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, 20132016
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. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
|
| |
Large accelerated filer o | Accelerated filer þo |
Non-accelerated filer þ (Do not check if a smaller reporting company) | Smaller reporting company 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 28, 201330, 2016, 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, 20142017, 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, 20132016
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 |
| 401(k) Plan | Qualified defined contribution retirement plan |
| ALJ | Administrative Law Judge |
| APSC | Arkansas Public Service Commission |
BARTASC | Best available retrofit technologyFinancial Accounting Standards Board Accounting Standards Codification |
| ASU | Financial Accounting Standards Board Accounting Standards Update |
| AVEC | Arkansas Valley Electric Cooperative Corporation |
| Bcf/d | Billion cubic feet per day |
| CSAPR | Cross-State Air Pollution Rule |
| Code | Internal Revenue Code of 1986 |
CO2 | Carbon dioxide |
| Dry Scrubbers | Dry flue gas desulfurization units with spray dryer absorber |
| ECP | Environmental Compliance Plan |
| Enable | Enable Midstream Partners, LP, partnership 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 plan |
| GAAP | Accounting principles generally accepted in the United States |
| 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 MW of new, efficient combustion turbines at the Mustang site in 2017 |
| MW | Megawatt |
MWHMWh | Megawatt-hour |
| NAAQS | National Ambient Air Quality Standards |
NOXNERC | North American Electric Reliability Corporation |
NOX | Nitrogen oxide |
NYMEX | New York Mercantile Exchange |
| OCC | Oklahoma Corporation Commission |
Off-system salesODEQ | Sales to other utilities and power marketersOklahoma 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 |
PRMPpb | Price risk managementParts per billion |
| PUD | Public Utility Division of the Oklahoma Corporation Commission |
| QF | Qualified cogeneration facilities |
| QF contracts | Contracts with QFs and small power production producers |
| Regional Haze Rule | The EPA's regional haze rule |
| Restoration of Retirement Income Plan | Supplemental retirement plan to the Pension Plan |
| SIP | State implementation plan |
SO2SO2 | Sulfur dioxide |
| SPP | Southwest Power Pool |
| Stock Incentive Plan | 2013 Stock Incentive Plan |
| System sales | Sales to OG&E's customers |
FORWARD-LOOKING STATEMENTS
Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate", "believe", "estimate", "expect", "intend", "objective", "plan", "possible", "potential","anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
the ability of OG&E and OGE Energy to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;
prices and availability of electricity, coal and natural gas;
business conditions in the energy industry;
competitive factors including the extent and timing of the entry of additional competition in the markets served by OG&E;
unusual weather;the impact on demand for our services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs
;
technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
availability and prices of raw materials for current and future construction projects;
the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters OG&E's markets;
environmental laws, andsafety laws or other regulations that may impact the cost of operations or restrict or change the way OG&E's&E operations;
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 cyber attackscyberattacks 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" and inExhibit 99.01 tothis Form 10-K.Factors."
OG&E undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
PART I
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 the Fort Smith, Arkansas area.and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. OG&E's principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone 405-553-3000.
OG&E Strategy
Mission and Focus
OGE Energy's mission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers'customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management.OGE Energy'scorporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses.
OG&E is focused on:
Providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.
Providing safe, reliable energy to the communities and customers we serve. A particular focus is on increased investment to preserve systemenhancing the value of the grid by improving distribution grid reliability by reducing the frequency and meet load growth by addingduration of customer interruptions and maintaining infrastructure equipment and replacing aging transmission and distribution systems. OG&E expects to maintain a diverse generation portfolio while remaining environmentally responsible. OG&E is focused on maintainingleveraging previous grid technology investments.
Having strong regulatory and legislative relationships for the long-term benefit of itsour customers, investors and members.
Continuing to grow a zero-injury culture and deliver top-quartile safety results.
Complying with the EPA's MATS and Regional Haze Rule requirements.
Ensuring we have the necessary mix of generation resources to meet the long-term needs of our customers. In an effort
Continuing focus on operational excellence and efficiencies in order to encourage more efficient use of electricity, OG&E is also providing energy management solutions to its customers throughprotect the Smart Grid program that utilizes newer technology to improve operational and environmental performance as well as allow customers to monitor and manage their energy usage, which should help reduce demand during critical peak times, resulting in lower capacity requirements. If these initiatives are successful, OG&E believes it may be able to defer the construction or acquisition of any incremental fossil fuel generation capacity until 2020. The Smart Grid program also provides benefits to OG&E, including more efficient use of its resources and access to increased information about customer usage, which should enable OG&E to have better distribution system planning data, better response to customer usage questions and faster detection and restoration of system outages. As the Smart Grid platform matures, OG&E anticipates providing new products and services to its customers. In addition, OG&E is also pursuing additional transmission-related opportunities within the SPP.bill.
General
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E furnishes retail electric service in 268267 communities and their contiguous rural and suburban areas.During2013, oneother community andtworural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area covers30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 268267 communities that OG&E serves, 242241 are located in Oklahoma and 26 are in Arkansas. OG&E derived 9092 percent of its total electric operating revenues in 20132016 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 20132016 was 6,3416,538 MWs on June 27, 2013August 11, 2016. OG&E's load responsibility peak demand was 5,8066,008 MWs on June 27, 2013August 11, 2016. As reflected in the table below and in the operating statistics that follow, there were 28.226.9 million MWHMWh system sales in 20132016, 28.027.2 million MWHMWh system sales in 20122015 and 28.528.0 million MWHMWh system sales in 20112014. Variations in system sales for the three years are reflected in the following table:
| | | Year ended December 31 | 2013 | 2013 vs. 2012 Increase | 2012 | 2012 vs. 2011 Decrease | 2011 | 2016 | 2016 vs. 2015 | 2015 | 2015 vs. 2014 | 2014 |
| System sales - millions of MWHs | 28.2 | 0.7% | 28.0 | (1.8)% | 28.5 | |
System sales - (Millions of MWh) | | 26.9 | (1.1)% | 27.2 | (2.9)% | 28.0 |
OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators.cogenerators as well
as from consumers choosing appliances powered by other energy sources. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. It is possible that changes in regulatory policies or advances in technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production. Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinate of our competitiveness.
| | OKLAHOMA GAS AND ELECTRIC COMPANY | CERTAIN OPERATING STATISTICS | | | | |
| Year ended December 31 | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
ELECTRIC ENERGY (Millions of MWH) | | |
ELECTRIC ENERGY (Millions of MWh) | | |
| Generation (exclusive of station use) | 24.2 |
| 26.3 |
| 26.7 |
| 21.4 |
| 20.9 |
| 22.8 |
|
| Purchased | 6.3 |
| 5.0 |
| 4.9 |
| 9.6 |
| 9.2 |
| 8.8 |
|
| Total generated and purchased | 30.5 |
| 31.3 |
| 31.6 |
| 31.0 |
| 30.1 |
| 31.6 |
|
| OG&E use, free service and losses | (1.9 | ) | (1.9 | ) | (2.1 | ) | (1.1 | ) | (1.2 | ) | (1.4 | ) |
| Electric energy sold | 28.6 |
| 29.4 |
| 29.5 |
| 29.9 |
| 28.9 |
| 30.2 |
|
ELECTRIC ENERGY SOLD (Millions of MWH) | | |
ELECTRIC ENERGY SOLD (Millions of MWh) | | |
| Residential | 9.4 |
| 9.1 |
| 9.9 |
| 9.3 |
| 9.2 |
| 9.4 |
|
| Commercial | 7.1 |
| 7.0 |
| 6.9 |
| 7.6 |
| 7.4 |
| 7.2 |
|
| Industrial | 3.9 |
| 4.0 |
| 3.9 |
| 3.6 |
| 3.6 |
| 3.8 |
|
| Oilfield | 3.4 |
| 3.3 |
| 3.2 |
| 3.2 |
| 3.4 |
| 3.4 |
|
| Public authorities and street light | 3.2 |
| 3.3 |
| 3.2 |
| 3.2 |
| 3.1 |
| 3.2 |
|
| Sales for resale | 1.2 |
| 1.3 |
| 1.4 |
| — |
| 0.5 |
| 1.0 |
|
| System sales | 28.2 |
| 28.0 |
| 28.5 |
| 26.9 |
| 27.2 |
| 28.0 |
|
| Off-system sales | 0.4 |
| 1.4 |
| 1.0 |
| |
| Integrated market | | 3.0 |
| 1.7 |
| 2.2 |
|
| Total sales | 28.6 |
| 29.4 |
| 29.5 |
| 29.9 |
| 28.9 |
| 30.2 |
|
ELECTRIC OPERATING REVENUES (In millions) | | |
| Residential | $ | 901.4 |
| $ | 878.0 |
| $ | 943.5 |
| $ | 951.9 |
| $ | 896.5 |
| $ | 925.5 |
|
| Commercial | 554.2 |
| 523.5 |
| 531.3 |
| 573.7 |
| 535.0 |
| 583.3 |
|
| Industrial | 220.6 |
| 206.8 |
| 216.0 |
| 194.6 |
| 190.6 |
| 224.5 |
|
| Oilfield | 176.4 |
| 163.4 |
| 165.1 |
| 156.9 |
| 162.8 |
| 188.3 |
|
| Public authorities and street light | 214.3 |
| 202.4 |
| 207.4 |
| 204.3 |
| 194.2 |
| 220.3 |
|
| Sales for resale | 59.4 |
| 54.9 |
| 65.3 |
| 0.3 |
| 21.7 |
| 52.9 |
|
| System sales revenues | 2,126.3 |
| 2,029.0 |
| 2,128.6 |
| 2,081.7 |
| 2,000.8 |
| 2,194.8 |
|
| Off-system sales revenues | 14.7 |
| 36.5 |
| 36.2 |
| |
| Provision for rate refund | | (33.6 | ) | — |
| — |
|
| Integrated market | | 49.3 |
| 48.6 |
| 94.1 |
|
| Other | 121.2 |
| 75.7 |
| 46.7 |
| 161.8 |
| 147.5 |
| 164.2 |
|
| Total operating revenues | $ | 2,262.2 |
| $ | 2,141.2 |
| $ | 2,211.5 |
| $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) | | |
| Residential | 690,390 |
| 683,214 |
| 675,806 |
| 712,467 |
| 705,294 |
| 697,048 |
|
| Commercial | 90,279 |
| 88,772 |
| 87,480 |
| 94,790 |
| 93,401 |
| 91,966 |
|
| Industrial | 2,921 |
| 2,957 |
| 2,991 |
| 2,831 |
| 2,872 |
| 2,901 |
|
| Oilfield | 6,431 |
| 6,426 |
| 6,451 |
| 6,469 |
| 6,328 |
| 6,460 |
|
| Public authorities and street light | 16,877 |
| 16,695 |
| 16,374 |
| 17,025 |
| 16,880 |
| 16,581 |
|
| Sales for resale | 42 |
| 46 |
| 44 |
| — |
| 1 |
| 26 |
|
| Total | 806,940 |
| 798,110 |
| 789,146 |
| |
| Total customers | | 833,582 |
| 824,776 |
| 814,982 |
|
| AVERAGE RESIDENTIAL CUSTOMER SALES | | |
| Average annual revenue | $ | 1,312.59 |
| $ | 1,292.11 |
| $ | 1,401.84 |
| $ | 1,342.88 |
| $ | 1,278.51 |
| $ | 1,334.05 |
|
| Average annual use (kilowatt-hour) | 13,718 |
| 13,477 |
| 14,738 |
| 13,105 |
| 13,062 |
| 13,540 |
|
| Average price per kilowatt-hour (cents) | $ | 9.57 |
| $ | 9.59 |
| $ | 9.51 |
| 10.25 |
| 9.79 |
| 9.85 |
|
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 20132016, 8586 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and sevensix percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
Crossroads Wind Farm
As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 megawatts. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On April 15, 2013, the APSC issued an order authorizing OG&E to recover the Arkansas portion of the cost to construct the Crossroads wind farm, effective retroactively to August 1, 2012. The costs are being recovered through the Energy Cost Recovery Rider.
Fuel Adjustment Clause Review for Calendar Year 2011
The OCC routinely reviews the costs recovered from customers through OG&E’s fuel adjustment clause. On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. OG&E filed information and documents in response to the OCC's application on October 1, 2012. On December 19, 2012, witnesses for the OCC Staff filed responsive testimony recommending that the OCC approve OG&E's fuel adjustment clause costs and recoveries for the calendar year 2011 and recommending that the OCC find that OG&E's electric generation, purchased power, fuel procurement and other fuel related practices, policies and decisions during calendar year 2011 were fair, just and reasonable and prudent. On April 9, 2013, the OCC administrative law judge recommended that the OCC find that for the calendar year 2011 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. On June 18, 2013, the OCC issued an order approving the administrative law judge’s recommendation.
Pending 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 in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 leaves torequires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffstariff and agreementsagreement 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 and Order No. 1000 does notor 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 currently hasSPP'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 variousprevious transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which were filed on November 13, 2012. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a right"right of first refusalrefusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts300kV that interconnect to those incumbent entities'owners' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000.
On July 18, 2013,The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP's Order No. 1000 compliance filing. This order accepted in part and rejected in partSPP filings that required the SPP's plan for complying with Order No. 1000. The FERC rejected the SPP's planSPP to retain the rightremove certain "right of first refusal for projects that would operate between 100 kilovoltsrefusal" language from the SPP Tariff and 300 kilovolts. However, the FERC clarified that a right of first refusal was appropriateSPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in certain circumstances. It is not clear howthe Court challenging the FERC's order will relate torequiring the recently enacted Oklahoma law addressing a rightremoval of the "right of first refusalrefusal" 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 lower voltages. On November 15, 2013,incumbent transmission providers from the SPP made itsMembership Agreement. The Court determined that the FERC compliance filing, as required byhad reasonably found the July 18, 2013 order. The"right of first refusal" in the SPP changes to its tariff and Membership Agreement included provisions that (i) clarify that facilities between 100 kilovolts and 300 kilovolts would be subject to the competitive selection process, (ii) only allow certain evidence, such as state laws (like House Bill 1932) and the holders of existing rights of way, to be considered during the competitive selection process and not earlier in the process; (iii) apply a right of first refusal to transmission projects needed for reliability within three years in certain situations; and (iv) revise the tariff’s competitive selection process, including changes to the criteria for identifying qualifying transmission owners, the requirements for submission of information by transmission owners seeking to participate in competitive selections, and the procedures that govern the competitive selection process.
anticompetitive.
OGE Energy cannot, at this time, determineOG&E does not believe the preciseCourt’s ruling will have any impact of Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E'sexisting transmission projects currently under development and construction for which OG&E has already received a notice to proceedconstruct 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 20122014
On July 31, 2013,28, 2015, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012,2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filedOn May 26, 2016, the necessary informationOCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and documents needed to satisfy the OCC's minimum filing requirement rules on October 9, 2013. A hearing on this matter is scheduled for April 24, 2014.fuel procurement processes and costs were prudent.
Request for Modification to Previous OrdersOklahoma 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 2,9, 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 OCCAPSC seeking authority to make minor modificationsconstruct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to three previous OCC orders. The purposeseek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas. The application was to addressdid not seek any cost recovery for the timing of certain requirements contained in those orders. OG&E's application proposed to address these issues in OG&E's next general rate case thus avoiding the cost associated with a rate case filing now and benefiting customers by deferring the recovery of certain costs identifiedcapital expenditures in the previous orders. On September 3, 2013, the PUD Staffapplication, 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 application. PUD Staff requestedfinancial results are dependent in part on timely and adequate decisions by the regulatory agencies that the OCC dismissset OG&E's application and issue an order requiring OG&E to file a rate case for the 2012 test year.rates.
Environmental Compliance Plan
On September 11, 2013, the PUD Staff withdrew their motion to dismiss OG&E's application and on September 12, 2013, filed an application requesting a public hearing, review and possible adjustment of the rates and charges of OG&E based on the 2012 test year. To date, no procedural schedule has been established for either the OG&E application or the PUD Staff application.
Energy Efficiency Program Filing
On October 9, 2013August 6, 2014, OG&E filed an application with the APSC requestingOCC for approval of interim modificationsits plan to approved Energy Efficiency Programs, new tariff revisionscomply 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 waiverconversion of certain provisionsMuskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of the Commission’s Rulesits Mustang Modernization Plan, which calls for Conservation and Energy Efficiency Programs.
Market-Based Rate Authority
On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order acceptingreplacing OG&E's June 2012 triennial market power update.
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 30, 2013,2, 2015, OG&E submitted to the FERC a market-based rate change in status filing and a revised market-based rate tariff. The revised tariff will authorize OG&E to (i) sell electric energy and capacity at market-based rates without geographic restriction, and (ii) sell ancillary services in the SPP and Midcontinent Independent System Operator, Inc. markets. The primary goal of this filing was to implement the market-based rate authority OG&E needs to fully participate in SPP’s Integrated Marketplace. OG&E requested that FERC issuereceived an order on or before February 28, 2014 that acceptsfrom 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 market-based rate tariff to be effective ondepreciation rates for both the date SPP’s Integrated Marketplace goes into operation, which is expected to be March 1, 2014.
Section 206 Complaintretirement 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 November 26, 2013,February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. On April 28, 2016, the OCC approved the Dry Scrubber project.
Two parties appealed the OCC's decision to the Oklahoma Supreme Court. 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 and capitalized ad valorem taxes. As of December 31, 2016, OG&E had invested $208.7 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $424.9 million and expects the project to be completed in late 2017. As of December 31, 2016, OG&E had invested $187.8 million on the Mustang Modernization Plan.
Integrated Resource Plans
In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Arkansas Electric Cooperative Corporationby October 1, 2017 and in Oklahoma by October 1, 2018.
Oklahoma Rate Case Filing
On December 18, 2015, OG&E filed a complaint atgeneral rate case with the FERC againstOCC 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 arguingimplemented 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 wholesale formula rate contract betweenALJ 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 and is unable to predict what action the OCC will take, or the timing of such action.
Arkansas Electric Cooperative Corporation (formerly betweenRate 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 Valley Electric Cooperative)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 unjustscheduled 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 unreasonable with respect to several items. After engagingfuel procurement costs. A hearing in settlement discussions, OG&E and Arkansas Electric Cooperative Corporation have tentatively agreed to terms of a settlement and are jointly preparing an offer of settlement to be filed with FERC. OG&E believes the reduction in revenuethis Cause will be less than $1.0 million per year.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 actual or anticipatedincurred 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 actual or anticipatedincurred costs and obligations as regulatory assets or liabilities if, it is probable, based on regulatory orders or other available evidence, it is probable that the costcosts or obligationobligations will be included in amounts allowable for recovery or refund in future rates.
At December 31, 20132016 and 20122015, OG&E had regulatory assets of $427.9526.6 million and $537.6448.7 million, respectively, and regulatory liabilities of $254.4312.0 million and $386.2342.4 million, respectively. See Note 1 of Notes toFinancial Statements for a further discussion.
Management continuously monitors the future recoverability of regulatory assets. When, in management's judgment, future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Rate Structures
Oklahoma
OG&E's standard tariff rates include a cost-of-service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power.
OG&E offers several alternate customer programs and rate options. Under OG&E's Smart Grid enabled SmartHours®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. Budget-minded customers that desire a fixed monthly bill may benefit from the guaranteed flat bill option. A secondAnother tariff rate option provides a "renewable energy" resource to OG&E's Oklahoma retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. Another program being offered to OG&E's commercial and industrial customers is a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required. OG&E also offers certain qualifying customers "day-ahead price" and "flex price" rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price" and "flex price" rate options are based on OG&E's projected next day hourly operating costs.
OG&E also has two rate classes,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. OG&E's rate choices, reduction in cogeneration rates, acquisition of additional generation resources and overall low costs of production and deliverability are expected to provide valuable benefits for OG&E's customers for many years to come.
Arkansas
OG&E's standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel.fuel and purchased power. OG&E offers several alternate customer programs and rate options. The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest. A second tariff rate option provides a "renewable energy" resource to OG&E's Arkansas retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. OG&E offers its commercial and industrial customers a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action. OG&E offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The day-ahead price is based on OG&E's projected next day hourly operating costs.
Fuel Supply and Generation
In 20132016, 5348.0 percent of the OG&E-generated energy was produced by coal-fired units, 4045.3 percent by natural gas-fired units and seven6.7 percent by wind-powered units. Of OG&E's 6,7856,667 total MWMWs of generation capability reflected in the table under Item 2. Properties, 3,7983,650 MWs, or 5654.7 percent, are from natural gas generation, 2,5382,568 MWs, or 3738.5 percent, are from coal generation and 449 MWs, or seven6.8 percent, are from wind generation. Though OG&E has a higher installed capability of generation from natural gas units, it has been more economical to generate electricity for our customers using lower priced coal. Over the last five years, the weighted average cost of fuel used, by type, was as follows:
| | Year ended December 31 (In Kilowatt-Hour - cents) | 2013 | 2012 | 2011 | 2010 | 2009 | |
Year ended December 31 (In cents/Kilowatt-Hour) | | 2016 | 2015 | 2014 | 2013 | 2012 |
| Natural gas | 3.905 | 2.930 | 4.328 | 4.638 | 3.696 | 2.488 | 2.529 | 4.506 | 3.905 | 2.930 |
| Coal | 2.273 | 2.310 | 2.064 | 1.911 | 1.747 | 2.213 | 2.187 | 2.152 | 2.273 | 2.310 |
| Weighted average | 2.784 | 2.437 | 2.897 | 3.012 | 2.474 | 2.199 | 2.196 | 2.752 | 2.784 | 2.437 |
The increase in the weighted average cost of fuel in 2016 as compared to 2015 was primarily due to higher coal prices. The decrease in the weighted average cost of fuel in 2015 as compared to 2014 was primarily due to lower natural gas prices. The decrease in the weighted average cost of fuel in 2014 as compared to 2013 was primarily due to less natural gas used, partially offset by higher natural gas prices. The increase in the weighted average cost of fuel in 2013 as compared to 2012 was primarily due to higher gas prices. The decrease in the weighted average cost of fuel in 2012 as compared to 2011 was primarily due to lower natural gas prices. The decrease in the weighted average cost of fuel in 2011 as compared to 2010 was primarily due to lower natural gas prices and lower natural gas generation. The increase in the weighted average cost of fuel in 2010 as compared to 2009 was primarily due to higher natural gas prices and increased natural gas generation. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.
OG&E participates in the SPP Integrated Marketplace. As part of the Integrated Marketplace, the SPP has balancing authority responsibilities for its market participants. The SPP Integrated Marketplace functions as a centralized dispatch, where market participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers. The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations, and determine which generating units will run at any given time for maximum cost-effectiveness. As a result, OG&E's generating units produce output that is different from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.
Coal
Coal
All of OG&E's coal-fired units, with an aggregate capability of2,538 2,568 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E has contracted for approximately 55 percent of its forecasted annual coal usage via multi-year contracts that expire in2016and the remainder of its forecasted2014usage via one-year contracts that expire in2014. In2013, OG&E purchased7.8 milliontons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of0.21 percent. 0.24 percent. Based uponon the average sulfur content and EPA certified emissionEPA-certified data, OG&E's coal units have an approximate emission rate of0.5lbs. lbs of SO2SO2 per MMBtu.As discussed
For 2017, OG&E has acquired 100 percent of its forecasted annual coal usage via existing inventory and purchase contracts that expire in "Item 7. Management's Discussion and AnalysisDecember 2017. In 2016, OG&E purchased 5.5 million tons of Financial Condition and Results of Operations - Environmental Laws and Regulations," emission limits are expected to become more stringent.
coal from various Wyoming suppliers. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
Natural Gas
As a participant in the SPP Integrated Marketplace, OG&E now purchases a relatively small percentage of its natural gas supply through long-term agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has entered into multiple month termthe right but not the obligation to purchase a defined quantity of natural gas, contracts for 31.5 percentcombined with day and intra-day purchases to meet the demands of its 2014 annual forecasted natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2014 natural gas requirements will be acquired through additional requests for proposal in early to mid-2014, along with monthly and daily purchases, all of which are expected to be made at market prices.
OG&E utilizes natural gas storage service on Enable's and OneOK Gas Transmission's pipelines. The storage services allow OG&E to maximize the value of its generation assets. AtDecember 31, 2013, OG&E had2.1 millionMMBtu's in natural gas storage valued at$7.6 million.SPP Integrated Marketplace.
Wind
OG&E's current wind power portfolio includes: (i)includes the following, in addition to the 120MW Centennial, wind farm, (ii) the101MW OU Spirit wind farm, (iii) the227.5and 228 MW Crossroads wind farm, (iv)farms owned by OG&E:(i) access to up to50MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (v)(ii) access to up to 152 150MWs 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, (vi)(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 20302031 and (vii)(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.
Solar
In 2015, OG&E placed its first solar plant in service. The plant consists of two separate solar farms and is located in Oklahoma City, on the site of the Mustang generating facility. The Mustang solar plant has a maximum capacity of 2.5 MWs and consists of almost 10,000 photovoltaic panels.
OG&E expects to begin construction on 10 MWs of new solar farms in 2017. OG&E will evaluate the need to build additional solar plants, based on customer demand, cost, and reliability.
8
Safety and Health Regulation
OG&E is subject to a number of Federal and state laws and regulations, including OSHA, the EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.
In addition, the OSHA hazard communication standard,Hazard Communication Standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
ENVIRONMENTAL MATTERS
General
The activities of OG&E are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection relating to air quality, water quality, waste management, wildlife conservation and natural resources.protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways such as restrictingincluding the way it can handlehandling or disposedisposal of its wastes, requiring remedial actionwaste material, future construction activities to avoid or mitigate environmental issues that may be caused by its operationsharm to threatened or that are attributable to former operators, requiring changes in operationsendangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.
TheUnder the Obama administration, the trend in environmental regulation however, iswas to place more restrictions and limitations on activities that may affect the environment. OG&E is unable to predict what changes the Trump administration may have on proposed or existing environmental regulations. 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. 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 20142017 will be $72.6241.3 million, of which $55.0221.9 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 20152018 will be approximately $49.6180.8 million, of which $31.3 161.6
million is for capital expenditures. The amounts above include capital expenditures for low NOXNOX burners, Dry Scrubbers and activated carbon injection and exclude certain other capital expenditures as discussed in footnote D to the capital expenditures table in"Finance and Construction" below.gas conversions. OG&E's management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
For a further discussion of environmental matters that may affect OG&E, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations."
Regulations" in this Form 10-K.
FINANCE AND CONSTRUCTION
Future Capital Requirements and Financing Activities
Capital Requirements
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.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'sestimates of capital expenditures for the years 20142017 through2018 2021 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.
| | | (In millions) | 2014 | 2015 | 2016 | 2017 | 2018 | 2017 | 2018 | 2019 | 2020 | 2021 |
| Base Transmission | $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 35 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
|
| Base Distribution | 175 |
| 175 |
| 175 |
| 175 |
| 175 |
| 195 |
| 175 |
| 175 |
| 175 |
| 175 |
|
| Base Generation | 140 |
| 75 |
| 75 |
| 75 |
| 75 |
| 40 |
| 75 |
| 75 |
| 75 |
| 75 |
|
| Other | 15 |
| 15 |
| 15 |
| 15 |
| 15 |
| 35 |
| 25 |
| 25 |
| 25 |
| 25 |
|
| Total Base Transmission, Distribution, Generation and Other | 360 |
| 295 |
| 295 |
| 295 |
| 295 |
| 305 |
| 305 |
| 305 |
| 305 |
| 305 |
|
| Known and Committed Projects: | | |
| Known and Committed Non-Base Projects: | | |
| Transmission Projects: | | |
| Regionally Allocated Base Projects (A) | 55 |
| 20 |
| 20 |
| 20 |
| 20 |
| |
| Balanced Portfolio 3E Projects (B)(C) | 15 |
| — |
| — |
| — |
| — |
| |
| SPP Priority Projects (B)(C) | 75 |
| — |
| — |
| — |
| — |
| |
| SPP Integrated Transmission Projects (B) (C) | 15 |
| 25 |
| 30 |
| 25 |
| 10 |
| |
| Other Regionally Allocated Projects (A) | | 50 |
| 20 |
| 20 |
| 20 |
| 20 |
|
| Large SPP Integrated Transmission Projects (B) (C) | | 155 |
| 20 |
| — |
| — |
| — |
|
| Total Transmission Projects | 160 |
| 45 |
| 50 |
| 45 |
| 30 |
| 205 |
| 40 |
| 20 |
| 20 |
| 20 |
|
| Other Projects: | | |
| Smart Grid Program | 25 |
| 10 |
| 10 |
| — |
| — |
| |
| Environmental - low NOX burners | 35 |
| 20 |
| 15 |
| 10 |
| — |
| |
| Environmental - activated carbon injection | 5 |
| 10 |
| 5 |
| — |
| — |
| |
| 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 | 65 |
| 40 |
| 30 |
| 10 |
| — |
| 440 |
| 195 |
| 45 |
| — |
| — |
|
| Total Known and Committed Projects | 225 |
| 85 |
| 80 |
| 55 |
| 30 |
| |
| Total (D) | $ | 585 |
| $ | 380 |
| $ | 375 |
| $ | 350 |
| $ | 325 |
| |
| 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%30 percent of revenue requirement allocated to SPP members other than OG&E.
|
| |
| (B) | Typically 300kV and above projects. Approximately 85%85 percent of revenue requirement allocated to SPP members other than OG&E.
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|
| | | | |
| (C) | Project Type | Project Description | Estimated Cost
(In millions) | Projected In-Service Date |
| | Balance Portfolio 3E | 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the Oklahoma /Texas Stateline to a companion transmission line to its Tuco substation | $110 | Mid-2014 |
| Priority Project | 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the western Beaver County line to a companion transmission line to its Hitchland substation | $165 | Mid-2014 |
| Priority Project | 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border | $140 | Late 2014 |
| Integrated Transmission Project | 4730 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substationsubstation. $5.0 million of the estimated cost has been spent prior to 2017. | $45 | Early 2018Late 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;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. | $180185 | Early 2021Mid 2018 |
| |
| (D) | TheRepresent capital expenditures above exclude any environmental expenditurescosts associated with: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.
|
Pollution control equipment related to controlling SO2 emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment.The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than$1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On January 2, 2014, the Tenth Circuit confirmed that the stay of the FIP has remained in place and continues
until the Tenth Circuit issues the mandate. A Petition for Certiorari was filed by the State of Oklahoma, the Industrial Consumers and OG&E with the United States Supreme Court on January 29, 2014. The mandate from the Tenth Circuit has been stayed until the Supreme Court acts on the petition. If the Supreme Court elects not to hear the case, OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP.
Installation of control equipment (other than activated carbon injection) for compliance with MATS by a deadline of April 16, 2016, which includes a one-year extension which was granted by the Oklahoma Department of Environmental Quality. As noted above, OG&E is currently planning to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above. OG&E continues to review whether additional controls such as dry sorbent injection are needed for compliance with MATS. Current capital costs for installing the necessary control equipment for dry sorbent injection are estimated to be approximately$45 millionover a three year period, but due to the uncertainty as to whether or not dry sorbent injection is necessary, such costs are not included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above.
OG&E is currently evaluating options to comply with environmental requirements. For further information, see"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -Environmental Laws and Regulations" 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 achieving OG&E's financial objectives.
Pension and Postretirement Benefit Plans
During both2013and2012, 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 of$35 million, of whichnonein 2013 and$33 millionin 2012 was OG&E's portion,Plan. OGE Energy has not determined whether it will need to help ensure thatmake any contributions to the Pension Plan maintains an adequate funded status.in 2017. During2014, OGE Energy expects to contribute up to$26 millionto its Pension Plan, of which$1 millionis expected to be OG&E's portion.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 (fromproceeds(proceeds from the sales ofitscommon 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.AtDecember 31, 20132016, there were $87.2 $49.9 million in net outstanding advances from OGE Energy as compared to $90.3 $333.6 million in net outstanding advances to OGE Energy at December 31, 2012.2015. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400400.0 million of OGE Energy's revolving credit amount. This agreement has a termination date ofDecember 13, 2017. AtDecember 31, 2013, there werenointercompany borrowings under this agreement.2018. OG&E has a$400 $400.0 millionrevolving 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, 20132016, there was $2.11.8 million supporting letters of credit at a weighted-average interest rate of 0.530.945 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 20132016. At December 31, 20132016, OG&E had $397.9398.2 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to $800800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 20132017 and ending December 31, 2014.AtDecember 31, 2013, OG&E had less than$0.1 millionin cash and cash equivalents.2018. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. Thismillion which expires in December 2018. OG&E expects to replace the existing agreement with a new revolving credit facility contains an option, which may be exercised upagreement during 2017, under terms and conditions generally similar to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreements to December 13, 2017.existing agreement.
Issuance of Long-Term Debt
On May 8, 2013, OG&E issued $250 million of 3.9% senior notes due May 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, to fund capital expenditures, to pay general corporate expenses and for working capital purposes.
Expected Issuance of Long-Term Debt
OG&E expects to issue up to$250$300.0 millionof long-term debt during 2014,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 had 1,8851,865 employees at December 31, 20132016.
EXECUTIVE OFFICERS
The following persons were Executive Officers of the Registrant as of February 25, 201422, 2017:
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| | |
| Name | Age | Title |
Peter B. DelaneySean Trauschke | 6049 | Chairman of the Board, President and Chief Executive Officer |
Sean TrauschkeE. Keith Mitchell | 4654 | President and Chief Operating Officer |
| Stephen E. Merrill | 52 | Chief Financial Officer |
William J. Bullard | 65 | General Counsel |
| Scott Forbes | 5659 | Controller and Chief Accounting Officer |
| Patricia D. Horn | 5558 | Vice President - Governance and Corporate Secretary |
Gary D. Huneryager | 63 | Vice President - Internal Audits |
Jesse B. Langston | 51 | Vice President - Retail Energy |
| Jean C. Leger, Jr. | 5558 | Vice President - Utility Operations |
| Kenneth R. Grant | 51 | Vice President- Sales and Marketing |
| Cristina F. McQuistion | 4952 | Vice President - Strategic Planning, Performance Improvement and Chief Information Officer |
| Jerry A. Peace | 5154 | Chief GenerationVice President - Integrated Resource Planning and Procurement - OG&EDevelopment |
| Paul L. Renfrow | 5760 | Vice President - Public Affairs HR, HS&E and RegulatoryCorporate Administration |
| William H. Sultemeier | 49 | General Counsel |
| Charles B. Walworth | 3942 | Treasurer |
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Trauschke, Bullard,Merrill, Forbes, Huneryager, 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 ShareownersShareholders of OGE Energy, currently scheduled forMay 15, 2014.18, 2017.
