installed atsystem on Sooner UnitsUnit 1 completed certain emission testing in October 2018 and 2. OG&E enteredwas placed into an agreement on February 9, 2015, to install theservice. The Dry Scrubber systems. The Dry Scrubbers are scheduled to besystem on Sooner Unit 2 completed by 2019.certain emission testing in January 2019 and was placed into service. More detail regarding the ECP can be found under the "Pending Regulatory Matters" in Note 13.14.
Clean Power Plan
On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO2 emissions from existing fossil-fuel-fired power plants along with state-specific CO2 reduction standards expressed as both rate-based (lbs/(lbs./MWh) and mass-based (tons/yr)yr.) goals. The 2030 rate-based reduction requirement for all existing generating unitsHowever, the rule was challenged in Oklahoma has decreased from a proposed 43 percent reduction to 32 percent in the final rule. The mass-based approach for existing units calls for a 24 percent reduction by 2030 in Oklahoma.
A number of states, including Oklahoma, filed lawsuits against the Clean Power Plan. On February 9, 2016,court when it was issued, and the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan on February 9, 2016 pending resolution of challengesthe court challenges. The EPA published a proposal on October 16, 2017 to repeal the rule. OG&E is unable to determine what impactClean Power Plan. On August 31, 2018, without acting on the lawsuits will ultimately have onproposed repeal of the Clean Power Plan, or what impact the stay in implementation will have; however, ifEPA published a proposed rule to replace the Clean Power Plan survives judicial reviewPlan. The ultimate timing and is implemented as written, itimpact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect ourOG&E's future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of these standards on our operations cannot be determined with certainty at this time.
Siemens Contract
On June 15, 2015 OG&E entered into a contract with Siemens Energy Inc. for the purchase, design and engineering of seven simple-cycle gas turbine generators for $170.3 million associated with the Mustang Modernization Plan.
Other
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on current available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.
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13.14. | Rate Matters and Regulation |
Regulation and Rates
OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 20162018, 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E,&E; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customerscustomers; and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate
transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
FERC Order No. 1000, Final Rule on Transmission Planning and Cost AllocationOklahoma Rate Review Filing - January 2018
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansionsJanuary 16, 2018, OG&E filed a general rate review in Oklahoma, requesting a rate increase of $1.9 million per year, assuming a 9.9 percent return on equity. The filing sought recovery of the seven combustion turbines that are part of the Mustang Modernization Plan, an increase in depreciation rates to levels similar with rates in existence prior to the March 2017 OCC rate order and credit to customers for the impacts of the 2017 Tax Act, which was enacted on December 22, 2017.
On December 22, 2017, the Attorney General of Oklahoma requested that the OCC reduce the rates and charges for electric transmission grid alongservice and provide for an immediate refund due to the customers of OG&E resulting from the 2017 Tax Act. In response, on January 4, 2018, the OCC ordered OG&E to record a reserve, beginning on January 4, 2018, to reflect the reduced federal corporate tax rate of 21 percent and the amortization of excess accumulated deferred income tax and any other tax implications of the 2017 Tax Act on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings and a final order was issued in the rate review. Further, the OCC ordered the amounts of any refunds of such reserves owed to customers should accrue interest at a rate equivalent to OG&E's cost of capital as previously recognized in the March 2017 OCC rate order. OG&E reserved the excess income taxes collected in current rates and any amortization of excess accumulated deferred income taxes associated with the corresponding process2017 Tax Act, plus interest, from January 2018 through June 2018.
