SEC Filing | CenterPoint Energy, Inc.,

CENTERPOINT ENERGY RESOURCES CORP.

Date: July 17, 2013

/s/ Christopher J. Arntzen

Christopher J. Arntzen

Vice President, Deputy General Counsel

and Assistant Secretary

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Form 8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

(Amendment No. 1)

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): May 1, 2013

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware

1-13265

76-0511406

(State or other jurisdiction

of incorporation)

(Commission

File Number)

(IRS Employer

Identification No.)


1111 Louisiana
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 207-1111

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

This Current Report on Form 8-K/A (Amendment No. 1) amends and supplements the Current Report on Form 8-K filed by CenterPoint Energy Resources Corp. (“CERC”), a wholly owned subsidiary of CenterPoint Energy, Inc. (“CenterPoint”), on May 7, 2013, in connection with CenterPoint’s previously announced midstream partnership with OGE Energy Corp. and two affiliates of ArcLight Capital Partners, LLC, the formation of which was completed on May 1, 2013 (the “Midstream Partnership”). The Current Report on Form 8-K filed May 7, 2013 is being amended by this Amendment No. 1 to include the audited and unaudited financial statements and information required by Item 9.01(a) and the pro forma financial information required by Item 9.01(b). No other amendments to the Form 8-K filing on May 7, 2013 are being made by this Amendment No. 1.

Item 9.01

Financial Statements and Exhibits.

(a)

Financial statements of businesses acquired.

The unaudited condensed consolidated balance sheet of Enogex LLC as of March 31, 2013, and the related condensed consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for the three months ended March 31, 2013, and the related notes to the consolidated financial statements, are attached as Exhibit 99.1 and incorporated herein by reference.

The audited consolidated balance sheets and statements of capitalization of Enogex LLC as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for each of the three years in the period ended December 31, 2012, and the related notes to the consolidated financial statements, and the independent auditors’ report related thereto, are attached as Exhibit 99.2 and incorporated herein by reference.

(b)

Pro forma financial information.

The unaudited pro forma condensed consolidated balance sheet of CERC as of March 31, 2013, and the unaudited pro forma condensed statements of consolidated income of CERC for the three months ended March 31, 2013 and for the year ended December 31, 2012, which give effect to the Midstream Partnership, are attached as Exhibit 99.3 and incorporated herein by reference.

(d)

Exhibits


Exhibit No.		Description

23.1		Consent of Ernst & Young LLP.

99.1		The unaudited condensed consolidated balance sheet of Enogex LLC as of March 31, 2013, and the related condensed consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for the three months ended March 31, 2013, and the related notes to the consolidated financial statements.

99.2		The audited consolidated balance sheets and statements of capitalization of Enogex LLC as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for each of the three years in the period ended December 31, 2012, and the related notes to the consolidated financial statements, and the independent auditors’ report related thereto.

99.3		The unaudited pro forma condensed consolidated balance sheet of CERC as of March 31, 2013, and the unaudited pro forma condensed statements of consolidated income of CERC for the three months ended March 31, 2013 and for the year ended December 31, 2012, which give effect to the Midstream Partnership.

SIGNATURE

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

EXHIBIT INDEX


Exhibit No.		Description

23.1		Consent of Ernst & Young LLP.

99.1		The unaudited condensed consolidated balance sheet of Enogex LLC as of March 31, 2013, and the related condensed consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for the three months ended March 31, 2013, and the related notes to the consolidated financial statements.

99.2		The audited consolidated balance sheets and statements of capitalization of Enogex LLC as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for each of the three years in the period ended December 31, 2012, and the related notes to the consolidated financial statements, and the independent auditors’ report related thereto.

99.3		The unaudited pro forma condensed consolidated balance sheet of CERC as of March 31, 2013, and the unaudited pro forma condensed statements of consolidated income of CERC for the three months ended March 31, 2013 and for the year ended December 31, 2012, which give effect to the Midstream Partnership.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-169666-01) of CenterPoint Energy Resources Corp. of our report dated February 27, 2013, with respect to the consolidated financial statements of Enogex LLC, included in this Current Report on Form 8-K of CenterPoint Energy Resources Corp. dated July 17, 2013.

/s/ Ernst & Young LLP

Ernst & Young LLP

Oklahoma City, Oklahoma

July 17, 2013

EX-99.1

Exhibit 99.1

ENOGEX LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2013 AND 2012

(UNAUDITED)

TABLE OF CONTENTS


	Page

GLOSSARY		ii

Part I - FINANCIAL INFORMATION
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED STATEMENTS OF INCOME		1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS		3
CONDENSED CONSOLIDATED BALANCE SHEETS		4
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S INTEREST		6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS		7

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this report.


Abbreviation		Definition
ArcLight group		Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively

Atoka		Atoka Midstream LLC joint venture

CenterPoint		CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.