12
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:
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| | |
| Name | Business Experience |
Peter B. DelaneySean Trauschke | 20122015 - Present: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. |
| | 20132014 - Present:2015: | DirectorPresident of Enable GP LLCOGE Energy Corp. |
| | 20132012 - 2014: | Vice President and Chief Financial Officer of OGE Energy Corp. |
| E. Keith Mitchell | 2015 - Present: | Chairman of the Board and Chief ExecutiveOperating Officer of OG&E |
| | 2013 - 2015: | Executive Vice President and Chief Operating Officer of Enable Midstream Partners, LP |
| 2012 - 2013: | Chairman of the Board, President and Chief Executive Officer of OG&E |
| 2010 - 2011: | Chairman of the Board and Chief Executive Officer of OGE Energy Corp. and OG&E |
| 2010 - 2013: | Chief ExecutiveOperating Officer of Enogex Holdings |
| 2009 - 2013: | Chief Executive OfficerHoldings; President of Enogex LLC |
| 2009 - 2010: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. and OG&E |
Sean TrauschkeStephen E. Merrill | 2014 - Present: | Chief Financial Officer of OGE Energy Corp. |
| | 2013 - Present:2014: | DirectorExecutive Vice President of Finance and Chief Administrative Officer of Enable GP LLCMidstream Partners, LP |
| | 2013 - Present: | President and Chief Financial Officer of OG&E |
| 2013 - 2014: | Vice President and Chief Financial Officer of OGE Energy Corp. |
| 2013: | Acting Chief Financial Officer of Enable GP LLC |
| 2009 - 2013: | Vice President and Chief Financial Officer of OGE Energy Corp. and OG&E |
| 20102012 - 2013: | Chief Financial Officer of Enogex Holdings |
| 2009 - 2013: | Chief FinancialOperating Officer of Enogex LLC |
| 2009: | Senior Vice President - Investor Relations and Financial Planning of Duke Energy (electric utility) |
William J. Bullard | 2010 - Present: | Assistant General Counsel of OGE Energy Corp.; General Counsel of OG&E |
| 2009 - 2010: | Assistant General Counsel of OGE Energy Corp. and OG&E |
| Scott Forbes | 20092012 - Present: | Controller and Chief Accounting Officer of OGE Energy Corp. and OG&E |
| 2009: | Interim Chief Financial Officer of OGE Energy Corp. and OG&E |
| Patricia D. Horn | 2014 - Present: | Vice President - Governance and Corporate Secretary of OGE Energy Corp. and OG&E |
| | 2012 - 2014: | Vice President - Governance, Environmental and Corporate Secretary of OGE Energy Corp. and OG&E |
| | 2010 - 2013: | Secretary of Enogex Holdings and Corporate Secretary of Enogex LLC |
| 2010 - 2012: | Vice President - Governance, Environmental, Health & Safety; Corporate Secretary of OGE Energy Corp. and OG&E |
| 2009 - 2010: | Vice President - Legal, Regulatory, Environmental Health & Safety and General Counsel of Enogex LLC |
| 2009 - 2010: | Assistant General Counsel of OGE Energy Corp. |
Gary D. Huneryager | 2009 - Present: | Vice President - Internal Audits of OGE Energy Corp. and OG&E |
Jesse B. Langston | 2009 - Present: | Vice President - Retail Energy of OG&E |
| Jean C. Leger, Jr. | 20092012 - Present: | Vice President - Utility Operations of OG&E |
| Kenneth R. Grant | 2016 - Present: | Vice President - Sales and Marketing of OG&E |
| 2015: | Vice President Marketing and Product Development of OG&E |
| 2013 - 2015: | Managing Director Tech Solutions & Ops of OG&E |
| 2012 - 2013: | Managing Director Customer Solutions of OG&E |
| Cristina F. McQuistion | 2017 - Present: | Vice President - Chief Information Officer of OG&E |
| 2016 - 2017: | Vice President - Chief Information Officer and Utility Strategy of OG&E |
| 2014 - Present: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 |
| 20112012 - 2013: | Vice President - Strategy and Performance Improvement of OGE Energy Corp. and OG&E |
| Jerry A. Peace | 20092016 - 2011:Present: | Vice President - ProcessIntegrated Resource Planning and Performance ImprovementDevelopment of OGE Energy Corp. and OG&E |
Jerry A. Peace
| 2014 - Present:2015 | Chief Generation Planning and Procurement Officer of OG&E |
| 20092012 - 2014: | Chief Risk Officer of OGE Energy Corp. and OG&E |
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| | |
| | |
| Paul L. Renfrow | 2014 - Present: | Vice President - Public Affairs HR, HS&E and RegulatoryCorporate Administration of OGE Energy Corp. |
| | 2012 - 2014: | Vice President - Public Affairs, Human Resources and Health & Safety of OGE Energy Corp. and OG&E |
| William H. Sultemeier | 2017 - Present: | General Counsel of OGE Energy Corp. |
| | 20112016: | Partner - 2012: | Vice President - Public Affairs and Human Resources of OGE Energy Corp. and OG&EJones Day |
| | 20092012-2015: | Shareholder - 2011: | Vice President - Public Affairs of OGE Energy Corp. and OG&EGreenberg Traurig, LLP |
| Charles B. Walworth | 2014 - Present: | Treasurer of OGE Energy Corp. and OG&E |
| | 2012 - 2014: | Assistant Treasurer of OGE Energy Corp. and OG&E |
| | 2010 - 2012: | Senior Manager Finance of OGE Energy Corp. |
| 2009 - 2010: | Manager Corporate Finance of OGE Energy Corp. |
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
OGE Energy's web sitewebsite address is www.oge.com. Through OGE Energy's website under the heading "Investors," "Investor Relations," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K.
Item 1A. Risk Factors.
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to OG&E. In addition to the other information in this Form 10-K and other documents filed by us with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OG&E. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.
REGULATORY RISKS
OG&E's profitability depends to a large extent on the ability to fully recover its costs from its customers in a timely manner and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.
OG&E is subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers.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 the future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations or the imposition of additional regulations could have an adverse impact on OG&E's results of operations.
OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a Federal agency, whose regulatory paradigms and goals may not be consistent.
OG&E is currently a vertically integrated electric utility and mostutility. 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 and from the sale of electricity to wholesale customers subject to rates and other matters approved by the FERC.commission.
OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to the FERC.FERC regulation of its transmission activities and any wholesale sales. Exposure to inconsistent state and Federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate, including a change in our authorized return on equity, may harm our financial position and results of operations.
Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position, or liquidity.
We are subject to extensive Federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future. As discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations", in 2011, the EPA accepted a portion of the Oklahoma SIP for regional haze, which requires the installation of low NOX burners on OG&E's affected units within five years at a cost of approximately$80 million. The EPA rejected Oklahoma's SO2 BART determination with respect to the four affected coal-fired units at the Sooner and Muskogee generating stations and issued a FIP in its place.The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than$1.0 billion. OG&E, the state of Oklahoma and other parties, filed an appeal to challenge this determination, which has delayed the implementation of the regional haze rule in Oklahoma.Although the court initially stayed implementation of EPA’s FIP, it ultimately issued a decision affirming the FIP, and unless the Supreme Court accepts an appeal of the case, the FIP will require installation of Dry Scrubbers or fuel switching with a deadline sometime in 2018 or 2019.
In response to recent regulatory and judicial decisions and international accords, emissions of greenhouse gases including, most significantly, carbon dioxideCO2 could be restricted in the future as a result of Federal or state legal requirements or litigation relating to greenhouse gas emissions. If mandatoryAdditionally, international treaties or protocols could result in future additional reductions of carbon dioxide and other greenhouse gases are required in the future, thisUnited States. In October 2015, the EPA issued standards for states to implement to control 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, they could result in significant additional compliance costs that would affect our futurefinancial position, results of operations and cash flows if such costs are not recovered through regulated rates. The EPA has started a processDue to implement carbon dioxide emission limitations for existing electric generating units,the pending litigation and neither the outcomeuncertainties in the state approaches, the ultimate timing and impact of the rule making process nor the timing of any required expenditures resulting from the EPA rule making process canthese standards on our operations cannot be predicteddetermined with any 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 due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. These activities are subject to stringent and complex Federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way itOG&E can handle or dispose of its its wastes or requiring remedial action to mitigate pollution conditions that may be caused by its its operations or that are attributable to former operators. OG&E may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
For a further discussion of environmental matters that may affect OG&E, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations."
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
OG&E's business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment. This could adversely affect OG&E's financial position and results of operations. While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
Our jurisdictions have fuel clauses that permit us to recover fuel costs through rates without a general rate case. While prudent capital investment and variable fuel costs each generally warrant recovery,As of December 31, 2016, OG&E had incurred $208.7 million of construction work in practical terms our regulators could limit
progress on the amount or timing of increased costs that we would recover through higher rates. Any such limitation could adversely affect our results of operations and financial position.Dry Scrubbers.
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 a regional day ahead and real-time markets for energy imbalance service market on February 1, 2007.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 participatesrepresents owned and contracted generation assets and customer load in the SPP energy imbalance service market to aid inIntegrated Marketplace for the optimizationsole benefit of its physical assets to serve OG&E's customers. OG&E has not participated in the SPP energy imbalance service marketIntegrated Marketplace for
any speculative trading activities. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourlySPP Integrated Marketplace transactions as sales to the SPP at market rates inor purchases with results reported as Operating Revenues and the hourly purchases from the SPP at market rates inor Cost of SalesGoods Sold 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, including the forthcoming SPP integrated marketplace, which is scheduled to begin operation in March 2014.SPP.
Increased competition resulting from restructuring efforts could have a significant financial impact onOG&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 already 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 an increased amount of 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 results of operations and cash flows.
We are subject to substantial utility and energy regulation by governmental agencies. ��Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
We are subject to substantial regulation from Federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain permits, approvals and certificatescertifications 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 North American Electric Reliability CorporationNERC as the national energy reliability organization. The North American Electric Reliability CorporationNERC is responsible for the
development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. One of OG&E's regulators, NERC, has comprehensive regulations and standards related to the reliability and security of our operating systems, and is continuously developing additional mandatory compliance requirements for the utility industry. The North American Electric Reliability Corporation has authority to assess penalties up to$1.0 millionper day per violationincreasing development of NERC rules and standards will increase compliance costs and our exposure for noncompliance. In order to comply with new or updated security regulations, we may be required to make changes to our current operations which could also result in additional expenses. OG&E is subject to a North American Electric Reliability Corporation compliance audit every three years as well as periodic spot check audits and cannot predict the outcomepotential violations of those audits.
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 (severesuch as a severe storm or generator or transmission facility outage)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 facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power purchase costs.
OG&E owns and operates coal-fired, natural gas-fired, wind-powered and wind-poweredsolar-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels. Included among these risks are:
increased prices for fuel and fuel transportation as existing contracts expire;
facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
operator error or safety related stoppages;
disruptions in the delivery of electricity; and
catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.
When unplanned maintenance work is required on power plants or other equipment, OG&E will not only incur unexpected maintenance expenses, but it may also have to make spot market purchases of replacement electricity that could exceed OG&E's costs of generation or be forced to retire a generation unit if the cost or timing of the maintenance is not reasonable and prudent. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.
Changes in technology and regulatory policies may cause our generating facilities to be less competitive.
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.
Increased deployment of renewable energy technologies could reduce utility electric sales, but would not reduce our need for ongoing investments in our infrastructure to reliably serve our customers. Continued utility infrastructure investment without increased electricity sales could cause increased rates for customers, potentially resulting in further reductions in electricity sales and reduced profitability.
Economic conditions could negatively impact our business and our results of operations.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity
markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
In addition, economic conditions, particularly budget shortfalls, could lead to increasedincrease the pressure on Federal, state and local governments to raise additional funds including through increasedby increasing corporate taxestax rates and/or through delaying, reducing or eliminating tax credits, grants or other incentives whichthat could have a material adverse impact on our results of operations.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, (carbon dioxideCO2 taxes or costs associated with additional regulatory requirements),requirements, OG&E may be adversely impacted. A declining economy could adversely impact the overall financial health of OG&E because ofdue 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 cyber securitycybersecurity 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 (including smart grid)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 gridSmart Grid program further increases potential risks associated with cyber securitycybersecurity attacks. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely way,manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on its financial position, results of operations and cash flows.
Our security procedures, which include among others, virus protection software, cyber securitycybersecurity 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 affecteffect of cyber securitycybersecurity 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 in the Middle East or other 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 in the Middle East or other 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, 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, and wind storms, earthquakes and prolonged droughts may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period. In addition, prolonged droughts could cause a lack of sufficient water for use in cooling during the electricity generating process. Additionally, if climate change exacerbates physical changes in weather, operations may be impacted as discussed above.
FINANCIAL RISKS
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our financial position, results of operations or liquidity.
cash flow.
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, 20132016, OGE Energy expects to continue to make future contributions to maintain required funding levels. It has been OGE Energy's practice in the past to also make voluntary contributions to maintain more prudent funding levels than minimally required. We 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, 3534 percent of our current employees will be eligiblemeet the eligibility requirements to retire with full pension benefits.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, including acquisitions and other corporate purposes. The levels of our debt could have important consequences, including the following:
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
our debt levels may limit our flexibility in responding to changing business and economic conditions.
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
We are exposed to credit risks in our generation and retail distribution operations.Credit risk includes the risk that counterparties thatwho 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 10 generating stations with an aggregate capability of 6,7856,667 MWs at December 31, 20132016. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
| | | | | 2013 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) | | 2016 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) |
| | | Year Installed | | Fuel Capability | Unit Run Type | | | Year Installed | | Fuel Capability | |
| Station & Unit | | Unit Design Type | 2013 Capacity Factor (A) | | Unit Design Type | 2016 Capacity Factor (A) |
| Seminole | 1 | 1971 | Steam-Turbine | Gas | Base Load | 20.2 | % | 486 |
| | 1 | 1971 | Steam-Turbine | Gas | 9.4 | % | 448 |
| |
| | 1GT | 1971 | Combustion-Turbine | Gas | Peaking | 0.1 | % | 16 |
| | |
| | 2 | 1973 | Steam-Turbine | Gas | Base Load | 26.1 | % | | 482 |
| | 2 | 1973 | Steam-Turbine | Gas | 14.7 | % | | 426 |
| |
| | 3 | 1975 | Steam-Turbine | Gas/Oil | Base Load | 24.1 | % | | 489 |
| 1,473 |
| 3 | 1975 | Steam-Turbine | Gas/Oil | 22.3 | % | | 471 |
| 1,345 |
|
| Muskogee | 4 | 1977 | Steam-Turbine | Coal | Base Load | 39.3 | % | | 491 |
| | 4 | 1977 | Steam-Turbine | Coal | 52.4 | % | | 508 |
| |
| | 5 | 1978 | Steam-Turbine | Coal | Base Load | 51.0 | % | | 506 |
| | 5 | 1978 | Steam-Turbine | Coal | 43.5 | % | | 497 |
| |
| | 6 | 1984 | Steam-Turbine | Coal | Base Load | 59.3 | % | | 500 |
| 1,497 |
| 6 | 1984 | Steam-Turbine | Coal | 39.8 | % | | 522 |
| 1,527 |
|
| Sooner | 1 | 1979 | Steam-Turbine | Coal | Base Load | 68.7 | % | | 520 |
| | 1 | 1979 | Steam-Turbine | Coal | 44.8 | % | | 521 |
| |
| | 2 | 1980 | Steam-Turbine | Coal | Base Load | 61.2 | % | | 521 |
| 1,041 |
| 2 | 1980 | Steam-Turbine | Coal | 42.4 | % | | 520 |
| 1,041 |
|
| Horseshoe Lake | 6 | 1958 | Steam-Turbine | Gas/Oil | Base Load | 1.4 | % | | 169 |
| | 6 | 1958 | Steam-Turbine | Gas/Oil | 10.5 | % | | 167 |
| |
| | 7 | 1963 | Combined Cycle | Gas/Oil | Base Load | 17.1 | % | | 193 |
| | 7 | 1963 | Combined Cycle | Gas/Oil | 8.4 | % | | 214 |
| |
| | 8 | 1969 | Steam-Turbine | Gas | Base Load | 10.1 | % | | 394 |
| | 8 | 1969 | Steam-Turbine | Gas | 7.4 | % | | 405 |
| |
| | 9 | 2000 | Combustion-Turbine | Gas | Peaking | 1.4 | % | (B) | 46 |
| | 9 | 2000 | Combustion-Turbine | Gas | 18.6 | % |
| 46 |
| |
| | 10 | 2000 | Combustion-Turbine | Gas | Peaking | 1.8 | % | (B) | 45 |
| 847 |
| 10 | 2000 | Combustion-Turbine | Gas | 13.1 | % |
| 46 |
| 878 |
|
| Redbud (C) | 1 | 2003 | Combined Cycle | Gas | Base Load | 48.6 | % | | 149 |
| | |
| Redbud (B) | | 1 | 2003 | Combined Cycle | Gas | 66.9 | % | | 155 |
| |
| | 2 | 2003 | Combined Cycle | Gas | Base Load | 41.9 | % | | 147 |
| | 2 | 2003 | Combined Cycle | Gas | 65.0 | % | | 154 |
| |
| | 3 | 2003 | Combined Cycle | Gas | Base Load | 46.7 | % | | 147 |
| | 3 | 2003 | Combined Cycle | Gas | 61.8 | % | | 155 |
| |
| | 4 | 2003 | Combined Cycle | Gas | Base Load | 50.3 | % | | 149 |
| 592 |
| 4 | 2003 | Combined Cycle | Gas | 66.7 | % | | 152 |
| 616 |
|
| Mustang | 1 | 1950 | Steam-Turbine | Gas | Peaking | 2.1 | % | (B) | 50 |
| | 3 | 1955 | Steam-Turbine | Gas | 6.6 | % | | 120 |
| |
| | 2 | 1951 | Steam-Turbine | Gas | Peaking | 2.2 | % | (B) | 50 |
| | 4 | 1959 | Steam-Turbine | Gas | 12.6 | % | | 252 |
| |
| | 3 | 1955 | Steam-Turbine | Gas | Base Load | 5.8 | % | | 121 |
| | 5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | 1.0 | % |
| 28 |
| |
| | 4 | 1959 | Steam-Turbine | Gas | Base Load | 17.3 | % | | 242 |
| | 5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | 1.1 | % |
| 32 |
| 432 |
|
| McClain (C) | | 1 | 2001 | Combined Cycle | Gas | 78.1 | % | | 379 |
| 379 |
|
| Total Generating Capability (all stations, excluding wind stations) | | Total Generating Capability (all stations, excluding wind stations) | 6,218 |
|
| | 5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 0.3 | % | (B) | 34 |
| | | |
| | 5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 0.4 | % | (B) | 36 |
| 533 |
| |
| McClain (D) | 1 | 2001 | Combined Cycle | Gas | Base Load | 75.7 | % | | 353 |
| 353 |
| |
| Total Generating Capability (all stations, excluding wind stations) (E) | 6,336 |
| |
| | | | | | |
| | | 2013 Capacity Factor (A) | | Unit Capability (MW) | Station Capability (MW) | |
| Renewable | | | | 2016 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 | | 2013 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) | | Location |
| Crossroads | | 2011 | Canton, OK | 98 | Wind | 44.3 | | 2011 | Canton, OK | 98 | Wind | 38.7 | % | 2.3 |
| 228 |
|
| Centennial | | 2007 | Laverne, OK | 80 | Wind | 36.9 | | 2007 | Laverne, OK | 80 | Wind | 31.9 | % | 1.5 |
| 120 |
|
| OU Spirit | | 2009 | Woodward, OK | 44 | Wind | 40.6 | % | | 2.3 |
| 101.2 |
| | 2009 | Woodward, OK | 44 | Wind | 36.0 | % | 2.3 |
| 101 |
|
| Total Generating Capability (wind stations) | Total Generating Capability (wind stations) | 448.7 |
| Total Generating Capability (wind stations) | 449 |
|
| |
| (A) | 2013 2016 Capacity Factor =2013 2016 Net Actual Generation / (2013 (2016 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760Hours)).
|
| |
| (B) | Peaking units are used when additional short-term capacity is required.
|
| |
(C) | Represents OG&E's51 percentownership interest in the Redbud Plant. |
| |
(D)(C) | Represents OG&E's77 percentownership interest in the McClain Plant. |
During 2017, OG&E anticipates retiring units 3 and 4 located at the Mustang station.
At December 31, 20132016, OG&E's transmission system included: (i) 5152 substations with a total capacity of 12.013.3 million kilovolt-ampskV-amps and 4,5894,911 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.42.5 million kilovolt-ampskV-amps and 278277 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 353342 substations with a total capacity of 9.59.7 million kilovolt-amps,kV-amps, 29,14429,278 structure miles of overhead lines, 2,2392,690 miles of underground conduit and 10,61710,817 miles of underground conductors in Oklahoma and (ii) 3330 substations with a total capacity of 1.00.9 million kilovolt-amps,kV-amps, 2,7752,782 structure miles of overhead lines, 232270 miles of underground conduit and 696692 miles of underground conductors in 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, 20132016, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $2.21.8 billion and gross retirements were $246.7259.8 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to 24.817.1 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 20132016.
Item 3. Legal Proceedings.
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, except as set forth below, under "Environmental Laws and Regulations" in Item 7 of Part II of this Form 10-K and in Notes 12 and 13 of Notes toFinancial Statements, 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 onOG&E'sfinancial position, results of operations or cash flows.
1. Patent Infringement Case.On September 16, 2011, TransData, Inc., a Texas corporation, sued OG&E in the Western District of Oklahoma, accusing OG&E of infringing three of their U.S. patents by using OG&E's General Electric "smart" meters with Silver Spring Networks wireless modules. The complaint seeks a judgment of infringement, unspecified damages, a permanent injunction, costs and attorneys fees. OG&E was served with the complaint on September 21, 2011 and has notified both General Electric and Silver Springs Network of the lawsuit and its intent to seek indemnity from those companies for any damages that it may incur from this lawsuit. TransData, Inc. sought to consolidate its OG&E lawsuit with similar lawsuits in the Eastern District of Texas, however, on December 13, 2011, the TransData, Inc. cases were consolidated in the Western District of Oklahoma. OG&E has filed a motion for extension of time to answer the complaint. On December 30, 2011, OG&E and General Electric agreed to terms for General Electric to provide OG&E with an unqualified defense in the matter and to indemnify OG&E for costs, expenses and damages awarded against OG&E subject to a reservation of rights.While OG&E cannot predict the outcome of this lawsuit at this time, OG&E intends to vigorously defend this action and believes that its ultimate resolution will not be material to OG&E's financial position, results of operations or cash flows.
Item 4. Mine Safety Disclosures.
Not Applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.
In 20132016, 2015 and 20122014, OG&E declared dividends to OGE Energy of $170.0190.0 million, $120.0 million and $75.0$120.0 million, respectively.In2011, OG&E declarednodividends to OGE Energy.
Item 6. Selected Financial Data
HISTORICAL DATA
| | | Year ended December 31 | 2013 | 2012 | 2011 | 2010 | 2009 | |
Year ended December 31 (In millions) | | 2016 | 2015 | 2014 | 2013 | 2012 |
| SELECTED FINANCIAL DATA | | |
| (In millions) | | |
| | | |
| Results of Operations Data: | | |
| Operating revenues | $ | 2,262.2 |
| $ | 2,141.2 |
| $ | 2,211.5 |
| $ | 2,109.9 |
| $ | 1,751.2 |
| $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
| $ | 2,262.2 |
| $ | 2,141.2 |
|
| Cost of sales | 965.9 |
| 879.1 |
| 1,013.5 |
| 1,000.2 |
| 796.3 |
| 880.1 |
| 865.0 |
| 1,106.6 |
| 965.9 |
| 879.1 |
|
| Operating expenses | 771.0 |
| 772.7 |
| 725.7 |
| 696.0 |
| 600.8 |
| 870.2 |
| 831.5 |
| 808.5 |
| 771.0 |
| 772.7 |
|
| Operating income | 525.3 |
| 489.4 |
| 472.3 |
| 413.7 |
| 354.1 |
| 508.9 |
| 500.4 |
| 538.0 |
| 525.3 |
| 489.4 |
|
| Allowance for equity funds used during construction | 6.6 |
| 6.2 |
| 20.4 |
| 11.4 |
| 15.1 |
| 14.2 |
| 8.3 |
| 4.2 |
| 6.6 |
| 6.2 |
|
| Other income | 8.1 |
| 8.2 |
| 8.5 |
| 6.6 |
| 21.5 |
| 16.4 |
| 13.3 |
| 4.8 |
| 8.1 |
| 8.2 |
|
| Other expense | 4.6 |
| 4.3 |
| 8.4 |
| 1.6 |
| 6.7 |
| 2.9 |
| 1.6 |
| 1.9 |
| 4.6 |
| 4.3 |
|
| Interest expense | 129.3 |
| 124.6 |
| 111.6 |
| 103.4 |
| 93.6 |
| 138.1 |
| 146.7 |
| 141.5 |
| 129.3 |
| 124.6 |
|
| Income tax expense | 113.5 |
| 94.6 |
| 117.9 |
| 111.0 |
| 90.0 |
| 114.4 |
| 104.8 |
| 111.6 |
| 113.5 |
| 94.6 |
|
| Net income | $ | 292.6 |
| $ | 280.3 |
| $ | 263.3 |
| $ | 215.7 |
| $ | 200.4 |
| $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
| $ | 292.6 |
| $ | 280.3 |
|
| Balance Sheet Data (at period end): | | |
| Property, plant and equipment, net | $ | 6,634.6 |
| $ | 6,044.1 |
| $ | 5,550.9 |
| $ | 4,877.3 |
| $ | 4,467.6 |
| $ | 7,681.8 |
| $ | 7,296.1 |
| $ | 6,941.5 |
| $ | 6,634.6 |
| $ | 6,044.1 |
|
| Total assets | $ | 7,694.9 |
| $ | 7,222.4 |
| $ | 6,620.9 |
| $ | 5,898.1 |
| $ | 5,478.1 |
| |
| Long-term debt | $ | 2,300.2 |
| $ | 2,050.3 |
| $ | 2,039.2 |
| $ | 1,790.4 |
| $ | 1,541.8 |
| |
| 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 stockholder's equity | $ | 2,829.3 |
| $ | 2,703.1 |
| $ | 2,494.0 |
| $ | 2,178.1 |
| $ | 2,024.3 |
| $ | 3,252.1 |
| $ | 3,155.7 |
| $ | 3,004.2 |
| $ | 2,829.3 |
| $ | 2,703.1 |
|
| Capitalization Ratios (A) | | |
| Capitalization Ratios (B) | | |
| Stockholder's equity | 55.2 | % | 56.9 | % | 55.0 | % | 54.9 | % | 56.8 | % | 56.2 | % | 54.3 | % | 53.1 | % | 55.2 | % | 56.9 | % |
| Long-term debt | 44.8 | % | 43.1 | % | 45.0 | % | 45.1 | % | 43.2 | % | 43.8 | % | 45.7 | % | 46.9 | % | 44.8 | % | 43.1 | % |
| Ratio of Earnings to Fixed Charges (B) | | |
| Ratio of Earnings to Fixed Charges (C) | | |
| Ratio of earnings to fixed charges | 3.96 |
| 3.87 |
| 4.01 |
| 3.90 |
| 3.71 |
| 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)]. |
| |
(B)(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 constructionand (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. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.
Overview
OG&E Strategy
Mission and Focus
OGE Energy's mission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers'customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management.OGE Energy'scorporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses.
OG&E is focused on:
Providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.
Providing safe, reliable energy to the communities and customers we serve. A particular focus is on increased investment to preserve systemenhancing the value of the grid by improving distribution grid reliability by reducing the frequency and meet load growth by addingduration of customer interruptions and maintaining infrastructure equipment and replacing aging transmission and distribution systems. OG&E expects to maintain a diverse generation portfolio while remaining environmentally responsible. OG&E is focused on maintainingleveraging previous grid technology investments.
Having strong regulatory and legislative relationships for the long-term benefit of itsour customers, investors and members.
Continuing to grow a zero-injury culture and deliver top-quartile safety results.
Complying with the EPA's MATS and Regional Haze Rule requirements.
Ensuring we have the necessary mix of generation resources to meet the long-term needs of our customers. In an effort
Continuing focus on operational excellence and efficiencies in order to encourage more efficient use of electricity, OG&E is also providing energy management solutions to its customers throughprotect the Smart Grid program that utilizes newer technology to improve operational and environmental performance as well as allow customers to monitor and manage their energy usage, which should help reduce demand during critical peak times, resulting in lower capacity requirements. If these initiatives are successful, OG&E believes it may be able to defer the construction or acquisition of any incremental fossil fuel generation capacity until 2020. The Smart Grid program also provides benefits to OG&E, including more efficient use of its resources and access to increased information about customer usage, which should enable OG&E to have better distribution system planning data, better response to customer usage questions and faster detection and restoration of system outages. As the Smart Grid platform matures, OG&E anticipates providing new products and services to its customers. In addition, OG&E is also pursuing additional transmission-related opportunities within the SPP.
bill.
Summary of Operating Results
20132016compared to20122015. OG&E reported net income of $292.6284.1 million and $280.3268.9 million, respectively, in 20132016 and 20122015, an increase of $12.315.2 million, or 4.45.7 percent, driven by higherprimarily due to an increase in gross margin primarily related to warmer summer weather and increased wholesale transmission revenuerevenues and loweran increase in other income. Partially offsetting these items was an increase in other operation and maintenance expense, partially offset by higher interestan increase in depreciation expense relateddue to the issuance of debtadditional assets being placed in May 2013service and an increase in income tax expense.
20122015 compared to 20112014. OG&E reported net income of $280.3$268.9 million and $263.3$292.0 million, respectively, in 20122015 and 2011, an increase2014, a decrease of $17.0$23.1 million, or 6.57.9 percent, primarily due to a higher gross margin primarily due to increased recovery of investments and increased transmission revenue partially offset by milder weather in OG&E's service territory. Thean increase in gross margin was partially offset by higher depreciation and amortization expense relateddue to additional assets being placed in service in 2015, a decrease in gross margin related to milder weather and lowerdecreased wholesale transmission revenues. Partially offsetting these items was an increase in customer growth, an increase in other income and an increase in allowance for equity funds used during construction related to higher levels of construction costs for the Crossroads wind farm in 2011.
2014 Outlook
construction.
2017 Outlook
OG&E projects to earn approximately $292$316 million to $303$340 million or $1.58 to $1.70 per average diluted share in 20142017 and is based on the following assumptions:
Normalnormal weather patterns are experienced for the remainder of the year;
new rates take effect in Oklahoma and Arkansas in 2017;
Grossgross margin on revenues of approximately $1.355$1.470 billion to $1.345$1.485 billion based on sales growth of approximately 1.2one percent on a weather-adjusted basis;
Approximately $115approximately $110 million of gross margin is primarily attributed to regionally allocated transmission projects;
Operatingoperating expenses of approximately $805$896 million to $815$917 million, with operation and maintenance expenses comprising 5654 percent of the total;
Interestinterest expense of approximately $141$147 million which assumes a $4$15 million allowance for borrowed funds used during construction reduction to interest expense and $250assumes a debt issuance of $300 million of long-term debt issued in the first half of 2014;2017;
other income of approximately $60 million including approximately $34 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;
Otheran effective tax rate of approximately 32 percent;
assumes revenue of approximately $23 million or net income of approximately $14 million including approximately $11 million of AEFUDC;or $0.07 per average diluted share for rates implemented on 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; andAn effective tax rateevery 10 basis point change in the allowed Oklahoma return on equity equates to a change of approximately 28 percent.
$3.6 million in revenue.
OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.