On June 19, 2018, the OCC approved a Joint Stipulation and Settlement Agreement. Key terms of the settlement include the following:
an annual net decrease of $64.0 million in OG&E's rates to its Oklahoma retail customers, which reflects recovery of the Mustang Modernization Plan, offset by reductions for allocating the costsimpact of such expansions. Order No. 1000 requires individual regionsthe lower corporate income taxes resulting from the 2017 Tax Act;
for purposes of calculating the Allowance for Funds Used During Construction and OG&E's various recovery riders that include a full return component, use of the most-recently approved return on equity of 9.5 percent and a capital structure of 47 percent debt/53 percent equity;
depreciation rates remain unchanged from the current depreciation rates approved in the March 2017 OCC rate order;
regulatory asset treatment for the Dry Scrubbers at Sooner Units 1 and 2 that will defer the non-fuel operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes, subject to determinea prudence review in a future general rate review and a determination as to whether a previously-approvedthe project is subjectused and useful;
production tax credits will be removed from base rates and placed into a separate rider;
a federal tax credit rider will be established to reevaluationrefund to customers the amount of excess taxes received from January to June 2018, as discussed above, and is therefore governed by the ongoing annual true up of excess accumulated deferred income taxes resulting from the reduction in corporate income tax rates as part of the 2017 Tax Act (further discussed in Note 8); and
the demand program rider tariff will be revised to allow for concurrent recovery of lost revenues from foregone sales due to certain achieved energy efficiency and demand savings.
As a result of the settlement, new rule.rates were implemented on July 1, 2018, reflecting the impacts of the order, and the tax reserve balance estimated for January 2018 through June 2018 of $18.9 million was returned to Oklahoma customers during the July billing cycle. As reserved amounts were estimated through June 2018, a true-up mechanism exists for the difference between the estimate and actuals to be calculated after the determination of year-end financial results.
Demand Program Rider - Energy Efficiency Lost Net Revenues
During the May 2017 implementation of new rates from the March 2017 OCC rate order, OG&E reserved $5.6 million, pending resolution of a dispute with the OCC's Public Utility Division staff regarding recovery of certain lost revenues associated with energy efficiency programs incurred prior to the March 2017 OCC rate order. These lost revenues are recovered through the Demand Program Rider as disclosed in Note 1. This dispute was resolved through the June 19, 2018 Oklahoma rate review settlement discussed above; as a result, the reserve was reversed at June 30, 2018, and an adjustment was recorded to the Demand Program Rider regulatory asset balance.
Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities.
The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement.
On July 1, 2016, the Court upheld the FERC's decision requiring removal of the "right of first refusal" for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the "right of first refusal" in the SPP Membership Agreement to be anticompetitive.
OG&E does not believe the Court’s ruling will have any impact on existing transmission projects for which OG&E has already received a notice to construct from the SPP. OG&E intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV.
Fuel Adjustment Clause Review for Calendar Year 20142016
On July 28, 2015,August 3, 2017, the OCC StaffOCC's Public Utility Division staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014,2016, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 7, 2018, an intervenor filed a recommendation to disallow the Oklahoma jurisdictional portion of $3.3 million related to wind sales in the SPP. On April 4, 2018, a Joint Stipulation and Settlement Agreement was filed with the OCC. As part of the agreement, the stipulating parties settled all claims regarding the issue of wind energy settlement costs for the period September 2016 through May 26, 2016,2017, and OG&E agreed to refund $2.4 million to customers related to wind sales in the SPP. On April 25, 2018, the OCC issued a final order, finding that forapproved the calendar year 2014Joint Stipulation and Settlement Agreement, and in May 2018, OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.&E refunded this settlement amount to customers.
Oklahoma Demand ProgramFERC - Request for Waiver
On May 22, 2018, OG&E submitted a request for waiver of applicable formula rate provisions in OG&E's Open Access Transmission Tariff and the SPP's Open Access Transmission Tariff. OG&E requested a waiver, effective January 1, 2018, to revise its 2018 projected net revenue requirement to reflect the federal corporate income tax rate reduction from 35 percent to 21 percent as a result of the 2017 Tax Act. On June 29, 2018, the FERC granted OG&E's request for waiver, effective January 1, 2018, which will allow OG&E to lower its current year projected net revenue requirement and provide benefits to customers through lower rates more promptly than if OG&E were to wait until the current year true-up adjustment to recognize the reduced federal corporate income tax rate. Based on the order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice. As the SPP adjusts the rates billed to OG&E's customers, OG&E reverses the reserve as the previous months in 2018 are resettled based on the lower tax rate.