EER		Enogex Energy Resources LLC, wholly-owned subsidiary of Enogex LLC (prior to June 30, 2012, the legal name was OGE Energy Resources LLC)

Enogex		Enogex LLC, collectively with its subsidiaries

Enogex Holdings		Enogex Holdings LLC, the parent company of Enogex and a majority-owned subsidiary of OGE Holdings, LLC, a wholly-owned subsidiary of OGE Energy

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States

Midstream Partnership		Partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint

NGLs		Natural gas liquids

NYMEX		New York Mercantile Exchange

OG&E		Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy

OGE Energy		OGE Energy Corp., parent company of OGE Holdings, LLC

Pension Plan		Qualified defined benefit retirement plan

PRM		Price risk management

Restoration of Retirement Income Plan		Supplemental retirement plan to the Pension Plan

Financial Statements.

ENOGEX LLC

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions)	2013			2012
OPERATING REVENUES	$	464.3		$	429.6

COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)		359.2			305.3


Gross margin on revenues		105.1			124.3


OPERATING EXPENSES
Other operation and maintenance		45.2			42.2
Depreciation and amortization		27.6			23.4
Impairment of assets		—			0.2
Gain on insurance proceeds		—			(7.5	)
Taxes other than income		8.0			7.3

Total operating expenses		80.8			65.6


OPERATING INCOME		24.3			58.7


OTHER INCOME (EXPENSE)
Other income		10.2			0.2
Other expense		(1.2	)		(0.6	)

Net other income (expense)		9.0			(0.4	)


INTEREST EXPENSE
Interest on long-term debt		7.2			6.8
Other interest charges		0.9			0.8

Interest expense		8.1			7.6


INCOME BEFORE TAXES		25.2			50.7


INCOME TAX EXPENSE		0.1			0.1


NET INCOME		25.1			50.6


Less: Net income attributable to noncontrolling interest		0.3			1.1


NET INCOME ATTRIBUTABLE TO ENOGEX LLC	$	24.8		$	49.5

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

ENOGEX LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions)	2013			2012
Net income	$	25.1		$	50.6
Other comprehensive income (loss)
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss		0.6			0.6
Postretirement Benefit Plans:
Amortization of deferred net loss		0.4			0.4
Amortization of prior service cost		(0.3	)		(0.3	)
Deferred commodity contracts hedging gains reclassified in net income		(0.2	)		(5.2	)
Deferred commodity contracts hedging gains (losses)		—			0.3

Other comprehensive income (loss)		0.5			(4.2	)

Comprehensive income (loss)		25.6			46.4

Less: Comprehensive income attributable to noncontrolling interest		0.3			1.1
Total comprehensive income attributable to Enogex LLC	$	25.3		$	45.3

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

ENOGEX LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
(In millions)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	25.1		$	50.6
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization		28.6			24.4
Impairment of assets		—			0.2
(Gain) loss on disposition and abandonment of assets		(8.7	)		0.5
Gain on insurance proceeds		—			(7.5	)
OGE Energy stock-based compensation		(0.9	)		(0.6	)
Price risk management assets		0.9			(0.7	)
Price risk management liabilities		—			(4.9	)
Other assets		(23.5	)		3.1
Other liabilities		1.2			0.3
Other liabilities - parent		2.3			2.4
Change in certain current assets and liabilities
Accounts receivable, net		(6.2	)		16.4
Accounts receivable - affiliates		(1.4	)		0.3
Natural gas, natural gas liquids, materials and supplies inventories		7.6			12.9
Gas imbalance assets		(3.1	)		(4.0	)
Other current assets		26.1			(0.8	)
Accounts payable		(2.7	)		(22.8	)
Accrued taxes		(6.5	)		(3.0	)
Accrued interest		(7.4	)		(7.4	)
Gas imbalance liabilities		0.7			(1.4	)
Other current liabilities		(3.2	)		(3.9	)

Net Cash Provided from Operating Activities		28.9			54.1

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(128.2	)		(118.5	)
Proceeds from sale of assets		35.4			0.1
Proceeds from insurance		—			6.1

Net Cash Used in Investing Activities		(92.8	)		(112.3	)

CASH FLOWS FROM FINANCING ACTIVITIES
Changes in advances with parent		80.4			91.1
Purchase of OGE Energy treasury stock		(3.5	)		(5.9	)
Distributions to parent		(12.5	)		(30.0	)

Net Cash Provided from Financing Activities		64.4			55.2

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		0.5			(3.0	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1.8			4.6

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2.3		$	1.6

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

ENOGEX LLC

CONDENSED CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2013 (Unaudited)		December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2.3	$	1.8
Accounts receivable, less reserve of less than $0.1 each		140.9		134.7
Accounts receivable - affiliates		2.1		0.7
Natural gas and natural gas liquids inventories		8.8		16.5
Materials and supplies, at average cost		5.0		4.9
Price risk management		1.7		2.6
Gas imbalances		12.1		9.0
Assets held for sale		—		25.5
Other		3.1		3.7