Results of Operations
The following discussion and analysis presents factors that affected OG&E's results of operations for the years endedDecember 31, 2013, 2012and2011and OG&E's financial position atDecember 31, 2013and2012. The following information should be read in conjunction with theNon-GAAP Financial Statements and Notes thereto.Known trends and contingencies of a material nature are discussed to the extent considered relevant.
|
| | | | | | | | | |
Year ended December 31 (In millions) | 2013 | 2012 | 2011 |
| Operating income | $ | 525.3 |
| $ | 489.4 |
| $ | 472.3 |
|
| Net income | $ | 292.6 |
| $ | 280.3 |
| $ | 263.3 |
|
In reviewing itsoperating results, OG&E believes that it is appropriate to focus on operating income as reported in its Statements of Income as those measures indicate the ongoing profitability of OG&E excluding the cost of capital and income taxes.
|
| | | | | | | | | |
Year ended December 31 (Dollars in millions) | 2013 | 2012 | 2011 |
| Operating revenues | $ | 2,262.2 |
| $ | 2,141.2 |
| $ | 2,211.5 |
|
| Cost of sales | 965.9 |
| 879.1 |
| 1,013.5 |
|
| Other operation and maintenance | 438.8 |
| 446.3 |
| 436.0 |
|
| Depreciation and amortization | 248.4 |
| 248.7 |
| 216.1 |
|
| Taxes other than income | 83.8 |
| 77.7 |
| 73.6 |
|
| Operating income | 525.3 |
| 489.4 |
| 472.3 |
|
| Allowance for equity funds used during construction | 6.6 |
| 6.2 |
| 20.4 |
|
| Other income | 8.1 |
| 8.2 |
| 8.5 |
|
| Other expense | 4.6 |
| 4.3 |
| 8.4 |
|
| Interest expense | 129.3 |
| 124.6 |
| 111.6 |
|
| Income tax expense | 113.5 |
| 94.6 |
| 117.9 |
|
| Net income | $ | 292.6 |
| $ | 280.3 |
| $ | 263.3 |
|
| Operating revenues by classification | | | |
| Residential | $ | 901.4 |
| $ | 878.0 |
| $ | 943.5 |
|
| Commercial | 554.2 |
| 523.5 |
| 531.3 |
|
| Industrial | 220.6 |
| 206.8 |
| 216.0 |
|
| Oilfield | 176.4 |
| 163.4 |
| 165.1 |
|
| Public authorities and street light | 214.3 |
| 202.4 |
| 207.4 |
|
| Sales for resale | 59.4 |
| 54.9 |
| 65.3 |
|
| System sales revenues | 2,126.3 |
| 2,029.0 |
| 2,128.6 |
|
| Off-system sales revenues | 14.7 |
| 36.5 |
| 36.2 |
|
| Other | 121.2 |
| 75.7 |
| 46.7 |
|
| Total operating revenues | $ | 2,262.2 |
| $ | 2,141.2 |
| $ | 2,211.5 |
|
| Reconciliation of gross margin to revenue: | | | |
| Operating revenues | 2,262.2 |
| 2,141.2 |
| 2,211.5 |
|
| Cost of sales | 965.9 |
| 879.1 |
| 1,013.5 |
|
| Gross Margin | 1,296.3 |
| 1,262.1 |
| 1,198.0 |
|
MWH sales by classification (In millions) | | | |
| Residential | 9.4 |
| 9.1 |
| 9.9 |
|
| Commercial | 7.1 |
| 7.0 |
| 6.9 |
|
| Industrial | 3.9 |
| 4.0 |
| 3.9 |
|
| Oilfield | 3.4 |
| 3.3 |
| 3.2 |
|
| Public authorities and street light | 3.2 |
| 3.3 |
| 3.2 |
|
| Sales for resale | 1.2 |
| 1.3 |
| 1.4 |
|
| System sales | 28.2 |
| 28.0 |
| 28.5 |
|
| Off-system sales | 0.4 |
| 1.4 |
| 1.0 |
|
| Total sales | 28.6 |
| 29.4 |
| 29.5 |
|
| Number of customers | 806,940 |
| 798,110 |
| 789,146 |
|
| Weighted-average cost of energy per kilowatt-hour - cents | | | |
| Natural gas | 3.905 |
| 2.930 |
| 4.328 |
|
| Coal | 2.273 |
| 2.310 |
| 2.064 |
|
| Total fuel | 2.784 |
| 2.437 |
| 2.897 |
|
| Total fuel and purchased power | 3.178 |
| 2.806 |
| 3.215 |
|
| Degree days (A) | | | |
| Heating - Actual | 3,673 |
| 2,667 |
| 3,359 |
|
| Heating - Normal | 3,349 |
| 3,349 |
| 3,631 |
|
| Cooling - Actual | 2,106 |
| 2,561 |
| 2,776 |
|
| Cooling - Normal | 2,092 |
| 2,092 |
| 1,911 |
|
| |
(A) | Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period. |
2013 compared to 2012.OG&E's operating income increased$35.9 million, or7.3 percent, in2013as compared to2012primarily due to a higher grossGross margin lower other operation and maintenance expense and lower depreciation and amortization expense partially offset by higher taxes other than income.
Gross Margin
Gross Margin is defined by OG&E as operating revenues less fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power and transmission expenses are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies.
For a reconciliation of gross margin to revenue for the years ended December 31, 2016, 2015 and 2014, see OG&E (Electric Utility) Results of Operations below.
Detailed below is a reconciliation of gross margin to revenue included in the 2017 Outlook.
|
| | | |
| Reconciliation of Gross Margin to Revenue |
|
| Year Ended December 31, (Dollars in Millions) | 2017
(A) |
| Operating revenues | $ | 2,088 |
|
| Cost of sales | 610 |
|
| Gross margin | $ | 1,478 |
|
| |
| (A) | Based on the midpoint of OG&E earnings guidance for 2017. |
Results of Operations
The following discussion and analysis presents factors that affected OG&E's results of operations for the years endedDecember 31, 2016, 2015and2014and OG&E's financial position atDecember 31, 2016and2015. The following information should be read in conjunction with theFinancial 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 |
| Operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
| Cost of sales | 880.1 |
| 865.0 |
| 1,106.6 |
|
| 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 |
|
| Operating income | 508.9 |
| 500.4 |
| 538.0 |
|
| 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 |
|
| Interest expense | 138.1 |
| 146.7 |
| 141.5 |
|
| Income tax expense | 114.4 |
| 104.8 |
| 111.6 |
|
| Net income | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
| Operating revenues by classification | | | |
| Residential | $ | 951.9 |
| $ | 896.5 |
| $ | 925.5 |
|
| Commercial | 573.7 |
| 535.0 |
| 583.3 |
|
| Industrial | 194.6 |
| 190.6 |
| 224.5 |
|
| Oilfield | 156.9 |
| 162.8 |
| 188.3 |
|
| Public authorities and street light | 204.3 |
| 194.2 |
| 220.3 |
|
| Sales for resale | 0.3 |
| 21.7 |
| 52.9 |
|
| System sales revenues | 2,081.7 |
| 2,000.8 |
| 2,194.8 |
|
| Provision for rate refund | (33.6 | ) | — |
| — |
|
| Integrated market | 49.3 |
| 48.6 |
| 94.1 |
|
| Other | 161.8 |
| 147.5 |
| 164.2 |
|
| Total operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
| Reconciliation of gross margin to revenue: | | | |
| Operating revenues | $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
| Cost of sales | 880.1 |
| 865.0 |
| 1,106.6 |
|
| Gross margin | $ | 1,379.1 |
| $ | 1,331.9 |
| $ | 1,346.5 |
|
MWh sales by classification (In millions) | | | |
| Residential | 9.3 |
| 9.2 |
| 9.4 |
|
| Commercial | 7.6 |
| 7.4 |
| 7.2 |
|
| Industrial | 3.6 |
| 3.6 |
| 3.8 |
|
| Oilfield | 3.2 |
| 3.4 |
| 3.4 |
|
| Public authorities and street light | 3.2 |
| 3.1 |
| 3.2 |
|
| Sales for resale | — |
| 0.5 |
| 1.0 |
|
| System sales | 26.9 |
| 27.2 |
| 28.0 |
|
| Integrated market | 3.0 |
| 1.7 |
| 2.2 |
|
| Total sales | 29.9 |
| 28.9 |
| 30.2 |
|
| Number of customers | 833,582 |
| 824,776 |
| 814,982 |
|
| Weighted-average cost of energy per kilowatt-hour - cents | | | |
| Natural gas | 2.488 |
| 2.529 |
| 4.506 |
|
| Coal | 2.213 |
| 2.187 |
| 2.152 |
|
| Total fuel | 2.199 |
| 2.196 |
| 2.752 |
|
| Total fuel and purchased power | 2.842 |
| 2.874 |
| 3.493 |
|
| Degree days (A) | | | |
| Heating - Actual | 2,800 |
| 3,038 |
| 3,569 |
|
| Heating - Normal | 3,349 |
| 3,349 |
| 3,349 |
|
| Cooling - Actual | 2,247 |
| 2,071 |
| 2,114 |
|
| Cooling - Normal | 2,092 |
| 2,092 |
| 2,092 |
|
| |
| (A) | Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the |
calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.
2016 compared to 2015.OG&E's net income increased $15.2 million, or 5.7 percent, in2016as compared to2015primarily due to an increase in gross margin related to warmer summer weather and increased transmission revenues and an increase in other income partially offset by increases in other operation and maintenance expense, depreciation expense and income tax expense.
Operating revenues were $2,262.22,259.2 million in 20132016 as compared to $2,141.22,196.9 million in 20122015, an increase of $121.062.3 million, or 5.72.8 percent. Cost of sales were $965.9880.1 million in 20132016 as compared to $879.1865.0 million in 20122015, an increase of $86.815.1 million, or 9.91.7 percent. Gross margin was $1,296.3$1,379.1 million in 20132016 as compared to $1,262.1$1,331.9 million in 20122015, an increase of $34.2$47.2 million, or 2.7 percent3.5 percent. The below factors contributed to the change in gross margin:
| | | | $ Change | |
| | (In millions) | |
| Wholesale transmission revenue (A) | $ | 44.9 |
| |
| (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 | 10.9 |
| 3.2 |
|
| Non-residential demand and related revenues | 0.1 |
| 0.6 |
|
| Other | 1.8 |
| (3.7 | ) |
| Price variance (B) | (17.1 | ) | |
| Quantity variance (primarily weather) | (6.4 | ) | |
| Expiration of AVEC contract (D) | | (9.7 | ) |
| Change in gross margin | $ | 34.2 |
| $ | 47.2 |
|
| |
| (A) | As discussed 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. |
| |
| (B) | Increased primarily due to the SPP's settlement of revenue credits related to the Windspeed Transmission line for the years 2008 through August 2016. Other increases include a recovery of the base plan projects in the SPP formula rate for 2015 and 2016. |
| |
| (C) | Increased primarily due to the reversal of a reserve for gas transportation charges in addition to the pricing impact of weather related sales. |
| |
| (D) | On June 30, 2015, the wholesale power contract with AVEC expired. |
Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission 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. 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.
Operating Expenses
Other operation and maintenance expense was$469.8 millionin2016as compared to$444.5 millionin2015, an increaseof$25.3 million, or5.7 percent. The below factors contributed to the change in other operation and maintenance expense:
|
| | | |
| (In millions) | $ Change |
| Salaries and wages (A) | $ | 10.4 |
|
| Contract professional services (B) | 8.7 |
|
| Corporate allocations and overheads (C) | 8.1 |
|
| Other | (1.9 | ) |
| Change in other operation and maintenance expense | $ | 25.3 |
|
| |
| (A) | Increased primarily due to higher investments related to certain FERC approved transmission projects includedincreases in formula rates.incentive compensation, pension expense, annual salaries and medical/dental expense partially offset by a decrease in overtime. |
| |
| (B) | Increased primarily due to increased consulting costs associated with demand side management programs. |
| |
| (C) | Increased primarily due to additional direct support in information technology, facility direct support, strategy and marketing support. |
Depreciation and amortization expense was$316.4 millionin2016as compared to$299.9 millionin2015, an increaseof$16.5 million, or 5.5 percent, primarily due to additional assets being placed in service and amortization of deferred storm costs.
Taxes other than income taxes 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 $5.9 million, or 71.1 percent, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.
Other Income. Other income was $16.4 million in 2016 as compared to $13.3 million in 2015, an increase of $3.1 million, or 23.3 percent, primarily due to an increase in the tax gross up related to higher allowance for equity funds used during construction and an increase in interest income related to riders partially offset by decreased guaranteed flat bill margins.
Other Expense. 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 increased 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 and an increase in allowance for equity funds used in construction.
Operating revenues were $2,196.9 million in 2015 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. The below factors contributed to the change in gross margin:
|
| | | |
| (In millions) | $ Change |
| Quantity variance (primarily weather) (A) | $ | (25.8 | ) |
| Wholesale transmission revenue (B) | (19.8 | ) |
| Expiration of AVEC contract (C) | (11.5 | ) |
| Industrial and oilfield sales | (4.5 | ) |
| Other | 2.1 |
|
| Non-residential demand and related revenues | 3.7 |
|
| Price Variance (D) | 19.8 |
|
| New customer growth | 21.4 |
|
| Change in gross margin | $ | (14.6 | ) |
| |
| (A) | The overall cooling degree days decreased two percent in 2015 compared to 2014 with August decreasing by 14.0 percent. |
| |
| (B) | Decreased primarily due to a true up for the base plan projects in the SPP formula rate for 2014 and 2015 as well as a reduction in the point-to-point credits shared with retail customers. |
| |
| (C) | On June 30, 2015, the wholesale power contract with AVEC expired. |
| |
| (D) | Increased primarily due to sales and customer mix. |
Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was$672.7 $458.5 millionin2013 2015 as compared to$642.4 $627.5 millionin2012, an increase 2014, a decrease of$30.3 $169.0 million,, or4.7 26.9 percent,, primarily due to lower natural gas prices offset by higher natural gas prices. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers.used. In2013, 2015, OG&E's fuel mix was53 49.0 percentcoal,40 44.0 percentnatural gas andseven percentwind. In2012, 2014, OG&E's fuel mix was52 61.0 percentcoal,42 32.0 percentnatural gas andsix seven percentwind. Purchased power costs were$267.6 $362.6 millionin2013 2015 as compared to$223.0 $444.1 millionin2012, an increase 2014, a decrease of$44.6 $81.5 million,, or20.0 18.4 percent,, primarily due to an increasea decrease in purchases from the SPP, reflecting the impact of OG&E's participation in the energy imbalance service market and short-term power agreements.SPP Integrated Marketplace, which began on March 1, 2014. Transmission related charges were$25.6 $43.9 millionin2013 2015 as compared to$13.7 $35.0 millionin2012, 2014, an increaseof$11.9 $8.9 million,, or86.9 25.4 percent,, primarily due to higher SPP charges for the base plan projects of other utilities.
Variances in theThe actual cost of fuel used in electric generation and certain purchased power costs as compared to the fuel component included in the cost-of-service for ratemaking, 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
Operating Expenses
Other operation and maintenance expenses were$438.8expense was $444.5 millionin2013 2015 as compared to$446.3 $453.2 millionin2012, 2014, a decreaseof$7.5 $8.7 million,, or1.7 percent. 1.9 percent. The below factors contributed to the change in other operationsoperation and maintenance expense:
|
| | | |
| | $ Change |
| | (In millions) |
| Employee benefits (A) | $ | (12.3 | ) |
| Total salaries and wages (B) | (6.5 | ) |
| Temporary labor | (2.3 | ) |
| Contract professional services (primarily smart grid) (C) | (1.7 | ) |
| Other | 0.6 |
|
| Other marketing and sales expense (primarily lower demand-side management initiatives) (C) | 1.2 |
|
| Administrative and assessment fees (primarily SPP Administration Fees) | 2.2 |
|
| Software expense (primarily smart grid) (C) | 2.7 |
|
| Capitalized labor | 8.6 |
|
| Change in other operation and maintenance expense | $ | (7.5 | ) |
|
| | | |
| (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 | ) |
| |
| (A) | Decreased primarily due to lower recoverable amounts of pension expensemore capital projects and postretirement medical expense allowed instorm costs exceeding the August 2012 rate case,$2.7 million threshold, which were moved to a decrease in medical expense, and a decrease in worker's compensation accruals.regulatory asset. |
| |
| (B) | Decreased primarily due to lower salaries and wages as a result of lower headcount in 2013 and a decrease in incentive pay, partially offset by annual salary increases and an increase in overtime wages related to 2013 storms. |
| |
(C) | Includes costs that are being recovered through a rider. |
Depreciation and amortization expense was$248.4 millionin2013as compared to$248.7 millionin2012, a decreaseof$0.3 million, primarily due to the amortization of the deferred pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1). These decreases in depreciation and amortization expense were partially offset by:
increases in depreciation rates from the August 2012 rate case; and
additional assets being placed in service throughout 2013 and 2012, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland to Sooner transmission project which was fully in service in February 2013.
Taxes other than income was$83.8 million in 2013 as compared to $77.7 million in 2012, an increase of $6.1 million, or 7.9 percent, primarily due to higher ad valorem taxes.
Additional Information
Interest Expense.Interest expense was$129.3 millionin2013as compared to$124.6 millionin2012, an increase of $4.7 million, or 3.8 percent, primarily due to a$6.4 millionincreasein interest on long term debt related to a $250 million debt issuance that occurred in May 2013, partially offset by a $2.0 million decrease in interest related to tax matters.
Income Tax Expense.Income tax expense was$113.5 millionin2013as compared to$94.6 millionin2012, an increaseof$18.9 million, or20.0 percent. primarily due tohigherpre-tax income and a reserve related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized.
2012 compared to 2011.OG&E's operating income increased $17.1 million, or 3.6 percent, in 2012 as compared to 2011 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense and higher depreciation and amortization expense.
Gross Margin
Operating revenues were $2,141.2 million in 2012 as compared to $2,211.5 million in 2011, a decrease of $70.3 million, or 3.2 percent. Fuel and purchased power was $879.1 million in 2012 as compared to $1,013.5 million in 2011, a decrease of $134.4 million, or 13.3 percent. Gross margin was $1,262.1 million in 2012 as compared to $1,198.0 million in 2011, an increase of $64.1 million, or 5.4 percent. The below factors contributed to the change in gross margin:
|
| | | |
| | $ Change |
| | (In millions) |
| Price variance (A) | $ | 54.1 |
|
| Wholesale transmission revenue (B) | 28.5 |
|
| New customer growth | 11.5 |
|
| Non-residential demand and related revenues | 4.9 |
|
| Enogex transportation credit (C) | 3.3 |
|
| Arkansas rate increase | 2.8 |
|
| Oklahoma rate increase | 2.7 |
|
| Renewal of wholesale contract with customer | 1.3 |
|
| Other | 0.3 |
|
| Quantity variance (primarily weather) | (45.3 | ) |
| Change in gross margin | $ | 64.1 |
|
| |
(A) | Increased due to revenues fromless work at the recovery of investments, including the Crossroads wind farm and smart grid.
|
| |
(B) | Increased primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction.power plants.
|
| |
| (C) | Increased due to a credit to OG&E's customers in 2011 related to the settlement of OG&E's 2009 fuel adjustment clause review.
|
Fuel expense was $642.4 million in 2012 as compared to $775.0 million in 2011, a decrease of $132.6 million, or 17.1 percent, primarily due to lower natural gas prices. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2012, OG&E's fuel mix was 52 percent coal, 42 percent natural gas and six percent wind. In 2011, OG&E's fuel mix was 58 percent coal, 39 percent natural gas and three percent wind. Purchased power costs were $223.0 million in 2012 as compared to $230.7 million in 2011, a decrease of $7.7 million, or 3.3 percent, primarily due to a decrease in cogeneration purchases and purchases in the energy imbalance service market due to milder weather partially offset by an increase in short-term power purchases. Transmission related charges were $13.7 million in 2012 as compared to $7.8 million in 2011, an increase of $5.9 million, or 75.6 percent, primarily due to higher SPP charges for the base plan projects of other utilities.
Operating Expenses
Other operation and maintenance expenses were $446.3 million in 2012 as compared to $436.0 million in 2011, an increase of $10.3 million, or 2.4 percent. The below factors contributed to the change in other operations and maintenance expense: |
| | | |
| | $ Change |
| | (In millions) |
| Salaries and wages (A) | $ | 6.4 |
|
| Contract professional and technical services (related to smart grid) (B) | 4.2 |
|
| Employee benefits (C) | 3.4 |
|
| Administration and assessment fees (primarily SPP and North American Electric Reliability Corporation) | 3.4 |
|
| Wind farm lease expense (primarily Crossroads) (B) | 3.0 |
|
| Injuries and damages | 1.9 |
|
| Ongoing maintenance at power plants (B) | 1.9 |
|
| Software (primarily smart grid) (B) | 1.8 |
|
| Other | 0.2 |
|
| Temporary labor | (1.7 | ) |
| Uncollectibles | (2.4 | ) |
| Vegetation management (primarily system hardening) (B) | (3.0 | ) |
| Allocations from holding company (primarily lower contract professional services and lower payroll and benefits) | (3.1 | ) |
| Capitalized labor | (5.7 | ) |
| Change in other operation and maintenance expense | $ | 10.3 |
|
| |
(A) | IncreasedDecreased primarily due to salary increases and an increase in incentive compensation expense partially offset by lower headcount in 2012 and a decrease in overtime expense.decreased engineering services. |
| |
(B)(D) | IncludesIncreased primarily due to higher medical costs that are being recovered through a rider.incurred partially offset by lower pension costs. |
| |
(C)(E) | Increased primarily due to an increase in worker's compensation accruals, an increase in medical expensehigher demand side management customer payments. |
| |
| (F) | Increased primarily due to annual salary increases and an increase in postretirement medical expense partially offset by a decrease in pension expense.increased overtime related to storms. |
Depreciation and amortization expense was $248.7$299.9 million in 20122015 as compared to $216.1$270.8 million in 2011,2014, an increase of $32.6$29.1 million, or 15.110.7 percent, primarily due to additional assets being placed in service, throughout 2011along with an increase resulting from the amortization of deferred pension credits and 2012, including the Crossroads wind farm, which was fully in service in January 2012, the Sooner-Rose Hill and Sunnyside-Hugo transmission projects,post-retirement medical regulatory liabilities which were fully amortized in service in April 2012,July 2014 and the smart grid project which was completed in late 2012.amortization of deferred storm costs.
Additional Information
Allowance for Equity Funds Used During Construction.Construction. Allowance for equity funds used during construction was $6.2$8.3 million in 20122015 as compared to $20.4$4.2 million in 2011, a decrease2014, an increase of $14.2$4.1 million or 69.697.6 percent, primarily due to higher levels of construction costswork in progress balances resulting from increased spending for the Crossroads wind farm in 2011.
environmental projects.
Other Income.Income. Other income was $8.0$13.3 million in both 2012 and 2011. Factors affecting other income included2015 as compared to $4.8 million in 2014, an increased marginincrease of $8.8$8.5 million, recognized in theprimarily due to increased guaranteed flat bill programmargins and an increase in 2012 as a result of milder weather offset by a decrease of $8.9 millionthe tax gross up related to the benefit associated with the tax gross-up ofhigher allowance for equity funds used during construction.
OtherIncome Tax Expense.OtherIncome tax expense was $4.3$104.8 million in 2012 as compared to $8.4 million in 2011, a decrease of $4.1 million, or 48.8 percent primarily due to a decrease in charitable contributions.
Interest Expense.Interest expense was $124.6 million in 20122015 as compared to $111.6 million in 2011, an increase2014, a decrease of $13.0$6.8 million, or 11.66.1 percent, primarily due to lower pretax income partially offset by a $6.9 million increasereduction in interest expense related to lower allowance for borrowed funds used during construction costs for the Crossroads wind farm in 2011 and a $5.5 million increase in interest expense related to the issuance of long-term debt in May 2011.
Federal tax credits.
Income Tax Expense.Income tax expense was $94.6 million in 2012 as compared to $117.9 million in 2011, a decrease of $23.3 million, or 19.8 percent. The decrease in income tax expense was primarily due to an increase in the amount of Federal renewable energy tax credits recognized associated with the Crossroads wind farm and lower pre-tax income in 2012 as compared to 2011.
Off-Balance Sheet Arrangement
Railcar Lease Agreement
OG&E has a noncancellable operating lease with a purchase options,option, covering 1,389 coalapproximately 1,250 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expensefuel expense and are recovered through OG&E's tariffs and fuel adjustment clauses.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed.
On October 14, 2014, OG&E signed a separate three-year lease effective December 2014 for 131 railcars to replace railcars that have been taken out of service or destroyed.
On December 15, 2010,17, 2015, OG&E renewed the lease agreement effective February 1, 2011.2016. At the end of the new lease term, which is February 1, 2016,2019, 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$22.8 million. $18.3 million. OG&E is also required to maintain all of the railcars it has under the operating lease and has entered into an agreement with a non-affiliated company to furnish this maintenance.lease.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed. OG&E has a unilateral right to terminate this lease upon a 6-month notice effective April 2015 and April 2016.
Liquidity and Capital Resources
Working Capital
Working capital is defined as the amount by whichdifference in current assets exceedand 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 Net and Accrued Unbilled Revenues was$238.1 $232.7 millionand$218.9 $226.6 millionatDecember 31, 20132016 and2012, 2015, respectively,an increase of $19.2$6.1 million,, or8.8 2.7 percent,, primarily due tohigher transmission revenue, an increase in billings for reimbursable construction costs and an increase in billings to partners of jointly-owned power plants.OG&E's retail customers reflecting higher usage in December 2016 compared to December 2015.
Fuel Inventories. The balance of Fuel Inventories was $79.8 million and $113.8 million at December 31, 2016 and 2015, respectively, a decrease of $34.0 million, or 29.9 percent, primarily due to lower coal inventory balances resulting from increased production from coal plants in 2016 and lower average prices.
Fuel Clause Recoveries. The Fuel Clause balance was an under recovery of $51.3 million at December 31, 2016 compared to an over recovery of $61.3 million at December 31, 2015, primarily due to lower amounts billed to OG&E retail customers as compared to the actual cost of fuel and purchased power.
Other Current Assets. The balance of Other Current Assets was $78.3 million and $51.6 million at December 31, 2016 and 2015, respectively, an increase of $26.7 million, or 51.7 percent, primarily due to lower revenue collections from customers associated with various rate riders.
Accounts Payable. The balance of Accounts Payable was $239.0 $196.4 million and $187.4 $238.2 million at atDecember 31, 20132016and20122015, respectively, an increase a decrease of $51.6 $41.8 million, or 27.5 17.5 percent, primarily due to a decrease in accruals and the timing of vendor payments andpartially offset by an increase in accrualsfuel 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 million and $23.8 million at December 31, 2016 and 2015, respectively, an increase of $7.5 million, or 31.5 percent, primarily due to an increase in accrued incentive compensation and a decrease in labor 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 million and $43.6 million at December 31, 2016 and 2015, respectively, an increase of $52.2 million, primarily due to revenue that has been collected from customers but is reserved and subject to refund until OG&E receives a rate case order from the OCC and the SPP credits that will be returned to customers.
Cash Flows
| | | | | 2013 vs. 2012 | 2012 vs. 2011 | | 2016 vs. 2015 | 2015 vs. 2014 |
Year ended December 31 (In millions) | 2013 | 2012 | 2011 | $ Change | % Change | $ Change | % Change | 2016 |
| 2015 |
| 2014 |
| $
Change | %
Change | $
Change | %
Change |
| Net cash provided from operating activities | $ | 545.1 |
| $ | 737.4 |
| $ | 549.3 |
| $ | (192.3 | ) | (26.1 | )% | $ | 188.1 |
| 34.2 | % | $ | 572.9 |
| $ | 770.5 |
| $ | 587.7 |
| $ | (197.6 | ) | (25.6 | )% | $ | 182.8 |
| 31.1 | % |
| Net cash used in investing activities | (796.8 | ) | (676.3 | ) | (794.3 | ) | (120.5 | ) | (17.8 | )% | 118.0 |
| (14.9 | )% | (659.2 | ) | (549.0 | ) | (564.7 | ) | (110.2 | ) | 20.1 | % | 15.7 |
| (2.8 | )% |
| Net cash provided from (used in) financing activities | 251.7 |
| (61.1 | ) | 245.0 |
| 312.8 |
| * |
| (306.1 | ) | * |
| 86.3 |
| (221.5 | ) | (23.0 | ) | 307.8 |
| * |
| (198.5 | ) | * |
|
* Percentage is greaterGreater than a 100 percent.
percent variance.
Operating Activities
Thedecrease decrease of $192.3$197.6 million,, or 26.125.6 percent,, in net cash provided from operating activities in2013 2016 as compared to2012 2015 was primarily due to a return of cash from fuel refundsin2013as comparedover recoveries to higher fuel recoveries incustomers.2012.
The increase of $188.1182.8 million, or 34.231.1 percent, in net cash provided from operating activities in 20122015 as compared to 20112014 was primarily due to:
higher fuel recoveriesin2012as compared to2011; and
an increase in cash received from fuel recoveries and a decrease in 2012 from transmission revenue and the recovery of investments including the Crossroads wind farm and smart grid partially offset by milder weather in 2012.payments to vendors.
Investing Activities
The increase of $120.5$110.2 million,, or 17.820.1 percent,, in net cash used in investing activities in2013 2016 as compared to2012 2015 was primarily due to increasedan increase in capital expenditures in 2013 related to various transmissionenvironmental projects.
The decrease of $118.0$15.7 million,, or 14.92.8 percent,, in net cash used in investing activities in 20122015 as compared to 20112014 was primarily due to a decrease in capital expenditures related to lower levels oftransmission projects partially offset by an increase in capital expenditures in2012related to the Crossroads wind farm. environmental projects.
Financing Activities
The increase of $312.8$307.8 million in net cash provided from financing activities in2013 2016 as compared to2012 2015 was primarily due to:
proceeds received from the issuance of long-term debt in May 2013; and
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.2013.
These The increases of $198.5 million in net cash provided from financing activities were partially offset by dividends paymentsused in 2013.
The decrease of $306.1 million in net cash provided from financing activities in2012 2015 as compared to2011 2014 was primarily due to:
proceeds received fromto the issuance of long-term debt during 2011; and
dividend payments in 2012; and
a capital contribution from OGE Energy during 2011.2014 partially offset by:
These decrease•the payment of $140.0 million in long-term debt during 2014;
•net cash provided from financing activities were partially offset by an increase in net advances with OGE Energy during 2012.2015; and
a decrease in dividend payments in 2015.
Future Capital Requirements and Financing Activities
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.
Capital Expenditures
OG&E's estimates of capital expenditures for the years 20142017 through2018 2021 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.
| | | (In millions) | 2014 | 2015 | 2016 | 2017 | 2018 | 2017 | 2018 | 2019 | 2020 | 2021 |
| Base Transmission | $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 35 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
| $ | 30 |
|
| Base Distribution | 175 |
| 175 |
| 175 |
| 175 |
| 175 |
| 195 |
| 175 |
| 175 |
| 175 |
| 175 |
|
| Base Generation | 140 |
| 75 |
| 75 |
| 75 |
| 75 |
| 40 |
| 75 |
| 75 |
| 75 |
| 75 |
|
| Other | 15 |
| 15 |
| 15 |
| 15 |
| 15 |
| 35 |
| 25 |
| 25 |
| 25 |
| 25 |
|
| Total Base Transmission, Distribution, Generation and Other | 360 |
| 295 |
| 295 |
| 295 |
| 295 |
| 305 |
| 305 |
| 305 |
| 305 |
| 305 |
|
| Known and Committed Projects: | | |
| Known and Committed Non-Base Projects: | | |
| Transmission Projects: | | |
| Regionally Allocated Base Projects (A) | 55 |
| 20 |
| 20 |
| 20 |
| 20 |
| |
| Balanced Portfolio 3E Projects (B)(C) | 15 |
| — |
| — |
| — |
| — |
| |
| SPP Priority Projects (B)(C) | 75 |
| — |
| — |
| — |
| — |
| |
| SPP Integrated Transmission Projects (B) (C) | 15 |
| 25 |
| 30 |
| 25 |
| 10 |
| |
| Other Regionally Allocated Projects (A) | | 50 |
| 20 |
| 20 |
| 20 |
| 20 |
|
| Large SPP Integrated Transmission Projects (B) (C) | | 155 |
| 20 |
| — |
| — |
| — |
|
| Total Transmission Projects | 160 |
| 45 |
| 50 |
| 45 |
| 30 |
| 205 |
| 40 |
| 20 |
| 20 |
| 20 |
|
| Other Projects: | | |
| Smart Grid Program | 25 |
| 10 |
| 10 |
| — |
| — |
| |
| Environmental - low NOX burners | 35 |
| 20 |
| 15 |
| 10 |
| — |
| |
| Environmental - activated carbon injection | 5 |
| 10 |
| 5 |
| — |
| — |
| |
| 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 | 65 |
| 40 |
| 30 |
| 10 |
| — |
| 440 |
| 195 |
| 45 |
| — |
| — |
|
| Total Known and Committed Projects | 225 |
| 85 |
| 80 |
| 55 |
| 30 |
| |
| Total (D) | $ | 585 |
| $ | 380 |
| $ | 375 |
| $ | 350 |
| $ | 325 |
| |
| 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%30 percent of revenue requirement allocated to SPP members other than OG&E.
|
| |
| (B) | Typically 300kV and above projects. Approximately 85%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 |
| | Balance Portfolio 3E | 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the Oklahoma /Texas Stateline to a companion transmission line to its Tuco substation | $110 | Mid-2014 |
| Priority Project | 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the western Beaver County line to a companion transmission line to its Hitchland substation | $165 | Mid-2014 |
| Priority Project | 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border | $140 | Late 2014 |
| Integrated Transmission Project | 4730 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substationsubstation. $5.0 million of the estimated cost has been spent prior to 2017. | $45 | Early 2018Late 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;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. | $180185 | Early 2021Mid 2018 |
| |
| (D) | TheRepresent capital expenditures above exclude any environmental expenditurescosts associated with: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.
|
Pollution control equipment related to controlling SO2 emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment.The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than$1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On January 2, 2014, the Tenth Circuit confirmed that the stay of the FIP has remained in place and continues until the Tenth Circuit issues the mandate. A Petition for Certiorari was filed by the State of Oklahoma, the Industrial
Consumers and OG&E with the United States Supreme Court on January 29, 2014. The mandate from the Tenth Circuit has been stayed until the Supreme Court acts on the petition. If the Supreme Court elects not to hear the case, OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP.
Installation of control equipment (other than activated carbon injection) for compliance with MATS by a deadline of April 16, 2016, which includes a one-year extension which was granted by the Oklahoma Department of Environmental Quality. As noted above, OG&E is currently planning to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above. OG&E continues to review whether additional controls such as dry sorbent injection are needed for compliance with MATS. Current capital costs for installing the necessary control equipment for dry sorbent injection are estimated to be approximately$45 millionover a three year period, but due to the uncertainty as to whether or not dry sorbent injection is necessary, such costs are not included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above.
OG&E is currently evaluating options to comply with environmental requirements. For further information, see "Environmental Laws and Regulations" 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 achieving OG&E's financial objectives.
