Edgar Filing: OGE ENERGY CORP.

2014 OGE 10-K

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, 2014

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: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)



Oklahoma		73-1481638
(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:



Title of each class	Name of each exchange on which registered
Common Stock	New York Stock Exchange

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.

þ Yes o 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 þ	Accelerated filer o
Non-accelerated filer o (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 30, 2014, 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 $7,749,203,331 based on the number of shares held by non-affiliates (198,290,771) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $39.08.

At January 30, 2015, there were 199,481,971 shares of common stock, par value $0.01 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for the Company's 2015 annual meeting of shareowners is incorporated by reference into Part III of this Form 10-K.

OGE ENERGY CORP.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2014

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1

Part I
Item 1. Business	2
The Company	2
Electric Operations - OG&E	3
Natural Gas Midstream Operations	11
Environmental Matters	13
Finance and Construction	14
Employees	16
Executive Officers	17
Access to Securities and Exchange Commission Filings	19
Item 1A. Risk Factors	19
Item 1B. Unresolved Staff Comments	40
Item 2. Properties	41
Item 3. Legal Proceedings	42
Item 4. Mine Safety Disclosures	42

Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	43
Item 6. Selected Financial Data	45
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	46
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	73
Item 8. Financial Statements and Supplementary Data	75
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	129
Item 9A. Controls and Procedures	129
Item 9B. Other Information	132

Part III
Item 10. Directors, Executive Officers and Corporate Governance	132
Item 11. Executive Compensation	132
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	132
Item 13. Certain Relationships and Related Transactions, and Director Independence	132
Item 14. Principal Accounting Fees and Services	132

Part IV
Item 15. Exhibits, Financial Statement Schedules	132
Signatures	139

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
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ASC	Financial Accounting Standards Board Accounting Standards Codification
BART	Best available retrofit technology
Bcf	Billion cubic feet
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned Subsidiary of CenterPoint Energy, Inc.
Code	Internal Revenue Code of 1986
Company	OGE Energy Corp, collectively with its subsidiaries and Enable Midstream Partners
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
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 Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex, LLC	Enogex, LLC collectively with its subsidiaries (effective June 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA	U.S. Environmental Protection Agency
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
MATS	Mercury and Air Toxics Standards
MMBtu	Million British thermal unit
MMcf/d	Million cubic feet per day
MW	Megawatt
MWH	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
Off-system sales	Sales to other utilities and power marketers
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy Corp
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy Corp, parent company of Enogex Holdings (prior to May 1, 2013) and 26.3 percent owner of Enable Midstream Partners
OSHA	Federal Occupational Safety and Health Act of 1970
Pension Plan	Qualified defined benefit retirement plan
QF	Qualified cogeneration facilities
QF contracts	Contracts with QFs and small power production producers
Regional Haze	The EPA's regional haze rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SESH	Southeast Supply Header, LLC
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
Stock Incentive Plan	2013 Stock Incentive Plan
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

FORWARD-LOOKING STATEMENTS

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


•	general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;


•	the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;


•	prices and availability of electricity, coal, natural gas and NGLs;


•	the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;


•	the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;


•	business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;


•	competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;


•	unusual weather;


•	availability and prices of raw materials for current and future construction projects;


•	Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets;


•	environmental laws and regulations that may impact the Company's operations;


•	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 attacks and other catastrophic events;


•	advances in technology;


•	creditworthiness of suppliers, customers and other contractual parties;


•	difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control; and


•	other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to this Form 10-K.

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

PART I

Item 1. Business.

THE COMPANY

Introduction

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20% and 50% and has the ability to exercise significant influence. The Company was incorporated in August 1995 in the state of Oklahoma and its principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone 405-553-3000.

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

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

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

On April 16, 2014, Enable completed an initial public offering of 25,000,000 common units resulting in Enable becoming a publicly traded Master Limited Partnership. The offering represented approximately 6.0 percent of the limited partner interests and raised approximately $464 million in net proceeds for Enable. In connection with the offering, underwriters exercised their option to purchase 3,750,000 additional common units which were fulfilled with units held by ArcLight. As a result of the offering, OGE Holding's ownership was reduced from 28.5 percent to 26.7 percent. In connection with Enable’s initial public offering, approximately 61.4 percent of OGE Holdings and CenterPoint’s common units were converted into subordinated units. As a result, following the initial public offering, OGE Holdings owned 42,832,291 common units and 68,150,514 subordinated units of Enable.

On May 13, 2014, CenterPoint exercised its put right with respect to a 24.95 percent interest in SESH and pursuant to that right, on May 30, 2014, Enable issued 6,322,457 common units representing limited partner interests in Enable in exchange for CenterPoint's 24.95 percent interest in SESH. At December 31, 2014, OGE Energy held 26.3 percent of the limited partner interests in Enable.

margins are affected by commodity price movements. Based on forward commodity prices, Enable expects to see a change in producer activity that will affect its future distribution growth rate. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. OGE Holdings is entitled to 60 percent of those “incentive distributions.”

Company Strategy

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

OG&E is focused on:


•	Providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.


•	Providing safe, reliable energy to the communities and customers we serve. A particular focus is on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments.


•	Maintaining strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members.


•	Continuing to grow a zero-injury culture and deliver top-quartile safety results.


•	Expanding transmission investments beyond traditional opportunities.


•	Executing on the Company’s Environmental Compliance Plan.


•	Ensuring we have the necessary mix of generation resources to meet the long term needs of our customers.


•	Continuing focus on operational excellence and efficiencies in order to protect the customer bill.

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders. The Company's financial objectives include a long-term annual earnings growth rate for OG&E of three to five percent on a weather-normalized basis, maintaining a strong credit rating as well as targeting dividend increases of approximately 10 percent annually through 2019. The targeted annual dividend increase has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets and the composition of the Company's assets and investment opportunities. The Company also relies on cash distributions from its investment in Enable to fund its capital needs and support future dividend growth. The cash distributions from Enable are expected to grow 3 percent to 7 percent in 2015 from the fourth quarter 2014 distribution. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

ELECTRIC OPERATIONS - OG&E

General

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. As of December 31, 2014, two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 267 communities that OG&E serves, 241 are located in Oklahoma and 26 in Arkansas. OG&E derived 90 percent of its total electric operating revenues in 2014 from sales in Oklahoma and the remainder from sales in Arkansas.

OG&E's system control area peak demand in 2014 was 6,339 MWs on August 25, 2014. OG&E's load responsibility peak demand was 5,813 MWs on August 25, 2014. As reflected in the table below and in the operating statistics that follow, there were 28.0 million MWH system sales in 2014, 28.2 million MWH system sales in 2013 and 28.0 million MWH system sales in 2012. Variations in system sales for the three years are reflected in the following table:



Year ended December 31	2014	2014 vs. 2013 Decrease	2013	2013 vs. 2012 Increase	2012
System sales - millions of MWHs	28.0	(0.7)%	28.2	0.7%	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. 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 newer 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	2014			2013			2012
ELECTRIC ENERGY (Millions of MWH)
Generation (exclusive of station use)	22.8			24.2			26.3
Purchased	8.8			6.3			5.0
Total generated and purchased	31.6			30.5			31.3
OG&E use, free service and losses	(1.4		)	(1.9		)	(1.9		)
Electric energy sold	30.2			28.6			29.4
ELECTRIC ENERGY SOLD (Millions of MWH)
Residential	9.4			9.4			9.1
Commercial	7.2			7.1			7.0
Industrial	3.8			3.9			4.0
Oilfield	3.4			3.4			3.3
Public authorities and street light	3.2			3.2			3.3
Sales for resale	1.0			1.2			1.3
System sales	28.0			28.2			28.0
Off-system sales	2.2			0.4			1.4
Total sales	30.2			28.6			29.4
ELECTRIC OPERATING REVENUES (In millions)
Residential	$	925.5		$	901.4		$	878.0
Commercial	583.3			554.2			523.5
Industrial	224.5			220.6			206.8
Oilfield	188.3			176.4			163.4
Public authorities and street light	220.3			214.3			202.4
Sales for resale	52.9			59.4			54.9
System sales revenues	2,194.8			2,126.3			2,029.0
Off-system sales revenues	94.1			14.7			36.5
Other	164.2			121.2			75.7
Total operating revenues	$	2,453.1		$	2,262.2		$	2,141.2
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential	697,048			690,390			683,214
Commercial	91,966			90,279			88,772
Industrial	2,901			2,921			2,957
Oilfield	6,460			6,431			6,426
Public authorities and street light	16,581			16,877			16,695
Sales for resale	26			42			46
Total	814,982			806,940			798,110
AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	1,334.05		$	1,312.59		$	1,292.11
Average annual use (kilowatt-hour)	13,540			13,718			13,477
Average price per kilowatt-hour (cents)	$	9.85		$	9.57		$	9.59

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 2014, 84 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and eight 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

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 accepting OG&E's June 2012 triennial market power update.

On December 30, 2013, OG&E submitted to the FERC a market-based rate change in status filing and a revised market-based rate tariff that would 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. On February 28, 2014, FERC issued a letter order accepting OG&E’s market-based rate filing and tariff effective March 1, 2014. FERC found that OG&E passed the market power screens and satisfied requirements related to horizontal market power and vertical market power.

Section 206 Complaint

On November 26, 2013, Arkansas Electric Cooperative Corporation filed a complaint at the FERC against OG&E, arguing that the wholesale formula rate contract between OG&E and Arkansas Electric Cooperative Corporation (formerly between OG&E and Arkansas Valley Electric Cooperative) is unjust and unreasonable with respect to several items. OG&E and Arkansas Electric Cooperative Corporation agreed to terms of a settlement and filed the offer of settlement with the FERC on February 24, 2014. On April 17, 2014, the FERC accepted the settlement making it effective March 1, 2014. The reduction in revenue for 2014 was $0.9 million.

Fuel Adjustment Clause Review for Calendar Year 2012

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2013, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on October 9, 2013. On April 24, 2014, the OCC administrative law judge at the hearing, on the merits, recommended that the OCC find that OG&E's 2012 electric generation, purchased power and fuel procurement processes and costs were prudent. On June 10, 2014, the OCC issued an order approving OG&E’s practices, policies and judgment regarding its electric generation, purchased power, and fuel procurement processes and costs for the calendar year 2012. The order also found that the costs were prudent, reasonable, and mathematically correct.

Integrated Resource Plans

In June 2014, OG&E initiated the process to update its Integrated Resource Plans in Oklahoma and Arkansas at OG&E's discretion. The prior Integrated Resource Plan, submitted in 2012, assumed that the Oklahoma SIP would be followed to comply with Regional Haze requirements. Subsequent to holding technical conferences and public stakeholder meetings, OG&E submitted

its revised Integrated Resource Plans, which included its environmental compliance plan described below, to the OCC on August 4, 2014 and to the APSC on September 8, 2014.

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 to 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 tariffs and agreements 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 not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are facilities subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) after November 13, 2012. On May 29, 2013, the Governor signed House Bill 1932 into law which establishes a right of first refusal for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts that interconnect to those incumbent owners' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000. On August 15, 2014, the U.S. Court of Appeals for the D.C. Circuit issued an order denying all appeals of Order No. 1000.