Total current assets		176.0		199.4

OTHER PROPERTY AND INVESTMENTS, at cost		1.5		1.5
PROPERTY, PLANT AND EQUIPMENT
In service		2,939.0		2,869.4
Construction work in progress		186.2		130.7

Total property, plant and equipment		3,125.2		3,000.1
Less accumulated depreciation		763.9		738.3

Net property, plant and equipment		2,361.3		2,261.8

DEFERRED CHARGES AND OTHER ASSETS
Intangible assets, net		126.0		127.4
Goodwill		39.4		39.4
Other		20.1		21.8

Total deferred charges and other assets		185.5		188.6

TOTAL ASSETS	$	2,724.3	$	2,651.3

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

ENOGEX LLC

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)


(In millions)	March 31, 2013 (Unaudited)			December 31, 2012
LIABILITIES AND MEMBER’S INTEREST
CURRENT LIABILITIES
Accounts payable	$	197.8		$	200.2
Advances from parent		217.9			137.5
Customer deposits		1.8			1.8
Accrued compensation - parent		9.3			10.7
Accrued taxes		6.2			12.9
Accrued interest		3.8			11.2
Price risk management		0.5			0.3
Gas imbalances		5.7			5.0
Deferred revenues		4.8			5.5
Other		7.3			8.5

Total current liabilities		455.1			393.6

LONG-TERM DEBT		698.5			698.4
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations - parent		81.0			79.4
Deferred revenues		38.4			37.7
Other		5.4			5.1

Total deferred credits and other liabilities		124.8			122.2

Total liabilities		1,278.4			1,214.2

COMMITMENTS AND CONTINGENCIES (NOTE 12)
MEMBER’S INTEREST
Member’s interest		1,469.8			1,461.8
Accumulated other comprehensive loss - parent		(44.5	)		(45.2	)
Accumulated other comprehensive income		—			0.2

Total Enogex LLC member’s interest		1,425.3			1,416.8
Noncontrolling interest		20.6			20.3

Total member’s interest		1,445.9			1,437.1
TOTAL LIABILITIES AND MEMBER’S INTEREST	$	2,724.3		$	2,651.3

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

ENOGEX LLC

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S INTEREST

(Unaudited)


(In millions)	Member’s Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest		Total Member’s Interest
Balance at December 31, 2012	$	1,461.8		$	(45.0	)	$	20.3	$	1,437.1
Comprehensive income (loss)
Net income		24.8			—			0.3		25.1
Other comprehensive income (loss)		—			0.5			—		0.5

Comprehensive income (loss)		24.8			0.5			0.3		25.6

Distributions to parent		(12.5	)		—			—		(12.5	)
OGE Energy stock-based compensation		(0.8	)		—			—		(0.8	)
Purchase of OGE Energy treasury stock		(3.5	)		—			—		(3.5	)

Balance at March 31, 2013	$	1,469.8		$	(44.5	)	$	20.6	$	1,445.9


Balance at December 31, 2011	$	1,295.3		$	(30.0	)	$	17.6	$	1,282.9
Comprehensive income (loss)
Net income		49.5			—			1.1		50.6
Other comprehensive income (loss)		—			(4.2	)		—		(4.2	)

Comprehensive income (loss)		49.5			(4.2	)		1.1		46.4

Distributions to parent		(30.0	)		—			—		(30.0	)
OGE Energy stock-based compensation		0.9			—			—		0.9
Purchase of OGE Energy treasury stock		(7.4	)		—			—		(7.4	)

Balance at March 31, 2012	$	1,308.3		$	(34.2	)	$	18.7	$	1,292.8

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

ENOGEX LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Summary of Significant Accounting Policies

Organization

Enogex is a Delaware single-member limited liability company, which, prior to May 1, 2013, was indirectly owned by OGE Energy and the ArcLight group. Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. Also, at March 31, 2013, Enogex held a 50 percent ownership interest in Atoka. At March 31, 2013, Enogex consolidated Atoka in its Condensed Consolidated Financial Statements as Enogex acted as the managing member of Atoka and had control over the operations of Atoka.

On March 14, 2013, OGE Energy entered into a Master Formation Agreement with the ArcLight group and CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight group and CenterPoint Energy, Inc., agreed to form the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint. This transaction closed on May 1, 2013. Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight group indirectly contributed Enogex to the Midstream Partnership and CenterPoint Energy, Inc. contributed its midstream natural gas business to the Midstream Partnership. At May 1, 2013, OGE Energy holds 28.5 percent of the limited partners interests, CenterPoint holds 58.3 percent of the limited partner interests and the ArcLight group holds 13.2 percent of the limited partner interests in the Midstream Partnership. The general partner of the Midstream Partnership is equally controlled by CenterPoint and OGE Energy, who each have 50 percent of the management rights. For additional information regarding the Midstream Partnership, see Note 3.