APSC Order - 2017 Tax Act
On January 12, 2018, as a result of the 2017 Tax Act, the APSC ordered OG&E to prepare and file an analysis of the ratemaking effects of the 2017 Tax Act on OG&E's revenue requirement and begin, effective January 1, 2018, to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act. On July 26, 2018, the APSC ordered OG&E to file a separate rider that includes the reduction in tax expense due to the 2017 Tax Act and amortization of the applicable excess accumulated deferred income taxes as a reduction in revenue requirement. On August 27, 2018, OG&E filed the request for a new Tax Adjustment Rider Review - SmartHours Programas well as filed updates to all riders with tax implications, which were then approved by the APSC on September 24, 2018. All rider changes were implemented on October 1, 2018. In October 2018, OG&E refunded the excess income taxes collected from January 1, 2018 through September 30, 2018 and also began refunding the amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus carrying charges, from January 2018 through September 2018, which was approximately $7.7 million. As reserved amounts were estimated through September 2018, a true-up mechanism exists for the difference between the estimate and actuals to be calculated after the determination of year-end financial results.
Integrated Resource Plans
In July 2012,September 2018, OG&E filed an application withsubmitted its final 2018 IRP to the OCC to recover certain costs associated with demand programs through the Oklahoma Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off-peak hours during the months of May through October, by offering lower rates to those customers in the off-peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit fromAPSC. The 2018 IRP identified a need for capacity, and OG&E issued a request for proposals to identify options to fill that capacity need. See "Pre-Approval for Acquisition of Existing Power Plants" under "Pending Regulatory Matters" for further discussion regarding the reductionoutcome of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.request for proposal process.
In December 2012, the OCC issued an order approving the recovery of costs associated with the demand programs, including the lost revenues associated with the SmartHours program, subject to the PUD Staff's review.Demand Program Portfolio Filing
In March 2014,Pursuant to OCC rules, OG&E is required to propose, implement and administer a portfolio of demand programs once every three years. On July 1, 2018, OG&E filed its proposed Demand Program Three Year Portfolio for the PUD Staff began their review of the demand2019 through 2021 program costs, including the lost revenues associated with the SmartHours program.
On August 9, 2016, OG&E entered into a settlement agreement with the PUD Staff to resolve the recoverable amount of lost revenues associated with the SmartHours program. The settlement provides for recovery of $10.1 million per year for 2013, 2014cycle, and 2015, for a total of $30.3 million. OG&E had recorded $36.6 million of lost revenues for 2013, 2014 and 2015. On August 16, 2016,on December 27, 2018, the OCC issued an order adopting the settlement agreement. Accordingly,approved OG&E reduced lost revenues and the Oklahoma Demand Program Rider regulatory asset by $6.3 million.
Mustang Modernization Plan - Arkansas
On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to seek approval from the APSC to construct a power-
generating facility located outside the boundaries of the state of Arkansas. The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings. In July 2016, OG&E filed a motion to dismiss this proceeding and in August, the APSC approved the dismissal. OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service. &E's 2019 through 2021 demand portfolio programs.
Pending Regulatory Matters
Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.
Environmental Compliance Plan
On August 6, 2014, OG&E filed an application under Oklahoma Statute Title 17, Section 286 (B) with the OCC for approval of its plan to comply with the EPA’sEPA's MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP, and for a recovery mechanism for the associated costs. The ECPwhich includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas.gas, as well as a recovery mechanism for the associated costs. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 400 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs.
On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.
On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP under Oklahoma Statute Title 17, Section 286 (B), and on December 23, 2015, the OCC rejected OG&E's motion.
On February 12, 2016, OG&E filed an application under Oklahoma Statute Title 17, Section 151, et seq. requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed, and OG&E seeks recovery in its rates. a general rate review. On April 28, 2016, the OCC approved the Dry Scrubber project.
Two parties appealed the OCC's decision to the Oklahoma Supreme Court. OG&Eis unable to predict what actionOn April 24, 2018, the Oklahoma Supreme Court may take orruled that the timingOCC did not have the authority to grant pre-approval of any such action.OG&E's Dry Scrubber project outside the authority of Oklahoma Statute Title 17, Section 286 (B).