The FERC has issued two orders on the SPP's Order No. 1000 compliance filings. In its most recent order, issued October 16, 2014, the FERC confirmed that “right of first refusal” language should be removed from the SPP tariff and Membership Agreement as applied to most transmission facilities, but that several types of facilities would remain subject to a right of first refusal. Projects that retained the right of first refusal included facilities that would operate below 100 kilovolts, facilities selected as part of the SPP’s Aggregate Study process, and short-term reliability projects. The FERC also approved SPP’s new competitive solicitation process for projects that are not subject to a right of first refusal. FERC found that SPP may consider state and local laws and regulations when deciding whether SPP will hold a competitive solicitation for a proposed project. On December 15, 2014, OG&E filed an appeal in the District of Columbia Circuit Court of Appeals of a portion of the October 2014 FERC order requiring removal of the right of first refusal language from the Membership Agreement. The court has not yet acted on OG&E's appeal.

OGE Energy cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.

Energy Efficiency Program Filing

On February 14, 2014, OG&E filed an application with the APSC requesting approval of interim modifications to approved Energy Efficiency Programs, new tariff revisions and the waiver of certain provisions of the Commission’s Rules for Conservation and Energy Efficiency Programs.

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the Commission to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application is scheduled to commence on March 3, 2015. Multiple parties advocating a variety of positions have intervened in the proceeding. OG&E expects a ruling from the OCC in the second quarter of 2015. At this time, OG&E cannot predict the outcome of the proceeding. OG&E plans to file applications in the first quarter of 2015 seeking related approvals from the APSC.

Fuel Adjustment Clause Review for Calendar Year 2013

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. A procedural schedule has not been established as of this date. OG&E expects an order in the second quarter of 2015.

Regulatory Assets and Liabilities

OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.

At December 31, 2014 and 2013, OG&E had regulatory assets of $508.6 million and $427.9 million, respectively, and regulatory liabilities of $287.4 million and $254.4 million, respectively. See Note 1 of Notes to Consolidated Financial 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® 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 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. A second 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 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, Public Schools-Demand and Public Schools Non-Demand, that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to our military partners.

The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.

Arkansas

OG&E's standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. OG&E 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 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 2014, 61 percent of the OG&E-generated energy was produced by coal-fired units, 32 percent by natural gas-fired units and seven percent by wind-powered units. Of OG&E's 6,845 total MW capability reflected in the table under Item 2. Properties, 3,880 MWs, or 57 percent, are from natural gas generation, 2,516 MWs, or 37 percent, are from coal generation and 449 MWs, or six percent, are from wind generation. 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)	2014	2013	2012	2011	2010
Natural gas	4.506	3.905	2.930	4.328	4.638
Coal	2.152	2.273	2.310	2.064	1.911
Weighted average	2.752	2.784	2.437	2.897	3.012

The decrease in the weighted average cost of fuel in 2014 as compared to 2013 was primarily due to less natural gas used, 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 less natural gas used. 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 began participating in the SPP Integrated Marketplace effective March 1, 2014. The SPP Integrated Marketplace replaced the SPP Energy Imbalance Services market. As part of the Integrated Marketplace, the SPP assumed 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 may produce output that differs from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.

Coal

All of OG&E's coal-fired units, with an aggregate capability of 2,516 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E has contracted for approximately 82 percent of its forecasted annual coal usage via multi-year contracts that expire in 2016. Approximately 10 percent of 2015's usage will be contracted, but undelivered coal from 2014. The remainder of the forecast needs will be procured via the spot market if necessary. In 2014, OG&E purchased 8.2 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.23 percent. Based upon the average sulfur content and EPA certified emission data, OG&E's coal units have an approximate emission rate of 0.5 lbs. of SO2 per MMBtu. As discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," emission limits are expected to become more stringent.

During 2014, railroad cycle times for deliveries of coal to OG&E’s Sooner power plant were higher than historical cycle times. As a result, coal inventory at Sooner is below OG&E’s targeted inventory level. Currently, railroad cycle times are improving and OG&E believes the coal inventory level at Sooner will begin to revert towards OG&E’s targeted level during 2015.

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 supply through term gas agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP market.

On March 17, 2014, OG&E entered into a new five year firm no-notice load following gas transportation contract with Enable effective May 1, 2014.

Wind

OG&E's current wind power portfolio includes the following, in addition to the 120 MW Centennial, 101 MW OU Spirit and 227.5 MW Crossroads wind 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, (ii) access to up to 152 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to 130 MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2030 and (iv) access to up to 60 MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032.

Safety and Health Regulation

OG&E is subject to a number of Federal and state laws and regulations, including OSHA, EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.

In addition, the OSHA hazard communication standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

NATURAL GAS MIDSTREAM OPERATIONS - ENABLE MIDSTREAM PARTNERS

Overview

Enable is a large-scale, growth-oriented publicly traded Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. Enable serves current and emerging production areas in the United States, including several, unconventional shale resource plays and local and regional end-user markets in the United States. Enable's assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for its producer customers, and interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers.

Enable's natural gas gathering and processing assets are located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in North Dakota's Bakken Shale formation of the Williston Basin that commenced initial operations in November 2013. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

Enable was formed on May 1, 2013, to own and operate the midstream businesses of OGE Energy and CenterPoint. As of December 31, 2014, Enable's portfolio of energy infrastructure assets included approximately 11,900 miles of gathering pipelines, 12 major processing plants with approximately 2.1 Bcf/d of processing capacity, approximately 7,900 miles of interstate pipelines (including SESH), approximately 2,300 miles of intrastate pipelines and eight storage facilities providing approximately 87.5 Bcf of storage capacity.

Enable's expansion capital expenditures are estimated to range from approximately $600 million to $800 million for the year ending December 31, 2015.

For the year ended December 31, 2014, approximately 72% of Enable's gross margin was generated from contracts that are fee-based, and approximately 50% of its gross margin was attributable to fees associated with firm contracts or contracts with minimum volume commitment features. Enable generated 88% of its transportation and storage gross margin under fee-based agreements as of December 31, 2014. The transportation and storage demand-based margin for this period represented 82% of the fee-based margin.

The following table shows the components of our gross margin for the year ended December 31, 2014.



	Fee-Based
	Demand/Commitment/Guaranteed Return		Volume Dependent		Commodity-Based		Total
Year Ended December 31, 2014
Gathering and Processing Segment	26	%	33	%	41	%	100	%
Transportation and Storage Segment	82	%	6	%	12	%	100	%
Partnership Weighted Average	50	%	22	%	28	%	100	%

Gathering and Processing

Enable owns and operates approximately 11,900 miles of natural gas gathering pipelines in the Anadarko, Arkoma and Ark-La-Tex basins with approximately 853,000 horsepower of compression and 12 natural gas processing plants with approximately 2.1 Bcf/d of processing capacity and 2.1 Bcf/d of treating capacity as of December 31, 2014. Enable provides gathering, compression, treating, dehydration, processing and NGL fractionation for producers who are active in the areas in which it operates. For the year ended December 31, 2014, its assets gathered an average of approximately 3.34 TBtu/d of natural gas. For the year ended December 31, 2014, Enable processed approximately 1.56 TBtu/d of natural gas and produced approximately 66.74 MBbl/d of NGLs. Enable also has a crude oil gathering business in the Bakken Shale formation, principally located in the Williston Basin, that commenced initial operations in November 2013.

As of December 31, 2014, Enable’s processing infrastructure consisted of 12 plants located in the Anadarko, Arkoma and Ark-La-Tex basins. The assets serving the Anadarko basin consist of nine processing plants, seven of which are interconnected through its super-header system, and are configured to facilitate the flow of natural gas from western Oklahoma and the Wheeler County area in the Texas Panhandle to the Cox City, Thomas, McClure, Calumet, Clinton, South Canadian and Wheeler processing plants. Enable is also currently constructing two cryogenic processing facilities that Enable plans to connect to its super-header system in Grady County, Oklahoma, which are expected to add 400 MMcf/d of natural gas processing capacity. The first of the two new plants (the Bradley Plant) is a 200 MMcf/d plant that is expected to be completed in the first quarter of 2015. The second plant (the Grady County Plant) is a 200 MMcf/d plant that is expected to be completed in the first quarter of 2016. Enable’s super-header system is intended to allow it to optimize the economics of our natural gas processing and to improve system utilization and reliability. The plant in the Arkoma basin serves the rich gas western portion of the area. The two plants in the Ark-La-Tex basin serve the Haynesville, Cotton Valley and Lower Bossier plays.

The following table sets forth certain information regarding Enable's gathering and processing assets as of or for the year ended December 31, 2014:



Asset/Basin	Length (miles)	Compression (Horsepower)	Average Gathering Volume (TBtu/d)	Number of Processing Plants	Processing Capacity (MMcf/d)	NGLs Produced (Bbl/d)	Gross Acreage Dedications (in millions)
Anadarko Basin	7,345	558,636	1.38	9	1,445	51,561	4.3
Arkoma Basin	2,893	139,620	0.77	1	60	4,408	1.4
Ark-La-Tex Basin⁽¹⁾	1,673	154,450	1.19	2	545	10,770	0.7
Total	11,911	852,706	3.34	12	2,050	66,739	6.4


(1)	Ark-La-Tex basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.

For the year ended December 31, 2014, Enable generated 59% of its gathering and processing gross margin from gathering and processing fees. The remaining 41% of gross margin for the year ended December 31, 2014 came from commodities, including natural gas, natural gas liquids, and condensate received under percent-of-proceeds, percent-of-liquids and keep-whole arrangements. For the year ended December 31, 2014, contracts generating 26% of gathering and processing gross margin had minimum volume commitments. Under a minimum volume commitment, a customer commits to ship a minimum volume of natural gas over a period of time on our gathering system, or, in lieu of shipping such volumes, to pay as if that minimum amount had been shipped.

As of December 31, 2014, Enable’s gathering agreements had acreage dedications with original terms ranging up to 15 years, which generally require that production by customers within the acreage dedication be delivered to Enable’s gathering system. As of December 31, 2014, Enable's natural gas gathering agreements had acreage dedications of 6.4 million gross acres with a volume-weighted average remaining term of approximately eight years. In addition, as of December 31, 2014, Enable had minimum volume commitments in lean natural gas developments of 1.5 Bcf/d with a weighted average remaining term of over six years. For the year ended December 31, 2014, Enable's top ten natural gas producer customers accounted for approximately 73% of its gathered volumes. Enable also owns a crude oil gathering business in the Bakken Shale formation of the Williston Basin that commenced initial operations in November 2013.

Transportation and Storage

Enable provides fee-based interstate and intrastate transportation and storage services across nine states. Enable owns and operates approximately 7,900 miles (including SESH) of interstate transportation pipelines with average firm contracted capacity of 7.73 Bcf/d (excluding SESH), for the year ended December 31, 2014. In addition, we own and operate approximately 2,300 miles of intrastate transportation pipelines with average aggregate throughput of 1.61 TBtu/d for the year ended December 31, 2014. Enable also owns and operates eight natural gas storage facilities in Oklahoma, Louisiana and Illinois with approximately 87.5 Bcf of aggregate storage capacity.