Basis of Presentation

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of Enogex at March 31, 2013 and the results of its operations and cash flows for the three months ended March 31, 2013 and 2012, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of subsequent events for inclusion in Enogex’s Condensed Consolidated Financial Statements occurring after March 31, 2013 through July 17, 2013, the date Enogex’s financial statements were available to be issued, and, in the opinion of management, Enogex’s Condensed Consolidated Financial Statements and Notes contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, Enogex’s operating results for the three months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013 or for any future period.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to Enogex during the three months ended March 31, 2013. At both March 31, 2013 and December 31, 2012, there was no accumulated other comprehensive loss related to Enogex’s noncontrolling interest in Atoka. All amounts below are presented net of noncontrolling interest.


	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
	Net loss			Prior service cost		Net loss			Prior service cost			Deferred commodity contracts hedging gains			Total
Balance at December 31, 2012	$	(36.5	)	$	0.4	$	(13.7	)	$	4.6		$	0.2		$	(45.0	)

Amounts reclassified from accumulated other comprehensive income (loss)		0.6			—		0.4			(0.3	)		(0.2	)		0.5

Balance at March 31, 2013	$	(35.9	)	$	0.4	$	(13.3	)	$	4.3		$	—		$	(44.5	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the three months ended March 31, 2013.


Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss			Affected Line Item in the Statement Where Net Income is Presented

Gains on cash flow hedges
Commodity contracts	$	0.2		Cost of goods sold

	$	0.2		Total


Amortization of defined benefit pension items
Actuarial gains (losses)	$	(0.6	)	(A)

		(0.6	)	Total

Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.4	)	(A)
Prior service cost		0.3		(A)

		(0.1	)	Total



Total reclassifications for the period	$	(0.5	)	Total

(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Related Party Transactions

OGE Energy charged operating costs to Enogex of $7.9 million and $7.5 million during the three months ended March 31, 2013 and 2012, respectively. OGE Energy charges operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Included in operating costs charged by OGE Energy are $0.6 million and $0.4 million during the three months ended March 31, 2013 and 2012, respectively, for payroll taxes and depreciation and amortization expense directly related to Enogex’s operations. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, either as overhead based primarily on labor costs or using the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the Staff of the Oklahoma Corporation Commission. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

Enogex has a transportation contract with its affiliate, OG&E, to transport natural gas to OG&E’s natural gas-fired generation facilities. During each of the three months ended March 31, 2013 and 2012, Enogex recorded revenues from OG&E of $8.7 million for transporting gas to OG&E’s natural gas-fired generating facilities. During each of the three months ended March 31, 2013 and 2012, Enogex recorded revenues from OG&E of $3.2 million for natural gas storage services. During the three months ended March 31, 2013 and 2012, Enogex also recorded natural gas sales to OG&E of $5.5 million and $3.6 million, respectively. During the three months ended March 31, 2013 and 2012, Enogex recorded an expense from OG&E of $1.8 million and $2.8 million, respectively, for electricity used to power Enogex’s electric compression assets.

On July 1, 2009, OG&E and Enogex entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority. These transactions are for 50,000 million British thermal unit per month from August 2009 to December 2013 (see Note 5).

During the three months ended March 31, 2013 and 2012, the parent made no contributions to Enogex. During the three months ended March 31, 2013 and 2012, Enogex made distributions to the parent of $12.5 million and $30.0 million, respectively.

Reclassifications

As discussed in Note 11, during the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented to conform to the 2013 presentation.

2.	Gas Gathering Divestiture

Texas Panhandle Gathering Divestiture

As previously reported, on January 2, 2013, Enogex and one of its five largest customers entered into new agreements, effective January 1, 2013, relating to the customer’s gathering and processing volumes on the Texas portion of Enogex’s system. The effects of this new arrangement are (i) a fixed-fee processing agreement replaced the previous keep-whole agreement, (ii) the acreage dedicated by the customer to Enogex for gathering and processing in Texas was increased for an extended term and (iii) the sale by Enogex of certain gas gathering assets in the Texas Panhandle portion of Enogex’s system to this customer for cash proceeds of approximately $35 million. Enogex recognized a pre-tax gain of $9.9 million in the first quarter of 2013 in its natural gas gathering and processing segment from the sale of these assets which is included in Other Income in the Condensed Consolidated Statements of Income.

3.	OGE Energy Midstream Partnership with CenterPoint Energy, Inc.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex to the Midstream Partnership. CenterPoint Energy Field Services, LLC, a Delaware limited liability company and wholly owned subsidiary of CenterPoint, was converted into a Delaware limited partnership that became the Midstream Partnership. CenterPoint contributed to the Midstream Partnership its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC, a Delaware limited liability company, CenterPoint Energy - Mississippi River Transmission, LLC, a Delaware limited liability company, and certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute a 24.95 percent interest in Southeast Supply Header, LLC, a Delaware limited liability company.