OG&E anticipates the total cost of Dry Scrubbers will be $547.5$520.0 million, including allowance for funds used during construction and capitalized ad valorem taxes. The Dry Scrubber system on Sooner Unit 1 completed certain emission testing in October 2018 and was placed into service. The Dry Scrubber system on Sooner Unit 2 completed certain emission testing in January 2019 and was placed into service. As of December 31, 2016,2018, OG&E hadhas invested $208.7$504.3 million of construction work in progress on the Dry Scrubbers. On December 31, 2018, OG&E anticipatesfiled a rate review with the total costOCC seeking recovery for the Mustang Modernization Plan will be $424.9 million and expects theDry Scrubber project, to be completed in late 2017. As of December 31, 2016, OG&E had invested $187.8 million on the Mustang Modernization Plan. as further discussed below.
Integrated Resource Plans FERC - Section 206 Filing
In October 2015,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 finalizedin calculating formula transmission rates under the 2015 IRPSPP Open Access Transmission Tariff is unjust and submitted itunreasonable and should be reduced from 10.60 percent to 7.85 percent, effective upon the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other partsdate of the plan. Currently,complaint. OG&E is scheduled to update its IRP in Arkansas by October 1, 2017 and in Oklahoma by October 1, 2018.
Oklahoma Rate Case Filing
On December 18, 2015,has reserved an amount within this range. OG&E filedestimates that if the FERC ultimately orders a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53 percent. The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million. Each 0.25 percent changereduction, each 25 basis point reduction in the requested return on equity affects the requested rate increasewould reduce OG&E's SPP Open Access Transmission Tariff transmission revenues by approximately $9.0 million.
In late March 2016,$1.5 million annually. OG&E contested the PUD Staff and other intervenors filed testimony in the case. The PUD Staff recommended a $6.1 million annual rate increase based on areduction of its base return on equity of 9.25 percent and a common equity percentage of 53 percent. Included
in the PUD Staff's recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement.
The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent, as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent. Included in the Oklahoma Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement.
The Oklahoma Industrial Energy Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent. Included in the Oklahoma Industrial Energy Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement.
On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million which is subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case. As of December 31, 2016, OG&E has recorded $39.0 million of revenues from the interim rate increase and has reserved $33.7 million of that revenue.
In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations include, among other things, the use of OG&E's actual capital structure of 53 percent equity and 47 percent long-term debt and a return on equity of 9.87 percent resulting in an annual increase in OG&E's revenues of $40.7 million. The parties provided comments on the ALJ's report in early January 2017, and the OCC held hearings in early February 2017.equity. While OG&E is unable to predict what final action the OCCFERC will take in response to the Oklahoma Municipal Power Authority's complaint or the timing of such action.action, if the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could have a material adverse effect on OG&E's financial position, results of operations and cash flows.
Arkansas Rate Case Filing In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. Based on an order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice, as discussed under "FERC - Request for Waiver" above. Further, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act.
On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management costs, and increased recovery of depreciation and dismantlement costs. A hearing in this matter is scheduled for the second quarter of 2017.
Fuel Adjustment Clause Review for Calendar Year 20152017
On September 8, 2016,July 9, 2018, the OCC Staffstaff filed an application to review OG&E’s&E's fuel adjustment clause for the calendar year 2015,2017, including the prudence of OG&E’s&E's electric generation, purchased power and fuel procurement costs. A hearing on the merits was held in this CauseDecember 2018, and 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. This recommendation is subject to OCC approval.
Arkansas Formula Rate Plan Filing
Per OG&E's settlement in its last general rate review in Arkansas, OG&E filed an evaluation report under its Formula Rate Plan on October 1, 2018, requesting a $6.4 million revenue increase. On January 30, 2019, OG&E and settling parties reached a settlement agreement for a $3.3 million revenue increase. The settlement agreement is subject to APSC approval. A final order is expected from the APSC in March 2019, and new rates will be heldbecome effective on March 30, 2017. April 1, 2019.
Oklahoma Rate Review Filing - December 2018
On December 31, 2018, OG&E filed a general rate review with the OCC, requesting a rate increase of $77.6 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 comply with the Regional Haze Rule. The filing also seeks to align OG&E's return on equity more closely to the industry average and to align OG&E's depreciation rates to more realistically reflect its assets' lifespans.