Contractual Obligations
The following table summarizes OG&E's contractual obligations at December 31, 20132016. See OG&E's Statements of Capitalization and Note 12 of Notes toFinancial Statements for additional information.
| | | (In millions) | 2014 | 2015-2016 | 2017-2018 | After 2018 | Total | 2017 | 2018-2019 | 2020-2021 | After 2021 | Total |
| Maturities of long-term debt (A) | $ | 0.2 |
| $ | 110.4 |
| $ | 375.2 |
| $ | 1,819.9 |
| $ | 2,305.7 |
| $ | 125.2 |
| $ | 500.2 |
| $ | 0.2 |
| $ | 1,929.7 |
| $ | 2,555.3 |
|
| Operating lease obligations | | | | |
| Railcars | 3.8 |
| 30.4 |
| — |
| — |
| 34.2 |
| 2.7 |
| 22.7 |
| — |
| — |
| 25.4 |
|
| Wind farm land leases | 2.1 |
| 4.2 |
| 4.8 |
| 48.8 |
| 59.9 |
| 2.5 |
| 5.0 |
| 5.8 |
| 43.5 |
| 56.8 |
|
| Total operating lease obligations | 5.9 |
| 34.6 |
| 4.8 |
| 48.8 |
| 94.1 |
| 5.2 |
| 27.7 |
| 5.8 |
| 43.5 |
| 82.2 |
|
| Other purchase obligations and commitments | | |
| Cogeneration capacity and fixed operation and maintenance payments | 85.1 |
| 164.6 |
| 156.6 |
| 235.2 |
| 641.5 |
| 77.1 |
| 140.4 |
| 105.7 |
| 48.8 |
| 372.0 |
|
| Expected cogeneration energy payments | 61.1 |
| 136.6 |
| 168.9 |
| 352.5 |
| 719.1 |
| 37.7 |
| 76.4 |
| 85.1 |
| 49.9 |
| 249.1 |
|
| Minimum fuel purchase commitments | 451.8 |
| 820.3 |
| 385.1 |
| — |
| 1,657.2 |
| 236.2 |
| 85.5 |
| 49.2 |
| 407.2 |
| 778.1 |
|
| Expected wind purchase commitments | 58.0 |
| 118.7 |
| 120.3 |
| 368.9 |
| 665.9 |
| 59.0 |
| 114.5 |
| 114.6 |
| 583.5 |
| 871.6 |
|
| Long-term service agreement commitments | 70.5 |
| 5.3 |
| 21.7 |
| 187.9 |
| 285.4 |
| 2.2 |
| 50.6 |
| 4.8 |
| 120.6 |
| 178.2 |
|
| Mustang Modernization expenditures | | 130.4 |
| 21.9 |
| — |
| — |
| 152.3 |
|
| Environmental compliance plan expenditures | | 169.2 |
| 71.9 |
| 0.2 |
| — |
| 241.3 |
|
| Total other purchase obligations and commitments | 726.5 |
| 1,245.5 |
| 852.6 |
| 1,144.5 |
| 3,969.1 |
| 711.8 |
| 561.2 |
| 359.6 |
| 1,210.0 |
| 2,842.6 |
|
| Total contractual obligations | 732.6 |
| 1,390.5 |
| 1,232.6 |
| 3,013.2 |
| 6,368.9 |
| 842.2 |
| 1,089.1 |
| 365.6 |
| 3,183.2 |
| 5,480.1 |
|
| Amounts recoverable through fuel adjustment clause (B) | (574.7 | ) | (1,106.0 | ) | (674.3 | ) | (721.4 | ) | (3,076.4 | ) | (335.6 | ) | (299.1 | ) | (248.9 | ) | (1,040.6 | ) | (1,924.2 | ) |
| Total contractual obligations, net | $ | 157.9 |
| $ | 284.5 |
| $ | 558.3 |
| $ | 2,291.8 |
| $ | 3,292.5 |
| $ | 506.6 |
| $ | 790.0 |
| $ | 116.7 |
| $ | 2,142.6 |
| $ | 3,555.9 |
|
| |
| (A) | Maturities of OG&E's long-term debt during the next five years consist of $0.2$125.2 million, $0.2$250.1 million,, $110.2 $250.1 million,, $125.1 $0.1 million and $250.1$0.1 million in years 20142017, 20152018, 20162019, 20172020 and2018, 2021, respectively. |
| |
| (B) | Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's expected cogeneration energy payments, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments. |
OG&E also has 440 MWs of QF contracts to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.
The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments
of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC the APSC and the FERC.APSC.
Pension and Postretirement Benefit Plans
At December 31, 20132016, 39.8 percent 40.6 percentof the Pension Plan investments were in listed common stocks with the balance primarily invested in U.S Governmentcorporate fixed income, other securities bonds, debentures and U.S. treasury notes a commingled fund and a common collective trustbonds as presented in Note 1111. of Notes toDuring Financial Statements.In20132016, assetactual returns on the Pension Plan were $48.0 million12.5 percentdue to, slightly higher than the gains in fixed income and equity investmentsexpected return on plan assets of. $41.5 million. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, increasedremained unchanged. During both2013and2012, OGE Energy made contributions to its Pension Plan of$35 millionof whichnonein 2013 and$33 millionin 2012 was OG&E's portion,to help ensure that the Pension Plan maintains an adequate funded status.The level of funding is dependent on returns on plan assets and future discount rates.During2014, 2016, OGE Energy expects to contribute up to$26made a $20.0 million contribution to its Pension Plan,, of which$1 millionis expected none related to be OG&E's portion.&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. 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 ofOG&E's portion of OGE Energy'sPension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 20132016and20122015. These amounts have been recorded in Accrued
Benefit Obligations with the offsetrecorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1of Notes toFinancial Statements. 1. Theregulatory assetrepresents represents a net periodic benefit cost to be recognized in theStatements 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) | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
| Benefit obligations | $ | (503.6 | ) | $ | (574.6 | ) | $ | (2.1 | ) | $ | (2.2 | ) | $ | (202.4 | ) | $ | (236.4 | ) | $ | 500.5 |
| $ | 514.4 |
| $ | 4.0 |
| $ | 2.7 |
| $ | 166.4 |
| $ | 176.1 |
|
| Fair value of plan assets | 516.5 |
| 519.0 |
| — |
| — |
| 56.7 |
| 55.5 |
| 457.3 |
| 464.2 |
| — |
| — |
| 47.8 |
| 50.0 |
|
| Funded status at end of year | $ | 12.9 |
| $ | (55.6 | ) | $ | (2.1 | ) | $ | (2.2 | ) | $ | (145.7 | ) | $ | (180.9 | ) | $ | (43.2 | ) | $ | (50.2 | ) | $ | (4.0 | ) | $ | (2.7 | ) | $ | (118.6 | ) | $ | (126.1 | ) |
In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2013,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 jurisdiction 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 to be paid to such employees upon retirement. As a result, and based in part on OG&E's historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, OG&E recorded pension settlement charges of $17.6$10.0 million in the third quarter of 2015 and $4.2 million in the fourth quarter of 2013,2015, of which $17.0$12.5 million related to OG&E’s&E's Oklahoma jurisdiction and has been included in the pension tracker. The pension settlement charge did not require a cash outlay by OG&E andcharges 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.
Security Ratings
|
| | | |
| | Moody’s Investors Services | Standard & Poor's Ratings Services | Fitch Ratings |
| Senior Notes | A1 | 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.
On May 2, 2013, Standard & Poor's Ratings Services upgraded the long-term senior unsecured rating of OG&E to A-.
On November 8, 2013, Moody's Investors Services placed the credit ratings of OG&E on review for possible upgrade. On January 31, 2014, Moody's upgraded the long-term senior unsecured rating of OG&E to A1 primarily due to their more favorable view of the relative credit supportiveness of the U.S. regulatory environment.
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.
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.
20132016 Capital Requirements, Sources of Financing and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $797.7770.3 million and contractual obligations, net of recoveries through fuel adjustment clauses, were $89.281.8 million resulting in total net capital requirements and contractual obligations of $886.9852.1 million in 20132016, of which $42.0137.9 million was to comply with environmental regulations. This compares to net capital requirements of $677.0551.8 million and net contractual obligations of $91.384.8 million totaling $768.3636.6 million in 20122015, of which $12.4130.6 million was to comply with environmental regulations.
In 20132016, OG&E's sources of capital were cash generated from operations and proceeds from the issuance of short-term debt. Changes in working capital reflect the seasonal nature of OG&E's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.
Issuance of Long-Term Debt
On May 8, 2013, OG&E issued $250 million of 3.9% senior notes due May 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, to fund capital expenditures, to pay general corporate expenses and for working capital purposes.
Potential Collateral Requirements Dodd-Frank Act
Derivative instruments are utilizedhave been used at times in managing OG&E's commodity price exposures. On July 21, 2010, President Obama signed into law the Dodd-Frank Act. Among other things, the Dodd-Frank Act provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps and margin requirements.exposure. The Dodd-Frank Act, contains provisions that should exemptamong other things, provides for regulation by the Commodity Futures Trading Commission of certain derivatives end-users such ascommodity-related contracts. Although OG&E from much of the clearing requirements. The regulations require that the decision on whether to use thequalifies for an end-user exception from mandatory clearing for derivative transactions be reviewedof commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and approved by an "appropriate committee" of the Board of Directors. The scope of the margin requirements and their potential direct impact on OG&E remain unclear because final rules have not been issued. Further, even if OG&E qualifies for the end-user exception to clearing and margin requirements are not imposed on end-users,could add additional regulatory oversight over its derivative counterparties may be subject to new capital, margin and business conduct requirements as a result of the new regulations, which may increase OG&E's transaction costs or make it more difficult to enter into derivative transactions on favorable terms. OG&E's inability to enter into derivative transactions on favorable terms, or at all, could increase operating expenses and put OG&E at increased exposure to risks of adverse changes in commodities prices. The impact of the provisions of the Dodd-Frank Act on OG&E cannot be fully determined at this time due to uncertainty over forthcoming regulations and potential changes to the derivatives markets arising from new regulatory requirements. 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 (fromproceeds(proceeds from the sales ofitscommon 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
AtDecember 31, 20132016, there were $87.2 $49.9 million in net outstanding advances from OGE Energy as compared to $90.3 $333.6 million in net outstanding advances fromto OGE Energy at December 31, 2012. 2015. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to$400400.0 millionof OGE Energy's revolving credit amount.This agreement has a termination date ofDecember 13, 20172018. AtDecember 31, 2013, there werenointercompany borrowings under this agreement.OG&E has a$400400.0 millionrevolving 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 AtDecember 31, 20132016, there was$2.1 $1.8 millionsupporting letters of credit at a weighted-average interest rate of0.530.95 percent. There werenooutstanding borrowings under this revolving credit agreement andnooutstanding commercial paper borrowings atDecember 31, 20132016. At AtDecember 31, 20132016, OG&E had$397.9 $398.2 millionof net available liquidity under its revolving credit agreement.OG&E has the necessary regulatory approvals to incur up to $800800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 20132017 and ending December 31, 2014.AtDecember 31, 20132018., OG&E had less than$0.1 millionin cash and cash equivalents.See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. This credit facility contains an option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreements to December 13, 2017.
Expected Issuance of Long-Term Debt
OG&E expects to issue up to$250$300.0 millionof long-term debt during 2014,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, impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations, assets and depreciable lives of property, plant and equipment, the existencedetermination of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with OGE Energy's Audit Committee. 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 of Notes toFinancial Statements.1.
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. Also, effectiveEffective 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 planPension Plan rate assumptions are shown in Note 1111. of Notes toFinancial Statements.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 is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan. The following table indicates the sensitivity of the Pension Plan funded status to these variables.
|
| | |
| | Change | Impact on Funded Status |
| Actual plan asset returns | +/- 1 percent | +/- $6.5$6.0 million |
| Discount rate | +/- 0.25 percent | +/- $18.3$14.8 million |
| Contributions | +/- $10 million | +/- $10$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 its financial 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.
Commitments and Contingencies
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 appropriate 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.
Except as disclosed otherwise in this Form 10-K,OG&Ebelieves 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 onOG&E'sfinancial position, results of operations or cash flows.See Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of OG&E's commitments and contingencies.
Asset Retirement Obligations
OG&E has previously recorded asset retirement obligations that are being amortizedaccreted over their respective lives ranging from 20three to 74 years. The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.
Hedging Policies
From time to time, OG&Emay engage in cash flow and fair value hedge transactionsto modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings.
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 actual or anticipatedincurred 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 actual or anticipatedincurred costs and obligations as regulatory assets or liabilities if, it is probable, based on regulatory orders or other available evidence, it is probable that the costcosts or obligationobligations 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 and net transition obligation.
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 the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. At December 31, 20132016, 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 $0.30.4 million. At December 31, 20132016 and 20122015, Accrued Unbilled Revenues were $58.759.7 million and $57.453.5 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
Customerbalances 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 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, 20132016, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.20.1 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on theBalance Sheets and is included in the Other Operation and Maintenance Expense on theStatements of Income.The allowance for uncollectible accounts receivable was$1.91.5 million and $2.61.4 million at December 31, 20132016 and 20122015, respectively.
Accounting Pronouncements
See Note 2 of Notes toFinancial Statements for discussion of a current accounting pronouncements that isare 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 appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, except as disclosed otherwise in this Form 10-K, 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 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K 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, state and local laws and regulations governing environmental protection relating to air quality, water quality, waste management, wildlife conservation and natural resources.protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways such as restrictingincluding the way it can handlehandling or disposedisposal of its wastes, requiring remedial actionwaste material, future construction activities to avoid or mitigate environmental issues that may be caused by its operationsharm to threatened or that are attributable to former operators, requiring changes in operationsendangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.
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 its financial position or results of operations. OG&E believes, however, that it is reasonably 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 expects that environmental capital expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a regulatory plan to handle state and Federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E's retail customers under House Bill 1910, which was enacted into law in May 2005.
It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 20142017 will be $72.6241.3 million, of which $55.0221.9 million is for capital expenditures. It is estimated that OG&E's total expenditures
to comply with environmental laws, regulations and requirements for 20152018 will be approximately $49.6180.8 million, of which $31.3161.6 million is for capital expenditures. The amounts above include capital expenditures for low NOXNOX burners, Dry Scrubbers and activated carbon injection and exclude certain other capital expenditures as discussed in footnote D to the capital expenditures table ingas conversions."Future Capital Requirements and Financing Activities" above.
Air
Federal Clean Air Act Overview
OG&E’s operations are subject to the Federal Clean Air Act as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.
Regional Haze Control Measures
On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous sources over a wide geographic area.
As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977. On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA's review and approval.
The Oklahoma SIP included requirements for reducing emissions of NOX and SO2 from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact onEPA's 2005 Regional Haze Rule is intended to protect visibility in nearbycertain national parks and wilderness areas. The SIP concludedareas throughout the United States that BART for reducing NOX emissions at all of the subject
units shouldmay be the installation of low NOX burners with overfireimpacted by air (flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits. OG&E preliminarily estimates that the total capital cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be approximately$80 million. With respect to SO2 emissions, the SIP included an agreement between the Oklahoma Department of Environmental Quality and OG&E that established BART for SO2 control at the four affected coal-fired units located at OG&E's Sooner and Muskogee generating stations as the continued use of low sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of Dry Scrubbers as BART for SO2 control from these units because the state determined that Dry Scrubbers were not cost effective on these units.
pollutant emissions. On December 28, 2011, the EPA issued a final rule inRegional Haze Rule for Oklahoma which it rejected portionsadopted a FIP for SO2 emissions at Sooner Units 1 and 2 and Muskogee Units 4 and 5. The FIP compliance date is now January 4, 2019 as a result of the Oklahoma SIPappeal filed by OG&E and issued aothers.
OG&E's current strategy for satisfying the FIP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. As described in their place. WhileNote 13, the EPA accepted Oklahoma's BART determination for NOX in the final rule, it rejected Oklahoma's SO2 BART determination with respectOCC has approved OG&E's decision to the four coal-fired unitsinstall Dry Scrubbers at the Sooner and Muskogee generating stations. The EPA is instead requiring thatunits. As of December 31, 2016, OG&E meet an SO2 emission ratehas incurred $208.7 million of 0.06pounds per MMBtu within five years. OG&E could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four affected units. OG&E estimates that installing Dry Scrubbers on these units would include capital costs to OG&E of more than$1.0 billion. OG&E and the state of Oklahoma filed an administrative stay request with the EPA on February 24, 2012. The EPA has not yet responded to this request. OG&E and other parties also filed a petition for review of the FIPconstruction work in the U.S. Court of Appeals for the Tenth Circuit on February 24, 2012 and a stay request on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the Tenth Circuit granted the stay request. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On January 2, 2014, the Tenth Circuit confirmed that the stay of the FIP has remained in place and continues until the Tenth Circuit issues the mandate. A Petition for Certiorari was filed by the State of Oklahoma, the Industrial Consumers and OG&E with the United States Supreme Court on January 29, 2014. The mandate from the Tenth Circuit has been stayed until the Supreme Court actsprogress on the petition. If the Supreme Court elects not to hear the case, OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP.
Dry Scrubbers.
Cross-State Air Pollution Rule
As previously reported, on July 7,In August 2011, the EPA finalized its Cross-State Air Pollution Rule to replaceCSAPR that required severalstates in the former Clean Air Interstate Rule that was remanded by a Federal court as a resulteastern half of legal challenges. The final rule would require 27 statesthe United States 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 effect until 2014. Several parties to that litigation, including OG&E, have petitions for review that remain pending although the rule is now effective. Compliance with the CSAPR began in 2015 using the amount of allowances originally scheduled to be available in 2012. As of December 31, 2016, OG&E has installed six low NOX burner systems on two Muskogee units, two Sooner units and two 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 take effect on May 1, 2017. The rule reduces the 2016 CSAPR emissions cap for all seven of OG&E’s coal and gas facilities by 47 percent combined. On December 27, 2011,23, 2016, OG&E filed a petition for reconsideration of the EPA published2016 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 supplementalpetition for review of the 2016 rule which would make six additional states, including Oklahoma, subject toin the Cross-State Air Pollution Rule for NOX emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. The Cross-State Air Pollution Rule was challenged in court by numerous states and power generators. On December 30, 2011, the U.S.Unites States Court of Appeals issued a stayfor the District of Columbia Circuit, asking the court to set aside the rule on the grounds that it is arbitrary, capricious, an abuse of the rule,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 includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the U.S. Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA to promulgate a replacement rule. On June 24, 2013, the U.S. Supreme Court agreed to review the decision by the U.S. Court of Appeals, with a decision expected during the first half of 2014. OG&E cannot predict the outcome of such challenges.
are currently pending.
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 AprilFebruary 16, 2012, regulations governingthe EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units, were published as the final MATS rule. This rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. In addition, the regulations include work practice standards for dioxins and furans. Compliancewhich became effective April 16, 2012. OG&E believes that it complied with the MATS rule is required within three years after the effective date of the rulewith the possibility of a one-year extension. OG&E requested and was granted a one-year extension by the Oklahoma Department of Environmental Quality resulting in a compliance date of April 16, 2016 fordeadline that applied to OG&E.To comply with this rule,OG&E Nonetheless, there is currently planningcontinuing litigation, to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above. OG&E continues to review whether additional controls such as dry sorbent injection are needed for compliance with MATS. Current capital costs for installing the necessary control equipment for dry sorbent injection are estimated to be approximately$45 millionover a three year period, but due to the uncertainty as to whether or not dry sorbent injection is necessary, such costs are not included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above.OG&E is evaluating the results of field testing to finalize its plans and cost estimates. The final MATS rule has been appealed by several parties. OG&E is not a party, to the appeals and cannot predict the outcome of any such appeals.
Federal Clean Air Act New Source Review Litigation
As previously reported, in July 2008, OG&E received a request for information fromchallenging whether the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants. In recent years,had statutory authority to issue the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act's new source review process. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that OG&E's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards.
In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club has intervened in this proceeding and has asserted claims for declaratory relief that are similar to those requested by the United States. OG&E expects to vigorously defend against these claims, but OG&E cannot predict the outcome of such litigation. On August 12, 2013, the Sierra Club filed a complaint against OG&E in the United States District Court for the Eastern District of Oklahoma (Case No. 13-CV-00356) alleging that OG&E modifications made at Unit 6 of the Muskogee generating plant in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant has exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act.
If OG&E does not prevail in these proceedings and if a new assessment of the projects were to conclude that they caused a significant emissions increase, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including scrubbers, baghouses and selective catalytic reduction systems with capital costs in excess of $1.0 billion and pay fines and significant penalties as a result of the allegations in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs.
MATS rule.
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 2013,2016, 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.
Acid Rain Program
The Federal Clean Air Act includes an Acid Rain Program. The goalEPA proposed to designate part of the Acid Rain Program is to achieve environmental and public health benefits through reductionsMuskogee County in SO2 and NOX emissions, which are the primary causes of acid rain. To achieve this goal, the program employs both traditional and market-based approaches for reducing emissions.
The Acid Rain Program introduces an allowance trading system that uses the free market to reduce emissions. Under this system, affected utility units are allocated allowances based on their historic fuel consumption and a specific emissions rate. Each allowance permits a unit to emit one ton of SO2 during or after a specified year. For each ton of SO2 emitted in a given year, one allowance is retired, that is, it can no longer be used. Allowances may be bought, sold or banked.
During Phase II of the program (now in effect), the Federal Clean Air Act set a permanent ceiling (or cap) of8.95 milliontotal annual allowances allocated to utilities. This cap firmly restricts emissions and ensures that environmental benefits will be achieved and maintained. Due to OG&E's earlier decision to burn low sulfur coal, these restrictions have had no significant financial impact.Muskogee Power Plant is located, as non-attainment for the 2010 SO
2
The Acid Rain Program also focuses NAAQS on one set of sources that emit NOX, coal-fired electric utility boilers. As with the SO2 emission reduction requirements, the NOX program was implemented in two phases, beginning in 1996 and 2000. The NOX program embodies many of the same principles of the SO2 trading program. However, it does not cap NOX emissions as the SO2 program does, nor does it utilize an allowance trading system.
Emission limitations for NOX focus on the emission rate to be achieved (expressed in pounds of NOX per MMBtu of heat input). In general, two options forMarch 1, 2016, even though nearby monitors indicate compliance with the emission limitations are provided: complianceNAAQS. 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 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 an individual emission rate forthe current deadline being February 27, 2017. 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 boiler; or averaging of emission rates over two or more unitsmaterial impact to meet an overall emission rate limitation.its
Since becoming subject to the Acid Rain Program, OG&E has met all obligations and limitations requirements.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 Fallin submitted to the EPA the recommendation of "attainment/unclassifiable" for all 77 counties in Oklahoma. This recommendation is subject to approval by the EPA.
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.
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 carbon dioxide,CO2, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the Earth'searth's atmosphere. There are variousIn December 2015, as part of the 21st Conference of the Parties to 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. The agreement could result in future additional emissions reductions in the United States, however, it is not possible to determine what the international agreements that restrictlegal standards for greenhouse gas emissions but none of them have a binding effect on sources locatedwill be in the United States. The U.S. Congress has not passed legislation to reduce emissions of greenhouse gasesfuture and the future prospects for any such legislation are uncertain, butextent to which commitments under the EPA believes it has existing authority underDecember 2015 Paris Agreement will be implemented through the Clean Air Act, to regulateother than existing statutes and new legislation.
If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of CO2 and other greenhouse gas emissions from stationary sources.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/MWh) and mass-based (tons/yr) goals. The 2030 rate-based reduction requirement for all existing generating units in
Oklahoma and Arkansasare not among them. If legislation or regulations are passed at the Federal or state levels has decreased from a proposed 43 percent reduction to 32 percent in the future requiring mandatory reductionsfinal rule. The mass-based approach for existing units calls for a 24 percent reduction by 2030 in Oklahoma.
A number of carbon dioxidestates, including Oklahoma, filed lawsuits against the Clean Power Plan. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan pending resolution of challenges to the rule. OG&E is unable to determine what impact the lawsuits will ultimately have on the Clean Power Plan or what impact the stay in implementation will have; however, if the Clean Power Plan survives judicial review and other greenhouse gases on OG&E's facilities, thisis implemented as written, it could result in significant additional compliance costs that would affect OG&E’s 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.
In 2009,Nonetheless, OG&E’s current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in "Pending Regulatory Matters," OG&E has filed an application with the EPA adopted a comprehensive national systemOCC for reporting emissionsapproval of carbon dioxideits plan to comply with the EPA’s MATS and other greenhouse gases producedRegional Haze Rule FIP by major sources in the United States. The reporting requirements apply to large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000metric tons per year, which includes certain OG&E facilities. OG&E also reports quarterly its carbon dioxide emissions fromconverting two coal-fired generating units subjectat Muskogee Station to the Federal Acid Rain Program. OG&E has submitted the reports required by the applicable reporting rules.
Following from the Supreme Court's interpretation of the Clean Air Act's applicability to greenhouse gases in Massachusetts v. EPA, the EPA has proposed regulations for new power plants. In 2010, the EPA also issued a final rule that makes certain existing sources subject to permitting requirements for greenhouse gas emissions. This rule requires sources that emit greater than100,000tons per year of greenhouse gases to obtain a permit for those emissions, even if they are not otherwise required to obtain a new or modified permit. Such sources that undergo construction or modification may have to install best available control technology to control greenhouse gas emissions. Although these rules currently do not have a material impact on OG&E's existing facilities, they ultimately could result in significant changes to OG&E's operations, significant capital expenditures by OG&E and a significant increase in OG&E's cost of conducting business. In October 2013, the U.S. Supreme Court granted certiorari to review EPA's greenhouse gas regulations, including the Tailoring Rule which limits the sources subject to greenhouse gas permitting requirements to the largest fossil-fueled power plants. It is conceivable that the Court could invalidate EPA's prevention of significant deterioration and Title V Tailoring Rule, but still leave power plants subject to anticipated new and existing source performance standards for greenhouse gas emissions described below.
In January 2014, the EPA issued new proposed New Source Performance Standards that specify permissible levels of greenhouse gas emissions from newly-constructed fossil fuel-fired electric generating units. The proposed New Source Performance Standards sets separate standards for natural gas, combined cycle units and coal-fired generating units. As directed by President Obama's June 25, 2013, Climate Action Plan,among other measures. OG&E’s deployment of Smart Grid technology helps to reduce the EPA also announced plans to establish, pursuant to Section 111(d) of the Clean Air Act, carbon dioxide emissions standards for existing fossil fuel fired electric generating units. EPA plans to publish the proposed standards for existing units by June 1, 2014, and finalize those guidelines by June 1, 2015. States must then submit their individual plans for reducing power plants' greenhouse gas emissions to EPA by June 30, 2016.
peak load demand. OG&E is continuing to review and evaluate available options for reducing, avoiding, offsetting or sequestering its greenhouse gas emissions.
OG&E also seeks to utilize renewable energy sources that do not emit greenhouse gases.OG&E's service territory is in central Oklahoma and borders one of the nation's best wind resource areas. OG&E has leveraged its advantageous 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 area 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 significantly 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 SIP of 36 states, including Oklahoma, regarding the treatment of emissions that occur during startup, shutdown and malfunction operations. The final rule clarifies the EPA's Startup, Shutdown and Malfunction Policy to assure consistency with the Clean Air Act and other recent court decisions. The ODEQ 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, this rule will impact certain OG&E units.
Endangered Species
Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which 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 windpipeline 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 announced a proposed ruleand 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, 2012. A final decision regarding2016, 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 is anticipatedof 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 March 30, 2014. Although2019. More detail regarding the lesser prairie chicken and its habitat are located in potential development areasECP can be found under the "Pending Regulatory Matters" section of OG&E, the impact "Notes to Financial Statements" of a final decision to listPart II, Item 8 of this species as threatened cannot be determined at this time.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.
For OG&E, these laws impose strict requirements on waste generators regarding their treatment, storage and disposal of waste. OG&E routinely generates small quantities of hazardous waste throughout its system. These wastes are treated, stored and disposed at facilities that are permitted to manage them.
In June 2010,On December 19, 2014, the EPA proposed new rulesfinalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of 1976 that could makecoal 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 extent to whichfinal rule is currently being appealed at the EPA intends to regulate coal ashD.C. Circuit Court of Appeals. OG&E is uncertain. The EPA continues to consider numerous comments received on the proposal. On January 29, 2014, the EPA entered into a consent decree directing them, by December 19, 2014, to sign for publication in the Federal Register a notice taking final action on the EPA's proposed Subtitle D option for coal ash which set performance standards for waste management, to be administered by the states.
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 20132016, OG&E obtained refunds of $3.51.9 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 analogouscomparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. The Federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Existing cooling water intake structures are regulated under the Federal Clean Water Act to minimize their impact on the environment.
With respectThe EPA issued a final rule on May 19, 2014 to cooling water intake structures,implement Section 316(b) of the Federal Clean Water Act, which requires that theirpower 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. In March 2011,OG&E submitted compliance plans to the state in April 2015. 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.
On September 30, 2015, the EPA proposed rules to implement Section 316(b). Recently, the EPA announced that it will issueissued a final rule by April 17, 2014. Inaddressing the interim,effluent limitation guidelines for power plants under the stateFederal Clean Water Act. The final rule establishes technology and performance based standards that may apply to discharges of Oklahoma requiressix waste streams including bottom ash transport water. Compliance with this rule occurs between 2018 and 2023. OG&E is evaluating what if any compliance actions are needed but is not able to implement best management practices related to the operation and maintenance of its existing cooling water intake structures as
a condition of renewing its discharge permits. Once the EPA promulgates the final rules,quantify with any certainty, what costs may be incurred. OG&E may incur additional capital and/or operatingexpects to be able to provide a reasonable estimate of any material costs to comply with them. The costs of complyingassociated with the final water intake standards are not currently determinable, but could be significant.
rule's implementation following issuance of the permits from the state.
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&Eutilizes various products and generate wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&Ecould 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.&E.
For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12 12.of Notes toFinancial Statements.