CenterPoint Energy Field Services, LLC provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States that interconnect with CenterPoint Energy Gas Transmission Company, LLC and CenterPoint Energy - Mississippi River Transmission, LLC pipelines, as well as other interstate and intrastate pipelines. As of December 31, 2012, CenterPoint Energy Field Services, LLC gathered an average of approximately 2.5 billion cubic feet per day of natural gas. In addition, CenterPoint Energy Field Services, LLC has the capacity available to treat up to 2.5 billion cubic feet per day and process nearly 625 million cubic feet per day of natural gas. CenterPoint Energy Gas Transmission Company, LLC is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas and includes the 1.9 billion cubic feet per day pipeline

from Carthage, Texas to Perryville, Louisiana, which CenterPoint Energy Gas Transmission Company, LLC operates as a separate line with a fixed fuel rate. CenterPoint Energy - Mississippi River Transmission, LLC is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Illinois and Missouri. Southeast Supply Header, LLC owns a 1.0 billion cubic feet per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama.

At May 1, 2013, OGE Energy holds 28.5 percent of the limited partners interests, CenterPoint holds 58.3 percent of the limited partner interests and the ArcLight group holds 13.2 percent of the limited partner interests in the Midstream Partnership, provided, however, if CenterPoint obtains the approvals required to contribute its remaining 25.05 percent indirect interest in Southeast Supply Header, LLC within 90 days after closing, CenterPoint will instead hold 59 percent of the limited partner interests, OGE would hold 28 percent of the limited partners interest and the ArcLight group would hold 13 percent of the limited partners interest.

After the expiration of the 90-day period after closing, CenterPoint has certain put rights, and the Midstream Partnership has certain call rights, exercisable with respect to the interest in Southeast Supply Header, LLC retained by CenterPoint, under which CenterPoint would contribute to the Midstream Partnership CenterPoint’s retained interest in Southeast Supply Header, LLC at a price equal to the fair market value of such interest at the time the put right or call right is exercised. If CenterPoint were to exercise such put right or the Midstream Partnership were to exercise such call right, CenterPoint’s retained interest in Southeast Supply Header, LLC would be contributed to the Midstream Partnership in exchange for consideration consisting of a specified number of limited partnership units and, subject to certain restrictions, a cash payment, payable either from CenterPoint to the Midstream Partnership or from the Midstream Partnership to CenterPoint, in an amount such that the total consideration exchanged is equal in value to the fair market value of the contributed interest in Southeast Supply Header, LLC.

The general partner of the Midstream Partnership is equally controlled by CenterPoint and OGE Energy, who each have 50 percent of the management rights. CenterPoint and OGE Energy also own a 40 percent and 60 percent interest, respectively, in any incentive distribution rights to be held by the general partner of the Midstream Partnership following an initial public offering of the Midstream Partnership. In addition, for a period of time, the ArcLight group will have board observation rights and approval rights over certain material activities of the Midstream Partnership, including material increases in capital expenditures and certain equity issuances, entering into transactions with related parties and acquiring, pledging or disposing of certain material assets. The general partner of the Midstream Partnership will initially be governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy, Inc. and OGE Energy. Based on the 50/50 management ownership, with neither company having control, effective May 1, 2013, OGE Energy deconsolidated its interest in Enogex. OGE Energy and CenterPoint will account for their respective interests in the Midstream Partnership under the equity method of accounting.

Pursuant to a Registration Rights Agreement dated as of May 1, 2013, OGE Energy and CenterPoint Energy, Inc. agreed to initiate the process for the sale of an equity interest in the Midstream Partnership in an initial public offering. OGE Energy, CenterPoint and the Midstream Partnership can give no assurances that the initial public offering will be consummated. Prior to consummating the initial public offering, OGE Energy, CenterPoint Energy, Inc. and the Midstream Partnership will need to complete the negotiation of the financial and other terms, including the initial public offering price. In addition, consummation of the initial public offering is subject to market conditions. For so long as the ArcLight group maintains a minimum ownership percentage, the ArcLight group is entitled to consult with the Midstream Partnership in connection with the initial public offering. The Midstream Partnership has agreed to file a registration statement for the initial public offering no later than May 1, 2014 and, subject to limited exceptions, consummate the initial public offering within 180 days of the filing of the registration statement.

Immediately prior to closing, on May 1, 2013, the ArcLight group contributed $107.0 million and OGE Energy contributed $9.1 million to Enogex in order to pay down short-term debt. In connection with the formation of the Midstream Partnership, on May 1, 2013, the Midstream Partnership entered into a $1.05 billion three-year senior unsecured term loan facility, the proceeds of which were used to repay $1.05 billion of intercompany indebtedness owed to CenterPoint. CenterPoint has guaranteed collection of the Midstream Partnership’s obligations under the term loan, which guarantee is subordinated to all senior debt of CenterPoint. Effective May 1, 2013, the Midstream Partnership also entered into a $1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex’s $400 million revolving credit facility was terminated.

At March 31, 2013, Enogex was obligated on approximately $700 million, in the aggregate, in indebtedness under its term loan, its revolving credit agreement and two series of its senior notes maturing in years 2014 and 2020. Certain of the entities contributed to the Midstream Partnership by CenterPoint are obligated on approximately $363 million of indebtedness owed to a wholly owned subsidiary of CenterPoint that is scheduled to mature in 2017.