Pre-Approval for Acquisition of Existing Power Plants
On December 28, 2018, OG&E filed an application for pre-approval from the OCC to acquire a 360 MW coal- and natural gas-fired plant from AES and a 146 MW natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC in 2019 for $53.5 million. The purchase of these assets is intended to replace capacity currently provided by power purchase contracts set to expire in 2019 and to help OG&E satisfy its customers' energy needs and load obligations to the SPP. In addition, the filing seeks approval of a rider mechanism to collect costs associated with the purchase of these generating facilities.
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14.15. | Quarterly Financial Data (Unaudited) |
Due to the seasonal fluctuations and other factors of OG&E's business, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In OG&E's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized quarterly unaudited financial data is as follows:
| | Quarter ended (In millions) | | March 31 | June 30 | September 30 | December 31 | Total | |
Quarter Ended (In millions) | | | March 31 | June 30 | September 30 | December 31 | Total |
| Operating revenues | 2016 | $ | 433.1 |
| $ | 551.4 |
| $ | 743.9 |
| $ | 530.8 |
| $ | 2,259.2 |
| 2018 | $ | 492.7 |
| $ | 567.0 |
| $ | 698.8 |
| $ | 511.8 |
| $ | 2,270.3 |
|
| | 2015 | $ | 480.1 |
| $ | 549.9 |
| $ | 719.8 |
| $ | 447.1 |
| $ | 2,196.9 |
| 2017 | $ | 456.0 |
| $ | 586.4 |
| $ | 716.8 |
| $ | 501.9 |
| $ | 2,261.1 |
|
| Operating income | 2016 | $ | 38.6 |
| $ | 131.4 |
| $ | 257.2 |
| $ | 81.7 |
| $ | 508.9 |
| 2018 | $ | 67.1 |
| $ | 138.3 |
| $ | 230.3 |
| $ | 58.5 |
| $ | 494.2 |
|
| | 2015 | $ | 57.3 |
| $ | 127.5 |
| $ | 255.7 |
| $ | 59.9 |
| $ | 500.4 |
| 2017 | $ | 49.6 |
| $ | 147.2 |
| $ | 248.2 |
| $ | 83.0 |
| $ | 528.0 |
|
| Net income | 2016 | $ | 6.1 |
| $ | 72.3 |
| $ | 159.9 |
| $ | 45.8 |
| $ | 284.1 |
| 2018 | $ | 31.3 |
| $ | 92.0 |
| $ | 183.9 |
| $ | 20.8 |
| $ | 328.0 |
|
| | 2015 | $ | 17.1 |
| $ | 69.0 |
| $ | 162.9 |
| $ | 19.9 |
| $ | 268.9 |
| 2017 | $ | 16.2 |
| $ | 86.2 |
| $ | 161.5 |
| $ | 41.6 |
| $ | 305.5 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheTo the Board of Directors and Stockholder
of Oklahoma Gas and Electric CompanyCompany.
Opinion on the Financial Statements
We have audited the accompanyingbalance sheets and statements of capitalization of Oklahoma Gas and Electric Company (the Company) "Company") as ofDecember 31, 20162018 and2015, and 2017, the relatedstatements of income, comprehensive income, stockholder's equity, and cash flowsandchanges instockholder's equityfor each of the three years in the period endedDecember 31, 2016. Our audits also included2018, and the related notes and financial statement schedule listed in the Index at Item 15(a).These financial statementsand scheduleare (collectively referred to as the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statementsand schedulebased on our audits.
We conducted our audits in accordance withthe standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.An audit also includesassessing theaccounting principles used andsignificantestimates made by management, as well as evaluating the overallfinancial statementpresentation"financial statements"). We believe that our auditsprovide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position ofOklahoma Gas and Electric the Companyat as of December 31, 20162018 and2015, 2017, and theresults of its operations and its cash flows for each of the three years in the period endedDecember 31, 2016, 2018, in conformity with U.S. generally accepted accounting principles.Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Oklahoma Gas and Electricthe Company's internal control over financial reporting as of December 31, 2016,2018, 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, 201720, 2019, 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 include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Oklahoma City, Oklahoma
February 22, 201720, 2019
We have served as the Company's auditor since 2002.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
OG&E maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by OG&E in reports that it files or submits 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 OG&E's management, including the chief executive officer and chief financial officer, of the effectiveness of OG&E's 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 OG&E's disclosure controls and procedures are effective.