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'sexposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper.OG&Emanages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates.OG&Emay utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives arewould be used solelyto modify interest rate exposure and not to modify the overall leverage of the debt portfolio.portfolio, but OG&E has no intent at this time to utilize interest rate derivatives
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 maturitiesor by calculating the net present value of the monthly payments discounted by OG&E's .currentcurrent 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) | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | 12/31/13 Fair Value | 2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total | 12/31/16 Fair Value |
| Fixed-rate debt (A) | | |
| Principal amount | $ | 0.2 |
| $ | 0.2 |
| $ | 110.2 |
| $ | 125.1 |
| $ | 250.1 |
| $ | 1,684.5 |
| $ | 2,170.3 |
| $ | 2,414.1 |
| $ | 125.2 |
| $ | 250.1 |
| $ | 250.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 1,794.3 |
| $ | 2,419.9 |
| $ | 2,668.5 |
|
| Weighted-average interest rate | 2.95 | % | 2.95 | % | 5.15 | % | 6.50 | % | 6.35 | % | 6.03 | % | 6.05 | % | | 6.50 | % | 6.35 | % | 8.25 | % | 3.01 | % | 3.01 | % | 5.19 | % | 5.70 | % | |
| Variable-rate debt (B) | | |
| Principal amount | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 135.4 |
| $ | 135.4 |
| $ | 135.4 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 135.4 |
| $ | 135.4 |
| $ | 135.4 |
|
| Weighted-average interest rate | — |
| — |
| — |
| — |
| — |
| 0.13 | % | 0.13 | % | | — | % | — | % | — | % | — | % | — | % | 0.76 | % | 0.76 | % | |
| |
| (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 $1.4 millionannually. |
Item 8. Financial Statements and Supplementary Data.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
| | Year ended December 31 (In millions) | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| OPERATING REVENUES | $ | 2,262.2 |
| $ | 2,141.2 |
| $ | 2,211.5 |
| $ | 2,259.2 |
| $ | 2,196.9 |
| $ | 2,453.1 |
|
| COST OF SALES | 965.9 |
| 879.1 |
| 1,013.5 |
| 880.1 |
| 865.0 |
| 1,106.6 |
|
| OPERATING EXPENSES | | | | | |
|
| Other operation and maintenance | 438.8 |
| 446.3 |
| 436.0 |
| 469.8 |
| 444.5 |
| 453.2 |
|
| Depreciation and amortization | 248.4 |
| 248.7 |
| 216.1 |
| 316.4 |
| 299.9 |
| 270.8 |
|
| Taxes other than income | 83.8 |
| 77.7 |
| 73.6 |
| 84.0 |
| 87.1 |
| 84.5 |
|
| Total operating expenses | 771.0 |
| 772.7 |
| 725.7 |
| 870.2 |
| 831.5 |
| 808.5 |
|
| OPERATING INCOME | 525.3 |
| 489.4 |
| 472.3 |
| 508.9 |
| 500.4 |
| 538.0 |
|
| OTHER INCOME (EXPENSE) | | | | | |
|
| Allowance for equity funds used during construction | 6.6 |
| 6.2 |
| 20.4 |
| 14.2 |
| 8.3 |
| 4.2 |
|
| Other income | 8.1 |
| 8.2 |
| 8.5 |
| 16.4 |
| 13.3 |
| 4.8 |
|
| Other expense | (4.6 | ) | (4.3 | ) | (8.4 | ) | (2.9 | ) | (1.6 | ) | (1.9 | ) |
| Net other income (expense) | 10.1 |
| 10.1 |
| 20.5 |
| |
| Net other income | | 27.7 |
| 20.0 |
| 7.1 |
|
| INTEREST EXPENSE | | | | | |
|
| Interest on long-term debt | 130.6 |
| 124.2 |
| 118.7 |
| 141.7 |
| 146.8 |
| 139.7 |
|
| Allowance for borrowed funds used during construction | (3.4 | ) | (3.5 | ) | (10.4 | ) | (7.5 | ) | (4.2 | ) | (2.4 | ) |
| Interest on short-term debt and other interest charges | 2.1 |
| 3.9 |
| 3.3 |
| 3.9 |
| 4.1 |
| 4.2 |
|
| Interest expense | 129.3 |
| 124.6 |
| 111.6 |
| 138.1 |
| 146.7 |
| 141.5 |
|
| INCOME BEFORE TAXES | 406.1 |
| 374.9 |
| 381.2 |
| 398.5 |
| 373.7 |
| 403.6 |
|
| INCOME TAX EXPENSE | 113.5 |
| 94.6 |
| 117.9 |
| 114.4 |
| 104.8 |
| 111.6 |
|
| NET INCOME | $ | 292.6 |
| $ | 280.3 |
| $ | 263.3 |
| $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
| Other comprehensive income (loss), net of tax | | — |
| — |
| — |
|
| COMPREHENSIVE INCOME | | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
CASH FLOWS
|
| | | | | | | | | |
Year ended December 31 (In millions) | 2013 | 2012 | 2011 |
| Net income | $ | 292.6 |
| $ | 280.3 |
| $ | 263.3 |
|
| Other comprehensive income (loss), net of tax | | | |
| Deferred commodity contracts hedging (gains) losses reclassified in net income, net of tax of $0.8, $0.7 and ($0.1), respectively | 1.3 |
| 1.2 |
| (0.4 | ) |
| Comprehensive income (loss) | $ | 293.9 |
| $ | 281.5 |
| $ | 262.9 |
|
|
| | | | | | | | | |
Year ended December 31 (In millions) | 2016 | 2015 | 2014 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | |
|
| Net income | $ | 284.1 |
| $ | 268.9 |
| $ | 292.0 |
|
| Adjustments to reconcile net income to net cash provided from operating activities | | |
|
| Depreciation and amortization | 316.4 |
| 299.9 |
| 270.8 |
|
| Deferred income taxes and investment tax credits | 116.8 |
| 127.6 |
| 161.4 |
|
| Allowance for equity funds used during construction | (14.2 | ) | (8.3 | ) | (4.2 | ) |
| Stock-based compensation expense | 2.3 |
| 2.6 |
| 2.9 |
|
| Regulatory assets | (21.4 | ) | (9.1 | ) | 4.6 |
|
| Regulatory liabilities | (11.8 | ) | (27.5 | ) | (4.4 | ) |
| Other assets | 13.7 |
| 10.1 |
| (1.2 | ) |
| Other liabilities | (20.1 | ) | 22.2 |
| 14.0 |
|
| 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 |
|
| Fuel, materials and supplies inventories | 32.5 |
| (56.2 | ) | 20.1 |
|
| Fuel clause under recoveries | (51.3 | ) | 68.3 |
| (42.1 | ) |
| Other current assets | (26.7 | ) | (16.0 | ) | (2.6 | ) |
| Accounts payable | (27.7 | ) | 20.4 |
| (66.4 | ) |
| Accounts payable - affiliates | (2.1 | ) | 1.9 |
| (1.5 | ) |
| Income taxes payable - parent | (3.1 | ) | (16.7 | ) | (50.2 | ) |
| Fuel clause over recoveries | (61.3 | ) | 61.3 |
| (0.4 | ) |
| Other current liabilities | 52.9 |
| 3.4 |
| 1.1 |
|
| Net Cash Provided from Operating Activities | 572.9 |
| 770.5 |
| 587.7 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | |
|
| Capital expenditures (less allowance for equity funds used during construction) | (660.1 | ) | (551.6 | ) | (565.4 | ) |
| Proceeds from sale of assets | 0.9 |
| 2.6 |
| 0.7 |
|
| Net Cash Used in Investing Activities | (659.2 | ) | (549.0 | ) | (564.7 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | |
|
| Proceeds from long-term debt | — |
| — |
| 489.6 |
|
| Dividends paid on common stock | (155.0 | ) | (120.0 | ) | (140.0 | ) |
| Changes in advances with parent | 351.5 |
| (101.3 | ) | (232.4 | ) |
| 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 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 toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
|
| | | | | | |
December 31 (In millions) | 2016 | 2015 |
| ASSETS | | |
| CURRENT ASSETS | | |
| Accounts receivable, less reserve of $1.5 and $1.4, respectively | $ | 173.0 |
| $ | 173.1 |
|
| Accrued unbilled revenues | 59.7 |
| 53.5 |
|
| Advances to parent | — |
| 333.6 |
|
| Fuel inventories | 79.8 |
| 113.8 |
|
| Materials and supplies, at average cost | 80.3 |
| 78.8 |
|
| Fuel clause under recoveries | 51.3 |
| — |
|
| Other | 78.3 |
| 51.6 |
|
| Total current assets | 522.4 |
| 804.4 |
|
| OTHER PROPERTY AND INVESTMENTS | 6.6 |
| 5.6 |
|
| PROPERTY, PLANT AND EQUIPMENT | | |
| In service | 10,572.3 |
| 10,179.3 |
|
| Construction work in progress | 495.1 |
| 278.5 |
|
| Total property, plant and equipment | 11,067.4 |
| 10,457.8 |
|
| Less accumulated depreciation | 3,385.6 |
| 3,161.7 |
|
| Net property, plant and equipment | 7,681.8 |
| 7,296.1 |
|
| DEFERRED CHARGES AND OTHER ASSETS | | |
| Regulatory assets | 404.8 |
| 402.2 |
|
| Other | 53.8 |
| 17.2 |
|
| Total deferred charges and other assets | 458.6 |
| 419.4 |
|
| TOTAL ASSETS | $ | 8,669.4 |
| $ | 8,525.5 |
|
The accompanying Notes toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
|
| | | | | | |
December 31 (In millions) | 2016 | 2015 |
| 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 |
| — |
|
| Customer deposits | 77.7 |
| 77.0 |
|
| Accrued taxes | 40.8 |
| 45.7 |
|
| Accrued interest | 40.2 |
| 42.8 |
|
| Accrued compensation | 31.3 |
| 23.8 |
|
| Long-term debt due within one year | 125.0 |
| 110.0 |
|
| Fuel clause over recoveries | — |
| 61.3 |
|
| Other | 95.8 |
| 43.6 |
|
| Total current liabilities | 657.1 |
| 642.4 |
|
| LONG-TERM DEBT | 2,405.8 |
| 2,529.3 |
|
| DEFERRED CREDITS AND OTHER LIABILITIES | | |
| Accrued benefit obligations | 167.7 |
| 179.9 |
|
| Deferred income taxes | 1,752.3 |
| 1,637.8 |
|
| Regulatory liabilities | 299.7 |
| 273.6 |
|
| Other | 134.7 |
| 106.8 |
|
| Total deferred credits and other liabilities | 2,354.4 |
| 2,198.1 |
|
| Total liabilities | 5,417.3 |
| 5,369.8 |
|
| COMMITMENTS AND CONTINGENCIES (NOTE 12) |
|
|
|
|
| STOCKHOLDER'S EQUITY | | |
| Common stockholder's equity | 1,024.1 |
| 1,021.8 |
|
| Retained earnings | 2,228.0 |
| 2,133.9 |
|
| Total stockholder's equity | 3,252.1 |
| 3,155.7 |
|
| TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | $ | 8,669.4 |
| $ | 8,525.5 |
|
The accompanying Notes toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
|
| | | | | | | |
December 31 (In millions) | 2016 | 2015 |
| STOCKHOLDER'S EQUITY | | |
| Common stock, par value $2.50 per share; authorized 100.0 shares; and outstanding 40.4 shares and 40.4 shares, respectively | $ | 100.9 |
| $ | 100.9 |
|
| Premium on common stock | 923.2 |
| 920.9 |
|
| Retained earnings | 2,228.0 |
| 2,133.9 |
|
| Total stockholder's equity | 3,252.1 |
| 3,155.7 |
|
| | | | |
| LONG-TERM DEBT | | | |
| SERIES | 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 |
|
| 8.25% | Senior Notes, Series Due January 15, 2019 | 250.0 |
| 250.0 |
|
| 6.65% | Senior Notes, Series Due July 15, 2027 | 125.0 |
| 125.0 |
|
| 6.50% | Senior Notes, Series Due April 15, 2028 | 100.0 |
| 100.0 |
|
| 5.75% | Senior Notes, Series Due January 15, 2036 | 110.0 |
| 110.0 |
|
| 6.45% | Senior Notes, Series Due February 1, 2038 | 200.0 |
| 200.0 |
|
| 5.85% | Senior Notes, Series Due June 1, 2040 | 250.0 |
| 250.0 |
|
| 5.25% | Senior Notes, Series Due May 15, 2041 | 250.0 |
| 250.0 |
|
| 3.90% | Senior Notes, Series Due May 1, 2043 | 250.0 |
| 250.0 |
|
| 4.55% | Senior Notes, Series Due March 15, 2044 | 250.0 |
| 250.0 |
|
| 4.00% | Senior Notes, Series Due December 15, 2044 | 250.0 |
| 250.0 |
|
| 3.70% | Tinker Debt, Due August 31, 2062 | 9.9 |
| 10.0 |
|
| | | | |
| 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 |
|
| | | | |
| Unamortized debt expense | (15.2 | ) | (16.3 | ) |
| Unamortized discount | (9.3 | ) | (9.8 | ) |
| Total long-term debt | 2,530.8 |
| 2,639.3 |
|
| 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 |
|
The accompanying Notes toFinancial 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 |
| 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 |
|
| Net income | — |
| — |
| 284.1 |
| 284.1 |
|
| Dividends declared on common stock | — |
| — |
| (190.0 | ) | (190.0 | ) |
| Stock-based compensation | — |
| 2.3 |
| — |
| 2.3 |
|
| Balance at December 31, 2016 | $ | 100.9 |
| $ | 923.2 |
| $ | 2,228.0 |
| $ | 3,252.1 |
|
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) | 2013 | 2012 | 2011 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | |
| Net income | $ | 292.6 |
| $ | 280.3 |
| $ | 263.3 |
|
| Adjustments to reconcile net income to net cash provided from operating activities | | | |
| Depreciation and amortization | 248.4 |
| 248.7 |
| 216.1 |
|
| Deferred income taxes and investment tax credits, net | 116.1 |
| 103.3 |
| 95.0 |
|
| Allowance for equity funds used during construction | (6.6 | ) | (6.2 | ) | (20.4 | ) |
| Stock-based compensation expense | 2.3 |
| 2.6 |
| 3.0 |
|
| Regulatory assets | 26.8 |
| 20.3 |
| 14.0 |
|
| Regulatory liabilities | (32.5 | ) | (14.8 | ) | (1.9 | ) |
| Other assets | 10.0 |
| (4.5 | ) | 2.0 |
|
| Other liabilities | (6.2 | ) | (28.7 | ) | (62.9 | ) |
| Change in certain current assets and liabilities | | | |
| Accounts receivable, net | (17.9 | ) | 20.9 |
| (40.1 | ) |
| Accrued unbilled revenues | (1.3 | ) | 1.9 |
| (2.5 | ) |
| Fuel, materials and supplies inventories | (2.3 | ) | 6.5 |
| 54.0 |
|
| Fuel clause under recoveries | (26.2 | ) | 1.8 |
| (0.8 | ) |
| Other current assets | 2.7 |
| (6.6 | ) | (7.5 | ) |
| Accounts payable | 49.4 |
| 9.7 |
| 13.4 |
|
| Accounts payable - affiliates | 1.1 |
| (0.6 | ) | (3.1 | ) |
| Income taxes payable - parent | 2.9 |
| (7.1 | ) | 23.0 |
|
| Fuel clause over recoveries | (108.8 | ) | 101.5 |
| (22.2 | ) |
| Other current liabilities | (5.4 | ) | 8.4 |
| 26.9 |
|
| Net Cash Provided from Operating Activities | 545.1 |
| 737.4 |
| 549.3 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | |
| Capital expenditures (less allowance for equity funds used during construction) | (797.6 | ) | (704.4 | ) | (844.5 | ) |
| Reimbursement of capital expenditures | — |
| 27.5 |
| 49.6 |
|
| Proceeds from sale of assets | 0.8 |
| 0.6 |
| 0.6 |
|
| Net Cash Used in Investing Activities | (796.8 | ) | (676.3 | ) | (794.3 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | |
| Proceeds from long-term debt | 247.4 |
| — |
| 246.3 |
|
| Changes in advances with parent | 124.4 |
| 14.0 |
| (51.3 | ) |
| Capital contribution from OGE Energy | — |
| — |
| 50.0 |
|
| Payment of long-term debt | (0.1 | ) | (0.1 | ) | — |
|
| Dividends paid on common stock | (120.0 | ) | (75.0 | ) | — |
|
| Net Cash Provided from (Used in) Financing Activities | 251.7 |
| (61.1 | ) | 245.0 |
|
| 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 toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
|
| | | | | | |
December 31 (In millions) | 2013 | 2012 |
| ASSETS | | |
| CURRENT ASSETS | | |
| Accounts receivable, less reserve of $1.9 and $2.6, respectively | $ | 179.4 |
| $ | 161.5 |
|
| Accrued unbilled revenues | 58.7 |
| 57.4 |
|
| Advances to parent | — |
| 90.3 |
|
| Fuel inventories | 74.4 |
| 76.8 |
|
| Materials and supplies, at average cost | 79.4 |
| 74.7 |
|
| Deferred income taxes | 189.2 |
| 138.7 |
|
| Fuel clause under recoveries | 26.2 |
| — |
|
| Other | 31.9 |
| 34.6 |
|
| Total current assets | 639.2 |
| 634.0 |
|
| OTHER PROPERTY AND INVESTMENTS | 2.6 |
| 2.7 |
|
| PROPERTY, PLANT AND EQUIPMENT | | |
| In service | 9,036.4 |
| 8,498.3 |
|
| Construction work in progress | 462.8 |
| 251.4 |
|
| Total property, plant and equipment | 9,499.2 |
| 8,749.7 |
|
| Less accumulated depreciation | 2,864.6 |
| 2,705.6 |
|
| Net property, plant and equipment | 6,634.6 |
| 6,044.1 |
|
| DEFERRED CHARGES AND OTHER ASSETS | | |
| Regulatory assets | 379.1 |
| 510.6 |
|
| Other | 39.4 |
| 31.0 |
|
| Total deferred charges and other assets | 418.5 |
| 541.6 |
|
| TOTAL ASSETS | $ | 7,694.9 |
| $ | 7,222.4 |
|
The accompanying Notes toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
|
| | | | | | |
December 31 (In millions) | 2013 | 2012 |
| LIABILITIES AND STOCKHOLDER'S EQUITY | | |
| CURRENT LIABILITIES | | |
| Accounts payable - affiliates | $ | 1.8 |
| $ | 0.7 |
|
| Accounts payable - other | 237.2 |
| 186.7 |
|
| Advances from parent | 87.2 |
| — |
|
| Customer deposits | 70.9 |
| 68.5 |
|
| Accrued taxes | 38.0 |
| 35.0 |
|
| Accrued interest | 42.8 |
| 43.2 |
|
| Accrued compensation | 30.0 |
| 33.2 |
|
| Fuel clause over recoveries | 0.4 |
| 109.2 |
|
| Other | 46.8 |
| 56.0 |
|
| Total current liabilities | 555.1 |
| 532.5 |
|
| LONG-TERM DEBT | 2,300.2 |
| 2,050.3 |
|
| DEFERRED CREDITS AND OTHER LIABILITIES | | |
| Accrued benefit obligations | 149.0 |
| 240.9 |
|
| Deferred income taxes | 1,545.2 |
| 1,377.8 |
|
| Deferred investment tax credits | 1.9 |
| 3.9 |
|
| Regulatory liabilities | 234.2 |
| 245.1 |
|
| Other | 80.0 |
| 68.8 |
|
| Total deferred credits and other liabilities | 2,010.3 |
| 1,936.5 |
|
| Total liabilities | 4,865.6 |
| 4,519.3 |
|
| COMMITMENTS AND CONTINGENCIES (NOTE 12) |
|
|
|
|
| STOCKHOLDER'S EQUITY | | |
| Common stockholder's equity | 1,016.3 |
| 1,014.0 |
|
| Retained earnings | 1,813.0 |
| 1,690.4 |
|
| Accumulated other comprehensive loss, net of tax | — |
| (1.3 | ) |
| Total stockholder's equity | 2,829.3 |
| 2,703.1 |
|
| TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | $ | 7,694.9 |
| $ | 7,222.4 |
|
The accompanying Notes toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
|
| | | | | | | |
December 31 (In millions) | 2013 | 2012 |
| STOCKHOLDER'S EQUITY | | |
| Common stock, par value $2.50 per share; authorized 100.0 shares; and outstanding 40.4 and 40.4 shares, respectively | $ | 100.9 |
| $ | 100.9 |
|
| Premium on common stock | 915.4 |
| 913.1 |
|
| Retained earnings | 1,813.0 |
| 1,690.4 |
|
| Accumulated other comprehensive loss, net of tax | — |
| (1.3 | ) |
| Total stockholder's equity | 2,829.3 |
| 2,703.1 |
|
| | | | |
| LONG-TERM DEBT | | | |
| SERIES | DUE DATE | | |
| Senior Notes | | | |
| 5.15% | Senior Notes, Series Due January 15, 2016 | 110.0 |
| 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 |
|
| 8.25% | Senior Notes, Series Due January 15, 2019 | 250.0 |
| 250.0 |
|
| 6.65% | Senior Notes, Series Due July 15, 2027 | 125.0 |
| 125.0 |
|
| 6.50% | Senior Notes, Series Due April 15, 2028 | 100.0 |
| 100.0 |
|
| 6.50% | Senior Notes, Series Due August 1, 2034 | 140.0 |
| 140.0 |
|
| 5.75% | Senior Notes, Series Due January 15, 2036 | 110.0 |
| 110.0 |
|
| 6.45% | Senior Notes, Series Due February 1, 2038 | 200.0 |
| 200.0 |
|
| 5.85% | Senior Notes, Series Due June 1, 2040 | 250.0 |
| 250.0 |
|
| 5.25% | Senior Notes, Series Due May 15, 2041 | 250.0 |
| 250.0 |
|
| 3.90% | Senior Notes, Series Due May 1, 2043 | 250.0 |
| — |
|
| 3.70% | Tinker Debt, Due August 31, 2062 | 10.3 |
| 10.7 |
|
| | | | |
| Other Bonds | | | |
| 0.18% - 0.34% | Garfield Industrial Authority, January 1, 2025 | 47.0 |
| 47.0 |
|
| 0.10% - 0.39% | Muskogee Industrial Authority, January 1, 2025 | 32.4 |
| 32.4 |
|
| 0.10% - 0.30% | Muskogee Industrial Authority, June 1, 2027 | 56.0 |
| 56.0 |
|
| | | | |
| Unamortized discount | (5.5 | ) | (5.8 | ) |
| Total long-term debt | 2,300.2 |
| 2,050.3 |
|
| Total Capitalization | $ | 5,129.5 |
| $ | 4,753.4 |
|
The accompanying Notes toFinancial 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 | Accumulated Other Comprehensive Income (Loss) | Total |
| Balance at December 31, 2010 | $ | 100.9 |
| $ | 857.5 |
| $ | 1,221.8 |
| $ | (2.1 | ) | $ | 2,178.1 |
|
| Net income | — |
| — |
| 263.3 |
| — |
| 263.3 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| (0.4 | ) | (0.4 | ) |
| Stock-based compensation | — |
| 3.0 |
| — |
| — |
| 3.0 |
|
| Capital contribution from OGE Energy | — |
| 50.0 |
| — |
| — |
| 50.0 |
|
| Balance at December 31, 2011 | $ | 100.9 |
| $ | 910.5 |
| $ | 1,485.1 |
| $ | (2.5 | ) | $ | 2,494.0 |
|
| Net income | — |
| — |
| 280.3 |
| — |
| 280.3 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| 1.2 |
| 1.2 |
|
| Dividends declared on common stock | — |
| — |
| (75.0 | ) | — |
| (75.0 | ) |
| Stock-based compensation and other | — |
| 2.6 |
| — |
| — |
| 2.6 |
|
| Balance at December 31, 2012 | $ | 100.9 |
| $ | 913.1 |
| $ | 1,690.4 |
| $ | (1.3 | ) | $ | 2,703.1 |
|
| Net income | — |
| — |
| 292.6 |
| — |
| 292.6 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| 1.3 |
| 1.3 |
|
| Dividends declared on common stock | — |
| — |
| (170.0 | ) | — |
| (170.0 | ) |
| Stock-based compensation | — |
| 2.3 |
| — |
| — |
| 2.3 |
|
| Balance at December 31, 2013 | $ | 100.9 |
| $ | 915.4 |
| $ | 1,813.0 |
| $ | — |
| $ | 2,829.3 |
|
The accompanying Notes toFinancial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
| |
| 1. | Summary of Significant Accounting Policies
|
Organization
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 the Fort Smith, Arkansas area.and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.
Basis of Presentation
In the opinion of management, all adjustments necessary to fairly present thefinancial position of OG&E atDecember 31, 2013and2012and the results of its operations and cash flows for the years endedDecember 31, 2013, 2012and2011, have been included and are of a normal recurring nature except as otherwise disclosed.
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 actual or anticipatedincurred 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 actual or anticipatedincurred costs and obligations as regulatory assets or liabilities if, it is probable, based on regulatory orders or other available evidence, it is probable that the costcosts or obligationobligations 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:
| | December 31 (In millions) | 2013 | 2012 | 2016 | 2015 |
| Regulatory Assets | | |
| Current | | |
| Fuel clause under recoveries | $ | 26.2 |
| $ | — |
| $ | 51.3 |
| $ | — |
|
| Oklahoma demand program rider under recovery (A) | 10.6 |
| 9.2 |
| 51.0 |
| 36.6 |
|
| Crossroads wind farm rider under recovery (A) | 4.7 |
| 14.9 |
| |
| SPP cost tracker under recovery (A) | | 10.0 |
| 4.5 |
|
| Other (A) | 7.3 |
| 2.9 |
| 9.5 |
| 5.4 |
|
| Total Current Regulatory Assets | $ | 48.8 |
| $ | 27.0 |
| $ | 121.8 |
| $ | 46.5 |
|
| Non-Current | | |
| Benefit obligations regulatory asset | $ | 227.4 |
| $ | 370.6 |
| $ | 232.6 |
| $ | 242.2 |
|
| Income taxes recoverable from customers, net | 56.5 |
| 54.7 |
| 62.3 |
| 56.7 |
|
| Smart Grid | 44.2 |
| 42.8 |
| 43.2 |
| 43.6 |
|
| Deferred storm expenses | 21.6 |
| 12.7 |
| 35.7 |
| 27.6 |
|
| Unamortized loss on reacquired debt | 11.8 |
| 13.0 |
| 13.4 |
| 14.8 |
|
| Pension tracker | 1.4 |
| — |
| |
| Other | 16.2 |
| 16.8 |
| 17.6 |
| 17.3 |
|
| Total Non-Current Regulatory Assets | $ | 379.1 |
| $ | 510.6 |
| $ | 404.8 |
| $ | 402.2 |
|
| Regulatory Liabilities | | |
| Current | | |
| Smart Grid rider over recovery (B) | $ | 16.7 |
| $ | 24.1 |
| |
| Fuel clause over recoveries | 0.4 |
| 109.2 |
| $ | — |
| $ | 61.3 |
|
| Other (B) | 3.1 |
| 7.8 |
| 12.3 |
| 7.5 |
|
| Total Current Regulatory Liabilities | $ | 20.2 |
| $ | 141.1 |
| $ | 12.3 |
| $ | 68.8 |
|
| Non-Current | | |
| Accrued removal obligations, net | $ | 227.7 |
| $ | 218.2 |
| $ | 262.8 |
| $ | 254.9 |
|
| Deferred pension credits | 6.5 |
| 17.7 |
| |
| Pension tracker | — |
| 9.2 |
| 35.5 |
| 17.7 |
|
| Other (C) | | 1.4 |
| 1.0 |
|
| Total Non-Current Regulatory Liabilities | $ | 234.2 |
| $ | 245.1 |
| $ | 299.7 |
| $ | 273.6 |
|
| |
| (A) | Included in Other Current Assets on the Balance Sheets. |
| |
| (B) | Included in Other Current Liabilities on theBalance Sheets.
|
OG&E recovers a return on the capital expenditures along with operation and maintenance expense and depreciation expense related to the Crossroads wind farm through riders established by the OCC and APSC. OG&E began recovery in the fourth quarter of 2011 in Oklahoma and June of 2013 in Arkansas, and believes the rider will continue until new rates are implemented in OG&E's next general rate case in each jurisdiction.
OG&E recovers program costs related to the Demand and Energy Efficiency Program. An extension of the demand program rider was approved in December 2012, which allows for the recovery of demand program costs, lost revenues associated with certain achieved energy, demand savings and performance based incentives and the recovery of costs associated with research and development investments through December 2015.
| |
| (C) | Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities. |
Fuel clause under recoveries are generated from under recoveries from OG&E's customers when OG&E's cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E's customers when the amount billed to its customers exceeds OG&E's cost of fuel.OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills.As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.
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 and net transition obligation.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 Accumulatedaccumulated other comprehensive income.
The following table is a summary of the components of the benefit obligations regulatory asset at:
| | December 31 (In millions) | 2013 | 2012 | 2016 | 2015 |
| Pension Plan and Restoration of Retirement Income Plan | | |
| Net loss | $ | 178.4 |
| $ | 278.6 |
| $ | 199.9 |
| $ | 214.1 |
|
| Prior service cost | 2.5 |
| 4.5 |
| |
| Postretirement Benefit Plans | | | | |
| Net loss | 79.9 |
| 134.6 |
| 32.7 |
| 34.2 |
|
| Prior service cost | (33.4 | ) | (47.1 | ) | — |
| (6.1 | ) |
| Total | $ | 227.4 |
| $ | 370.6 |
| $ | 232.6 |
| $ | 242.2 |
|
The following amounts in the benefit obligations regulatory asset at December 31, 20132016 are expected to be recognized as components of net periodic benefit cost in 20142017:
| | | (In millions) | | |
| Pension Plan and Restoration of Retirement Income Plan | | |
| Net loss | $ | 11.4 |
| $ | 12.4 |
|
| Prior service cost | 2.0 |
| |
| Postretirement Benefit Plans | | |
| Net loss | 11.0 |
| 2.3 |
|
| Prior service cost | (13.7 | ) | |
| Total | $ | 10.7 |
| $ | 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 liabilities 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 Incomeincome 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 and stranded costs associated with OG&E's existing meters.The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program were capped at$366.4 million (inclusive of the U.S. Department of Energy grant award of $130.0 million) subject to an offset for any recovery of those costs from Arkansas customers.reports. These amounts are currently being recovered through a rider whichrate 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 remain in effect until the smart grid project costs arebe included in base rates in OG&E's next general rate case.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 $6.9 million, and the stranded costs associated with OG&E's existinganalog electric meters, which have been replaced by smart meters whichand 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 OG&E's nextthe current general rate case.cases.
OG&E defers annual Oklahoma storm-related operation and maintenance expensesincludes in excess of$2.7 millionand expensesexpense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million. annually and defers any additional expenses incurred over $2.7 million. OG&E willexpects to recover the amounts deferred amountseach year over a five-year period ending in August 2017.accordance with historical practice.
Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expenses and are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is not included inrecovered as a part of OG&E's rate base and does not otherwise earn a ratecost of return.capital.
Accrued removal obligations, net represent asset retirement costs previously recovered from ratepayers for other than legal obligations.
OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory liability in the regulatory assets and liabilities table above.
In September 2011, OG&E was allowed to include postretirement medical expenses in its pension tracker. In August 2012, OG&E was allowed to recover pension and postretirement medical expenses over a two-year period ending July 2014 which is included in Deferred pension credits in the regulatory assets and liabilities table above.
Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations.
Management continuously monitors the future recoverability of regulatory assets. When, in management's judgment, future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to
discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, 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, impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations, assets and depreciable lives of property, plant and equipment, the existencedetermination of regulatory assets and liabilities and unbilled revenues.
Cash and Cash Equivalents
For purposes of the Financial Statements, OG&E considers all highly liquid debt instrumentsinvestments 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 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 million $1.9 millionand$2.6 $1.4 millionatDecember 31, 20132016 and and2015, 2012, 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 $74.482.4 million and $76.8119.3 million at December 31, 20132016 and 20122015, respectively. respectively.
Gas ImbalancesEffective May 1, 2014, the gas storage services agreement with Enable was terminated. As a result of this contract termination, approximately 5.3 Bcf of cushion gas owned by OG&E and stored on the Enable system is being directed to OG&E's power plants over a five year period during peak time of June 1 to August 31 at a rate of 11,500 MMBtu/day for a total of 1.06 Bcf per year. In 2014, approximately
$11.0 million of cushion gas was reclassified from Plant-in-Service to Other Deferred Assets, representing natural gas in storage, that will be removed from storage over four years. As of December 31, 2016, the balance of cushion gas in Fuel Inventories is $3.0 million and the balance in Other Deferred Assets is $2.7 million.
Gas imbalances occur when the actual amounts of natural gas delivered from or received by OG&E differ from the amounts scheduled to be delivered or received. OG&E values all imbalances at an average of current market indices applicable to OG&E's operations, not to exceed net realizable value.
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 tabletables below presentspresent 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 StatementStatements of Income.
| | December 31, 2013 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2016 (In millions) | | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| McClain Plant (A) | 77 | % | $ | 180.8 |
| $ | 62.1 |
| $ | 118.7 |
| 77 | % | $ | 234.2 |
| $ | 72.3 |
| $ | 161.9 |
|
| Redbud Plant (A)(B) | 51 | % | $ | 498.9 |
| $ | 89.7 |
| $ | 409.2 |
| 51 | % | $ | 489.0 |
| $ | 121.0 |
| $ | 368.0 |
|
| |
| (A) | Construction work in progress was $0.1$0.2 million and $39.5$1.8 million for the McClain and Redbud Plants, respectively. |
| |
| (B) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $28.845.3 million. |
| | December 31, 2012 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2015 (In millions) | | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| McClain Plant (A) | 77 | % | $ | 182.1 |
| $ | 56.3 |
| $ | 125.8 |
| 77 | % | $ | 220.4 |
| $ | 62.8 |
| $ | 157.6 |
|
| Redbud Plant (A)(B) | 51 | % | $ | 458.5 |
| $ | 69.5 |
| $ | 389.0 |
| 51 | % | $ | 487.5 |
| $ | 101.2 |
| $ | 386.3 |
|
| |
| (A) | Construction work in progress was $0.1$1.6 million and $0.3$1.3 million for the McClain and Redbud Plants, respectively. |
| |
| (B) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $23.3$39.8 million. |
OG&E's property, plant and equipment and related accumulated depreciation are divided into the following major classes at:
| | December 31, 2013 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2016 (In millions) | | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| Distribution assets | $ | 3,403.8 |
| $ | 1,028.2 |
| $ | 2,375.6 |
| $ | 3,896.2 |
| $ | 1,221.5 |
| $ | 2,674.7 |
|
| Electric generation assets (A) | 3,551.0 |
| 1,306.1 |
| 2,244.9 |
| 4,155.9 |
| 1,493.3 |
| 2,662.6 |
|
| Transmission assets (B) | 2,163.7 |
| 385.0 |
| 1,778.7 |
| 2,548.8 |
| 481.3 |
| 2,067.5 |
|
| Intangible plant | 50.5 |
| 27.1 |
| 23.4 |
| 85.0 |
| 43.9 |
| 41.1 |
|
| Other property and equipment | 330.2 |
| 118.2 |
| 212.0 |
| 381.5 |
| 145.6 |
| 235.9 |
|
| Total property, plant and equipment | $ | 9,499.2 |
| $ | 2,864.6 |
| $ | 6,634.6 |
| $ | 11,067.4 |
| $ | 3,385.6 |
| $ | 7,681.8 |
|
| |
| (A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $28.8$45.3 million. |
| |
| (B) | This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.30.6 million. |
| | December 31, 2012 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |
December 31, 2015 (In millions) | | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment |
| Distribution assets | $ | 3,222.7 |
| $ | 969.6 |
| $ | 2,253.1 |
| $ | 3,728.8 |
| $ | 1,152.8 |
| $ | 2,576.0 |
|
| Electric generation assets (A) | 3,446.6 |
| 1,242.4 |
| 2,204.2 |
| 3,837.4 |
| 1,407.0 |
| 2,430.4 |
|
| Transmission assets (B) | 1,712.6 |
| 359.8 |
| 1,352.8 |
| 2,454.2 |
| 440.7 |
| 2,013.5 |
|
| Intangible plant | 50.2 |
| 25.0 |
| 25.2 |
| 81.0 |
| 38.0 |
| 43.0 |
|
| Other property and equipment | 317.6 |
| 108.8 |
| 208.8 |
| 356.4 |
| 123.2 |
| 233.2 |
|
| Total property, plant and equipment | $ | 8,749.7 |
| $ | 2,705.6 |
| $ | 6,044.1 |
| $ | 10,457.8 |
| $ | 3,161.7 |
| $ | 7,296.1 |
|
| |
| (A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $23.339.8 million. |
| |
| (B) | This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.30.5 million. |
TheOG&E's unamortized computer software costs were $16.836.5 million and $17.634.3 million at December 31, 20132016 and 20122015, respectively. In 20132016, 20122015 and 20112014, amortization expense for computer software costs was $4.08.0 million, $4.26.9 million and $1.85.2 million, respectively.
Depreciation and Amortization
The provision for depreciation, which was2.8 percentand3.0 percent and 2.9 percent , respectively, of the average depreciable utility plant for2013 2016 and 20122015, respectively, is provided on a 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 2014,2017, the provision for depreciation is projected to be 2.83.1 percent of the average depreciable utility plant. Amortization of intangible assets is computed using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2013,2016, 93.597.0 percent will be amortized over9.30 16 years with the remaining 6.53.0 percentof the remaining amortizable intangible plant balance atDecember 31, 20132016 being amortized over 25.623.7 years. Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which areis being amortized over a 27-year27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 2637 to 59-year59year period.
Asset Retirement Obligations
OG&E has previously recorded asset retirement obligations that are being amortizedaccreted over their respective lives ranging from 20three to 74 years.
The following table summarizes changes to OG&E's asset retirement obligations during the years ended December 31, 20132016 and 20122015.
| | | (In millions) | 2013 | 2012 | 2016 | 2015 |
| Balance at January 1 | $ | 53.6 |
| $ | 24.8 |
| $ | 63.3 |
| $ | 58.6 |
|
| Accretion expense | 2.3 |
| 1.9 |
| 2.8 |
| 2.6 |
|
| Revisions in estimated cash flows (A) | (0.7 | ) | 26.9 |
| 3.6 |
| 1.6 |
|
| Additions | | — |
| 0.9 |
|
| Liabilities settled | | (0.1 | ) | (0.4 | ) |
| Balance at December 31 | $ | 55.2 |
| $ | 53.6 |
| $ | 69.6 |
| $ | 63.3 |
|
| |
| (A) | Due to changes to OG&E's asset retirement obligations related to its wind farms as a result of changes in the assumptionAssumptions changed related to the timingestimated cost of removal used in the valuation of the asset retirement obligations.
asbestos abatement.
|
Allowance for Funds Used During Construction
For OG&E, allowanceAllowance 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 net other incomeOther Income and a reduction to interest expenseInterest 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 rates, compounded semi-annually, were 8.338.2 percent, 8.938.1 percent and 8.716.9 percent for the years ended December 31, 20132016, 20122015 and 20112014, respectively. The decreaseincrease in the allowance for funds used during construction rates in 20132016 was primarily due to two factors. First, a decrease in the common equity cost rate caused the equity portion of allowance for equity fundsshort-term debt being used duringto finance construction to decrease. Second, an increase in the average daily balance of short term debt allowed the fixed commercial paper fees to be lower per dollar of short term debt, resulting in a lower short term debt rate,projects, which caused the debt portion of allowance for funds used during construction to decrease.