The following table sets forth certain information regarding Enable's transportation and storage assets as of December 31, 2014:



Asset	Length (miles)	Capacity		Total Firm Contracted Capacity (Bcf/d)	Average Throughput Volume (Tbtu/d)		Percent of Capacity under Firm Contracts	Weighted Average Remaining Firm Contract Life (years)
Interstate Transportation⁽¹⁾	7,896	8.5	BCF/d	7.7	3.4	⁽²⁾	93%	3.5
Intrastate Transportation	2,286	1.9	BCF/d⁽³⁾	—	1.6		—%	4.5
Storage	—	87.5	BCF	65.1	—		74%	3.3


(1)	Except with respect to length, this information does not include amounts for SESH. SESH is a non-consolidated entity in which Enable own a 49.90% ownership interest.

(2) Actual volumes transported per day may be less than total firm contracted capacity based on demand.

(3) This represents the maximum single day receipts on the intrastate systems. Enable's Oklahoma intrastate pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits the ability to determine an overall system capacity. During the year ended December 31, 2014, the peak daily throughput was 1.9 TBtu or, on a volumetric basis, 1.9 Bcf/d.

ENVIRONMENTAL MATTERS

General

The activities of the Company are subject to numerous, stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.

The trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment. The Company 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 2015 will be approximately $136.0 million, of which $116.0 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2016 will be approximately $159.0 million of which $139.0 million is for capital expenditures. The amounts for OG&E above include capital expenditures for low NOX burners, activated carbon injection and scrubbers. The Company'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 the Company, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations."

FINANCE AND CONSTRUCTION

Future Capital Requirements and Financing Activities

Capital Requirements

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for a discussion of the Company's capital requirements.

Capital Expenditures

The Company's consolidated estimates of capital expenditures for the years 2015 through 2019 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company's businesses) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included in the table below.



(In millions)	2015		2016		2017		2018		2019
OG&E Base Transmission	$	40	$	30	$	30	$	30	$	30
OG&E Base Distribution	175		175		175		175		175
OG&E Base Generation	90		75		75		75		75
OG&E Other	50		25		25		25		25
Total Base Transmission, Distribution, Generation and Other	355		305		305		305		305
OG&E Known and Committed Projects:
Transmission Projects:
Regionally Allocated Base Projects (A)	20		20		20		20		20
SPP Integrated Transmission Projects (B) (C)	30		35		25		10		60
Total Transmission Projects	50		55		45		30		80
Other Projects:
Smart Grid Program	10		10		—		—		—
Environmental - low NOX burners (D)	35		20		10		—		—
Environmental - activated carbon injection (D)	20		—		—		—		—
Environmental - natural gas conversion (D)	—		—		—		40		35
Environmental - scrubbers (D)	60		115		75		215		55
Combustion turbines - Environmental Compliance Plan	15		45		175		165		—
Total Other Projects	140		190		260		420		90
Total Known and Committed Projects	190		245		305		450		170
Total	$	545	$	550	$	610	$	755	$	475


(A)	Approximately 30% of revenue requirement allocated to SPP members other than OG&E.


(B)	Approximately 85% of revenue requirement allocated to SPP members other than OG&E.



(C)	Project Type	Project Description	Estimated Cost (In millions)	Projected In-Service Date
	Integrated Transmission Project	30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation	$45	Early 2018
	Integrated Transmission Project	126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation; construction of the Mathewson substation on this transmission line	$180	Early 2021

(D)

Represent capital costs associated with OG&E’s Environmental Compliance Plan to comply with the EPA’s MATS and Regional Haze rules. More detailed discussion regarding Regional Haze and OG&E’s Environmental Compliance Plan can be found in Note 15 of Notes to Financial Statements under "Environmental Compliance Plan" in Item 8 of Part II of this Form 10-K, and under “Environmental Laws and Regulations” within “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Part II, Item 7 of this Form 10-K.

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

Pension and Postretirement Benefit Plans

During 2013, OGE Energy made contributions to its Pension Plan of $35 million, but did not make any contributions to its Pension Plan in 2014. OGE Energy has not yet determined whether it will need to make any contributions to the Pension Plan in 2015. 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.

Common Stock Dividends

At the Company's September 2014 Board meeting, the Board of Directors approved management's recommendation of an 11 percent increase in the quarterly dividend rate to $0.25000 per share from $0.22500 per share effective in October 2014. 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 further discussion.

Future Sources of Financing

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

Short-Term Debt and Credit Facilities

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The Company has revolving credit facilities totaling in the aggregate $1,150.0 million. These bank facilities can also be used as letter of credit facilities. The short-term debt balance was $98.0 million and $439.6 million at December 31, 2014 and 2013, respectively. The weighted-average interest rate on short-term debt at December 31, 2014 was 0.41 percent. The average balance of short-term debt in 2014 was $417.8 million at a weighted-average interest rate of 0.30 percent. The maximum month-end balance of short-term debt in 2014 was $562.7 million. At December 31, 2014, the Company had $1,050.0 million of net available liquidity under its revolving credit agreements. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016. At December 31, 2014, the Company had $5.5 million in cash and cash equivalents. See Note 11 of Notes to Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

In December 2011, the Company and OG&E entered into unsecured five-year revolving credit agreements to total in the aggregate $1,150.0 million ($750.0 million for the Company and $400.0 million for OG&E). Each of the credit facilities contained an option, which could be exercised up to two times, to extend the term for an additional year. In the third quarter of 2013, the Company and OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of their credit agreements from December 13, 2016 to December 13, 2017. In the second quarter of 2014, the Company and OG&E utilized their second extension to extend the maturity of their respective credit facility from December 13, 2017 to December 13, 2018. As of December 31, 2014, commitments of a single existing lender with respect to approximately $16.3 million and $8.7 million of the Company's and OG&E's credit facilities, respectively, however, were not extended and, unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.

Issuance of Long-Term Debt

On March 25, 2014, OG&E completed the issuance of $250 million of 4.55 percent senior notes due March 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.

On November 19, 2014, the Company completed the issuance of $100 million in aggregate principal of its Floating Rate Senior Notes, Series due November 24, 2017. The proceeds from the issuance were used to refinance its $100 million of 5.00 percent Senior Notes due November 15, 2014.

On December 11, 2014, OG&E completed the issuance of $250 million of 4.00 percent Senior Notes, Series due December 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.

Redemption of Long-Term Debt

On August 1, 2014, OG&E redeemed all $140 million principal amount outstanding of its 6.50 percent senior notes due August 1, 2034 at 103.25 percent of their principal amount, plus accrued interest. The redemption premium of $4.6 million was deferred and will be amortized through March 2044 to match the expected regulatory treatment.

Common Stock

The Company expects to issue between $10 million and $15 million of common stock in its Automatic Dividend Reinvestment and Stock Purchase Plan in 2015. See Note 9 of Notes to Consolidated Financial Statements for a discussion of the Company's common stock activity.

Distributions by Enable

Pursuant to the Enable limited partnership agreement, during 2014 Enable made distributions of $143.7 million to the Company.

EMPLOYEES

The Company had 3,329 employees at December 31, 2014. Included in this total are 884 employees that are seconded to Enable. In October 2014, CenterPoint, OGE Energy and Enable agreed to continue the secondment to Enable of 192 OGE Energy employees that participate in OGE Energy's defined benefit and retirement plans beyond December 31, 2014. The remaining OGE Energy seconded employees were terminated from OGE Energy on December 31, 2014 and were offered employment by Enable.

EXECUTIVE OFFICERS

The following persons were Executive Officers of the Registrant as of February 26, 2015:



Name	Age	Title
Peter B. Delaney	61	Chairman of the Board and Chief Executive Officer - OGE Energy Corp.
Sean Trauschke	47	President - OGE Energy Corp.
E. Keith Mitchell	52	Chief Operating Officer - OG&E
Stephen E. Merrill	50	Chief Financial Officer - OGE Energy Corp.
William J. Bullard	66	Assistant General Counsel - OGE Energy Corp.
Scott Forbes	57	Controller and Chief Accounting Officer - OGE Energy Corp.
Patricia D. Horn	56	Vice President - Governance and Corporate Secretary - OGE Energy Corp.
Jesse B. Langston	52	Vice President - Retail Energy - OG&E
Jean C. Leger, Jr.	56	Vice President - Utility Operations - OG&E
Cristina F. McQuistion	50	Vice President - Strategic Planning, Performance Improvement and Chief Information Officer - OG&E
Jerry A. Peace	52	Chief Generation Planning and Procurement Officer - OG&E
Paul L. Renfrow	58	Vice President - Public Affairs and Corporate Administration - OGE Energy Corp.
Charles B. Walworth	40	Treasurer - OGE Energy Corp.

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Merrill, Trauschke, Bullard, Forbes, Renfrow, Walworth and Ms. Horn are also officers of OG&E. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners, currently scheduled for May 14, 2015.

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

The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:



Name	Business Experience
Peter B. Delaney	2014 - Present:	Chairman of the Board and Chief Executive Officer of OGE Energy Corp.
	2012 - 2014:	Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp.
	2010 - 2011:	Chairman of the Board and Chief Executive Officer of OGE Energy Corp.
Sean Trauschke	2014 - Present:	President of OGE Energy Corp.
	2014:	Chief Financial Officer of OGE Energy Corp.
	2010 - 2014:	Vice President and Chief Financial Officer of OGE Energy Corp.
E. Keith Mitchell	2015 - Present	Chief Operating Officer of OG&E
	2013 - 2015:	Chief Operating Officer of Enable GP, LLC
	2011 - 2013:	President and Chief Operating Officer of Enogex Holdings; President of Enogex LLC
	2010 - 2011:	Senior Vice President and Chief Operating Officer of Enogex LLC
Stephen E. Merrill	2014 - Present:	Chief Financial Officer of OGE Energy Corp.
	2013 - 2014:	Executive Vice President of Finance and Chief Administrative Officer of Enable GP LLC
	2011 - 2013:	Chief Operating Officer of Enogex LLC
	2010 - 2011:	Vice President - Human Resources of OGE Energy Corp.
William J. Bullard	2010 - Present:	Assistant General Counsel of OGE Energy Corp.
Scott Forbes	2010 - Present:	Controller and Chief Accounting Officer of OGE Energy Corp.
Patricia D. Horn	2014 - Present:	Vice President - Governance and Corporate Secretary of OGE Energy Corp.
	2012 - 2014:	Vice President - Governance, Environmental and Corporate Secretary of OGE Energy Corp.
	2010 - 2012:	Vice President - Governance, Environmental, Health & Safety; Corporate Secretary of OGE Energy Corp.
Jesse B. Langston	2010 - Present:	Vice President - Retail Energy of OG&E
Jean C. Leger, Jr.	2010 - Present:	Vice President - Utility Operations of OG&E
Cristina F. McQuistion	2014 - Present:	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
	2011 - 2013:	Vice President - Strategy and Performance Improvement of OGE Energy Corp. and OG&E
	2010 - 2011:	Vice President - Process and Performance Improvement of OGE Energy Corp. and OG&E
Jerry A. Peace	2014 - Present:	Chief Generation Planning and Procurement Officer of OG&E
	2010 - 2014:	Chief Risk Officer of OGE Energy Corp.
Paul L. Renfrow	2014 - Present:	Vice President - Public Affairs and Corporate Administration of OGE Energy Corp.
	2014:	Vice President - Public Affairs, HR, HS&E and Regulatory of OGE Energy Corp.
	2012 - 2014:	Vice President - Public Affairs, Human Resources and Health & Safety of OGE Energy Corp.
	2011 - 2012:	Vice President - Public Affairs and Human Resources of OGE Energy Corp.
	2010 - 2011:	Vice President - Public Affairs of OGE Energy Corp.
Charles B. Walworth	2014 - Present:	Treasurer of OGE Energy Corp
	2012 - 2014:	Assistant Treasurer of OGE Energy Corp.
	2010 - 2012:	Senior Manager Finance of OGE Energy Corp.
	2010:	Manager Corporate Finance of OGE Energy Corp.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

The Company's web site address is www.oge.com. Through the Company's website under the heading "Corporate," "Investor Relations," "SEC Filings," the Company makes available, free of charge, its 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 the Company. In addition to the other information in this Form 10-K and other documents filed by us and/or our subsidiaries with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

REGULATORY RISKS

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

OG&E is subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers.