No change in OG&E's internal control over financial reporting has occurred during OG&E's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, OG&E's 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 OG&E is responsible for establishing and maintaining adequate internal control over financial reporting. OG&E's internal control system was designed to provide reasonable assurance to OG&E's management and 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.
OG&E management assessed the effectiveness of OG&E's internal control over financial reporting as of December 31, 20162018. 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, 20162018, OG&E's internal control over financial reporting is effective based on those criteria.
OG&E's independent auditors have issued an attestation report on OG&E's internal control over financial reporting. This report appears on the following page.
|
| | |
| /s/ Sean Trauschke | | /s/ Scott ForbesSarah R. Stafford |
| Sean Trauschke, Chairman of the Board, President | | Scott Forbes,Sarah R. Stafford, Controller |
| and Chief Executive Officer | | and Chief Accounting Officer |
| | | |
| /s/ Stephen E. Merrill | | |
| Stephen E. Merrill | | |
| Chief Financial Officer | | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheTo the Board of Directors and Stockholder
of Oklahoma Gas and Electric CompanyCompany.
Opinion on Internal Control over Financial Reporting
We have auditedOklahoma Gas and Electric Company'sinternal control over financial reporting as ofDecember 31, 2016, 2018, 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, 2018, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2018 financial statements of the Company and our report dated February 20, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Company'smanagement 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 Overover Financial Reporting. Our responsibility is to express an opinion on the company'sCompany'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 Public Company Accounting Oversight Board (United States).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.
In our opinion,Oklahoma Gas and Electric Companymaintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2016 and 2015, and the related statements of income, comprehensive income, cash flows and changes in stockholder's equity for each of the three years in the period ended December 31, 2016 of Oklahoma Gas and Electric Company and our report dated February 22, 2017 expressed an unqualified opinion thereon.
Oklahoma City, Oklahoma
February 22, 201720, 2019
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Code of Ethics Policy
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 OGE Energy's website address www.oge.comwww.ogeenergy.com under the heading "Investors," "Investor Relations," "Corporate Governance."Governance." The code of ethics will be provided, free of charge, upon request. OGE 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. OGE Energy will also include in its proxy statement information regarding the Audit Committee financial experts.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 has been omitted.
Item 11. Executive Compensation.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 11 has been omitted.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 12 has been omitted.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 has been omitted.
Item 14. Principal AccountingAccountant 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 | 2016 | 2015 | |
| Year Ended December 31 | | 2018 | 2017 |
| Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting | $ | 1,185,800 |
| $ | 1,141,700 |
| $ | 1,136,800 |
| $ | 1,234,800 |
|
| Services in support of debt and stock offerings | — |
| — |
| 65,000 |
| 100,000 |
|
| Other (A) | 302,200 |
| 299,100 |
| 312,000 |
| 312,000 |
|
| Total audit fees (B) | 1,488,000 |
| 1,440,800 |
| 1,513,800 |
| 1,646,800 |
|
| Employee benefit plan audits | 138,000 |
| 133,000 |
| 144,000 |
| 144,000 |
|
| Total audit-related fees | 138,000 |
| 133,000 |
| 144,000 |
| 144,000 |
|
Assistance with examinations and other return issues (C) | 329,728 |
| 47,570 |
| 80,800 |
| 78,693 |
|
| Review of Federal and state tax returns | 35,000 |
| 33,500 |
| |
| Review of federal and state tax returns | | 32,900 |
| 29,900 |
|
| Total tax preparation and compliance fees | 364,728 |
| 81,070 |
| 113,700 |
| 108,593 |
|
| Total tax fees | 364,728 |
| 81,070 |
| 113,700 |
| 108,593 |
|
| Total fees | $ | 1,990,728 |
| $ | 1,654,870 |
| $ | 1,771,500 |
| $ | 1,899,393 |
|
| |
| (A) | Includes reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q, audits of OGE Energy's subsidiaries, preparation for Audit Committee meetings and fees for consulting with OGE Energy's and OG&E's executives regarding accounting issues. |
| |
| (B) | The aggregate audit fees include fees billed for the audit of OGE Energy's and OG&E's annual financial statements and for the reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q. For 20162018, this amount includes estimated billings for the completion of the 20162018 audit, which services were rendered after year-end. |
| |
(C) | For 2016, this amount includes billings associated with a research and development tax study. |
All Other Fees
There were no other fees billed by the principal independent accountants to OGE Energy in20162018and20152017for 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.