Subject to the exceptions provided below, pursuant to the terms of an Omnibus Agreement dated as of May 1, 2013 among OGE Energy, the ArcLight group and CenterPoint Energy, Inc., each of OGE Energy and CenterPoint Energy, Inc. will be required to hold or otherwise conduct all of its respective Midstream Operations (as defined below) located within the United States in the Midstream Partnership. This restriction will cease to apply to both OGE Energy and CenterPoint Energy, Inc. as soon as either OGE Energy or CenterPoint Energy, Inc. ceases to hold (i) any interest in the general partner of the Midstream Partnership or (ii) at least 20 percent of the limited partner interests of the Midstream Partnership. “Midstream Operations” generally means, subject to certain exceptions, the gathering, compression, treatment, processing, blending, transportation, storage, isomerization and fractionation of crude oil and natural gas, its associated production water and enhanced recovery materials such as carbon dioxide, and its respective constituents and the following products: methane, NGLs (Y-grade, ethane, propane, normal butane, isobutane and natural gasoline), condensate, and refined products and distillates (gasoline, refined product blendstocks, olefins, naphtha, aviation fuels, diesel, heating oil, kerosene, jet fuels, fuel oil, residual fuel oil, heavy oil, bunker fuel, cokes, and asphalts), to the extent such activities are located within the United States.

In addition, if OGE Energy or CenterPoint Energy, Inc. acquires any assets or equity of any person engaged in Midstream Operations with a value in excess of $50 million (or $100 million in the aggregate with such party’s other acquired Midstream Operations that have not been offered to the Midstream Partnership), the acquiring party will be required to offer the Midstream Partnership the opportunity to acquire such assets or equity for such value; provided, that the acquiring party will not be obligated to offer any such assets or equity to the Midstream Partnership if the acquiring party intends to cease using them in Midstream Operations within 12 months. If the Midstream Partnership does not exercise its option, then the acquiring party will be free to retain and operate such Midstream Operations; provided, however, that if the fair market value of such Midstream Operations is greater than 66 2/3 percent of the fair market value of all of the assets being acquired in such transaction, then the acquiring party will be required to dispose of such Midstream Operations within 24 months.

As long as the ArcLight group has board observation rights, the ArcLight group will be prohibited from pursuing any transaction independently from the Midstream Partnership (i) if the ArcLight group’s consent is required for the Midstream Partnership to pursue such transaction and (ii) the ArcLight group affirmatively votes not to consent to such transaction.

4.	Fair Value Measurements

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

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing.

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Enogex utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as

readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. Enogex has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize Enogex’s assets and liabilities that are measured at fair value on a recurring basis at March 31, 2013 and December 31, 2012 as well as reconcile Enogex’s commodity contracts fair value to PRM Assets and Liabilities on Enogex’s Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012. Enogex adopted the Financial Accounting Standards Board accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. Enogex posted $0.1 million and $0.2 million of collateral at March 31, 2013 and December 31, 2012, respectively, which has been included within netting adjustments in the table below. Enogex held no collateral at March 31, 2013 or December 31, 2012. Enogex has offset all amounts subject to master netting agreements in Enogex’s Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012. Enogex held no Level 1 investments at March 31, 2013 and no Level 3 investments at March 31, 2013 or December 31, 2012.


March 31, 2013
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Significant other observable inputs (Level 2)	$	1.8		$	0.7		$	3.6	$	4.6

Total fair value		1.8			0.7			3.6		4.6
Netting adjustments		(0.1	)		(0.2	)		—		—

Total	$	1.7		$	0.5		$	3.6	$	4.6


December 31, 2012
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	5.0		$	5.0		$	—	$	—
Significant other observable inputs (Level 2)		2.6			0.5			3.1		3.8

Total fair value		7.6			5.5			3.1		3.8
Netting adjustments		(5.0	)		(5.2	)		—		—
Total	$	2.6		$	0.3		$	3.1	$	3.8

(A)	Enogex uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B)

Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $8.5 million and $5.9 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(C)

Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.1 million and $1.2 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the fair value and carrying amount of Enogex’s financial instruments, including derivative contracts related to Enogex’s PRM activities, at March 31, 2013 and December 31, 2012.

March 31, 2013

December 31, 2012

(In millions)

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

PRM Assets

Energy Derivative Contracts

1.7

2.6

PRM Liabilities

Energy Derivative Contracts

0.5

0.3

Long-Term Debt

Enogex Senior Notes

448.5

492.1

448.4

493.4

Enogex Term Loan

250.0

250.0

The carrying value of the financial instruments included in the Condensed Consolidated Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of Enogex’s energy derivative contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties. The fair value of Enogex’s long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

5.	Derivative Instruments and Hedging Activities

Enogex is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. Enogex is also exposed to credit risk in its business operations.