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
General
OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
SPP Purchases and Sales
OG&E participatescurrently 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 energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlementsIntegrated Marketplace for over or under schedulesthe sole benefit of generation and load. Market participants, includingits customers. OG&E are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants' MWH entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale tohas not participated in the SPP at the respective market priceIntegrated Marketplace for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase fromany speculative trading activities. OG&E records the SPP at the respective market price forIntegrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that hour. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales tobe recorded on a net basis for each settlement period of the SPP at market rates inIntegrated Marketplace. These results are reported as Operating Revenues and the hourly purchases from the SPP at market rates inor Cost of SalesGoods Sold in its Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.
Fuel Adjustment Clauses
Variances in theThe actual cost of fuel used in electric generation and certain purchased power costs as compared to the fuel component included in the cost-of-service for ratemaking, 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 andhave 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.
Income Taxes
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. 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 expenseInterest Expense and recognizes penalties in other expense.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. OGE employees can carryover no more than 80 hours to be used in future years.
Accumulated Other Comprehensive Loss
The balance of Accumulated Other Comprehensive Loss was $1.3 million at December 31, 2012 related to deferred commodity contracts hedging activity. There was no balance in Accumulated Other Comprehensive Loss at December 31, 2013.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. OG&E had $6.213.9 million and $5.810.0 million in accrued environmental liabilities at December 31, 20132016 and 2012,2015, respectively, which are included in the summary of asset retirement obligations above.
table.
Reclassifications
Certain prior-year amounts have been reclassified to conform to the current year presentation.
The December 31, 2015 Balance Sheet has been adjusted for the reclassification of $16.3 million 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, "Simplifying the Presentation of Debt Issuance Costs," in 2016.
| |
| 2. | Accounting Pronouncements
|
Revenue from Contracts with Customers.In July 2013,May 2014, the Emerging Issues Task ForceFASB issued "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward or Tax Credit Carryforward Exists.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 revenue standard requiresby one year. Reporting entities may choose to present an unrecognized tax benefit, or a portionadopt the standard as of an unrecognized tax benefit,the original effective date. The deferral results in the statementnew revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. OG&E currently expects to apply 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 of the new standard on its results of operations and financial position, as a reductionbut believes that it will change the income statement presentation of revenues and will require new disclosures.
Consolidation. In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810)." The amendments in ASU 2015-02 affect reporting entities that are required to a deferred tax asset for a net operating loss carryforwardevaluate whether they should consolidate certain legal entities. The new standard modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or a tax credit carryforward, except as follows: tovoting interest entities along with eliminating the extentpresumption that a net operating loss carryforward or tax credit carryforward at the reporting date is not available under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance ofgeneral partner should consolidate a tax position, the unrecognized tax benefit would be presented in the statement of financial position as a liability.limited partnership. The new standard is applicableeffective for fiscal years beginning after December 15, 2015. The adoption of this new standard did not result in the consolidation of any non-consolidated entities.
Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between current lease accounting and Topic 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as OG&E, will need to recognize a right-of-use asset and a lease liability for virtually all entitiesof their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance, but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 15, 2018. The new guidance must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. OG&E has started evaluating its current lease contracts. OG&E has not determined the amount of impact on its Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities.
Investments. In March 2016, the FASB issued ASU 2016-07, "Investments-Equity Method and Joint Ventures; Simplifying the Transition to the Equity Method of Accounting (Topic 323)." The amendments in ASU 2016-07 eliminate the requirement to retroactively adopt the equity method of accounting 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 unrecognizedany 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. The new guidance among other requirements will require all of the tax effects related 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 required to be applied prospectively to all excess tax benefits and tax deficiencies resulting from settlements after the date of 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 netmodified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating loss carryforwardactivities 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 equity
will 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 taxreporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit carryforward exists.losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The new standard is effective for interim and annual reporting periods beginning after December 15, 20132019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. OG&E does not requirebelieve this ASU will have any new financial statement disclosures. This new standard may be applied retrospectively or prospectively with early adoption permitted. OG&E retrospectively adopted this new standard effective January 1, 2013.effect on its Financial Statements.
Simplifying the Presentation of Debt Issuance Costs.In February 2013,April 2015, the Financial Accounting Standards BoardFASB issued "Comprehensive Income: ReportingASU 2015-03, "Interest - Imputation of Amounts Reclassified OutInterest (Subtopic 835-30): Simplifying the Presentation of Accumulated Other Comprehensive Income.Debt Issuance Costs." The newamendments 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 requires an entityand adjusted the December 31, 2015 Balance Sheet for the reclassification of debt issuance costs from Total Deferred Charges and Other Assets to provide information aboutLong-Term Debt to be consistent with the amounts reclassified outDecember 31, 2016 presentation.
Classification of accumulated other comprehensive income by component.Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued 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 new standard requires an entity to present, eitherASU also provides additional guidance on the faceapplication of the statement where net income is presented or in the notes, significant amounts reclassified outpredominance principle when cash receipts and payments have aspects of accumulated other comprehensive income by the respective line items in net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts.more than one class of cash flows. The new standard is applicable for all entities that issue financial statements that are presented in conformity with U.S. GAAP and that report items of other comprehensive income. The new standard is effective forinterim andannual reporting periods financial statements issued for fiscal years beginning afterDecember 15, 20122017, and interim periods within those fiscal years and retrospective application is required to be applied prospectively.required. OG&E adopteddoes not believe this new standard effectiveJanuary 1, 2013.ASU will have a material effect on its Statements of Cash Flows.
Going Concern. 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, the FASB issued ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent." ASU 2015-07 removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and eliminates certain disclosures for those investments. OG&E adopted this standard in 2016 which minimally impacted disclosures within the Retirement Plans and Postretirement Benefit Plans footnote included in this filing.
| |
| 3. | Related Party Transactions
|
OGE Energy charged operating costs to OG&E of of$120.1131.5 million, $118.4123.0 millionand$129.7120.3 millionin20132016, 20122015and20112014, respectively.OGE Energy charges operating costs to its subsidiaries and unconsolidated affiliateOG&E based on several factors. Operating costs directly related to specific subsidiaries or unconsolidated affiliateOG&E are assigned to those subsidiaries or unconsolidated affiliate.Where more than one subsidiary or unconsolidated affiliate benefits from certain expenditures, the costs are shared between those subsidiaries and unconsolidated affiliate receiving the benefits.as such. Operating costs incurred for the benefit of all subsidiaries and unconsolidated affiliateOG&E are allocated among the subsidiaries and unconsolidated affiliate, either as overhead based primarily on labor costs or using the "Distrigas" method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.
OG&E entered into a contract with Enable to provide transportation services effective May 1, 2014. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will be effective upon the conversion of units 4 and 5 at Muskogee from coal to gas. The following table summarizes related party transactions between OG&E and its affiliate, Enable during the years ended December 31, 2016, 2015 and 2014.
|
| | | | | | | | | |
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 |
|
In20132016, 2012 and 2011.
|
| | | | | | | | | |
| | December 31, |
| (In millions) | 2013 | 2012 | 2011 |
| Operating Revenues: | | | |
| Electricity to power electric compression assets | $ | 10.2 |
| $ | 12.4 |
| $ | 8.1 |
|
| Cost of Sales: | | | |
| Natural gas transportation services | $ | 34.8 |
| $ | 34.8 |
| $ | 34.8 |
|
| Natural gas storage services | 12.9 |
| 12.9 |
| 12.7 |
|
| Natural gas purchases | 22.4 |
| 20.4 |
| 34.7 |
|
In20132015 and 20122014, OG&E declared dividends to OGE Energy of $170.0190.0 million, $120.0 million and $75.0$120.0 million, respectively.In2011, OG&E declared no dividends to OGE Energy.
In June 2011, OGE Energy made a capital contribution to OG&E for $50.0 million.
| |
| 4. | 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 hierarchyare as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessibleat 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 thereporting entity'sown 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 atDecember 31, 20132016 and December 31, 2012.2015.
The following table summarizes the fair value and carrying amount of OG&E's financial instruments atDecember 31, 2013 and December 31, 2012.
|
| | | | | | | | | | | | |
| | 2013 | 2012 |
December 31 (In millions) | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
| Long-Term Debt | | | | |
| Senior Notes | $ | 2,154.5 |
| $ | 2,405.0 |
| $ | 1,904.2 |
| $ | 2,401.6 |
|
| Industrial Authority Bonds | 135.4 |
| 135.4 |
| 135.4 |
| 135.4 |
|
| Tinker Debt | 10.3 |
| 9.1 |
| 10.7 |
| 10.0 |
|
The carrying value of the financial instruments included in theBalance Sheets approximates fair value except for long-term debt which is valued at the carrying amount.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 maturitiesand 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, 2016 and 2015.
|
| | | | | | | | | | | | |
Year Ended December 31 (In millions) | 2016 | 2015 |
| | 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 |
|
| Industrial Authority Bonds | 135.4 |
| 135.4 |
| 135.4 |
| 135.4 |
|
| Tinker Debt | 9.9 |
| 11.3 |
| 10.0 |
| 9.2 |
|
| |
| 5. | Stock-Based Compensation
|
In 2013, OGE Energy adopted, and its shareownersshareholders approved, the 2013 Stock Incentive Plan. The 2013 Plan replaced the 2008 Plan and no further awards will be granted under the 2008 Plan. Under the 2013 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 to 7,400,000 shares under the 2013 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, 20132016, 20122015 and 20112014 related to performance units and restricted stock for OG&E employees.
| | Year ended December 31 (In millions) | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Performance units | | |
| Total shareholder return | $ | 1.7 |
| $ | 1.7 |
| $ | 1.6 |
| $ | 2.1 |
| $ | 2.4 |
| $ | 2.0 |
|
| Earnings per share | 0.5 |
| 0.9 |
| 1.1 |
| 0.1 |
| 0.4 |
| 0.8 |
|
| Total performance units | 2.2 |
| 2.6 |
| 2.7 |
| 2.2 |
| 2.8 |
| 2.8 |
|
| Restricted stock | 0.1 |
| 0.1 |
| 0.2 |
| — |
| 0.1 |
| 0.1 |
|
| Net compensation expense | $ | 2.3 |
| $ | 2.7 |
| $ | 2.9 |
| $ | 2.2 |
| $ | 2.9 |
| $ | 2.9 |
|
| Income tax benefit | $ | 0.9 |
| $ | 1.2 |
| $ | 1.2 |
| $ | 0.9 |
| $ | 1.1 |
| $ | 1.1 |
|
OGE Energy has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. In 20132016, 20122015 and 20112014, there were 139,7061,131 shares, 205,83818,820 shares and 113,602100,640 shares, respectively, of new common stock issued to OG&E's employees pursuant to OGE Energy's stock incentive plansStock Incentive Plan related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. In 20132016, there were 692658 shares of restricted stock returned to OGE Energy to satisfy tax liabilities.
Performance Units
Under the 2008 Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of OGE Energy's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the 2008 Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle.
The 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. 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 arewere not accrued or paid during the performance periodfor awards prior to February 2014, and were therefore are not included in the fair value calculation. Beginning with the February 2014 performance unit awards, dividends are accrued on a quarterly basis pending achievement of payout criteria, and were therefore included in the fair value calculations. Expected price volatility is based on the historical volatility of 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.
| | | | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Number of units granted to OG&E employees | 71,850 |
| 81,122 |
| 86,604 |
| 105,076 |
| 90,098 |
| 67,773 |
|
| Fair value of units granted | $ | 25.89 |
| $ | 25.91 |
| $ | 23.05 |
| $ | 20.84 |
| $ | 31.02 |
| $ | 34.73 |
|
| Expected dividend yield | 2.8 | % | 3.0 | % | 3.2 | % | 3.5 | % | 2.6 | % | 2.5 | % |
| Expected price volatility | 20.0 | % | 22.0 | % | 33.0 | % | 19.8 | % | 16.9 | % | 20.0 | % |
| Risk-free interest rate | 0.37 | % | 0.38 | % | 1.40 | % | 0.88 | % | 0.91 | % | 0.67 | % |
| Expected life of units (in years) | 2.84 |
| 2.87 |
| 2.87 |
| 2.85 |
| 2.85 |
| 2.88 |
|
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 Energy reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to 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.
| | | | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Number of units granted to OG&E employees | 23,952 |
| 27,038 |
| 28,862 |
| 35,025 |
| 30,034 |
| 22,592 |
|
| Fair value of units granted | $ | 26.73 |
| $ | 23.82 |
| $ | 20.81 |
| $ | 26.59 |
| $ | 33.99 |
| $ | 34.74 |
|
Restricted Stock
Under the 2008 Stock Incentive Plan, and beginning in 2008, OGE Energy issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.
The fair value of the restricted stock was based on the closing market price of OGE Energy's common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, 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.calculation for such restricted stock granted prior to July 2014.
For restricted stock granted after July 2014, dividends will only be paid on restricted stock awards that vest. Accordingly, for restricted stock granted after July 2014, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related toOGE Energy'srestricted stock.The number of shares of restricted stock grantedrelated to OG&E employeesand the grant date fair value are shown in the following table.
There were no restricted stock grants during 2016.
| | | | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Shares of restricted stock granted to OG&E employees | 3,824 |
| 2,216 |
| 4,468 |
| — |
| — |
| 6,204 |
|
| Fair value of restricted stock granted | $ | 29.71 |
| $ | 26.93 |
| $ | 23.61 |
| $ | — |
| $ | — |
| $ | 35.66 |
|
A summary of the activity for OGE Energy's performance units and restricted stockapplicable to OG&E's employees OG&E'S employeesat December 31, 20132016 and changes in 20132016 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 | |
| Units/Shares Outstanding at 12/31/12 | 224,012 |
| | | 74,670 |
| | | 6,046 |
| | |
| (Dollars in millions) | | Number
of Units | | Aggregate Intrinsic Value | Number
of Units | | Aggregate Intrinsic Value | Number
of Shares | Aggregate Intrinsic Value |
| Units/Shares Outstanding at 12/31/15 | | 214,652 |
| | | 71,555 |
| | | 5,715 |
| |
| Granted | 71,850 |
| (A) | | 23,952 |
| (A) | | 3,824 |
| | 105,076 |
| (A) | | 35,025 |
| (A) | | — |
| |
| Converted | (75,452 | ) | (B) | $ | 4.4 |
| (25,152 | ) | (B) | $ | 1.5 |
| N/A |
| | (80,581 | ) | (B) | $ | — |
| (26,862 | ) | (B) | $ | — |
| N/A |
| |
| Vested | N/A |
| | | N/A |
| | | (3,038 | ) | $ | 0.1 |
| N/A |
| | | N/A |
| | | (3,651 | ) | $ | 0.1 |
|
| Forfeited | (7,940 | ) | | | (2,648 | ) | | | (884 | ) | | (7,172 | ) | | | (2,388 | ) | | | (268 | ) | |
| Employee migration | (5,644 | ) | (C) | | (1,884 | ) | (C) | | — |
| | 4,606 |
| (C) | | 1,534 |
| (C) | | — |
| |
| Units/Shares Outstanding at 12/31/13 | 206,826 |
| | $ | 9.9 |
| 68,938 |
| | $ | 2.7 |
| 5,948 |
| $ | 0.2 |
| |
| Units/Shares Fully Vested at 12/31/13 | 68,750 |
| | $ | 3.7 |
| 22,914 |
| | $ | 1.6 |
| | | |
| 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 |
| | $ | — |
| | |
| |
| (A) | For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from 0zero percent to 200 percent of the target. |
| |
| (B) | These amounts represent performance units that vested at December 31, 20122015 which were settled in February 2013.2016. |
| |
| (C) | Due to certain employees transferring between OG&E and its affiliates. |
A summary of the activity for OGE Energy's non-vested performance units and restricted stock applicable to OG&E'S&E's employees at December 31, 20132016 and changes in 20132016 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 12/31/12 | 148,560 |
| | $ | 24.51 |
| 49,518 |
| | $ | 22.34 |
| 6,046 |
| $ | 24.62 |
| |
| Units/Shares Non-Vested at 12/31/15 | | 134,071 |
| | $ | 32.62 |
| 44,693 |
| | $ | 34.22 |
| 5,715 |
| $ | 34.04 |
|
| Granted | 71,850 |
| (A) | $ | 25.89 |
| 23,952 |
| (A) | $ | 26.73 |
| 3,824 |
| $ | 29.71 |
| 105,076 |
| (A) | $ | 20.84 |
| 35,025 |
| (A) | $ | 26.59 |
| — |
| $ | — |
|
| Converted | | — |
|
| $ | — |
| — |
|
| $ | — |
| N/A |
| N/A |
|
| Vested | (68,750 | ) | | $ | 23.05 |
| (22,914 | ) | | $ | 20.81 |
| (3,038 | ) | $ | 23.51 |
| (57,484 | ) | | $ | 34.73 |
| (19,164 | ) | | $ | 34.74 |
| (3,651 | ) | $ | 33.10 |
|
| Forfeited | (7,940 | ) | | $ | 25.23 |
| (2,648 | ) | | $ | 24.03 |
| (884 | ) | $ | 28.31 |
| (7,172 | ) | | $ | 26.45 |
| (2,388 | ) | | $ | 30.32 |
| (268 | ) | $ | 37.31 |
|
| Employee migration | (5,644 | ) | (B) | $ | 24.74 |
| (1,884 | ) | (B) | $ | 23.23 |
| — |
| $ | — |
| 4,606 |
| (B) | $ | 26.67 |
| 1,534 |
| (B) | $ | 30.34 |
| — |
| $ | — |
|
| Units/Shares Non-Vested at 12/31/13 | 138,076 |
| | $ | 25.90 |
| 46,024 |
| | $ | 25.25 |
| 5,948 |
| $ | 27.91 |
| |
| 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 | 126,390 |
| (C) | | 42,130 |
| (C) | | 5,948 |
| | 167,588 |
| (C) | | 55,863 |
| (C) | | 1,796 |
| |
| |
| (A) | For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from 0zero percent to 200 percent of the target. |
| |
| (B) | Due to certain employees transferring betweenOG&Eand its affiliates. |
| |
| (C) | The intrinsic value of the performance units based on total shareholder return and earnings per share is $5.6$5.8 million and $1.1$1.9 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) | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Performance units | | |
| Total shareholder return | $ | 1.6 |
| $ | 1.4 |
| $ | 1.2 |
| $ | 2.0 |
| $ | 2.1 |
| $ | 1.9 |
|
| Earnings per share | 1.0 |
| 0.8 |
| 0.6 |
| — |
| — |
| 0.7 |
|
| Restricted stock | 0.1 |
| 0.1 |
| 0.3 |
| 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, 2013 | Unrecognized Compensation Cost (in millions) | Weighted Average to be Recognized (in years) | |
| December 31, 2016 | | Unrecognized Compensation Cost (in millions) | Weighted Average to be Recognized (in years) |
| Performance units | | | | |
| Total shareholder return | $ | 1.7 |
| 1.63 | $ | 2.2 |
| 1.66 |
| Earnings per share | 0.3 |
| 1.52 | 0.9 |
| 1.70 |
| Total performance units | 2.0 |
|
| 3.1 |
|
|
| Restricted stock | 0.1 |
| 2.17 | — |
| 0.78 |
| Total | $ | 2.1 |
|
| $ | 3.1 |
|
|
Stock Options
OGE Energy last issued stock options in2004and as ofDecember 31, 2006, all stock options were fully vested and expensed. All stock options have a contractual life of10years.A summary of the activity for OGE Energy's stock optionsapplicable to OG&E'S employeesatDecember 31, 2013and changes during2013are shown in the following table.
|
| | | | | | | | | | |
| (dollars in millions) | Number of Options | Weighted-Average Exercise Price | Aggregate Intrinsic Value | Weighted-Average Remaining Contractual Term |
| Options Outstanding at 12/31/12 | 7,000 |
| $ | 9.62 |
| |
| | |
| Exercised | (7,000 | ) | $ | (9.62 | ) | $ | 0.2 |
| | |
| Options Outstanding at 12/31/13 | — |
| $ | — |
| $ | — |
| 0.00 | years |
| Options Fully Vested and Exercisable at 12/31/13 | — |
| $ | — |
| $ | — |
| 0.00 | years |
A summary of the activity for OG&E's exercised stock options in2013, 2012and2011are shown in the following table. |
| | | | | | | | | |
Year ended December 31 (In millions) | 2013 | 2012 | 2011 |
| Intrinsic value (A) | $ | 0.2 |
| $ | 0.2 |
| $ | 0.3 |
|
| |
(A) | The difference between the market value on the date of exercise and the option exercise price.
|
| |
| 6. | Supplemental Cash Flow Information
|
The following table discloses information about investing and financing activities that affected recognized assets and liabilities but which did not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.
| | Year ended December 31 (In millions) | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| NON-CASH INVESTING AND FINANCING ACTIVITIES | | |
| Installment payments for Tinker electric distribution system | $ | — |
| $ | 10.6 |
| $ | — |
| |
| Power plant long-term service agreement | 9.7 |
| — |
| 1.7 |
| $ | 39.5 |
| $ | 2.3 |
| $ | — |
|
| | | |
| SUPPLEMENTAL CASH FLOW INFORMATION | | |
| Cash Paid During the Period for | | |
| Cash paid during the period for | | |
| Interest (net of interest capitalized) (A) | $ | 127.5 |
| $ | 122.1 |
| $ | 108.2 |
| $ | 138.3 |
| $ | 143.6 |
| $ | 143.6 |
|
| Income taxes (net of income tax refunds) | (5.5 | ) | (1.2 | ) | 4.5 |
| — |
| (6.2 | ) | 0.2 |
|
| |
| (A) | Net of interest capitalized of $3.47.5 million, $3.54.2 million and $10.42.4 million in 20132016, 20122015 and 20112014, respectively. |
The items comprising income tax expense are as follows:
| | Year ended December 31 (In millions) | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Provision (Benefit) for Current Income Taxes | | |
| Federal | $ | (3.2 | ) | $ | (9.0 | ) | $ | 23.4 |
| $ | 2.9 |
| $ | (17.5 | ) | $ | (43.4 | ) |
| State | 0.6 |
| 0.3 |
| (0.5 | ) | (5.3 | ) | (5.3 | ) | (6.3 | ) |
| Total Provision (Benefit) for Current Income Taxes | (2.6 | ) | (8.7 | ) | 22.9 |
| (2.4 | ) | (22.8 | ) | (49.7 | ) |
| Provision for Deferred Income Taxes, net | | |
| Federal | 106.4 |
| 111.4 |
| 98.0 |
| 99.8 |
| 117.0 |
| 146.8 |
|
| State | 11.7 |
| (5.9 | ) | 0.3 |
| 17.2 |
| 11.3 |
| 15.4 |
|
| Total Provision for Deferred Income Taxes, net | 118.1 |
| 105.5 |
| 98.3 |
| 117.0 |
| 128.3 |
| 162.2 |
|
| Deferred Federal Investment Tax Credits, net | (2.0 | ) | (2.2 | ) | (3.3 | ) | (0.2 | ) | (0.7 | ) | (0.9 | ) |
| Total Income Tax Expense | $ | 113.5 |
| $ | 94.6 |
| $ | 117.9 |
| $ | 114.4 |
| $ | 104.8 |
| $ | 111.6 |
|
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, OG&E is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 20102013 or state and local tax examinations by tax authorities for years prior to 20092012. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce OG&E's effective tax rate.
The following schedule reconciles the statutory Federal tax raterates to the effective income tax rate:
| | | Year ended December 31 | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| Statutory Federal tax rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % |
| Amortization of net unfunded deferred taxes | 0.8 |
| 1.0 |
| 0.9 |
| 0.8 |
| 0.9 |
| 0.8 |
|
| Medicare Part D subsidy | — |
| — |
| 0.4 |
| |
| Federal investment tax credits, net | (0.5 | ) | (0.6 | ) | (0.9 | ) | (0.9 | ) | (0.2 | ) | (0.2 | ) |
| State income taxes, net of Federal income tax benefit | — |
| (0.7 | ) | 0.1 |
| 1.8 |
| 0.5 |
| 0.8 |
|
| Federal renewable energy credit (A) | (9.2 | ) | (9.4 | ) | (4.4 | ) | (8.2 | ) | (8.8 | ) | (9.4 | ) |
| Uncertain tax positions | 2.0 |
| — |
| — |
| 0.1 |
| 0.7 |
| 0.7 |
|
| Other | (0.2 | ) | (0.1 | ) | (0.2 | ) | 0.1 |
| (0.1 | ) | — |
|
| Effective income tax rate | 27.9 | % | 25.2 | % | 30.9 | % | 28.7 | % | 28.0 | % | 27.7 | % |
| |
| (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 atDecember 31, 20132016 and2012, 2015, respectively, were as follows:
| | December 31 (In millions) | 2013 | 2012 | 2016 | 2015 |
| Current Deferred Income Tax Assets | | |
| Net operating losses | $ | 168.7 |
| $ | 113.8 |
| |
| Accrued liabilities | 9.0 |
| 14.0 |
| |
| Federal tax credits | 8.0 |
| 6.0 |
| |
| Accrued vacation | 2.8 |
| 3.1 |
| |
| Uncollectible accounts | 0.7 |
| 1.0 |
| |
| Derivative instruments | — |
| 0.8 |
| |
| Total Current Deferred Income Tax Assets | $ | 189.2 |
| $ | 138.7 |
| |
| | | |
| Non-Current Deferred Income Tax Liabilities | | |
| Non-Current Deferred Income Tax Liabilities, net | | |
| Accelerated depreciation and other property related differences | $ | 1,747.0 |
| $ | 1,648.5 |
| $ | 2,101.4 |
| $ | 2,012.1 |
|
| OG&E pension plan | 84.7 |
| 102.2 |
| 48.0 |
| 55.1 |
|
| Regulatory asset | 26.0 |
| 18.8 |
| 34.4 |
| 32.7 |
|
| Income taxes refundable to customers, net | 21.9 |
| 21.2 |
| 24.1 |
| 22.0 |
|
| Bond redemption-unamortized costs | 3.6 |
| 4.0 |
| 4.3 |
| 4.8 |
|
| Total Non-Current Deferred Income Tax Liabilities | 1,883.2 |
| 1,794.7 |
| |
| Non-Current Deferred Income Tax Assets | | |
| Federal tax credits | (101.9 | ) | (69.5 | ) | (209.3 | ) | (174.0 | ) |
| State tax credits | (86.1 | ) | (78.1 | ) | (102.6 | ) | (98.6 | ) |
| Postretirement medical and life insurance benefits | | (34.3 | ) | (40.8 | ) |
| Regulatory liabilities | (61.3 | ) | (71.4 | ) | (34.6 | ) | (46.3 | ) |
| Postretirement medical and life insurance benefits | (45.2 | ) | (42.1 | ) | |
| Asset retirement obligations | (20.8 | ) | — |
| (24.5 | ) | (22.5 | ) |
| Net operating losses | (17.6 | ) | (150.0 | ) | (26.1 | ) | (89.7 | ) |
| Other | | (16.7 | ) | (7.1 | ) |
| Accrued liabilities | | (8.0 | ) | (5.9 | ) |
| Accrued vacation | | (2.4 | ) | (2.6 | ) |
| Deferred Federal investment tax credits | (0.7 | ) | (1.5 | ) | (0.8 | ) | (0.9 | ) |
| Other | (4.4 | ) | (4.3 | ) | |
| Total Non-Current Deferred Income Tax Assets | (338.0 | ) | (416.9 | ) | |
| Uncollectible accounts | | (0.6 | ) | (0.5 | ) |
| Non-Current Deferred Income Tax Liabilities, net | $ | 1,545.2 |
| $ | 1,377.8 |
| $ | 1,752.3 |
| $ | 1,637.8 |
|
As of December 31, 2013,2016, OG&E has classified $7.8$13.5 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 the OG&E’s total gross unrecognized tax benefits as of the years ended December 31, 2013, 2012,2016, 2015, and 2011.
2014.
| | | (Millions) | 2013 | 2012 | 2011 | |
| (In millions) | | 2016 | 2015 | 2014 |
| Balance at January 1 | $ | — |
| $ | — |
| $ | — |
| $ | 20.2 |
| $ | 16.1 |
| $ | 12.0 |
|
| Tax positions related to current year: | | |
| Additions | 2.7 |
| — |
| — |
| 0.5 |
| 4.1 |
| 4.1 |
|
| Tax positions related to prior years: | | |
| Additions | 5.1 |
| — |
| — |
| |
| Balance at December 31 | $ | 7.8 |
| $ | — |
| $ | — |
| $ | 20.7 |
| $ | 20.2 |
| $ | 16.1 |
|
Where applicable, OG&E classifies income tax-related interest and penalties as interest expense and selling general and administrative expense, respectively. During the year ended As of December 31, 2013,2016, 2015 and 2014, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions. The total amountare $13.5 million, $13.2 million and $10.5 million of unrecognized tax benefits that if recognized would impactaffect the annual effective tax rate, if recognized, was $7.8 million as of December 31, 2013.rate.
68
As previously reported, in January 2013, 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 the first quarter of 2013,2016, OG&E recorded aan additional reserve for this item of $7.8$0.5 million ($5.1 ($0.3 million after tax)the federal tax benefit) related to a portion of the same Oklahoma investment tax credits generated in years prior to 2013the 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. An additional reserve of $4.1 million ($2.7 million after tax) was established
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, there were no income tax-related interest or penalties recorded with regard to these credits generated in the current year.
Prior to2013 , OG&E had a Federaluncertain tax operating loss primarily caused by the accelerated tax "bonus" depreciation provision contained within the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 which allowed OG&E to record a current income tax deduction for100 percentof the cost of certain property placed into service in 2011 and50 percentfor certain property placed into service in 2012. During 2013, OG&E began to utilize these net operating lossespositions.
On January 2, 2013, the American Taxpayer Relief Act of 2012 was signed into law. Among other things, the law included an extension of bonus depreciation for one year for property generally placed in service before January 1, 2014. The impact of the new law was reflected in OG&E's 2013Financial Statements as an increase in Deferred Tax Liabilities with a corresponding increase in Deferred Tax Assets related to the net operating loss.
In June 2010, new legislation was passed in Oklahoma that created a moratorium, from July 1, 2010 through June 30, 2012, on 30 income tax credits. For income tax purposes, credits affected by the moratorium could not be claimed for any event, transaction, investment, expenditure or other act for which the credits would otherwise be allowable. During this two-year period, affected credits generated by OG&E were deferred and will be utilized at a future date. For financial accounting purposes, OG&E is receiving the benefits as most of these credits did not expire if they were not utilized in the period they were generated.
Other
OG&E sustained Federal and state tax operating losses through2012caused primarily by bonus depreciation and other book versesversus tax temporary differences. As a result, OG&E had accrued Federal and state income tax benefits carrying into 20132016. As OG&E can no longer carry these losses back to prior periods, these losses are being carried forward for utilization in future years.years which began in 2013. In addition to the tax operating losses, OG&E was unable to utilize the various tax credits that were generatinggenerated 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 the losses and remaining credits before they begin to expire, accordingly no valuation allowance is considered necessary.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 | $ | 656.3 |
| $ | 24.2 |
| 2030 | $ | 403.1 |
| $ | 14.8 |
| 2030 |
| Federal operating loss | 463.1 |
| 162.1 |
| 2030 | 32.2 |
| 11.3 |
| 2030 |
| Federal tax credits | 109.9 |
| 109.9 |
| 2029 | 209.3 |
| 209.3 |
| 2029 |
| State tax credits | | | | |
| Oklahoma investment tax credits | 96.3 |
| 62.6 |
| N/A | 121.7 |
| 79.1 |
| N/A |
| Oklahoma capital investment board credits | 7.3 |
| 7.3 |
| N/A | 7.3 |
| 7.3 |
| N/A |
| Oklahoma zero emission tax credits | 24.1 |
| 16.2 |
| 2020 | 24.1 |
| 16.2 |
| 2020 |
OG&E projects full utilization of all Federal operating losses in 2014 as well as partial utilization of State operating loss carryforwards. Accordingly, a current deferred tax asset of $168.7 million has been reflected on the balance sheet.
| |
| 8. | Common Stock and Cumulative Preferred Stock |
There were no new shares of common stock issued in 20132016, 20122015 or 20112014.
A summary of OG&E's long-term debt is included in the Statements of Capitalization. At December 31, 20132016, 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) |
| 0.18% | - | 0.34% | Garfield Industrial Authority, January 1, 2025 | $ | 47.0 |
|
| 0.10% | - | 0.39% | Muskogee Industrial Authority, January 1, 2025 | 32.4 |
|
| 0.10% | - | 0.30% | Muskogee Industrial Authority, June 1, 2027 | 56.0 |
|
| Total (redeemable during next 12 months) | $ | 135.4 |
|
|
| | | | | | |
| 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 |
|
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 debtLong-Term Debt in OG&E's Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.
Issuance of Long-Term Debt
On May 8, 2013, OG&E issued $250 million of 3.9% senior notes due May 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures, general corporate expenses and for working capital purposes. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.
Long-Term Debt Maturities
Maturities of OG&E's long-term debt during the next five years consist of $0.2$125.2 million, $0.2$250.1 million, $110.2$250.1 million, $125.1$0.1 million and $250.1$0.1 million in years 20142017, 20152018, 20162019, 20172020 and2018, 2021, respectively.
OG&E has previously incurred costs related to debt refinancings.refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset, unamortized debt expense is classified asand Deferred Charges and Other Assets and the unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Balance Sheets and are being amortized over the life of the respective debt.
| |
| 10. | Short-Term Debt and Credit Facility |
At December 31, 2013, 2016, there were $87.2 $49.9 million in net outstanding advances from OGE Energy as compared to $90.3 $333.6 million in net outstanding advances to OGE Energy at December 31, 2012.2015. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400400.0 million of OGE Energy's revolving credit amount. Effective July 29, 2013, OG&E extended the termination date of this agreement to December 13, 20172018. At December 31, 2013, there were no intercompany borrowings under this agreement. OG&E has a $400400.0 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. At December 31, 20132016, there was $2.1$1.8 million supporting letters of credit at a weighted-average interest rate of0.530.95 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 20132016. At December 31, 2013, OG&E had less than $0.1 million in cash and cash equivalents.