For20162018, 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, Financial Statement Schedules.
(a) 1. Financial Statements
The following Financial Statements are included in Part II, Item 8 of this Annual Report:
Statements of Income for the years ended December 31, 2016, 20152018, 2017 and 20142016
Statements of Comprehensive Income for the years ended December 31, 2016, 20152018, 2017 and 20142016
Statements of Cash Flows for the years ended December 31, 2016, 20152018, 2017 and 20142016
Balance Sheets at December 31, 20162018 and 20152017
Statements of Capitalization at December 31, 20162018 and 20152017
Statements of Changes in Stockholder's Equity for the years ended December 31, 2016, 20152018, 2017 and 20142016
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)
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 Financial Statements or Notes thereto.
3. Exhibits
|
| |
| Exhibit No. | Description |
| 2.01 | |
| 2.02 | |
| 2.03 | |
| 2.04 | |
| 2.05 | |
| 2.06 | |
| 2.07 | |
| 2.08 | |
| 2.09 | |
| 2.10 | |
| 2.11 | |
| 2.12 | |
| 2.13 | |
| 3.01 | |
| 3.02 | |
| 4.01 | |
| 4.02 | |
| 4.03 | |
|
| |
| 4.04 | |
| 4.05 | |
| 4.06 | |
| 4.07 | |
| 4.08 | |
| 4.09 | |
| 4.10 | |
| 4.11 | |
| 4.12 | |
| 4.13 | |
| 4.14 | |
10.014.15 | Copy |
10.024.16 | |
| 4.17 | |
| 4.18 | |
| 10.01 | |
10.0310.02 | |
10.0410.03 | |
10.05*10.04* | |
10.0610.05* | Credit agreement dated as of December 13, 2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed December 19, 2011 (File No. 1-12579) and incorporated by reference herein). |
10.07* | |
10.08*10.06* | |
|
| 10.08 | |
10.10* | Form of Restricted Stock Agreement under OGE Energy's 2008 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended September 30, 2008 (File No. 1-12579) and incorporated by reference herein). |
10.11 | |
10.12*10.09* | |
10.1310.10* | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.02 to |
10.1410.11* | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Crossroads wind farm application. (Filed as Exhibit 99.01 to |
10.15 | Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 19, 2011 (File No. 1-12579) and incorporated by reference herein). |
10.16 | Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed June 28, 2011 (File No. 1-12579) and incorporated by reference herein). |
10.17* | Director Compensation. (Filed as Exhibit 10.38 to OGE Energy's Form 10-K for the year ended December 31, 2012 (File No. 1-12579) and incorporated by reference herein) |
10.18* | Executive Officer Compensation. (Filed as Exhibit 10.39 to OGE Energy's Form 10-K for the year ended December 31, 2012 (File No. 1-12579) and incorporated by reference herein). |
10.19*10.12* | |
10.20*10.13* | |
10.2110.14* | Letter of extension dated as of July 29, 2013 for OG&E's credit agreement dated as of December 13,2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed August 2, 2013 (File No. 1-12579) and incorporated by reference herein). |
10.21 | Letter of extension dated as of June 24, 2014 for OG&E's credit agreement dated as of December 13, 2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC and Union Bank, N.A., as Co-Documentation Agents (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed June 25, 2014 (File No. 1-12579) and incorporated by reference herein). |
10.23 | Letter of extension dated as of June 24, 2014 for OG&E's credit agreement dated as of December 13,2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC and Union Bank, N.A., as Co-Documentation Agents (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed June 25, 2014 (File No. 1-12579) and incorporated by reference herein). |
10.24* | |
| 10.15* | |
10.25*10.16* | Form of Restricted Stock Agreement under OGE Energy's 2013 Stock Incentive Plan. (Filed as Exhibit 10.54 to OGE Energy's Form 10-K for the year ended December 31, 2016 (File No. 1-12579) and incorporated by reference herein). |
10.26* | |