In 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. 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.

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. 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 return on equity, may harm our financial position and results of operations.

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

We are subject to extensive Federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require

additional pollution 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". As discussed in "Pending Regulatory Matters", OG&E is required to comply with the EPA's FIP by January 4, 2019 and has in response to this requirement, filed an application with the OCC for approval of its plan to comply with the EPA's MATS and Regional Haze FIP.

In response to recent regulatory and judicial decisions, emissions of greenhouse gases including, most significantly, carbon dioxide could be restricted in the future as a result of Federal or state legal requirements or litigation relating to greenhouse gas emissions. If mandatory reductions of carbon dioxide and other greenhouse gases are required in the future, this could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. The EPA has started a process to implement carbon dioxide emission limitations for existing electric generating units, and neither the outcome of the rule making process nor the timing of any required expenditures resulting from the EPA rule making process can be predicted with any certainty at this time.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry operations practices. These activities are subject to stringent and complex Federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way it can handle or dispose of their wastes or requiring remedial action to mitigate pollution conditions that may be caused by their 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.

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 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, in practical terms our regulators could limit 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.

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. On March 1, 2014, the SPP implemented and the FERC approved regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its’ customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records SPP Integrated Marketplace transactions as sales or purchases with results reported as Operating Revenues or Cost of Goods Sold in its Consolidated Financial Statements. OG&E's revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP.

Increased competition resulting from restructuring efforts could have a significant financial impact on us and OG&E and consequently decrease our revenue.

We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes 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 consolidated 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 consolidated financial position, results of operations or cash flows.

Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, consolidated financial position, results of operations, cash flows and access to capital.

As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, consolidated financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our 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 certificates 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 Corporation as the national energy reliability organization. The North American Electric Reliability Corporation 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. The North American Electric Reliability Corporation has authority to assess penalties up to $1.0 million per day per violation 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 outcome of those audits.

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 (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our consolidated financial position, results of operations and cash flows.

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

OG&E owns and operates coal-fired, natural gas-fired and wind-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.

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.

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. Economic conditions may also impact the valuation of certain long-lived assets, including our investment in unconsolidated affiliates, that are subject to impairment testing, potentially resulting in impairment charges, which could have a material adverse impact on our results of operations.

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 increased pressure on Federal, state and local governments to raise additional funds, including through increased corporate taxes and/or through delaying, reducing or eliminating tax credits, grants or other incentives, which could have a material adverse impact on our results of operations and cash flows.

We are subject to financial risks associated with climate change.

Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to the Company. In addition, to the extent that any climate change adversely affects the national or regional economic health through increased rates caused by the inclusion of additional regulatory imposed costs (carbon dioxide taxes or costs associated with additional regulatory requirements), the Company may be adversely impacted. A declining economy could adversely impact the overall financial health of the Company because of 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 security risks and increased reliance on processes automated by technology.

In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our consolidated financial position, results of operations and cash flows.

OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems (including smart grid) which may result in a loss of service to customers and also subject OG&E to financial harm due to the significant expense to repair security breaches or system damage. The implementation of OG&E's smart grid program further increases potential risks associated with cyber security attacks. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on its consolidated financial position, results of operations and cash flows.

Our security procedures, which include among others, virus protection software, cyber security 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 affect of cyber security attacks on our systems, which could adversely impact our operations.

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 consolidated financial position, results of operations and cash flows.

The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility and natural gas midstream industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities 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, and prolonged droughts, as well as seasonal temperature variations may adversely affect our consolidated financial position, results of operations and cash flows.

Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms and wind storms, 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.

FINANCIAL RISKS

Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our consolidated financial position, results of operations or cash flow.

We have a Pension Plan that covers a significant amount of our employees hired before December 1, 2009. We also have 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, 2014, we expect to continue to make future contributions to maintain required funding levels. At times, it has been our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. We may continue to make voluntary contributions in the future. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.

If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our consolidated financial position and results of operations. Those factors are outside of our control.

In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased 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 consolidated 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, 25 percent of our current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.

We are a holding company with our primary assets being investments in our subsidiary and equity investments.

We are a holding company and thus our investments in our subsidiary and unconsolidated affiliate, accounted for under the equity method, are our primary assets. Substantially all of our operations are conducted by our subsidiary and unconsolidated affiliate. Consequently, our operating cash flow and our ability to pay our dividends and service our indebtedness depends upon the operating cash flow of our subsidiary and unconsolidated affiliate and the payment of funds by them to us in the form of dividends or distributions. At December 31, 2014, the Company and its subsidiary had outstanding indebtedness and other liabilities of $6.3 billion. Our subsidiary and unconsolidated affiliate are separate legal entities that have no obligation to pay any amounts due on our indebtedness or to make any funds available for that purpose, whether by dividends or otherwise. In addition, their ability to pay dividends to us depends on any statutory and contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of our subsidiary or unconsolidated affiliate on their respective assets will generally have priority over our claims (except to the extent that we may be a creditor of the subsidiaries and our claims are recognized) and claims by our shareowners.

In addition, as discussed above, OG&E is regulated by state utility commissions in Oklahoma and Arkansas as well as a Federal regulatory agency which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions or Federal regulatory agency attempt to impose restrictions on the ability of OG&E to pay dividends to us, it could adversely affect our ability to continue to pay dividends.

Certain provisions in our charter documents have anti-takeover effects.

Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporations statute, may have the effect of delaying, deferring or preventing a change in control of the Company. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders' meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of the Company without stockholder approval, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder's best interest.

We and OG&E 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 or our subsidiaries from incurring additional indebtedness. If we or OG&E are in compliance with the financial covenants set forth in our revolving credit agreements

and the indentures governing our debt securities, we and OG&E may be able to incur substantial additional indebtedness. If we or OG&E 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 or the ratings of our subsidiaries' will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with our credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

We have revolving credit agreements for working capital, capital expenditures, 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 consolidated financial position, results of operations and cash flows.

We are exposed to credit risks in our generation, retail distribution and pipeline operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

RISKS ASSOCIATED WITH OUR INVESTMENT IN ENABLE MIDSTREAM PARTNERS

OGE Energy does not control Enable and therefore is not able to cause or prevent certain actions by Enable.

Enable has its own governing board, and OGE Energy does not control all of the decisions of that board. Consequently, OGE Energy will be unable solely to cause Enable to take actions that OGE Energy believes would be in our or Enable's best interests. Likewise, OGE Energy will be unable to prevent certain actions of Enable.

A significant portion of our earnings and operating cash flows depend on the performance of Enable. If any of the following risks were actually to occur, our business, financial condition, results of operations or cash flows could be materially adversely affected.

Our operating cash flow is derived partially from cash distributions we receive from Enable.

Our operating cash flow is derived partially from cash distributions we receive from Enable. The amount of cash it can distribute principally depends upon the amount of cash flow it generates from its operations, which may fluctuate from quarter to quarter based on, among other things.


•	the fees and gross margins realized with respect to the volume of natural gas and crude oil handled;


•	the prices of, levels of production of, and demand for natural gas and crude oil;


•	the volume of natural gas and crude oil gathered, compressed, treated, dehydrated, processed, fractionated, transported and stored;


•	the relationship among prices for natural gas, NGLs and crude oil;


•	cash calls and settlements of hedging positions;


•	margin requirements on open price risk management assets and liabilities;


•	the level of competition from other midstream energy companies;


•	adverse effects of governmental and environmental regulation;


•	the level of operation and maintenance expenses and general and administrative costs; and


•	prevailing economic conditions.

In addition, the actual amount of cash available for distribution will depend on other factors, including:


•	the level and timing of capital expenditures;


•	the cost of acquisitions;


•	debt service requirements and other liabilities;


•	fluctuations in working capital needs;


•	ability to borrow funds and access capital markets;


•	restrictions contained in debt agreements;


•	the amount of cash reserves established by Enable GP, LLC


•	other business risks affecting its cash levels.

Enable's contracts are subject to renewal risk

Enable generates a substantial portion of its gross margins under long-term, fee-based agreements. For the year ended December 31, 2014, approximately 72% of its gross margin was generated from contracts that are fee-based and approximately 50% of its gross margin was attributable to fees associated with firm contracts or contracts with minimum volume commitment features. As these and other contracts expire, Enable may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. Enable may be unable to obtain new contracts on favorable commercial terms, if at all, and also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of its contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with fixed-fee or fixed-margin contracts may desire to enter into contracts under different fee arrangements. To the extent Enable is unable to renew its existing contracts on terms that are favorable to Enable, if at all, or successfully manage its overall contract mix over time, its revenue, results of operations and distributable cash flow could be adversely affected.

Enable depends on a small number of customers for a significant portion of its firm transportation and storage services revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of its transportation and storage services and its consolidated financial position, results of operations and its ability to make cash distributions to us.

Enable provides firm transportation and storage services to certain key customers on its system. Enable's major transportation customers are affiliates of CenterPoint Energy, Laclede Group, American Electric Power Company, Inc., XTO Energy, Inc. and OGE Energy.

The loss of all or even a portion of the interstate or intrastate transportation and storage services for any of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could adversely affect Enable's combined and consolidated financial position, results of operations and its ability to make cash distributions to OGE Energy.

The businesses of Enable are dependent, in part, on the drilling and production decisions of others.