In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. This credit facility contain an option, which may be exercised up to two times, to extend the term for an additional year, subject to consent
of a specified percentage of the lenders. Effective July 29, 2013, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreements to December 13, 2017.
OGE Energy's and OG&E'sability 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 downgradeof OGE Energy or OG&Ecould also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post collateral or letters of credit.
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 20132017 and ending December 31, 2014.2018.
| |
| 11. | Retirement Plans and Postretirement Benefit Plans
|
Pension Plan and Restoration of Retirement Income Plan
OG&E's employees participate in OGE Energy's Pension Plan and Restoration of Retirement Income Plan.
Employees hired or rehired on or after December 1, 2009 do not participate in the Pension Plan but are eligible to participate in the 401(k) Plan where, for each pay period,OGE Energycontributes to the 401(k) Plan, on behalf of each participant,200 percentof the participant's contributions up tofive percentof compensation.
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. During both2013and2012, OGE Energy made contributions to its Pension Plan of$35 millionof whichnonein 2013 and$33 millionin 2012 was OG&E's portion,to help ensure that the Pension Plan maintains an adequate funded status.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.During2014, 2016, OGE Energy expects to contribute up to$26made a $20.0 million contribution to its Pension Plan,, of which$1 millionis expected none related to be OG&E's portion.&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. The expectedAny contribution to the Pension Plan during 20142017 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
net periodic pension cost. During 2013,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 jurisdiction 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 to be paid to such employees upon retirement. As a result, and based in part on OG&E's historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, OG&E recorded pension settlement charges of $17.6$10.0 million in the third quarter of 2015 and $4.2 million in the fourth quarter of 2013,2015, of which $17.0$12.5 million related to OG&E’s&E's Oklahoma jurisdiction and has been included in the pension tracker. The pension settlement charge did not require a cash outlay by OG&E andcharges 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.
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 Federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.
Obligations and Funded Status
The following table presents the status ofOG&E's portion of OGE Energy'sPension Plan, andthe Restoration of Retirement Income Plan atand the postretirement benefit plans for December 31, 20132016and20122015. These amounts have been recorded in Accrued Benefit Obligations with the offsetrecorded as a regulatory asset in OG&E's Balance SheetSheets as discussed in Note 1. 1. Theregulatory assetrepresents represents a net periodic benefit cost to be recognized in theStatements of Income in future periods.
|
| | | | | | | | | | | | |
| | Pension Plan | Restoration of Retirement
Income Plan |
December 31 (In millions) | 2013 | 2012 | 2013 | 2012 |
| Benefit obligations | $ | (503.6 | ) | $ | (574.6 | ) | $ | (2.1 | ) | $ | (2.2 | ) |
| Fair value of plan assets | 516.5 |
| 519.0 |
| — |
| — |
|
| Funded status at end of year | $ | 12.9 |
| $ | (55.6 | ) | $ | (2.1 | ) | $ | (2.2 | ) |
The following table summarizes OG&E's portion of the benefit paymentsobligation 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 expects to pay related to its&E's Pension Plan and Restoration of Retirement Income Plan.These expected benefits are based onPlan differs from the same assumptions used to measure OGE Energy's 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, 2016 was $458.1 million and $3.4 million, respectively. The accumulated postretirement benefit obligation for the endPension Plan and the Restoration of Retirement Income Plan at December 31, 2015 was $470.6 million and $2.2 million, respectively. The details of the yearfunded status of the Pension Plan, the Restoration of Retirement Income Plan and include benefits attributable to estimated future employee service.the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | Pension Plan | Restoration of Retirement
Income Plan | Postretirement
Benefit Plans |
December 31 (In millions) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
| Change in Benefit Obligation | | | | | | |
| Beginning obligations | $ | 514.4 |
| $ | 543.5 |
| $ | 2.7 |
| $ | 2.8 |
| $ | 176.1 |
| $ | 217.6 |
|
| Service cost | 10.3 |
| 10.3 |
| 0.1 |
| 0.1 |
| 0.6 |
| 1.0 |
|
| Interest cost | 19.2 |
| 19.8 |
| 0.1 |
| 0.1 |
| 7.4 |
| 7.9 |
|
| Plan settlements | — |
| (36.5 | ) | (1.0 | ) | — |
| — |
| — |
|
| Participants' contributions | — |
| — |
| — |
| — |
| 2.9 |
| 2.6 |
|
| Actuarial (gains) losses | 1.2 |
| (8.6 | ) | 2.1 |
| (0.1 | ) | (7.2 | ) | (40.0 | ) |
| Benefits paid | (44.6 | ) | (14.1 | ) | — |
| (0.2 | ) | (13.4 | ) | (13.0 | ) |
| Ending obligations | $ | 500.5 |
| $ | 514.4 |
| $ | 4.0 |
| $ | 2.7 |
| $ | 166.4 |
| $ | 176.1 |
|
| | | | | | | |
| Change in Plans' Assets | | | | | | |
| Beginning fair value | $ | 464.2 |
| $ | 532.5 |
| $ | — |
| $ | — |
| $ | 50.0 |
| $ | 54.2 |
|
| Actual return on plans' assets | 37.7 |
| (17.7 | ) | — |
| — |
| 1.8 |
| (0.5 | ) |
| Employer contributions | — |
| — |
| 1.0 |
| 0.2 |
| 6.5 |
| 6.7 |
|
| Plan settlements | — |
| (36.5 | ) | (1.0 | ) | — |
| — |
| — |
|
| Participants' contributions | — |
| — |
| — |
| — |
| 2.9 |
| 2.6 |
|
| Benefits paid | (44.6 | ) | (14.1 | ) | — |
| (0.2 | ) | (13.4 | ) | (13.0 | ) |
| Ending fair value | $ | 457.3 |
| $ | 464.2 |
| $ | — |
| $ | — |
| $ | 47.8 |
| $ | 50.0 |
|
| Funded status at end of year | $ | (43.2 | ) | $ | (50.2 | ) | $ | (4.0 | ) | $ | (2.7 | ) | $ | (118.6 | ) | $ | (126.1 | ) |
Net Periodic Benefit Cost
|
| | | |
(In millions) | Projected Benefit Payments |
| 2014 | $ | 75.4 |
|
| 2015 | 65.1 |
|
| 2016 | 59.9 |
|
| 2017 | 53.1 |
|
| 2018 | 49.1 |
|
| After 2018 | 183.3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
| Service cost | $ | 10.3 |
| $ | 10.3 |
| $ | 9.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | — |
| $ | 0.6 |
| $ | 1.0 |
| $ | 2.0 |
|
| Interest cost | 19.2 |
| 19.8 |
| 21.4 |
| 0.1 |
| 0.1 |
| 0.1 |
| 7.4 |
| 7.9 |
| 8.8 |
|
| Expected return on plan assets | (33.1 | ) | (36.5 | ) | (35.8 | ) | — |
| — |
| — |
| (2.1 | ) | (2.2 | ) | (2.2 | ) |
| Amortization of net loss | 12.4 |
| 13.8 |
| 11.4 |
| 0.1 |
| 0.1 |
| 0.1 |
| 2.5 |
| 11.9 |
| 11.0 |
|
| Amortization of unrecognized prior service cost (A) | — |
| 0.5 |
| 1.9 |
| — |
| — |
| 0.1 |
| (6.1 | ) | (13.6 | ) | (13.7 | ) |
| Settlement | — |
| 14.2 |
| — |
| 0.4 |
| — |
| — |
| — |
| — |
| — |
|
| Net periodic benefit cost (B) | $ | 8.8 |
| $ | 22.1 |
| $ | 8.0 |
| $ | 0.7 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 2.3 |
| $ | 5.0 |
| $ | 5.9 |
|
| |
| (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 $11.8 million, $27.4 million and $14.2 million of net periodic benefit cost recognized in 2016, 2015 and 2014, respectively, OG&E recognized the following: |
a change in pension expense in 2016, 2015 and 2014 of $9.9 million, $(3.1) million and $11.2 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 2016, 2015 and 2014 of $7.9 million, $5.8 million and $5.2 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 2016 and 2015 of $0.1 million and $1.9 million related to the Arkansas jurisdictional portion of the pension settlement charge of $0.4 million and $14.2 million, respectively.
|
| | | | | | | | | |
| (In millions) | 2016 | 2015 | 2014 |
| Capitalized portion of net periodic pension benefit cost | $ | 2.9 |
| $ | 2.6 |
| $ | 2.6 |
|
| Capitalized portion of net periodic postretirement benefit cost | 0.8 |
| 1.6 |
| 1.8 |
|
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 |
|
N/A - not applicable
The overall expected rate of return on plan assets assumption was 7.50 percent in both 2016 and 2015, 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 6.75 percent in 2017 with the rates trending downward to 4.50 percent by 2026. A one-percentage point change in the assumed health care cost trend rate would have the following effects:
|
| | | | | | | | | |
| ONE-PERCENTAGE POINT INCREASE |
Year ended December 31 (In millions) | 2016 | 2015 | 2014 |
| Effect on aggregate of the service and interest cost components | $ | — |
| $ | — |
| $ | — |
|
| Effect on accumulated postretirement benefit obligations | 0.1 |
| 0.1 |
| 0.1 |
|
|
| | | | | | | | | |
| ONE-PERCENTAGE POINT DECREASE |
Year ended December 31 (In millions) | 2016 | 2015 | 2014 |
| Effect on aggregate of the service and interest cost components | $ | — |
| $ | — |
| $ | — |
|
| Effect on accumulated postretirement benefit obligations | 0.5 |
| 0.5 |
| 0.5 |
|
Plan Investments, Policies and Strategies
The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.
|
| | | | | | | |
| Projected Benefit Obligation Funded Status Thresholds | <90% | 95% | 100% | 105% | 110% | 115% | 120% |
| Fixed income | 50% | 58% | 65% | 73% | 80% | 85% | 90% |
| Equity | 50% | 42% | 35% | 27% | 20% | 15% | 10% |
| Total | 100% | 100% | 100% | 100% | 100% | 100% | 100% |
Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below. | | | Asset Class | Target Allocation | Minimum | Maximum | Target Allocation | Minimum | Maximum |
| Domestic All-Cap/Large Cap Equity | 50% | 60% | |
| Domestic Large Cap Equity | | 40% | 35% | 60% |
| Domestic Mid-Cap Equity | 15% | 5% | 25% | 15% | 5% | 25% |
| Domestic Small-Cap Equity | 15% | 5% | 25% | 25% | 5% | 30% |
| International Equity | 20% | 10% | 30% | 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) |
CoreActive Duration Fixed Income | Bloomberg Barclays Capital Aggregate Index |
Interest Rate Sensitive Fixed Income | Barclays Capital Aggregate Index |
| Long Duration Fixed Income | Duration blended Barclays Long Government/Credit & Barclays Universal |
| Equity Index | Standard & Poor's 500 Index |
All-Cap Equity | Russell 3000 Index |
| Russell 3000 Value Index |
| Mid-Cap Equity | Russell Midcap Index |
| | Russell Midcap Value Index |
| Small-Cap Equity | Russell 2000 Index |
| | Russell 2000 Value Index |
| International Equity | Morgan Stanley Capital Investment ACWI ex-US |
The fixed income manager ismanagers are expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of 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: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-US Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-US 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. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of$100 millionare allowable. No more thanfive percentof the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and 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 eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (10 percent for mid-cap and small-cap equity managers) 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.
Plan Investments
The following tables summarize OG&E's portion of OGE Energy's Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 20132016 and 20122015. There were no Level 3 investments held by the Pension Plan at December 31, 20132016 and 20122015.
| | | (In millions) | December 31, 2013 | Level 1 | Level 2 | December 31, 2016 | Level 1 | Level 2 | NAV |
| Common stocks | | $ | 237.1 |
| $ | 237.1 |
| $ | — |
| $ | — |
|
| U.S. common stocks | $ | 236.8 |
| $ | 236.8 |
| $ | — |
| |
| Foreign common stocks | 39.3 |
| 39.3 |
| — |
| |
| U.S. Government obligations | | |
| U.S. treasury notes and bonds (A) | 159.8 |
| 159.8 |
| — |
| 122.3 |
| 122.3 |
| — |
| — |
|
| Mortgage-backed securities | 50.3 |
| — |
| 50.3 |
| |
| Bonds, debentures and notes (B) | |
| |
| |
| |
| Mortgage and asset-backed securities | | 59.2 |
| — |
| 59.2 |
| — |
|
| Corporate fixed income and other securities | 110.6 |
| — |
| 110.6 |
| 137.6 |
| — |
| 137.6 |
| — |
|
| Mortgage-backed securities | 22.3 |
| — |
| 22.3 |
| |
| Commingled fund (C) | 29.2 |
| — |
| 29.2 |
| |
| Common/collective trust (D) | 26.0 |
| — |
| 26.0 |
| |
| Commingled fund (B) | | 23.8 |
| — |
| — |
| 23.8 |
|
| Foreign government bonds | 4.0 |
| — |
| 4.0 |
| 5.2 |
| — |
| 5.2 |
| — |
|
| U.S. municipal bonds | 2.0 |
| — |
| 2.0 |
| 1.9 |
| — |
| 1.9 |
| — |
|
| Interest-bearing cash | 0.1 |
| 0.1 |
| — |
| |
| 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) | 1.1 |
| — |
| 1.1 |
| 0.2 |
| — |
| 0.2 |
| — |
|
| Payable (foreign currency) | (1.1 | ) | — |
| (1.1 | ) | |
| Total Plan investments | $ | 680.4 |
| $ | 436.0 |
| $ | 244.4 |
| $ | 607.2 |
| $ | 368.7 |
| $ | 212.5 |
| $ | 26.0 |
|
| Receivable from broker for securities sold | 11.5 |
| |
| |
| — |
| |
| |
| |
| Interest and dividends receivable | 3.2 |
| |
| |
| 3.0 |
| |
| |
| |
| Payable to broker for securities purchased | (40.2 | ) | |
| |
| (14.3 | ) | |
| |
| |
| Plan investments attributable to affiliates | (138.4 | ) | | (138.6 | ) | |
| Total Plan assets | $ | 516.5 |
| |
| |
| $ | 457.3 |
| |
| |
| |
| | | (In millions) | December 31, 2012 | Level 1 | Level 2 | December 31, 2015 | Level 1 | Level 2 | NAV |
| Common stocks | | $ | 208.2 |
| $ | 208.2 |
| $ | — |
| $ | — |
|
| U.S. common stocks | $ | 232.2 |
| $ | 232.2 |
| $ | — |
| |
| Foreign common stocks | 39.9 |
| 39.9 |
| — |
| |
| U.S. Government obligations | | |
| U.S. treasury notes and bonds (A) | 138.6 |
| 138.6 |
| — |
| 158.9 |
| 158.9 |
| — |
| — |
|
| Mortgage-backed securities | 55.8 |
| — |
| 55.8 |
| 14.5 |
| — |
| 14.5 |
| — |
|
| Bonds, debentures and notes (B) | | |
| Corporate fixed income and other securities | 98.4 |
| — |
| 98.4 |
| 140.2 |
| — |
| 140.2 |
| — |
|
| Mortgage-backed securities | 13.5 |
| — |
| 13.5 |
| |
| Commingled fund (C) | 34.9 |
| — |
| 34.9 |
| |
| Common/collective trust (D) | 25.6 |
| — |
| 25.6 |
| |
| Commingled fund (B) | | 24.4 |
| — |
| — |
| 24.4 |
|
| Foreign government bonds | 3.9 |
| — |
| 3.9 |
| 5.6 |
| — |
| 5.6 |
| — |
|
| U.S. municipal bonds | 0.8 |
| — |
| 0.8 |
| 4.9 |
| — |
| 4.9 |
| — |
|
| Interest-bearing cash | 0.2 |
| 0.2 |
| — |
| 0.4 |
| 0.4 |
| — |
| — |
|
| Money market fund | | 11.7 |
| — |
| — |
| 11.7 |
|
| Index fund | | 1.8 |
| 1.8 |
| — |
| — |
|
| Mutual fund | | 24.3 |
| 24.3 |
| — |
| — |
|
| Preferred stocks | | 0.3 |
| 0.3 |
| — |
| — |
|
| Futures | | |
| U.S. Treasury futures (receivable) | | 17.6 |
| — |
| 17.6 |
| — |
|
| U.S. Treasury futures (payable) | | (12.4 | ) | — |
| (12.4 | ) | — |
|
| Forward contracts | | |
| Receivable (foreign currency) | 0.4 |
| — |
| 0.4 |
| 0.1 |
| — |
| 0.1 |
| — |
|
| Payable (foreign currency) | (0.4 | ) | — |
| (0.4 | ) | (0.1 | ) | — |
| (0.1 | ) | — |
|
| Total Plan investments | $ | 643.8 |
| $ | 410.9 |
| $ | 232.9 |
| $ | 600.4 |
| $ | 393.9 |
| $ | 170.4 |
| $ | 36.1 |
|
| Receivable from broker for securities sold | 0.8 |
| |
| |
| — |
| |
| |
| |
| Interest and dividends receivable | 2.8 |
| |
| |
| 3.5 |
| |
| |
| |
| Payable to broker for securities purchased | (21.4 | ) | |
| |
| (22.2 | ) | |
| |
| |
| Plan investments attributable to affiliates | (107.0 | ) | | (117.5 | ) | |
| Total Plan assets | $ | 519.0 |
| | |
| $ | 464.2 |
| | |
| |
| |
| (A) | This category represents U.S. treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher. |
| |
| (B) | This category primarily represents U.S. corporate bonds with an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings. |
| |
(C) | This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.
|
| |
(D) | This category represents units of participation in an investment pool which primarily invests in foreign or domestic bonds, debentures, mortgages, equipment or other trust certificates, notes, obligations issued or guaranteed by the U.S. Government or its agencies, bank certificates of deposit, bankers' acceptances and repurchase agreements, high grade commercial paper and other instruments with money market characteristics with a fixed or variable interest rate. There are no restrictions on redemptions in the common/collective trust.
|
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. treasury notes and bonds, mutual funds, index funds and interest-bearing cash.
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage-backed securities, other U.S. Government obligations,a commingled fund, a common/collective trust, U.S. municipal bonds, foreign government bonds, a repurchase agreement, money market fund, 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 Energyprovides 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 asOGE Energyspecifies 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 to expense the 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 andOGE Energycovers 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 Energyprovides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to OGE Energy's sponsored health 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.
Plan Investments
The following tables summarize OG&E's portion of OGE Energy's postretirement benefit plans investments that are measured at fair value on a recurring basis at December 31, 20132016 and 20122015. There were no Level 2 investments held by the postretirement benefit plans at December 31, 20132016 and 20122015.
| | | (In millions) | December 31, 2013 | Level 1 | Level 3 | December 31, 2016 | Level 1 | Level 3 |
| Group retiree medical insurance contract (A) | $ | 53.1 |
| $ | — |
| $ | 53.1 |
| $ | 44.7 |
| $ | — |
| $ | 44.7 |
|
| Mutual funds investment | | |
| U.S. equity investments | 7.9 |
| 7.9 |
| — |
| 8.1 |
| 8.1 |
| — |
|
| Money market funds investment | 0.4 |
| 0.4 |
| — |
| |
| Cash | | 0.3 |
| 0.3 |
| — |
|
| Total Plan investments | $ | 61.4 |
| $ | 8.3 |
| $ | 53.1 |
| $ | 53.1 |
| $ | 8.4 |
| $ | 44.7 |
|
| Plan investments attributable to affiliates | (4.7 | ) | | (5.3 | ) | |
| Total Plan assets | $ | 56.7 |
|
|
|
|
| $ | 47.8 |
|
|
|
|
|
| | | (In millions) | December 31, 2012 | Level 1 | Level 3 | December 31, 2015 | Level 1 | Level 3 |
| Group retiree medical insurance contract (A) | $ | 53.3 |
| $ | — |
| $ | 53.3 |
| $ | 46.8 |
| $ | — |
| $ | 46.8 |
|
| Mutual funds investment | | |
| U.S. equity investments | 6.0 |
| 6.0 |
| — |
| 7.8 |
| 7.8 |
| — |
|
| Money market funds investment | 0.3 |
| 0.3 |
| — |
| 0.7 |
| 0.7 |
| — |
|
| Total Plan investments | $ | 59.6 |
| $ | 6.3 |
| $ | 53.3 |
| $ | 55.3 |
| $ | 8.5 |
| $ | 46.8 |
|
| Plan investments attributable to affiliates | (4.1 | ) | | (5.3 | ) | |
| Total Plan assets | $ | 55.5 |
|
|
|
|
| $ | 50.0 |
|
|
|
|
|
| |
| (A) | This category represents a 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 plans pro-rata share of the total assets in the contract.
The following table summarizes the postretirement benefit plans investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
| | Year ended December 31 (In millions) | 2013 | 2016 |
| Group retiree medical insurance contract | | |
| Beginning balance | $ | 53.3 |
| $ | 46.8 |
|
| Net unrealized gains related to instruments held at the reporting date | (0.5 | ) | |
| Interest income | 1.1 |
| 0.9 |
|
| Dividend income | 0.6 |
| 0.6 |
|
| Realized gains | 0.4 |
| |
| Administrative expenses and charges | (0.1 | ) | |
| Net unrealized gains related to instruments held at the reporting date | | 0.2 |
|
| Realized losses | | (0.1 | ) |
| Claims paid | (1.7 | ) | (3.7 | ) |
| Ending balance | $ | 53.1 |
| $ | 44.7 |
|
The following table presents the status ofOG&E's portion of OGE Energy'spostretirement benefit plans atDecember 31, 2013and2012. These amounts have been recorded in Accrued Benefit Obligations with the offsetrecorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1. Theregulatory assetrepresents a net periodic benefit cost to be recognized in theStatements of Income in future periods.
|
| | | | | | |
December 31 (In millions) | 2013 | 2012 |
| Benefit obligations | $ | (202.4 | ) | $ | (236.4 | ) |
| Fair value of plan assets | 56.7 |
| 55.5 |
|
| Funded status at end of year | $ | (145.7 | ) | $ | (180.9 | ) |
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 be8.35 percentin2014with the rates trending downward to4.48 percentby2028. 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) | 2013 | 2012 | 2011 |
| Effect on aggregate of the service and interest cost components | $ | — |
| $ | — |
| $ | — |
|
| Effect on accumulated postretirement benefit obligations | 0.1 |
| 0.1 |
| 0.1 |
|
|
| | | | | | | | | |
| ONE-PERCENTAGE POINT DECREASE |
Year ended December 31 (In millions) | 2013 | 2012 | 2011 |
| Effect on aggregate of the service and interest cost components | $ | — |
| $ | 0.1 |
| $ | 0.1 |
|
| Effect on accumulated postretirement benefit obligations | 0.4 |
| 0.7 |
| 0.4 |
|
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 |
| 2014 | $ | 13.1 |
|
| 2015 | 13.5 |
|
| 2016 | 13.8 |
|
| 2017 | 14.0 |
|
| 2018 | 14.3 |
|
| After 2018 | 71.6 |
|
|
| | | |
(In millions) | Gross Projected
Postretirement
Benefit
Payments |
| 2017 | $ | 11.4 |
|
| 2018 | 11.4 |
|
| 2019 | 11.3 |
|
| 2020 | 11.3 |
|
| 2021 | 11.2 |
|
| After 2021 | 53.8 |
|
Obligations and Funded Status
The following table presents the status ofOG&E's portion of OGE Energy'sPension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for2013and2012. OG&E's portion ofsummarizes the benefit obligation forpayments OG&E expects to pay related to OGE Energy'sPension 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 forOGE Energy'sPension Plan and Restoration of Retirement Income Plan differs fromPlan. These expected benefits are based on the projectedsame assumptions used to measure OGE Energy's benefit obligation in thatat 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 atDecember 31, 2013was$483.0 millionand$1.9 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan atDecember 31, 2012was$549.3 millionand$2.1 million, respectively. The detailsend of the funded status of the Pension Plan, the Restoration of Retirement Income Planyear and the postretirement benefit plans and the amounts included in theBalance Sheets are as follows:
include benefits attributable to estimated future employee service.
|
| | | | | | | | | | | | | | | | | | |
| | Pension Plan | Restoration of Retirement
Income Plan | Postretirement
Benefit Plans |
December 31 (In millions) | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Change in Benefit Obligation | | | | | | |
| Beginning obligations | $ | (574.6 | ) | $ | (546.9 | ) | $ | (2.2 | ) | $ | (2.2 | ) | $ | (236.4 | ) | $ | (223.1 | ) |
| Service cost | (11.6 | ) | (10.9 | ) | (0.1 | ) | (0.1 | ) | (2.9 | ) | (2.7 | ) |
| Interest cost | (20.4 | ) | (23.5 | ) | (0.1 | ) | (0.1 | ) | (8.1 | ) | (9.4 | ) |
| Participants' contributions | 49.9 |
| — |
| — |
| — |
| (2.5 | ) | (2.5 | ) |
| Medicare subsidies received | — |
| — |
| — |
| — |
| — |
| (0.5 | ) |
| Actuarial gains (losses) | 39.8 |
| (43.7 | ) | 0.2 |
| (0.4 | ) | 35.4 |
| (9.4 | ) |
| Benefits paid | 13.3 |
| 50.4 |
| 0.1 |
| 0.6 |
| 12.1 |
| 11.2 |
|
| Ending obligations | $ | (503.6 | ) | $ | (574.6 | ) | $ | (2.1 | ) | $ | (2.2 | ) | $ | (202.4 | ) | $ | (236.4 | ) |
| | | | | | | |
| Change in Plans' Assets | | | | | | |
| Beginning fair value | $ | 519.0 |
| $ | 485.9 |
| $ | — |
| $ | — |
| $ | 55.5 |
| $ | 57.2 |
|
| Actual return on plans' assets | 60.7 |
| 50.5 |
| — |
| — |
| 3.4 |
| 4.3 |
|
| Employer contributions | — |
| 33.0 |
| 0.1 |
| 0.6 |
| 7.4 |
| 2.2 |
|
| Participants' contributions | (49.9 | ) | — |
| — |
| — |
| 2.5 |
| 2.5 |
|
| Medicare subsidies received | — |
| — |
| — |
| — |
| — |
| 0.5 |
|
| Benefits paid | (13.3 | ) | (50.4 | ) | (0.1 | ) | (0.6 | ) | (12.1 | ) | (11.2 | ) |
| Ending fair value | $ | 516.5 |
| $ | 519.0 |
| $ | — |
| $ | — |
| $ | 56.7 |
| $ | 55.5 |
|
| Funded status at end of year | $ | 12.9 |
| $ | (55.6 | ) | $ | (2.1 | ) | $ | (2.2 | ) | $ | (145.7 | ) | $ | (180.9 | ) |
Net Periodic Benefit Cost
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Plan | Restoration of Retirement
Income Plan | Postretirement Benefit Plans |
Year ended December 31 (In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 |
| Service cost | $ | 11.6 |
| $ | 10.9 |
| $ | 10.8 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 2.9 |
| $ | 2.7 |
| $ | 2.4 |
|
| Interest cost | 20.4 |
| 23.5 |
| 26.2 |
| 0.1 |
| 0.1 |
| 0.1 |
| 8.1 |
| 9.4 |
| 10.0 |
|
| Expected return on plan assets | (38.9 | ) | (38.2 | ) | (37.3 | ) | — |
| — |
| — |
| (2.4 | ) | (2.8 | ) | (4.9 | ) |
| Amortization of transition obligation | — |
| — |
| — |
| — |
| — |
| — |
| — |
| 2.5 |
| 2.6 |
|
| Amortization of net loss | 20.7 |
| 19.3 |
| 15.6 |
| — |
| 0.1 |
| 0.1 |
| 18.2 |
| 17.4 |
| 15.5 |
|
| Amortization of unrecognized prior service cost (A) | 1.9 |
| 2.2 |
| 2.5 |
| 0.1 |
| 0.2 |
| 0.2 |
| (13.7 | ) | (13.6 | ) | (13.7 | ) |
| Settlement | 17.6 |
| — |
| — |
| — |
| 0.3 |
| — |
| — |
| — |
| — |
|
| Net periodic benefit cost (B) | $ | 33.3 |
| $ | 17.7 |
| $ | 17.8 |
| $ | 0.3 |
| $ | 0.8 |
| $ | 0.5 |
| $ | 13.1 |
| $ | 15.6 |
| $ | 11.9 |
|
| |
(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$46.7 million, $34.1 millionand$30.2 millionof net periodic benefit cost recognized in2013, 2012and2011, respectively, OG&E recognized the following:
|
an increase in pension expense in2013, 2012 and 2011 of $5.8 million, $8.3 millionand$10.8 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); and
an increase in postretirement medical expense in2013and2012of$0.6 millionand$0.8 millionrespectively, 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);
a deferral of pension expense in 2013 of $17.0 million which includes a portion of OGE Energy's pension settlement charge, related to the pension settlement charge of $17.6 million which is included in the Pension tracker regulatory account (see Note 1). |
| | | |
(In millions) | Projected Benefit Payments |
| 2017 | $ | 35.3 |
|
| 2018 | 37.0 |
|
| 2019 | 40.3 |
|
| 2020 | 42.3 |
|
| 2021 | 42.7 |
|
| After 2021 | 210.0 |
|
The capitalized portion of the net periodic pension benefit cost was$4.2 million, $5.5 millionand$5.3 millionatDecember 31, 2013, 2012and2011, respectively. The capitalized portion of the net periodic postretirement benefit cost was$3.4 million, $4.7 millionand$3.3 millionatDecember 31, 2013, 2012and2011, respectively.
Rate Assumptions
|
| | | | | | | | | | | | |
| | Pension Plan and
Restoration of Retirement Income Plan | Postretirement
Benefit Plans |
| Year ended December 31 | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 |
| Discount rate | 4.60 | % | 3.70 | % | 4.50 | % | 4.60 | % | 3.60 | % | 4.50 | % |
| Rate of return on plans' assets | 8.00 | % | 8.00 | % | 8.00 | % | 4.00 | % | 4.00 | % | 6.50 | % |
| Compensation increases | 4.20 | % | 4.20 | % | 4.40 | % | N/A |
| N/A |
| N/A |
|
| Assumed health care cost trend: | |
| |
| |
| |
| |
| |
|
| Initial trend | N/A |
| N/A |
| N/A |
| 8.35 | % | 8.55 | % | 8.75 | % |
| Ultimate trend rate | N/A |
| N/A |
| N/A |
| 4.48 | % | 4.48 | % | 4.48 | % |
| Ultimate trend year | N/A |
| N/A |
| N/A |
| 2028 |
| 2028 |
| 2028 |
|
N/A - not applicable
The overall expected rate of return on plan assets assumption remained at8.00 percentin2012and2013in determining net periodic benefit cost due to recent returns onOGE Energy'slong-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.
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 $1.42.1 million and $2.21.1 million at December 31, 20132016 and 20122015, respectively.
401(k) Plan
OGE Energyprovides a 401(k) Plan. Each regular full-time employee ofOGE Energyor a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees ofOGE Energyor 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 attained 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; or (ii) a contribution made on ana non 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 her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, 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.
NoOGE Energycontributions 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 Energymatch contributions vest over a three-year period. After two years of service, participants become 20 percent vested in theirOGE Energycontribution 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, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed byOGE Energyor its affiliates. OG&E contributed $7.88.8 million, $7.68.2 million and $7.08.2 million in 20132016, 20122015 and 20112014, respectively, to the 401(k) Plan.
Deferred Compensation Plan
OGE Energyprovides 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 ofOGE Energyand 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 Energymatches 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 firstfive percentof total compensation, depending on the option theprior participant elected under the choice provided to eligible employees in the qualified 401(k) Plan discussed above,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 ofOGE Energyor termination of the plan. Deferrals, plus anyOGE Energymatch, 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 20132016, those investment options includedan OGE EnergyCommon Stock fund, whose value was determined based on the stock price ofOGE Energy'sCommon Stock.
Supplemental Executive Retirement Plan
OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee ofOGE Energy'sBoard of Directors who may not otherwise qualify for a sufficient level of benefits underOGE Energy'sPension Plan and Restoration of Retirement Income Plan.The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code.
| |
| 12. | 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) | 2014 | 2015 | 2016 | 2017 | 2018 | After 2018 | Total | 2017 | 2018 | 2019 | 2020 | 2021 | After 2021 | Total |
| Operating lease obligations | | | | | | | | | | | | | | |
| Railcars | $ | 3.8 |
| $ | 3.1 |
| $ | 27.3 |
| $ | — |
| $ | — |
| $ | — |
| $ | 34.2 |
| $ | 2.7 |
| $ | 1.7 |
| $ | 21.0 |
| $ | — |
| $ | — |
| $ | — |
| $ | 25.4 |
|
| Wind farm land leases | 2.1 |
| 2.1 |
| 2.1 |
| 2.4 |
| 2.4 |
| 48.8 |
| 59.9 |
| 2.5 |
| 2.5 |
| 2.5 |
| 2.9 |
| 2.9 |
| 43.5 |
| 56.8 |
|
| Total operating lease obligations | $ | 5.9 |
| $ | 5.2 |
| $ | 29.4 |
| $ | 2.4 |
| $ | 2.4 |
| $ | 48.8 |
| $ | 94.1 |
| $ | 5.2 |
| $ | 4.2 |
| $ | 23.5 |
| $ | 2.9 |
| $ | 2.9 |
| $ | 43.5 |
| $ | 82.2 |
|
Payments for operating lease obligations were$5.7 $8.5 million,, $5.8 $6.9 millionand$4.2 $5.9 millionfor the years endedDecember 31, 2013, 20122016, 2015 and2011, 2014, respectively.
Railcar Lease Agreement
OG&E has a noncancellable operating lease with a purchase options,option, covering 1,389 coalapproximately 1,250 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expensefuel expense and are recovered through OG&E's tariffs and fuel adjustment clauses.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed.
On October 14, 2014, OG&E signed a separate three-year lease effective December 2014 for 131 railcars to replace railcars that have been taken out of service or destroyed.
On December 15, 2010,17, 2015, OG&E renewed the lease agreement effective February 1, 2011.2016. At the end of the new lease term, which is February 1, 2016,2019, 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$22.8 million. $18.3 million. OG&E is also required to maintain all of the railcars it has under the operating lease and has entered into an agreement with a non-affiliated company to furnish this maintenance.lease.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed. OG&E has a unilateral right to terminate this lease upon a 6-month notice effective April 2015 and April 2016.