12.0110.17 | CalculationCredit Agreement dated as of RatioMarch 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 EarningsCanada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to Fixed Charges.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). |
| 10.18 | |
| 10.19 | Letter of extension dated as of March 9, 2018 for OG&E's and OGE Energy's credit agreements dated as March 8, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., Syndication Agent, Mizuho Bank, Ltd. MUFG Union Bank, N.A. Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, the Lenders thereto, and OG&E and OGE Energy, for their respective credit facility. (Filed as Exhibit 10.01 to OG&E's Form 10-Q for the quarter ended March 31, 2018 (File No. 1-1097) and incorporated by reference herein). |
| 23.01 | |
| 24.01 | |
| 31.01 | |
|
| |
| 32.01 | |
| 99.01 | Copy of APSC order with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 22, 2011 (File No. 1-12579) and incorporated by reference herein). |
99.02 | Copy of OCC Order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed July 7, 2010 (File No. 1-12579) and incorporated by reference herein). |
99.03 | Copy of OCC Order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Crossroads wind farm application. (Filed as Exhibit 99.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2010 (File No. 1-12579) and incorporated by reference herein). |
99.04 | |
99.0599.02 | |
99.0699.03 | |
99.07 | Copy of OG&E's Application with the OCC for general rate case (Filed and Exhibit 99.02 to OGE Energy's Form 8-K filed December 23, 2015 (File No. 1-12579) and incorporated by reference herein). |
| 101.INS | XBRL Instance Document. |
| 101.SCH | XBRL Taxonomy Schema Document. |
| 101.PRE | XBRL Taxonomy Presentation Linkbase Document. |
| 101.LAB | XBRL Taxonomy Label Linkbase Document. |
| 101.CAL | XBRL Taxonomy Calculation Linkbase Document. |
| 101.DEF | XBRL Definition Linkbase Document. |
| | |
| * Represents executive compensation plans and arrangements. |
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
| | | | | Additions | | | Additions | |
| Description | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions (A) | Balance at End of Period | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions (A) | Balance at End of Period |
(In millions) | | Balance at December 31, 2014 | | |
| Reserve for Uncollectible Accounts | $ | 1.9 |
| $ | 2.3 |
| $ | 2.6 |
| $ | 1.6 |
| |
| Balance at December 31, 2015 | | |
| Reserve for Uncollectible Accounts | $ | 1.6 |
| $ | 2.4 |
| $ | 2.6 |
| $ | 1.4 |
| |
| Balance at December 31, 2016 | | |
| Reserve for Uncollectible Accounts | $ | 1.4 |
| $ | 2.5 |
| $ | 2.4 |
| $ | 1.5 |
| $ | 1.4 |
| $ | 2.5 |
| $ | 2.4 |
| $ | 1.5 |
|
| 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 |
| $ | 1.6 |
| $ | 1.4 |
| $ | 1.7 |
|
| |
| (A) | Uncollectible accounts receivable written off, net of recoveries. |
Item 16. Form 10-K Summary.
None.
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 22,20, 20172019.
|
| | | |
| | OKLAHOMA GAS AND ELECTRIC COMPANY | |
| | (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 |
| | | | |
| /s/ Sean Trauschke | | | |
| Sean Trauschke | | Principal Executive | |
| | | Officer and Director; | February 22, 201720, 2019 |
| | | | |
| /s/ Stephen E. Merrill | | | |
| Stephen E. Merrill | | Principal Financial Officer; | February 22, 201720, 2019 |
| | | | |
/s/ Scott ForbesSarah R. Stafford | | | |
Scott ForbesSarah R. Stafford | | Principal Accounting Officer. | February 22, 201720, 2019 |
| | | | |
| Frank A. Bozich | | Director; | |
| James H. Brandi | | Director; | |
| Peter D. Clarke | | Director; | |
| Luke R. Corbett | | Director; | |
John D. Groendyke | | Director; | |
| David L. Hauser | | Director; | |
Kirk Humphreys | | Director; | |
| Robert O. Lorenz | | 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 22, 201720, 2019 |
Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.
The Registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.