The businesses of Enable are dependent on the continued availability of natural gas and crude oil production. Enable has no control over the level of drilling activity in its areas of operation, the amount of reserves associated with wells connected to its systems or the rate at which production from a well declines. In addition, its cash flows associated with wells currently connected to its systems will decline over time. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, its customers must continually obtain new natural gas and crude oil supplies. The primary factors affecting its ability to obtain new supplies of natural gas and crude oil and attract new customers to its assets are the level of successful drilling activity near these systems, its ability to compete for volumes from successful new wells and its ability to expand capacity as needed. If Enable is not able to obtain new supplies of natural gas and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities would decline, which could have a material adverse effect on its results of operations and distributable cash flow. Enable has no control over producers or its drilling and production decisions, which are affected by, among other things:


•	the availability and cost of capital;


•	prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;


•	demand for natural gas, NGLs and crude oil;


•	levels of reserves;


•	geological considerations;


•	environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and


•	the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new natural gas and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond its control. Because of these factors, even if new natural gas or crude oil reserves are known to exist in areas served by its assets, producers may choose not to develop those reserves. Declines in natural gas or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. A sustained decline could also lead producers to shut in production from its existing wells. Sustained reductions in exploration or production activity in its areas of operation could lead to further reductions in the utilization of its systems, which could have a material adverse effect on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders, including us.

In addition, it may be more difficult to maintain or increase the current volumes on its gathering systems, as several of the formations in the unconventional resource plays in which Enable operates generally has higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, it may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require Enable to incur higher maintenance capital expenditures relative to throughput over time, which will reduce its distributable cash flow.

Because of these and other factors, even if new reserves are known to exist in areas served by its assets, producers may choose not to develop those reserves. Reductions in drilling activity would result in an inability to maintain the current levels of throughput on its systems and could have a material adverse effect on its results of operations and distributable cash flow.

Enable’s industry is highly competitive, and increased competitive pressure could adversely affect its results of operations and distributable cash flow.

Enable competes with similar enterprises in its respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Competitors include large crude oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil other than Enable. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enable provides to its customers. Excess pipeline capacity in the regions served by our interstate pipelines could also increase competition and adversely impact the ability to renew or enter into new contracts with respect to available capacity when existing contracts expire. In addition, customers that are significant producers of natural gas may develop their own gathering, processing, transportation and storage systems in lieu of using Enable. Enable’s ability to renew or replace existing contracts with customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and transportation services. All of these competitive pressures could adversely affect its results of operations and distributable cash flow.

Enable derives a substantial portion of its operating income and cash flow from subsidiaries through which it holds a substantial portion of its assets.

Enable derives a substantial portion of its operating income and cash flow from, and holds a substantial portion of its assets through, its subsidiaries. As a result, it depends on distributions from its subsidiaries in order to meet its payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide Enable with funds for its payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit its subsidiaries’ ability to make payments or other distributions, and its subsidiaries could agree to contractual restrictions on its ability to make distributions.

The right by Enable to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if Enable were a creditor of any subsidiary, its rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by them.

The amount of cash Enable has available for distribution to holders of its common and subordinated units depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which Enable records net income.

The amount of cash Enable has available for distribution depends primarily upon its cash flows and not solely on profitability, which will be affected by non-cash items. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

Enable is expected to pay a specified minimum quarterly distribution on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates. The principal difference between Enable’s common units and subordinated units is that in any quarter during the applicable subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on common units from prior quarters. If Enable does not pay distributions on its subordinated units, its subordinated units will not accrue arrearages for those unpaid distributions.

Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates.

Enable's business plan calls for extensive investment in capital improvements and additions. Capital expenditures are could range from approximately $600 million to $800 million for the year ending December 31, 2015, not including opportunities currently under evaluation which could add up to an additional $300 million of expansion capital expenditures. For example, Enable is currently constructing two cryogenic processing facilities that it plans to connect to its super-header system in Grady County, Oklahoma, which are expected to add 400 MMcf/d of natural gas processing capacity. The first of the two new plants (the Bradley Plant) is expected to be completed in the first quarter of 2015. The second plant (the Grady County Plant) is a 200 MMcf/d plant that is expected to be completed in the first quarter of 2016. Enable also plans to construct significant natural gas gathering and compression infrastructure to support producer activity in its growth areas, and Enable anticipates that in 2015 it will complete the construction of its two crude gathering systems in North Dakota’s Bakken shale formation with combined capacity of 49,500 Bbl/d.

The construction of additions or modifications to Enable's existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond its control and may require the expenditure of significant amounts of capital, which may exceed estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if an existing pipeline expanded or a new pipeline constructed, the construction may occur over an extended period of time, and not receive any material increases in revenues or cash flows until the project is completed. In addition Enable may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able

to achieve an expected investment return, which could adversely affect its results of operations and ability to make cash distributions to its unitholders, including us.

In connection with its capital investments, Enable may engage a third party to estimate potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enable relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate due to numerous uncertainties inherent in estimating future production. As a result, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect its results of operations and ability to make cash distributions to unitholders. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable, and it may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, its results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.

Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable's results of operations and its ability to make cash distributions.

Enable's results of operations and ability to make cash distributions to us could be negatively affected by adverse movements in the prices of natural gas, NGLs and crude oil depending on factors that are beyond its control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquefied natural gas, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

Enable's keep-whole natural gas processing arrangements, which accounted for 7% of its natural gas processed volumes in 2014, expose them to fluctuations in the pricing spreads between NGL prices and natural gas prices. Under these arrangements, the processor processes raw natural gas to extract NGLs and pays to the producer the natural gas equivalent Btu value of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. The processor is generally entitled to retain the processed NGLs and to sell them for its own account. Accordingly, the processor’s margin is a function of the difference between the value of the NGLs produced and the cost of the processed natural gas used to replace the natural gas equivalent Btu value of those NGLs. Therefore, if natural gas prices increase and NGL prices do not increase by a corresponding amount, the processor has to replace the Btu of natural gas at higher prices and processing margins are negatively affected.

Enable's percent-of-proceeds and percent-of-liquids natural gas processing agreements accounted for 44% of its natural gas processed volumes in 2014. Under these arrangements, the processor generally gathers raw natural gas from producers at the wellhead, transports the natural gas through its gathering system, processes the natural gas and sells the processed natural gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of the actual proceeds of the sale of processed natural gas, NGLs or both, or the expected proceeds based on an index price. Enable refers to contracts in which the processor shares in specified percentages of the proceeds from the sale of natural gas and NGLs as “percent-of-proceeds” arrangements, and contracts in which the processor receives proceeds from the sale of a percentage of the NGLs or the NGLs themselves as compensation for processing services as “percent-of-liquids” arrangements. These arrangements expose Enable to risks associated with the price of natural gas and NGLs.

At any given time, Enable's overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that it is a net buyer of natural gas) and a net long position in NGLs (meaning that it is a net seller of NGLs). As a result, its gross margin could be adversely impacted to the extent the price of NGLs decreases in relation to the price of natural gas.

Enable has limited experience in the crude oil gathering business.

In November 2013, Enable commenced operations on its initial crude oil gathering pipeline system located in Dunn and McKenzie Counties in North Dakota within the Bakken Shale formation. Additionally in February 2014, Enable executed a crude oil gathering agreement to gather crude oil production through a new system in Williams and Mountrail Counties in North Dakota that is expected to commence operations in the first quarter of 2015. These facilities, with a combined capacity of 49,500 barrels per day, are the first crude oil gathering systems that we have built and operated. Other operators of gathering systems in the Bakken Shale formation may have more experience in the construction, operation and maintenance of crude oil gathering systems

than Enable does. This relative lack of experience may hinder Enable's ability to fully implement its business plan in a timely and cost efficient manner, which, in turn, may adversely affect its results of operations and its ability to make cash distributions to unitholders.

Enable provides certain transportation and storage services under long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts, and, as a result, costs could exceed revenues received under such contracts.

Enable has been authorized by the FERC, to provide transportation and storage services at its facilities at negotiated rates. Generally, negotiated rates are in excess of the maximum recourse rates allowed by the FERC, but it is possible that costs to perform services under “negotiated rate” contracts will exceed the revenues obtained under these agreements. If this occurs, it could decrease the cash flow realized by its systems and, therefore, decrease the cash available for distribution to its unitholders, including us.

As of December 31, 2014, approximately 56% of Enable's contracted transportation firm capacity and 44% of its contracted storage firm capacity was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies.

If third-party pipelines and other facilities interconnected to Enable's gathering, processing or transportation facilities become partially or fully unavailable to Enable for any reason, Enable's results of operations and its ability to make cash distributions to us could be adversely affected.

Enable depends upon third-party natural gas pipelines to deliver natural gas to, and take natural gas from, its transportation systems. it also depends on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of the processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. For example, an outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of its processing plants, and a prolonged outage or disruption could ultimately result in a reduction in the volume of NGLs it is able to produce. Additionally, Enable depends on third parties to provide electricity for compression at many of its facilities. Since it does not own or operate any of these third-party pipelines or other facilities, continuing operation of those facilities is not within its control. If any of these third-party pipelines or other facilities become partially or fully unavailable to Enable for any reason, its results of operations and ability to make cash distributions to us could be adversely affected.

Enable does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

Enable does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Enable may obtain the rights to construct and operate its pipelines on land owned by third parties and governmental agencies for a specific period of time. A loss of these rights, through its inability to renew right-of-way contracts or otherwise, could cause a cease in operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect its results of operations and ability to make cash distributions to unitholders, including us.

Enable conducts a portion of its operations through joint ventures, which subjects them to additional risks that could have a material adverse effect on the success of its operations, financial position and results of operations.

Enable conducts a portion of its operations through joint ventures with third parties, including affiliates of Spectra Energy Corp., DCP Midstream Partners, LP, Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. It may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside the control of Enable. If these parties do not satisfy their obligations under these arrangements, Enable's business may be adversely affected.

The joint venture arrangements of Enable may involve risks not otherwise present when operating assets directly, including, for example:


•	joint venture partners may share certain approval rights over major decisions;


•	joint venture partners may not pay their share of the joint venture’s obligations, leaving Enable liable for their shares of joint venture liabilities;


•	it may be unable to control the amount of cash it will receive from the joint venture;


•	it may incur liabilities as a result of an action taken by its joint venture partners;


•	it may be required to devote significant management time to the requirements of and matters relating to the joint ventures;


•	its insurance policies may not fully cover loss or damage incurred by both them and its joint venture partners in certain circumstances;


•	its joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and


•	disputes between them and its joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue joint ventures or to resolve disagreements with joint venture partners could adversely affect Enable's ability to transact the business that is the subject of such joint venture, which would in turn negatively affect its financial condition and results of operations. The agreements under which certain joint ventures were formed may subject them to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require them to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If it does not timely meet its financial commitments or otherwise do not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of its joint venture partners may have substantially greater financial resources than Enable has and it may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture.

Under certain circumstances, affiliates of Spectra Energy Corp will have the right to purchase an ownership interest in SESH at fair market value.

Enable owns a 49.90% ownership interest in SESH. The remaining 0.1% and 50% ownership interests are held by affiliates of CenterPoint Energy and Spectra Energy Corp, respectively. Under the master formation agreement, CenterPoint Energy has certain put rights, and Enable has certain call rights, exercisable with respect to the interest in SESH retained by CenterPoint Energy, under which CenterPoint Energy would contribute to Enable its interest in SESH at a price equal to the fair market value of the interest at the time the put right or call right is exercised.