Wind Farm Land Lease Agreements
OG&E has wind farm land 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 economicuseful 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) | 2014 | 2015 | 2016 | 2017 | 2018 | Total | 2017 | 2018 | 2019 | 2020 | 2021 | Total |
| Other purchase obligations and commitments | | |
| Cogeneration capacity and fixed operation and maintenance payments | $ | 85.1 |
| $ | 82.7 |
| $ | 81.9 |
| $ | 79.6 |
| $ | 77.0 |
| $ | 406.3 |
| $ | 77.1 |
| $ | 73.9 |
| $ | 66.5 |
| $ | 54.7 |
| $ | 51.0 |
| $ | 323.2 |
|
| Expected cogeneration energy payments | 61.1 |
| 60.9 |
| 75.7 |
| 81.5 |
| 87.4 |
| 366.6 |
| 37.7 |
| 37.5 |
| 38.9 |
| 40.7 |
| 44.4 |
| 199.2 |
|
| Minimum fuel purchase commitments | 451.8 |
| 451.8 |
| 368.5 |
| 385.1 |
| — |
| 1,657.2 |
| 236.2 |
| 49.3 |
| 36.2 |
| 24.6 |
| 24.6 |
| 370.9 |
|
| Expected wind purchase commitments | 58.0 |
| 58.9 |
| 59.8 |
| 60.8 |
| 59.5 |
| 297.0 |
| 59.0 |
| 57.9 |
| 56.6 |
| 57.1 |
| 57.5 |
| 288.1 |
|
| Long-term service agreement commitments | 70.5 |
| 2.8 |
| 2.5 |
| 2.6 |
| 19.1 |
| 97.5 |
| 2.2 |
| 28.4 |
| 22.2 |
| 2.4 |
| 2.4 |
| 57.6 |
|
| Mustang Modernization expenditures | | 130.4 |
| 21.9 |
| — |
| — |
| — |
| 152.3 |
|
| Environmental compliance plan expenditures | | 169.2 |
| 63.0 |
| 8.9 |
| 0.2 |
| — |
| 241.3 |
|
| Total other purchase obligations and commitments | $ | 726.5 |
| $ | 657.1 |
| $ | 588.4 |
| $ | 609.6 |
| $ | 243.0 |
| $ | 2,824.6 |
| $ | 711.8 |
| $ | 331.9 |
| $ | 229.3 |
| $ | 179.7 |
| $ | 179.9 |
| $ | 1,632.6 |
|
Public Utility Regulatory Policy Act of 1978
At December 31, 20132016, OG&E has a QF contracts having terms ofcontract with Oklahoma Cogeneration LLC which expires on August 31, 2019 and a QF contract with AES-Shady Point, Inc. which expires on January 15,to32years. 2023. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978. Stated generally, the Public Utility Regulatory Policy Act of 1978 and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a QF. The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E; 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 MWMWs AES-Shady Point, Inc. QF contract and the 120 MW PowerSmithMWs Oklahoma Cogeneration Project, L.P.LLC QF contract, OG&E purchases 100 percent of the electricity generated by the QFs.
For the years ended December 31, 20132016, 20122015 and 20112014, OG&E made total payments to cogenerators of $134.8124.8 million, $135.1124.0 million and $140.7129.4 million, respectively, of which $74.466.3 million, $77.169.5 million and $78.072.3 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 purchased necessary fuel supplies of coal and natural gas for its generating units of $680.8 million, $653.7 million and $729.8 million for the years endedDecember 31, 2013, 2012and2011, respectively.OG&E has coal contracts for purchases from through December 2016.2017. As a participant in the SPP Integrated Marketplace, OG&E now purchases a relatively small percentage of its natural gas supply through long-term agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has entered into multiple month termthe right but not the obligation to purchase a defined quantity of natural gas, contracts for 31.5 percentcombined with day and intra-day purchases to meet the demands of its 2014 annual forecasted natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2014 natural gas requirements will be acquired through additional requests for proposal in early to mid-2014, along with monthly and daily purchases, all of which are expected to be made at market prices.
the SPP Integrated Marketplace.
Wind Purchase Commitments
OG&E's current wind power portfolio includes: (i)includes the following, in addition to the 120MW Centennial, wind farm, (ii) the101MW OU Spirit wind farm, (iii) the227.5and 228 MW Crossroads wind farm, (iv)farms owned by OG&E:(i) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (v)(ii) access to up to 150152 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, (vi)(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 20302031 and (vii)(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 following table summarizes OG&E's wind power purchases for the years ended December 31, 20132016, 20122015 and 20112014.
| | Year ended December 31 (In millions) | 2013 | 2012 | 2011 | 2016 | 2015 | 2014 |
| CPV Keenan | $ | 30.9 |
| $ | 25.1 |
| $ | 24.5 |
| $ | 29.2 |
| $ | 26.7 |
| $ | 28.1 |
|
| Edison Mission Energy | 20.6 |
| 20.2 |
| 8.5 |
| 21.1 |
| 19.7 |
| 21.3 |
|
| FPL Energy | 3.3 |
| 3.4 |
| 3.7 |
| 3.4 |
| 3.2 |
| 3.6 |
|
| NextEra Energy | 7.2 |
| 0.8 |
| — |
| 7.3 |
| 7.0 |
| 7.8 |
|
| Total wind power purchased | $ | 62.0 |
| $ | 49.5 |
| $ | 36.7 |
| $ | 61.0 |
| $ | 56.6 |
| $ | 60.8 |
|
Long-Term Service Agreement Commitments
OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. The existing contract will expire on January 1, 2015. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 3,6004,800 factored-fired starts. On December 30, 2015, the McClain LTSA 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. 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 2031.2028. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.
Wind Energy Purchased Power Lawsuit
In 2009, OG&E entered into a wind energy purchase power agreement with CPV Keenan for the purchase of all the energy output from its 150 MW wind farm in Woodward County, Oklahoma. In August of 2013, CPV Keenan filed suit against OG&E for the non-payment of curtailment charges. In December 2013, OG&E settled its current case with CPV Keenan and recorded additional purchased power expense of $4.3 million, which will be recovered through the fuel adjustment clause.
Enable Gas Transportation and Storage Agreement
OG&E contracts with Enable for firm non-notice load following gas transportation and storage services.services, under a five year contract. The stated term of this contract expiredwill expire in April 30, 2009, but remained in effect from year-to-year thereafter. On January 31, 2014, in anticipation of entering into a new, five-year contract,2019. In 2016, OG&E provided written notice of termination of theentered into an additional gas transportation services contract effective April 30, 2014. Negotiations regarding the new contract are ongoing, and there can be no assurance that the new contractwith Enable which will be agreedeffective upon or if agreed upon, that the termsconversion of the new contract will be as favorableunits 4 and 5 at Muskogee from coal to us as the expiring contract.gas.
Environmental Laws and Regulations
The activities of OG&E are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection relating to air quality, water quality, waste management, wildlife conservation and natural resources.protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways such as restrictingincluding the way it can handlehandling or disposedisposal of its wastes, requiring remedial actionwaste material, future construction activities to avoid or mitigate environmental issues that may be caused by its operationsharm to threatened or that are attributable to former operators, requiring changes in operationsendangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.
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 its financial position or results of operations. OG&E believes, however, that it is reasonably 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.
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of OG&E's environmental matters.
Air Quality Control System
Federal Clean Air Act New Source Review Litigation
As previously reported, in July 2008,On September 10, 2014, OG&E receivedexecuted a requestcontract for information from the EPAdesign, 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 Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permitsECP can be found under the Federal "Pending Regulatory Matters" in Note 13.
Clean Air Act's new source review process. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that OG&E's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards.
In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club has intervened in this proceeding and has asserted claims for declaratory relief that are similar to those requested by the United States. OG&E expects to vigorously defend against these claims, but OG&E cannot predict the outcome of such litigation. On August 12, 2013, the Sierra Club filed a complaint against OG&E in the United States District Court for the Eastern District of Oklahoma (Case No. 13-CV-00356) alleging that OG&E modifications made at Unit 6 of the Muskogee generating plant in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant has exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act.Power Plan
If OG&E does not prevail in these proceedings and if a new assessment of the projects were to conclude that they caused a significant emissions increase,On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO2 emissions from existing fossil-fuel-fired power plants along with state-specific CO2 reduction standards expressed as both rate-based (lbs/MWh) and the Sierra Club could seekmass-based (tons/yr) goals. The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed 43 percent reduction to require OG&E to install additional pollution control equipment, including scrubbers, baghouses and selective catalytic reduction systems with capital costs in excess of $1.0 billion and pay fines and significant penalties as a result of the allegations32 percent in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) providesfinal rule. The mass-based approach for civil penalties as much as $37,500 per dayexisting units calls for each violation. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs.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, the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan pending resolution of challenges to the rule. OG&E is unable to determine what impact the lawsuits will ultimately have on the Clean Power Plan or what impact the stay in implementation will have; however, if the Clean Power Plan survives judicial review and is implemented as written, it 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.
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 appropriate 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 currentlycurrent available information, except as otherwise stated above, in Note 13 below, in Item 3 of Part I and under "Environmental Laws and Regulations" in Item 7 of Part II of this Form 10-K, 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. | 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 20132016, 8586 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and sevensix percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
Crossroads Wind Farm
As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 megawatts. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On April 15, 2013, the APSC issued an order authorizing OG&E to recover the Arkansas portion of the cost to construct the Crossroads wind farm, effective retroactively to August 1, 2012. The costs are being recovered through the Energy Cost Recovery Rider.
Fuel Adjustment Clause Review for Calendar Year 2011
The OCC routinely reviews the costs recovered from customers through OG&E’s fuel adjustment clause. On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. OG&E filed information and documents in response to the OCC's application on October 1, 2012. On December 19, 2012, witnesses for the OCC Staff filed responsive testimony recommending that the OCC approve OG&E's fuel adjustment clause costs and recoveries for the calendar year 2011 and recommending that the OCC find that OG&E's electric generation, purchased power, fuel procurement and other fuel related practices, policies and decisions during calendar year 2011 were fair, just and reasonable and prudent. On April 9, 2013, the OCC administrative law judge recommended that the OCC find that for the calendar year 2011 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. On June 18, 2013, the OCC issued an order approving the administrative law judge’s recommendation.
Pending 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 in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 leaves torequires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffstariff and agreementsagreement 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 and Order No. 1000 does notor 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 currently hasSPP'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 variousprevious transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which were filed on November 13, 2012. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a right"right of first refusalrefusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts300kV that interconnect to those incumbent entities'owners' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000.
On July 18, 2013,The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP's Order No. 1000 compliance filing. This order accepted in part and rejected in partSPP filings that required the SPP's plan for complying with Order No. 1000. The FERC rejected the SPP's planSPP to retain the rightremove certain "right of first refusal for projects that would operate between 100 kilovoltsrefusal" language from the SPP Tariff and 300 kilovolts. However, the FERC clarified that a right of first refusal was appropriateSPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in certain circumstances. It is not clear howthe Court challenging the FERC's order will relate torequiring the recently enacted Oklahoma law addressing a rightremoval of the "right of first refusalrefusal" 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 lower voltages. On November 15, 2013,incumbent transmission providers from the SPP made itsMembership Agreement. The Court determined that the FERC compliance filing, as required byhad reasonably found the July 18, 2013 order. The"right of first refusal" in the SPP changes to its tariff and Membership Agreement included provisions that (i) clarify that facilities between 100 kilovolts and 300 kilovolts would be subject to the competitive selection process, (ii) only allow certain evidence, such as state laws (like House Bill 1932) and the holders of existing rights of way, to be considered during the competitive selection process and not earlier in the process; (iii) apply a right of first refusal to transmission projects needed for reliability within three years in certain situations; and (iv) revise the tariff’s competitive selection process, including changes to the criteria for identifying qualifying transmission owners, the requirements for submission of information by transmission owners seeking to participate in competitive selections, and the procedures that govern the competitive selection process.anticompetitive.
OGE Energy cannot, at this time, determineOG&E does not believe the preciseCourt’s ruling will have any impact of Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E'sexisting transmission projects currently under development and construction for which OG&E has already received a notice to proceedconstruct 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 20122014
On July 31, 2013,28, 2015, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012,2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filedOn May 26, 2016, the necessary informationOCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and documents needed to satisfy the OCC's minimum filing requirement rules on October 9, 2013. A hearing on this matter is scheduled for April 24, 2014.fuel procurement processes and costs were prudent.
Oklahoma Demand Program Rider Review - SmartHours Program
Request for ModificationIn July 2012, OG&E filed an application with the OCC to Previous Ordersrecover 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 2,9, 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 OCCAPSC seeking authority to make minor modificationsconstruct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to three previous OCC orders. The purposeseek approval from the APSC to construct a power-
generating facility located outside the boundaries of the state of Arkansas. The application was to addressdid not seek any cost recovery for the timing of certain requirements contained in those orders. OG&E's application proposed to address these issues in OG&E's next general rate case thus avoiding the cost associated with a rate case filing now and benefiting customers by deferring the recovery of certain costs identifiedcapital expenditures in the previous orders. On September 3, 2013, the PUD Staffapplication, 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 application. PUD Staff requestedfinancial results are dependent in part on timely and adequate decisions by the regulatory agencies that the OCC dismissset OG&E's application and issue an order requiring OG&E to file a rate case for the 2012 test year.rates.
Environmental Compliance Plan
On September 11, 2013, the PUD Staff withdrew their motion to dismiss OG&E's application and on September 12, 2013, filed an application requesting a public hearing, review and possible adjustment of the rates and charges of OG&E based on the 2012 test year. To date, no procedural schedule has been established for either the OG&E application or the PUD Staff application.
Energy Efficiency Program Filing
On October 9, 2013August 6, 2014, OG&E filed an application with the APSC requestingOCC for approval of interim modificationsits plan to approved Energy Efficiency Programs, new tariff revisionscomply 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 waiverconversion of certain provisionsMuskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of the Commission’s Rulesits Mustang Modernization Plan, which calls for Conservation and Energy Efficiency Programs.
Market-Based Rate Authority
On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order acceptingreplacing OG&E's June 2012 triennial market power update.
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 30, 2013,2, 2015, OG&E submitted to the FERC a market-based rate change in status filing and a revised market-based rate tariff. The revised tariff will authorize OG&E to (i) sell electric energy and capacity at market-based rates without geographic restriction, and (ii) sell ancillary services in the SPP and Midcontinent Independent System Operator, Inc. markets. The primary goal of this filing was to implement the market-based rate authority OG&E needs to fully participate in SPP’s Integrated Marketplace. OG&E requested that FERC issuereceived an order on or before February 28, 2014 that acceptsfrom 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 market-based rate tariff to be effective ondepreciation rates for both the date SPP’s Integrated Marketplace goes into operation, which is expected to be March 1, 2014.
Section 206 Complaintretirement 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 November 26, 2013,February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. On April 28, 2016, the OCC approved the Dry Scrubber project.
Two parties appealed the OCC's decision to the Oklahoma Supreme Court. OG&Eis unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.
OG&E anticipates the total cost of Dry Scrubbers will be $547.5 million, including allowance for funds used during construction and capitalized ad valorem taxes. As of December 31, 2016, OG&E had invested $208.7 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $424.9 million and expects the project to be completed in late 2017. As of December 31, 2016, OG&E had invested $187.8 million on the Mustang Modernization Plan.
Integrated Resource Plans
In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Arkansas Electric Cooperative Corporationby October 1, 2017 and in Oklahoma by October 1, 2018.
Oklahoma Rate Case Filing
On December 18, 2015, OG&E filed a complaint atgeneral rate case with the FERC againstOCC 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 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 arguingimplemented 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 wholesale formula rate contract betweenALJ 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 and is unable to predict what action the OCC will take, or the timing of such action.
Arkansas Electric Cooperative Corporation (formerly betweenRate 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 Valley Electric Cooperative)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 unjustscheduled 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 unreasonable with respect to several items. After engagingfuel procurement costs. A hearing in settlement discussions, OG&E and Arkansas Electric Cooperative Corporation have tentatively agreed to terms of a settlement and are jointly preparing an offer of settlement to be filed with FERC. OG&E believes the reduction in revenuethis Cause will be less than $1.0 million per year.held on March 30, 2017.
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| 14. | 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 | | March 31 | June 30 | September 30 | December 31 | Total |
| Operating revenues | 2013 | $ | 455.5 |
| $ | 574.6 |
| $ | 723.2 |
| $ | 508.9 |
| $ | 2,262.2 |
| 2016 | $ | 433.1 |
| $ | 551.4 |
| $ | 743.9 |
| $ | 530.8 |
| $ | 2,259.2 |
|
| | 2012 | $ | 426.7 |
| $ | 528.0 |
| $ | 721.0 |
| $ | 465.5 |
| $ | 2,141.2 |
| 2015 | $ | 480.1 |
| $ | 549.9 |
| $ | 719.8 |
| $ | 447.1 |
| $ | 2,196.9 |
|
| Operating income | 2013 | $ | 52.9 |
| $ | 138.1 |
| $ | 261.0 |
| $ | 73.3 |
| $ | 525.3 |
| 2016 | $ | 38.6 |
| $ | 131.4 |
| $ | 257.2 |
| $ | 81.7 |
| $ | 508.9 |
|
| | 2012 | $ | 39.8 |
| $ | 127.8 |
| $ | 258.0 |
| $ | 63.8 |
| $ | 489.4 |
| 2015 | $ | 57.3 |
| $ | 127.5 |
| $ | 255.7 |
| $ | 59.9 |
| $ | 500.4 |
|
| Net income | 2013 | $ | 13.0 |
| $ | 79.0 |
| $ | 171.5 |
| $ | 29.1 |
| $ | 292.6 |
| 2016 | $ | 6.1 |
| $ | 72.3 |
| $ | 159.9 |
| $ | 45.8 |
| $ | 284.1 |
|
| | 2012 | $ | 12.1 |
| $ | 73.4 |
| $ | 167.2 |
| $ | 27.6 |
| $ | 280.3 |
| 2015 | $ | 17.1 |
| $ | 69.0 |
| $ | 162.9 |
| $ | 19.9 |
| $ | 268.9 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited the accompanying balance sheets and statements of capitalizationofOklahoma Gas and Electric Company (the Company) as of December 31, 20132016 and 20122015, 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, 20132016. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management.Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the 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 includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Oklahoma Gas and Electric Company at December 31, 20132016 and 20122015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20132016, 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),Oklahoma Gas and Electric Company'sinternal control over financial reporting as ofDecember 31, 2013, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992(2013 framework) and our report datedFebruary 25, 201422, 2017 expressed an unqualified opinion thereon.
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| | |
| | /s/ Ernst & Young LLP | |
| | Ernst & Young LLP
| |
Oklahoma City, Oklahoma
February 25, 201422, 2017
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, 20132016. 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 (1992)(2013). Based on our assessment, we believe that, as of December 31, 20132016,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.
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| | |
/s/ Peter B. DelaneySean Trauschke | | /s/ Scott Forbes |
Peter B. Delaney,Sean Trauschke, Chairman of the Board, President | | Scott Forbes, Controller |
| and Chief Executive Officer | | and Chief Accounting Officer |
| | | |
/s/ Sean TrauschkeStephen E. Merrill | | |
Sean Trauschke, PresidentStephen E. Merrill | | |
and Chief Financial Officer | | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 20132016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992(2013 framework) (the COSO criteria). Oklahoma Gas and Electric Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the 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 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.
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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 20132016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), thebalance sheets and statements of capitalization ofOklahoma Gas and Electric Companyas ofDecember 31, 20132016 and2012, 2015, and the relatedstatements of income, comprehensive income, cash flows and changes in stockholder's stockholder's equity for each of the three years in the period endedDecember 31, 20132016 ofOklahoma Gas and Electric Companyand our report datedFebruary 25, 201422, 2017 expressed an unqualified opinion thereon.
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| | |
| | /s/ Ernst & Young LLP | |
| | Ernst & Young LLP
| |
Oklahoma City, Oklahoma
February 25, 201422, 2017
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 web sitewebsite address www.oge.com under the heading "Investors," "Investor Relations",Relations," "Corporate 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 web sitewebsite 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 Accounting 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&E.
Fees for Principal Independent Accountants
| | | Year ended December 31 | 2013 | 2012 | 2016 | 2015 |
| Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting | $ | 1,063,300 |
| $ | 1,610,000 |
| $ | 1,185,800 |
| $ | 1,141,700 |
|
| Services in support of debt and stock offerings | 65,000 |
| 7,500 |
| — |
| — |
|
| Other (A) | 431,750 |
| 447,100 |
| 302,200 |
| 299,100 |
|
| Total audit fees (B) | 1,560,050 |
| 2,064,600 |
| 1,488,000 |
| 1,440,800 |
|
| Employee benefit plan audits | 124,000 |
| 120,000 |
| 138,000 |
| 133,000 |
|
| Other (C) | 142,224 |
| 130,665 |
| |
| Total audit-related fees | 266,224 |
| 250,665 |
| 138,000 |
| 133,000 |
|
| Assistance with examinations and other return issues | 351,670 |
| 175,215 |
| |
| Assistance with examinations and other return issues (C) | | 329,728 |
| 47,570 |
|
| Review of Federal and state tax returns | 30,000 |
| 27,500 |
| 35,000 |
| 33,500 |
|
| Total tax preparation and compliance fees | 381,670 |
| 202,715 |
| 364,728 |
| 81,070 |
|
| Total tax fees | 381,670 |
| 202,715 |
| 364,728 |
| 81,070 |
|
| Total fees | $ | 2,207,944 |
| $ | 2,517,980 |
| $ | 1,990,728 |
| $ | 1,654,870 |
|
| |
| (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. For20132016, this amount includes estimated billings for the completion of the20132016audit, which services were rendered after year-end. |
| |
| (C) | Includes the U.S. Department of Energy Smart Grid grant audits.
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 in 20132016 and 20122015 for other services.
Audit Committee Pre-Approval Procedures
Rules adopted by the Securities and Exchange Commission in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. OGE Energy's Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the principal independent accountants for additional services not contemplated in the original pre-approval. In those instances, OGE Energy will obtain the specific pre-approval of the Audit Committee before engaging the principal independent accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee's responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
For 20132016, 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, 2013, 20122016, 2015 and 20112014
Statements of Comprehensive Income for the years ended December 31, 2013, 20122016, 2015 and 20112014
Statements of Cash Flows for the years ended December 31, 2013, 20122016, 2015 and 20112014
Balance Sheets at December 31, 20132016 and 20122015
Statements of Capitalization at December 31, 20132016 and 20122015
Statements of Changes in Stockholder's Equity for the years ended December 31, 2013, 20122016, 2015 and 20112014
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)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 | Asset Purchase Agreement, dated as of August 18, 2003 by and between OG&E and NRG McClain LLC. (Certain exhibits and schedules were omitted and registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed August 20, 2003 (File No. 1-12579) and incorporated by reference herein). |
| 2.02 | Amendment No. 1 to Asset Purchase Agreement, dated as of October 22, 2003 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein). |
| 2.03 | Amendment No. 2 to Asset Purchase Agreement, dated as of October 27, 2003 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.04 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein). |
| 2.04 | Amendment No. 3 to Asset Purchase Agreement, dated as of November 25, 2003 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.05 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein). |
| 2.05 | Amendment No. 4 to Asset Purchase Agreement, dated as of January 28, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.06 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein). |
| 2.06 | Amendment No. 5 to Asset Purchase Agreement, dated as of February 13, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.07 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein). |
| 2.07 | Amendment No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein). |
| 2.08 | Amendment No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein). |
| 2.09 | Amendment No. 8 to Asset Purchase Agreement, dated as of May 15, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein). |
| 2.10 | Amendment No. 9 to Asset Purchase Agreement, dated as of June 2, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein). |
| 2.11 | Amendment No. 10 to Asset Purchase Agreement, dated as of June 17, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein). |
| 2.12 | Purchase and Sale Agreement, dated as of January 21, 2008, entered into by and among Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC and OG&E. (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein). |
| 2.13 | Asset Purchase Agreement, dated as of January 21, 2008, entered into by and among OG&E, the Oklahoma Municipal Power Authority and the Grand River Dam Authority. (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein). |
| 3.01 | Copy of Restated Oklahoma Gas and Electric Company Certificate of Incorporation. (Filed as Exhibit 3.01 to OG&E's Form 8-K filed May 19, 2011 (File No. 1-1097) and incorporated by reference herein) |
| 3.02 | Copy of Amended Oklahoma Gas and Electric Company By-laws dated May 19, 2011.November 30, 2015. (Filed as Exhibit 3.02 to OG&E'sOGE Energy's Form 8-K filed May 19, 2011November 30, 2015 (File No. 1-1097)1-12579) and incorporated by reference herein). |
| 4.01 | Trust Indenture dated October 1, 1995, from OG&E to Boatmen's First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to Registration Statement No. 33-61821 and incorporated by reference herein). |
| 4.02 | Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed July 17, 1997 (File No. 1-1097) and incorporated by reference herein). |
| 4.03 | Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed April 16, 1998 (File No. 1-1097) and incorporated by reference herein). |
|
| |
| 4.04 | Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to Registration Statement No. 333-104615 and incorporated by reference herein). |
| 4.05 | Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein). |
| 4.06 | Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to OG&E's Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein). |
| 4.07 | Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein). |
| 4.08 | Supplemental Indenture No. 9 dated as of September 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed September 9, 2008 (File No. 1-1097) and incorporated by reference herein). |
| 4.09 | Supplemental Indenture No. 10 dated as of December 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2008 (File No. 1-1097) and incorporated by reference herein). |
| 4.10 | Supplemental Indenture No. 11 dated as of June 1, 2010 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed June 8, 2010 (File No. 1-1097) and incorporated by reference herein). |
| 4.11 | Supplemental Indenture No. 12 dated as of May 15, 2011 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 27, 2011 (File No. 1-1097) and incorporated by reference herein). |
| 4.12 | Supplemental Indenture No. 13 dated as of May 1, 2013 between OG&E and UMB Bank, N.A., as trustee, creating the Senior Notes. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 13, 2013 (File No. 1-1097) and incorporated by reference herein). |
10.01*4.13 | OGE Energy's 1998 Stock Incentive Plan.Supplemental Indenture No. 14 dated as of March 15, 2014 between OG&E and UMB Bank, N.A., as trustee, creating the Senior Notes. (Filed as Exhibit 10.074.01 to OGE Energy'sOG&E's Form 10-K for the year ended December 31, 19988-K filed March 25, 2014 (File No. 1-12579)1-1097) and incorporated by reference herein). |
10.02*4.14 | OGE Energy's 2003 Stock Incentive Plan.Supplemental Indenture No. 15 dated as of December 1, 2014 between OG&E and UMB Bank, N.A., as trustee, creating the Senior Notes. (Filed as Annex AExhibit 4.01 to OGE Energy's Proxy Statement for the 2003 Annual Meeting of ShareownersOG&E's Form 8-K filed December 11, 2014 (File No. 1-12579)1-1097) and incorporated by reference herein). |
10.0310.01 | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed July 9, 2012 (File No. 1-12579) and incorporated by reference herein). |
10.0410.02 | Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein). |
10.0510.03 | Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein). |
10.0610.04 | Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein). |
10.07* | Amendment No. 1 to OGE Energy's 2003 Stock Incentive Plan. (Filed as Exhibit 10.23 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.08 | Intrastate Firm No-Notice, Load Following Transportation and Storage Services Agreement dated as of May 1, 2003 between OG&E and Enogex. [Confidential treatment has been requested for certain portions of this exhibit.] (Filed as Exhibit 10.24 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.10*10.05* | Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein). |
10.1110.06 | 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). |
10.12* | Amendment No. 1 to OGE Energy's 1998 Stock Incentive Plan. (Filed as Exhibit 10.26 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.13* | Amendment No. 2 to OGE Energy's 2003 Stock Incentive Plan. (Filed as Exhibit 10.27 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
|
| |
10.14*10.07* | OGE Energy Supplemental Executive Retirement Plan, as amended and restated. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein). |
10.15*10.08* | OGE Energy Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein). |
10.16* | OGE Energy Deferred Compensation Plan, as amended and restated. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.17* | Amendment No. 3 to OGE Energy's 2003 Stock Incentive Plan. (Filed as Exhibit 10.06 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.18* | Amendment No. 2 to OGE Energy's 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.19* | OGE Energy's 2008 Stock Incentive Plan. (Filed as Annex A to OGE Energy's Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.20* | OGE Energy's 2008 Annual Incentive Compensation Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.2110.09* | Form of Employment Agreement for all existing and future officers of OG&E relating to change of control. (Filed as Exhibit 10.28 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein). |
|
10.22* | |
| 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). |
10.2310.11 | Agreement, dated February 17, 2010, between OG&E and Oklahoma Department of Environmental Quality. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein). |
10.24*10.12* | Amendment No. 1 to OGE Energy's Restoration of Retirement Income Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein). |
10.25* | Amendment No. 1 to OGE Energy's Deferred Compensation Plan. (Filed as Exhibit 10.33 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.2610.13 | 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 OGE Energy's Form 8-K filed June 1, 2010 (File No. 1-12579) and incorporated by reference herein). |
10.2710.14 | 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 OGE Energy's Form 8-K filed July 1, 2010 (File No. 1-12579) and incorporated by reference herein). |
10.2810.15 | 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). |
10.2910.16 | 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). |
10.30* | Amendment No. 2 to OGE Energy's Deferred Compensation Plan. (Filed as Exhibit 10.41 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein) |
10.31* | Amendment No. 3 to OGE Energy's Deferred Compensation Plan. (Filed as Exhibit 10.39 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.32* | Amendment No. 1 to OGE Energy's 2008 Stock Incentive Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.33*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) |
10.34*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). |
10.35*10.19* | OGE Energy's 2013 Stock Incentive Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein). |
10.36*10.20* | OGE Energy's 2013 Annual Incentive Compensation Plan. (Filed as Annex C to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
| . |
| |
10.3710.21 | 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). |
10.38*10.21 | Amendment No. 4 toLetter 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 Company's Deferred Compensation PlanLenders 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 10.0110.02 to OGE Energy's Form 10-Q8-K filed November 6, 2013June 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* | Form of Performance Unit Agreement under OGE Energy's 2013 Stock Incentive Plan. (Filed as Exhibit 10.53 to OGE Energy's Form 10-K for the year ended December 31, 2016 (File No. 1-12579) and incorporated by reference herein). |
| 10.25* | 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* | OGE Energy's Deferred Compensation Plan (As amended and restated effective October 1, 2016). (Filed as Exhibit 10.37 to OGE Energy's Form 10-K for the year ended December 31, 2016 (File No. 1-12579) and incorporated by reference herein). |
| 12.01 | Calculation of Ratio of Earnings to Fixed Charges. |
| 23.01 | Consent of Ernst & Young LLP. |
| 24.01 | Power of Attorney. |
| 31.01 | Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
| |
| 32.01 | Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| 99.01 | Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995. |
99.02 | 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). |
99.0399.02 | 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). |
99.0499.03 | 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 | Copy of the Report of Administrative Law Judge dated June 8, 2015. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 12, 2015 (File No. 1-12579) and incorporated by reference herein). |
| 99.05 | Copy of OCC Order relating to OG&E's environmental compliance plan application (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed December 7, 2015 (File No. 1-12579) and incorporated by reference herein). |
| 99.06 | Copy of OG&E's Motion for Rehearing on its environmental compliance plan application (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed December 15, 2015 (File No. 1-12579) and incorporated by reference herein). |
| 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, 2011 | | |
| Balance at December 31, 2014 | | |
| Reserve for Uncollectible Accounts | $ | 1.6 |
| $ | 5.8 |
| $ | 3.7 |
| $ | 3.7 |
| $ | 1.9 |
| $ | 2.3 |
| $ | 2.6 |
| $ | 1.6 |
|
| Balance at December 31, 2012 | | |
| Balance at December 31, 2015 | | |
| Reserve for Uncollectible Accounts | $ | 3.7 |
| $ | 3.3 |
| $ | 4.4 |
| $ | 2.6 |
| $ | 1.6 |
| $ | 2.4 |
| $ | 2.6 |
| $ | 1.4 |
|
| Balance at December 31, 2013 | | |
| Balance at December 31, 2016 | | |
| Reserve for Uncollectible Accounts | $ | 2.6 |
| $ | 2.5 |
| $ | 3.2 |
| $ | 1.9 |
| $ | 1.4 |
| $ | 2.5 |
| $ | 2.4 |
| $ | 1.5 |
|
| |
| (A) | Uncollectible accounts receivable written off, net of recoveries. |
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 the25th day of February2014 22, 2017.
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| | OKLAHOMA GAS AND ELECTRIC COMPANY | |
| | (Registrant) | |
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| | By /s/ | Peter B. DelaneySean Trauschke | |
| | | Peter B. DelaneySean 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.
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| Signature | | Title | Date |
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/s/ Peter B. DelaneySean Trauschke | | | |
Peter B. DelaneySean Trauschke | | Principal Executive | |
| | | Officer and Director; | February 25, 201422, 2017 |
| | | | |
/s/ Sean TrauschkeStephen E. Merrill | | | |
Sean TrauschkeStephen E. Merrill | | Principal Financial Officer; and | February 25, 201422, 2017 |
| | | | |
| /s/ Scott Forbes | | | |
| Scott Forbes | | Principal Accounting Officer. | February 25, 201422, 2017 |
| | | | |
James H. BrandiFrank A. Bozich | | Director; | |
WayneJames H. BrunettiBrandi | | Director; | |
| Luke R. Corbett | | Director; | |
| John D. Groendyke | | Director; | |
Kirk HumphreysDavid L. Hauser | | Director; | |
Robert KelleyKirk Humphreys | | Director; | |
| Robert O. Lorenz | | Director; | |
| Judy R. McReynolds | | Director; | |
Leroy C. Richie | | Director. and | |
| Sheila G. Talton | | DirectorDirector; | |
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/s/ Peter B. DelaneySean Trauschke | | | |
By Peter B. DelaneySean Trauschke (attorney-in-fact) | | | February 25, 201422, 2017 |
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.