Commodity Price Risk

Enogex has used forward physical contracts, commodity price swap contracts and commodity price option features to manage Enogex’s commodity price risk exposures in the past. Commodity derivative instruments used by Enogex are as follows:

•

NGLs put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;

•

natural gas swaps are used to manage Enogex’s keep-whole natural gas exposure associated with its processing operations and Enogex’s natural gas exposure associated with operating its gathering, transportation and storage assets; and

•

natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage Enogex’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by Enogex’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by Enogex’s gathering and processing business.

Enogex recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

Credit Risk

Enogex is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe Enogex money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, Enogex may be forced to enter into alternative arrangements. In that event, Enogex’s financial results could be adversely affected and Enogex could incur losses.

Cash Flow Hedges

For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income (Loss) and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. Enogex measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument. Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.

Enogex designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing operations and natural gas transportation and storage operations (operational gas hedges). Enogex also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex had no instruments designated as cash flow hedges at March 31, 2013.

Fair Value Hedges

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. Enogex includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.

At March 31, 2013 and December 31, 2012, Enogex had no derivative instruments that were designated as fair value hedges.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments are utilized in Enogex’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

At March 31, 2013, Enogex had the following derivative instruments that were not designated as hedging instruments.


(In millions)	Gross Notional Volume (A)
	Purchases		Sales
Natural gas (B)
Physical (C)(D)		7.0		72.6
Fixed Swaps/Futures		0.1		1.0
Basis Swaps		5.2		11.6

(A)	Natural gas in million British thermal units.

(B)	94.4 percent of the natural gas contracts have durations of one year or less, 4.1 percent have durations of more than one year and less than two years and 1.5 percent have durations of more than two years.

(C)	Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

(D)	Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex’s processing contracts, which are not derivative instruments and are excluded from the table above.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in Enogex’s Condensed Consolidated Balance Sheet at March 31, 2013 are as follows:


		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	1.3	$	—
	Other Current Assets		0.1		0.2
Physical Purchases/Sales	Current PRM		0.4		0.4

Total		$	1.8	$	0.6

Total Gross Derivatives (A)		$	1.8	$	0.6

(A)	See Note 4 for a reconciliation of Enogex’s total derivatives fair value to Enogex’s Condensed Consolidated Balance Sheet at March 31, 2013.

The fair value of the derivative instruments that are presented in Enogex’s Condensed Consolidated Balance Sheet at December 31, 2012 are as follows:


		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	—	$	0.5

Total		$	—	$	0.5


Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	2.2	$	—
	Other Current Assets		5.0		4.7
Physical Purchases/Sales	Current PRM		0.4		0.3

Total		$	7.6	$	5.0

Total Gross Derivatives (A)		$	7.6	$	5.5

(A)	See Note 4 for a reconciliation of Enogex’s total derivatives fair value to Enogex’s Condensed Consolidated Balance Sheet at December 31, 2012.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on Enogex’s Condensed Consolidated Statement of Income for the three months ended March 31, 2013.

Derivatives in Cash Flow Hedging Relationships

(In millions)

Amount Recognized in Other
Comprehensive Income

Amount Reclassified from
Accumulated Other
Comprehensive Income
(Loss) into Income

Amount Recognized
in Income

Natural Gas Financial Futures/Swaps

—

0.2

—

Total

—

0.2

—

Derivatives Not Designated as Hedging Instruments


(In millions)	Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(1.1	)

Total	$	(1.1	)

The following tables present the effect of derivative instruments on Enogex’s Condensed Consolidated Statement of Income for the three months ended March 31, 2012.

Derivatives in Cash Flow Hedging Relationships


(In millions)	Amount Recognized in Other Comprehensive Income		Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income		Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	0.3	$	5.2	$	—

Total	$	0.3	$	5.2	$	—

Derivatives Not Designated as Hedging Instruments


(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(2.4	)
Natural Gas Financial Futures/Swaps		0.4

Total	$	(2.0	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income (Loss) into income (effective portion) and amounts recognized in income (ineffective portion) for the three months ended March 31, 2013 and 2012, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the three months ended March 31, 2013 and 2012, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, Enogex would have been required to post no cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at March 31, 2013. Enogex could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

6.	Stock-Based Compensation

The following table summarizes Enogex’s compensation expense during the three months ended March 31, 2013 and 2012 related to Enogex’s performance units and restricted stock.


	Three Months Ended
	March 31,
(In millions)	2013		2012
Performance units
Total shareholder return	$	0.6		0.6
Earnings per share		0.1		0.2

Total performance units		0.7		0.8
Restricted stock		0.1		0.2

Total compensation expense	$	0.8		1.0

OGE Energy has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During the three months ended March 31, 2013, Enogex purchased 62,632 shares of OGE Energy’s treasury stock to satisfy the payouts of earned performance units and restricted stock grants. Enogex records treasury stock purchases from OGE Energy at cost. Purchased treasury stock is included in Member’s Interest in Enogex’s Condensed Consolidated Balance Sheet. During the three months ended March 31, 2013, there were 16,707 shares of new common stock issued to Enogex’s employees pursuant to OGE Energy’s stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. During the three months ended March 31, 2013, there were no shares of restricted stock returned to OGE Energy to satisfy tax liabilities.