CenterPoint Energy owns a 55.4% limited partner interest in Enable and a 40% economic interest in the general partner. Pursuant to the terms of the limited liability company agreement of SESH, as amended (the SESH LLC Agreement), if, at any time, CenterPoint Energy has a right to receive less than 50% of Enable's distributions through its limited partner interest in Enable and its economic interest in the general partner, affiliates of Spectra Energy Corp will have the right to purchase Enable's 49.90% interest in SESH at fair market value. Affiliates of Spectra Energy Corp will also have a preferential purchase right with respect to any interest in SESH transferred to Enable by CenterPoint Energy if, at the time such interest is transferred, Enable is not an “affiliate” of CenterPoint Energy, as such term is defined in the SESH LLC Agreement. Under the master formation agreement, Enable is entitled to receive the cash consideration related to any exercise of these rights by Spectra Energy Corp or its affiliates.

Enable business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely impact its results of operations or ability to make cash distributions to us.

Enable' operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:


•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;


•	inadvertent damage from construction, vehicles, farm and utility equipment;


•	leaks of natural gas, crude oil and other hydrocarbons or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;


•	ruptures, fires and explosions; and


•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of its operations. A natural disaster or other hazard affecting the areas in which it operates could have a material adverse effect on its operations. Enable is not fully insured against all risks inherent in its business. Enable currently has general liability and property insurance in place to cover certain of its facilities in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles. It does not have business interruption insurance coverage for all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of its facilities may not be sufficient to restore the loss or damage without negative impact on its results of operations and ability to make cash distributions to its unitholders, including us.

The use of derivative contracts by Enable and its subsidiaries in the normal course of business could result in financial losses that could negatively impact its results of operations and its ability to make cash distributions to unitholders.

Enable and its subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage its commodity and financial market risks. Enable and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Failure to attract and retain an appropriately qualified workforce could adversely impact Enable's results of operations.

Enable transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for those employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. Employees of OGE Energy that Enable determines to hire are under no obligation to accept Enable's offer of employment on the terms Enable provides, or at all.

Enable's business is dependent on its ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Enable's costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Enable's ability to manage and operate our business. If Enable is unable to successfully attract and retain an appropriately qualified workforce, its results of operations could be negatively affected.

Enable’s ability to grow is dependent on its ability to access external financing sources.

Enable expects its operating subsidiaries will distribute all of their available cash to Enable and that it will distribute all of its available cash to its unitholders. As a result, Enable expects that it and its operating subsidiaries will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As a result, to the extent Enable or its operating subsidiaries are unable to finance growth externally, its operating subsidiaries' cash distribution policy will significantly impair its operating subsidiaries' ability to grow. In addition, because it and its operating subsidiaries distribute all available cash, its operating subsidiaries' growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk it will be unable to maintain or increase its per unit

distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in the partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable or its operating subsidiaries to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that its operating subsidiaries have to distribute to it, and thus that it has to distribute to its unitholders, including us.

If Enable does not make acquisitions or is unable to make acquisitions on economically acceptable terms, its future growth will be limited.

Enable's growth strategy includes, in part, the ability to make acquisitions that result in an increase in its cash generated from operations. If it is unable to make these accretive acquisitions either because: (i) it is unable to identify attractive acquisition targets or it is unable to negotiate purchase contracts on acceptable terms, (ii) it is unable to obtain acquisition financing on economically acceptable terms, or (iii) it is outbid by competitors, then its future growth and ability to increase distributions will be adversely affected.

Enable's merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated.

From time to time, Enable has made, and it intends to continue to make, acquisitions of businesses and assets. Such acquisitions involve substantial risks, including the following:


•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;


•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;


•	it may assume liabilities that were not disclosed to it, that exceed its estimates, or for which its rights to indemnification from the seller are limited;


•	it may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and


•	acquisitions, or the pursuit of acquisitions, could disrupt its ongoing businesses, distract management, divert resources and make it difficult to maintain its current business standards, controls and procedures.

Enable and its operating subsidiaries’ debt levels may limit its flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2014, Enable had approximately $1.9 billion of long-term debt outstanding, excluding the premiums on senior notes. Enable has $363 million of long-term notes payable - affiliated companies due to CenterPoint Energy. Enable also has a $1.4 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, of which $1.1 billion was available as of December 31, 2014. As of January 31, 2015, Enable had the ability to issue up to $1.2 billion in commercial paper, subject to available borrowing capacity under its revolving credit facility and market conditions, to manage the timing of cash flows and fund short-term working capital deficits. As of January 31, 2015, $224 million was outstanding under its commercial paper program. Enable will continue to have the ability to incur additional debt, subject to limitations in its credit facilities. The levels of debt could have important consequences, including the following:


•	the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;


•	a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;


•	the debt level will make Enable more vulnerable to competitive pressures or a downturn in the business or the economy generally; and


•	the debt level may limit flexibility in responding to changing business and economic conditions.

Enable’s and its operating subsidiaries’ ability to service its debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If operating results are not sufficient to service its operating subsidiaries' current or future indebtedness, it and its subsidiaries may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.

Enable’s credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond its control, which could adversely affect its business, financial condition, results of operations and ability to make quarterly distributions to its unitholders.


•	Enable's credit facilities contain customary covenants that, among other things, limit the ability to:


•	permit its subsidiaries to incur or guarantee additional debt;


•	incur or permit to exist certain liens on assets;


•	dispose of assets;


•	merge or consolidate with another company or engage in a change of control;


•	enter into transactions with affiliates on non-arm’s length terms; and


•	change the nature of its business.

Enable’s credit facilities also require it to maintain certain financial ratios. Its ability to meet those financial ratios can be affected by events beyond its control, and assurance it will meet those ratios cannot be guaranteed. In addition, its credit facilities contain events of default customary for agreements of this nature.

Enable's ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, its ability to comply with these covenants may be impaired. If any of the restrictions, covenants, ratios or tests in its credit facilities is violated, a significant portion of its indebtedness may become immediately due and payable. In addition, its lenders’ commitments to make further loans to Enable under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments.

Cyber-attacks, acts of terrorism or other disruptions could adversely impact Enable's results of operations and its ability to make cash distributions to unitholders.

Enable is subject to cyber-security risks related to breaches in the systems and technology that it uses (i) to manage its operations and other business processes and (ii) to protect sensitive information maintained in the normal course of its businesses. The gathering, processing and transportation of natural gas from its gathering, processing and pipeline facilities are dependent on communications among its facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from its facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural phenomena, by failure of equipment or technology, or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt its ability to deliver natural gas and control these assets. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt its operations and critical business functions, adversely affect its reputation, and subject Enable to possible legal claims and liability. Enable is not fully insured against all cyber-security risks any of which could have a material adverse effect on its results of operations and its ability to make cash distributions to unitholders. In addition, its natural gas pipeline systems may be targets of terrorist activities that could disrupt its ability to conduct its business and have a material adverse effect on its results of operations and its ability to make cash distributions to unitholders. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on its business, financial condition and results of operations.

Enable may be unable to obtain or renew permits necessary for its operations, which could inhibit its ability to do business.

Performance of its operations require it obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate.

All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect its ability to initiate or continue operations at the affected location or facility and on its financial condition, results of operations and cash flows.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.

Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect Enable's results of operations and its ability to make cash distributions to unitholders, including us.

Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. 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.

There is inherent risk of the incurrence of environmental costs and liabilities in its operations due to the handling of natural gas, NGLs and crude oil, air emissions related to its operations and historical industry operations and waste disposal practices. These activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact business activities in many ways, such as restricting the handling or disposing of wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from its properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. Private parties, including the owners of the properties through which its gathering systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non- compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of its pipelines could subject them to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Enable may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact its customers’ production and operations, resulting in less demand for its services.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by Enable's customers, which could adversely affect its results of operations and ability to make cash distributions to its unitholders, including us.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Many of its customers commonly use hydraulic fracturing techniques in their drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. For example, in January 2015, the EPA indicated its intention to propose more stringent rules regulating methane and volatile organic compound emissions from hydraulic fracturing and other well completion activity. Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic

fracturing activities in particular, in some cases banning hydraulic fracturing. For example, in Texas, the City of Denton recently enacted a local ordinance that would restrict hydraulic fracturing activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where its oil and natural gas exploration and production customers operate, such customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for its services to those customers.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review by March 2015. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

Enable may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

Because Enable's operations emit various types of greenhouse gases, legislation and regulations governing greenhouse gas emissions could increase its costs related to operating and maintaining its facilities, and could delay future permitting. At the federal level, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of Enable's operations. Additional EPA rules could affect Enable's ability to obtain air permits for new or modified facilities. In addition, the U.S. Congress has in the past and may in the future consider legislation to reduce emissions of greenhouse gases, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs. These programs typically require major sources of greenhouse gas emissions to acquire and surrender emission allowances in return for emitting those greenhouse gases. Any such future laws and regulations imposing reporting obligations on, or limiting emissions of, greenhouse gases could require Enable to incur costs to reduce emissions of greenhouse gases. Substantial limitations on greenhouse gas emissions could also adversely affect demand for oil and natural gas. Depending on the particular program, Enable could in the future be required to purchase and surrender emission allowances or otherwise undertake measures to reduce greenhouse gas emissions. Any additional costs or operating restrictions associated with new legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on its operating results and cash flows, in addition to the demand for its services.

Increased regulatory-imposed costs may increase the cost of consuming, and thereby reduce demand for, the products that Enable gathers, treats and transports. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this view could negatively affect its ability to access capital markets or cause them to receive less favorable terms and conditions. Consequently, legislation and regulatory initiatives aimed at reducing greenhouse gases could have a material adverse effect on its results of operations and ability to make cash distributions to its unitholders, including us.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on Enable's operations.

Enable's operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on its results of operations and ability to make cash distributions to its unitholders, including us.

The rates charged by several of Enable's pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. The FERC and state regulatory agencies also regulate other terms and conditions of the services it may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service it might propose or offer, the profitability of its pipeline businesses could suffer. If it were permitted to raise its tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit profitability. Furthermore, competition from other pipeline systems may prevent them from raising its tariff rates even if permitted by regulatory agencies. The regulatory agencies that regulate its systems periodically implement new rules, regulations and terms and conditions of services subject to its jurisdiction. New initiatives or

orders may adversely affect the rates charged for services or otherwise adversely affect its financial condition, results of operations and cash flows and ability to make cash distributions to its unitholders, including us.

Enable's natural gas interstate pipelines are regulated by FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005, Generally, FERC’s authority over interstate natural gas transportation extends to:


•	rates, operating terms, conditions of service and service contracts;


•	certification and construction of new facilities;


•	extension or abandonment of services and facilities or expansion of existing facilities;


•	maintenance of accounts and records;


•	acquisition and disposition of facilities;


•	initiation and discontinuation of services;


•	depreciation and amortization policies;


•	conduct and relationship with certain affiliates;


•	market manipulation in connection with interstate sales, purchases or natural gas transportation; and


•	various other matters.

FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from FERC. Certain minor expansions are authorized by blanket certificates that FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Enable's inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.

FERC conducts audits to verify compliance with FERC’s regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. FERC’s regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.

The rates, terms and conditions for transporting natural gas in interstate commerce on certain of our intrastate pipelines and for services offered at certain of Enable's storage facilities are subject to the jurisdiction of FERC under Section 311 of the Natural Gas Policy Act. Rates to provide such interstate transportation service must be “fair and equitable” under the Natural Gas Policy Act and are subject to review, refund with interest if found not to be fair and equitable, and approval by FERC at least once every five years.

Enable's crude oil gathering pipelines are subject to common carrier regulation by FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that Enable maintain tariffs on file with FERC setting forth the rates Enable charges for providing transportation services, as well as the rules and regulations governing such services. The ICA requires, among other things, that Enable's rates must be “just and reasonable” and that Enable provide service in a manner that is nondiscriminatory. Shippers on Enable's crude oil gathering pipelines may protest its tariff filings, file complaints against its existing rates, or FERC can investigate Enable's rates on its own initiative. In the event that FERC finds that Enable's existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order Enable to reduce its rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.

Enable’s operations may also be subject to regulation by state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect its results of operations and its ability to make cash distributions to unitholders, including us.

The pipeline operations of Enable that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural and transportation services. The relevant states in which it operates include North Dakota, Oklahoma, Arkansas, Louisiana, Texas, Missouri, Kansas, Mississippi, Tennessee and Illinois. State and local regulations generally focus on

safety, environmental and, in some circumstances, prohibition of undue discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. The effect, if any, such changes might have on operations cannot be predicted, but Enable could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect the business. Any such state or local regulation could have an adverse effect on the business and the results of operations.

Gathering lines may be subject to ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict the right by Enable as an owner of gathering facilities to decide with whom it contracts to purchase or transport oil or natural gas. Federal law leaves economic regulation of natural gas gathering to the states. The states in which it operates have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to access to oil and natural gas gathering pipelines and rate discrimination.

Other state regulations may not directly regulate the business, but may nonetheless affect the availability of natural gas for processing, including state regulation of production rates and maximum daily production allowable from gas wells. While its gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the regulatory status of a line, or the rates, terms and conditions of a gathering line providing transportation service.

A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Enable’s natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of FERC under the Natural Gas Act, but FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, it cannot be assured that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although the FERC has not made a formal determination with respect to all of its facilities they consider to be gathering facilities, Enable believes that its natural gas gathering pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of its gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect Enable’s financial condition, results of operations and cash flows and our ability to make cash distributions to its unitholders. In addition, if any of its facilities were found to have provided services or otherwise operated in violation of the Natural Gas Act or Natural Gas Policy Act regulations, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, Enable's natural gas gathering operations could be adversely affected should it become subject to the application of state regulation of rates and services. Enable’s gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. The effect, if any, such changes might have on its operations cannot be predicted, but additional capital expenditures could be required and increased costs could be incurred depending on future legislative and regulatory changes.

Enable may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs.

The U.S. Department of Transportation has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas,” which are those areas where a leak or rupture could do the most harm. The regulations require operators, including Enable, to, among other things:


•	develop a baseline plan to prioritize the assessment of a covered pipeline segment;


•	identify and characterize applicable threats that could impact a high consequence area;


•	improve data collection, integration, and analysis;


•	repair and remediate pipelines as necessary; and


•	implement preventive and mitigating action.

Although many of Enable's pipelines fall within a class that is currently not subject to these requirements, it may incur significant cost and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt pipelines could be incurred. This work is part of its normal integrity management program and it does not expect to incur any extraordinary costs during 2013 or 2014 to complete the testing required by existing Department of Transportation regulations and its state counterparts. Costs have not been estimated for any repair, remediation, preventive or mitigation actions that may be determined to be necessary as a result of the testing program, which could be substantial, or any lost cash flows resulting from the shutting down of pipelines during the pendency of such repairs. Should Enable fail to comply with Department of Transportation or comparable state regulations, it could be subject to penalties and fines. Also, the scope of the integrity management program and other related pipeline safety programs could be expanded in the future. The cost of complying with such future requirements has not been estimated.

The adoption of financial reform legislation by the United States Congress could adversely affect Enable's ability to use derivative instruments to hedge risks associated with its business.

At times, Enable may hedge all or a portion of its commodity risk and its interest rate risk. The United States Congress adopted comprehensive financial reform legislation that changed federal oversight and regulation of the derivatives markets and entities, including businesses like Enable, that participate in those markets. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission and the SEC to promulgate rules and regulations implementing the legislation. In its rulemaking under the Dodd-Frank Act, the Commodity Futures Trading Commission adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. The Commodity Futures Trading Commission appealed this ruling, but subsequently withdrew its appeal. In December 2013, the Commodity Futures Trading Commission published a Notice of Proposed Rulemaking designed to implement new position limits regulation. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain. However, reporting obligations for transactions involving non-financial swap counterparties such as Enable began on July 1, 2013 with regard to interest rate swaps and August 19, 2013 with regard to other commodity swaps such as natural gas swap products.

Under final rules adopted by the Commodity Futures Trading Commission, Enable believes its hedging transactions will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where the counterparty such as Enable has a required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. The Dodd-Frank Act may also require Enable to comply with margin requirements in connection with its hedging activities, although the application of those provisions to Enable is uncertain at this time. The Dodd-Frank Act may also require the counterparties to its derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.

The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for Enable's industry (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks Enable encounters, reduce its ability to monetize or restructure its existing derivatives contracts, and increase its exposure to less creditworthy counterparties, particularly if Enable is unable to utilize the commercial end user exception with respect to certain of its hedging transactions. If Enable reduces

its use of hedging as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Enable's revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect its results of operations and its ability to make cash distributions to unitholders.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

OG&E

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 6,845 MWs at December 31, 2014. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.



					2014 Capacity Factor (A)				Unit Capability (MW)	Station Capability (MW)
		Year Installed		Fuel Capability
Station & Unit		Year Installed	Unit Design Type	Fuel Capability
Seminole	1	1971	Steam-Turbine	Gas	6.7	%			492
	1GT	1971	Combustion-Turbine	Gas	0.1	%	(B)		—
	2	1973	Steam-Turbine	Gas	7.0	%			500
	3	1975	Steam-Turbine	Gas/Oil	9.2	%			498	1,490
Muskogee	4	1977	Steam-Turbine	Coal	62.2	%			487
	5	1978	Steam-Turbine	Coal	74.6	%			503
	6	1984	Steam-Turbine	Coal	35.9	%			485	1,475
Sooner	1	1979	Steam-Turbine	Coal	50.8	%			521
	2	1980	Steam-Turbine	Coal	67.1	%			520	1,041
Horseshoe Lake	6	1958	Steam-Turbine	Gas/Oil	13.0	%			166
	7	1963	Combined Cycle	Gas/Oil	15.9	%			221
	8	1969	Steam-Turbine	Gas	6.9	%			411
	9	2000	Combustion-Turbine	Gas	9.9	%	(B)		46
	10	2000	Combustion-Turbine	Gas	11.1	%	(B)		45	889
Redbud (C)	1	2003	Combined Cycle	Gas	44.1	%			151
	2	2003	Combined Cycle	Gas	61.8	%			153
	3	2003	Combined Cycle	Gas	63.9	%			152
	4	2003	Combined Cycle	Gas	51.1	%			151	607
Mustang	1	1950	Steam-Turbine	Gas	4.8	%	(B)		51
	2	1951	Steam-Turbine	Gas	5.1	%	(B)		51
	3	1955	Steam-Turbine	Gas	8.7	%			117
	4	1959	Steam-Turbine	Gas	10.6	%			257
	5A	1971	Combustion-Turbine	Gas/Jet Fuel	0.7	%	(B)		34
	5B	1971	Combustion-Turbine	Gas/Jet Fuel	0.8	%	(B)		33	543
McClain (D)	1	2001	Combined Cycle	Gas	56.6	%			351	351
Total Generating Capability (all stations, excluding wind stations)										6,396

							2014 Capacity Factor (A)		Unit Capability (MW)	Station Capability (MW)
		Year Installed		Number of Units	Fuel Capability
Station		Year Installed	Location	Number of Units	Fuel Capability
Crossroads		2011	Canton, OK	98	Wind		46.0	%	2.3	227.5
Centennial		2007	Laverne, OK	80	Wind		36.0	%	1.5	120.0
OU Spirit		2009	Woodward, OK	44	Wind		39.1	%	2.3	101.2
Total Generating Capability (wind stations)										448.7


(A)	2014 Capacity Factor = 2014 Net Actual Generation / (2014 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).


(B)	Peaking units are used when additional short-term capacity is required.


(C)	Represents OG&E's 51 percent ownership interest in the Redbud Plant.


(D)	Represents OG&E's 77 percent ownership interest in the McClain Plant.

At December 31, 2014, OG&E's transmission system included: (i) 53 substations with a total capacity of 13.0 million kilovolt-amps and 4,888 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.4 million kilovolt-amps and 277 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 354 substations with a total capacity of 9.7 million kilovolt-amps, 29,197 structure miles of overhead lines, 2,369 miles of underground conduit and 10,646 miles of

underground conductors in Oklahoma and (ii) 31 substations with a total capacity of 1.0 million kilovolt-amps, 2,778 structure miles of overhead lines, 243 miles of underground conduit and 694 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, 2014, the Company's gross property, plant and equipment (excluding construction work in progress) additions were $2.3 billion and gross retirements were $273.7 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper), long-term borrowings and permanent financings. The additions during this three-year period amounted to 23.4 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2014.

Item 3. Legal Proceedings.

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

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 the Company cannot predict the outcome of this lawsuit at this time, the Company intends to vigorously defend this action and believes that its ultimate resolution will not be material to the Company's consolidated 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.

The Company's Common Stock is listed for trading on the New York Stock Exchange under the ticker symbol "OGE." Quotes may be obtained in daily newspapers where the common stock is listed as "OGE Engy" in the New York Stock Exchange listing table. The following table gives information with respect to price ranges, as reported in The Wall Street Journal as New York Stock Exchange Composite Transactions, and dividends paid for the periods shown.



	Dividend Paid		Price
2015	Dividend Paid		High		Low
First Quarter (through February 20)	$	0.2500	$	36.48	$	32.92
2014
First Quarter	$	0.2250	$	37.29	$	32.91
Second Quarter	0.2250		39.10		34.93
Third Quarter	0.2250		39.28		34.88
Fourth Quarter	0.2500		37.90		32.85
2013
First Quarter	$	0.2088	$	35.08	$	27.70
Second Quarter	0.2088		36.59		32.20
Third Quarter	0.2088		39.55		33.85
Fourth Quarter	0.2088		40.00		32.85

At the Company's September 2014 Board meeting, the Board of Directors approved management's recommendation of an 11 percent increase in the quarterly dividend rate to $0.2500 per share from $0.22500 per share effective in October 2014.

The number of record holders of the Company's Common Stock at December 31, 2014, was 16,957. The book value of the Company's Common Stock at December 31, 2014 was $16.27.

Dividend Restrictions

Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of preferred stock of the Company outstanding. Because the Company is a holding company and conducts all of its operations through its subsidiaries and equity affiliates, the Company's cash flow and ability to pay dividends will be dependent on the earnings and cash flows of its subsidiaries and equity affiliates and the distribution or other payment of those earnings to the Company in the form of dividends or distributions, or in the form of repayments of loans or advances to it. The Company expects to derive principally all of the funds required by it to enable it to pay dividends on its common stock from dividends paid by OG&E, on OG&E's common stock, and from distributions paid by Enable. The Company's ability to receive dividends on OG&E's common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding, any covenants of OG&E's certificate of incorporation and OG&E's debt instruments limiting the ability of OG&E to pay dividends and the ability of public utility commissions that regulate OG&E to effectively restrict the payment of dividends by OG&E. The Company's ability to receive distributions on its limited partnership interest in Enable is subject to Enable's cash available for distribution, the terms of its limited partnership agreement, and the covenants of Enable's debt instruments limiting the ability of Enable to pay distributions. Enable's partnership agreement requires that it distribute all "available cash", as defined as cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves, and cash on hand resulting from working capital borrowings made after the end of the quarter.

Pursuant to the leverage restriction in the Company’s revolving credit agreement, the Company must maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $452.6 million of the Company’s retained earnings from being paid out in dividends. Accordingly, approximately $1.7 billion of the Company’s retained earnings as of December 31, 2014 are unrestricted for the payment of dividends.

Pursuant to the Federal Power Act, OG&E is restricted from paying dividends from its capital accounts. Dividends are paid from retained earnings. Pursuant to the leverage restriction in OG&E’s revolving credit agreement, OG&E must also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $412.2 million of OG&E’s retained earnings from being paid out in dividends. Accordingly, approximately $1.6 billion of OG&E’s retained earnings as of December 31, 2014 are unrestricted for the payment of dividends.

Issuer Purchases of Equity Securities

The following table contains information about the Company's purchases of its common stock during the fourth quarter of 2014.



Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
10/1/14 - 10/31/14	—		$	—	N/A	N/A
11/1/14 - 11/30/14	576	(A)	$	36.34	N/A	N/A
12/1/14 - 12/31/14	—		$	—	N/A	N/A


(A)	These shares of restricted stock were returned to the Company to satisfy tax liabilities.

N/A – not applicable

Item 6. Selected Financial Data

HISTORICAL DATA



Year ended December 31	2014			2013			2012			2011			2010
SELECTED FINANCIAL DATA
(In millions, except per share data)

Results of Operations Data:
Operating revenues	$	2,453.1		$	2,867.7		$	3,671.2		$	3,915.9		$	3,716.9
Cost of sales	1,106.6			1,428.9			1,918.7			2,277.9			2,187.4
Operating expenses	809.7			885.3			1,075.6			991.3			935.6
Operating income	536.8			553.5			676.9			646.7			593.9
Equity in earnings of unconsolidated affiliates	172.6			101.9			—			—			—
Allowance for equity funds used during construction	4.2			6.6			6.2			20.4			11.4
Other income	17.8			31.8			17.6			19.8			13.7
Other expense	14.4			22.2			16.5			21.7			17.9
Interest expense	148.4			147.5			164.1			140.9			139.7
Income tax expense	172.8			130.3			135.1			160.7			161.0
Net income	395.8			393.8			385.0			363.6			300.4
Less: Net income attributable to noncontrolling interests	—			6.2			30.0			20.7			5.1
Net income attributable to OGE Energy	$	395.8		$	387.6		$	355.0		$	342.9		$	295.3
Basic earnings per average common share attributable to OGE Energy common shareholders	$	1.99		$	1.96		$	1.80		$	1.75		$	1.51
Diluted earnings per average common share attributable to OGE Energy common shareholders	$	1.98		$	1.94		$	1.79		$	1.73		$	1.49
Dividends declared per common share	$	0.95000		$	0.85125		$	0.79750		$	0.75875		$	0.73125
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	6,979.9		$	6,672.8		$	8,344.8		$	7,474.0		$	6,464.4
Total assets	$	9,527.8		$	9,134.7		$	9,922.2		$	8,906.0		$	7,669.1
Long-term debt	$	2,755.3		$	2,400.1		$	2,848.6		$	2,737.1		$	2,362.9
Total stockholders' equity	$	3,244.4		$	3,037.1		$	3,072.4		$	2,819.3		$	2,400.0
Capitalization Ratios (A)
Stockholders' equity	54.1		%	55.9		%	51.9		%	50.7		%	50.4		%
Long-term debt	45.9		%	44.1		%	48.1		%	49.3		%	49.6		%
Ratio of Earnings to Fixed Charges (B)
Ratio of earnings to fixed charges	4.49			3.98			3.94			4.12			4.02


(A)	Capitalization ratios = [Total stockholders' equity / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)].

(B)

For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of income from continuing operations before income taxes and equity in earnings of unconsolidated affiliates, plus distributed equity income plus fixed charges, less allowance for borrowed funds used during construction and other capitalized interest and (ii) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.

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

Introduction

On January 26, 2015, Enable announced a quarterly dividend distribution of $0.30875 per unit on its outstanding common and subordinated units, representing an increase of approximately 2.1 percent over the prior quarter distribution. Enable's gross margins are affected by commodity price movements. Based on forward commodity prices, Enable expects to see a change in producer activity that will affect its future distribution growth rate. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. OGE Holdings is entitled to 60 percent of those “incentive distributions.”

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 may produce output that differs from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.

Overview

Company Strategy

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 enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments.


•	Maintaining strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members.


•	Continuing to grow a zero-injury culture and deliver top-quartile safety results.


•	Expanding transmission investments beyond traditional opportunities.


•	Executing on the Company’s Environmental Compliance Plan.


•	Ensuring we have the necessary mix of generation resources to meet the long term needs of our customers.


•	Continuing focus on operational excellence and efficiencies in order to protect the customer bill.

Summary of Operating Results

2014 compared to 2013. Net income attributable to OGE Energy was $395.8 million, or $1.98 per diluted share, in 2014 as compared to $387.6 million, or $1.94 per diluted share, in 2013. The increase in net income attributable to OGE Energy of $8.2 million, or 2.1 percent, or $0.04 per diluted share, in 2014 as compared to 2013 was primarily due to:


•	an increase in net income at OGE Holdings of $2.4 million, or 2.4 percent, or $0.01 per diluted share of the Company's common stock, due partially to the accretive effect to OGE Holdings of Enable partially offset by a reduction in deferred state income taxes in 2013 associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable;


•	an increase in net income at OGE Energy of $6.4 million, or $0.04 per diluted share of the Company's common stock, primarily due to decreased transaction expenses related to the formation of Enable and a decrease in losses for the deferred compensation plan; and

•

a decrease in net income at OG&E of $0.6 million, or 0.2 percent, or $0.01 per diluted share of the Company's common stock, reflecting an increase in depreciation expense due to additional assets being placed in service in 2014, a decrease in gross margin related to milder weather compared to 2013, an increase in other operation and maintenance expense and an increase in interest expense related to the issuance of debt. Partially offsetting these items was an increase in wholesale transmission revenues, an increase in customer growth and a decrease in incentive compensation.

2013 compared to 2012. Net income attributable to OGE Energy was $387.6 million, or $1.94 per diluted share, in 2013 as compared to $355.0 million, or $1.79 per diluted share, in 2012. The increase in net income attributable to OGE Energy of $32.6 million, or 9.2 percent, or $0.15 per diluted share, in 2013 as compared to 2012 was primarily due to:


•	an increase in net income at OG&E of $12.3 million, or 4.4 percent, or $0.06 per diluted share of the Company's common stock, driven by higher gross margin primarily related to increased wholesale transmission revenue and lower other operation and maintenance expense, partially offset by higher interest expense related to the issuance of debt in May 2013;

•

an increase in net income at OGE Holdings of $25.8 million, or 34.8 percent, or $0.13 per diluted share of the Company's common stock, due partially to the accretive effect to OGE Holdings of its investment in Enable since May 1, 2013 and a reduction in deferred state income taxes, associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable. Also contributing to the increase was the performance of Enogex for the first four months of 2013. Compared to the same period of 2012, earnings were higher for Enogex due to increased gathering rates and volumes and inlet processing volumes associated with its expansion projects and gas gathering assets acquired in August 2012. These increases were partially offset by lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex's five largest customers from keep-whole to fixed-fee; and


•	a decrease in net income at OGE Energy of $5.5 million, or $0.04 per diluted share of the Company's common stock, primarily due to transaction expenses related to the formation of Enable as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

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

2015 Outlook

Key assumptions for 2015 include:

OG&E

The Company projects OG&E to earn approximately $282 million to $298 million, or $1.41 to $1.49 per average diluted share in 2015 and is based on the following assumptions:


•	Normal weather patterns are experienced for the remainder of the year;


•	Gross margin on revenues of approximately $1.375 billion to $1.385 billion based on sales growth of approximately 1 percent on a weather-adjusted basis;


•	Approximately $114 million of gross margin is primarily attributed to regionally allocated transmission projects;


•	Operating expenses of approximately $844 million to $861 million, with operation and maintenance expenses comprising 54 percent of the total;


•	Interest expense of approximately $146 million which assumes a $5 million allowance for borrowed funds used during construction reduction to interest expense;


•	Other income of approximately $17 million including approximately $9 million of allowance for equity funds used during construction; and


•	An effective tax rate of approximately 27 percent.

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

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

Reconciliation of gross margin to revenue:



	Twelve Months Ended
(Dollars in Millions)	December 31, 2015 (A)
Operating revenues	$	2,188
Cost of sales	808
Gross Margin	$	1,380


(A)	Based on the midpoint of OG&E earnings guidance for 2015.

OGE Enogex Holdings LLC

The Company projects cash distributions from its ownership interest in Enable Midstream to be between approximately $139 million to $142 million, and the earnings contribution to be approximately $70 million to $80 million or $0.35 to $0.40 per average diluted share.

Consolidated OGE

The Company’s 2015 earnings guidance is between approximately $352 million and $378 million of net income, or $1.76 to $1.89 per average diluted share and is based on the following assumptions:


•	Approximately 200 million average diluted shares outstanding;


•	An effective tax rate of approximately 29 percent.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 and the Company's consolidated financial position at December 31, 2014 and 2013. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.



Year ended December 31 (In millions except per share data)	2014		2013		2012
Net income attributable to OGE Energy	$	395.8	$	387.6	$	355.0
Basic average common shares outstanding	199.2		198.2		197.1
Diluted average common shares outstanding	199.9		199.4		198.1
Basic earnings per average common share attributable to OGE Energy common shareholders	$	1.99	$	1.96	$	1.80
Diluted earnings per average common share attributable to OGE Energy common shareholders	$	1.98	$	1.94	$	1.79
Dividends declared per common share	$	0.95000	$	0.85125	$	0.79750

Results by Business Segment



Year ended December 31 (In millions)	2014		2013		2012
Net Income attributable to OGE Energy
OG&E (Electric Utility)	$	292.0	$	292.6