The following table summarizes the activity of Enogex’s stock-based compensation during the three months ended March 31, 2013.


	Units/Shares		Fair Value
Grants
Performance units (Total shareholder return)		45,695	$	51.78
Conversions
Performance units (Total shareholder return) (A)		44,232		N/A
Performance units (Earnings per share) (A)		14,743		N/A

(A)	Performance units were converted based on a payout ratio of 200 percent of the target number of performance units granted in February 2010 and are included in the 16,707 and 62,632 shares of common stock issued during the three months ended March 31, 2013 as discussed above.

7.	Income Taxes

Prior to November 1, 2010, Enogex was a member of an affiliated group that filed consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, Enogex is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2009 or state and local tax examinations by tax authorities for years prior to 2005. Income taxes were generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Enogex earns Oklahoma state tax credits associated with its investments in natural gas processing facilities which further reduce Enogex’s effective tax rate.

Effective November 1, 2010, Enogex was converted to a partnership for income tax purposes and is not subject to Federal income taxes and most state income taxes, with the exception of Texas state margin taxes. For Federal and state income tax purposes other than Texas, all income, expenses, gains, losses and tax credits generated flow through to the owners, and accordingly do not result in a provision for income taxes.

8.	Long-Term Debt

At March 31, 2013, Enogex was in compliance with all of its debt agreements.

Effective May 1, 2013, the Midstream Partnership entered into a $1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex’s $400 million revolving credit facility was terminated.

9.	Intercompany Agreements

At March 31, 2013 and December 31, 2012, there were $217.9 million and $137.5 million, respectively, in outstanding advances from OGE Energy.

Prior to May 1, 2013, Enogex had an intercompany borrowing agreement with OGE Energy whereby Enogex had access to up to $350 million of OGE Energy’s revolving credit amount. This agreement was terminated on May 1, 2013 in conjunction with the formation of the Midstream Partnership. At March 31, 2013 and December 31, 2012, there were $204.9 million and $128.1 million, respectively, in outstanding intercompany borrowings under this agreement, which are included in the outstanding advances from OGE Energy above.

10.

Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of Enogex’s portion of OGE Energy’s Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows:

Net Periodic Benefit Cost


	Pension Plan						Postretirement Benefit Plans
	Three Months Ended						Three Months Ended
	March 31,						March 31,
(In millions)	2013			2012			2013			2012
Service cost	$	1.1		$	1.0		$	0.2		$	0.2
Interest cost		0.7			0.8			0.3			0.3
Expected return on plan assets		(0.6	)		(0.7	)		—			—
Amortization of net loss		0.6			0.6			0.4			0.4
Amortization of unrecognized prior service cost (A)		—			—			(0.3	)		(0.3	)

Net periodic benefit cost	$	1.8		$	1.7		$	0.6		$	0.6

(A)	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

The capitalized portion of net periodic pension benefit cost was $0.2 million during each of the three months ended March 31, 2013 and 2012. The capitalized portion of net periodic postretirement benefit cost was $0.2 million during the three months ended March 31, 2013 as compared to $0.1 million during the same period in 2012.

11.

Report of Business Segments

Previously, Enogex’s business was divided into three segments as follows: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. During the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented. As a result of this change, Enogex’s business is now divided into two segments for financial reporting purposes as follows: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. In reviewing its segment operating results, Enogex focuses on operating income as its measure of segment profit and loss, and, therefore, has presented this information below. The following tables summarize the results of Enogex’s business segments during the three months ended March 31, 2013 and 2012.

Three Months Ended March 31, 2013

Natural Gas
Transportation
and
Storage

Natural Gas
Gathering and
Processing

Eliminations

Total

(In millions)

Operating revenues

216.4

317.9

(70.0

)

464.3

Cost of goods sold

182.7

246.4

(69.9

)

359.2

Gross margin on revenues

33.7

71.5

(0.1

)

105.1

Other operation and maintenance

10.9

34.3

—

45.2

Depreciation and amortization

5.8

21.8

—

27.6

Taxes other than income

4.8

3.2

—

8.0

Operating income (loss)

12.2

(0.1

)

24.3

Total assets

2,453.0

1,948.9

(1,677.6

)

2,724.3


Three Months Ended March 31, 2012	Natural Gas Transportation and Storage		Natural Gas Gathering and Processing			Eliminations			Total
(In millions)
Operating revenues	$	169.5	$	304.5		$	(44.4	)	$	429.6
Cost of goods sold		131.8		217.9			(44.4	)		305.3

Gross margin on revenues		37.7		86.6			—			124.3
Other operation and maintenance		12.1		30.1			—			42.2
Depreciation and amortization		5.6		17.8			—			23.4
Impairment of assets		—		0.2			—			0.2
Gain on insurance proceeds		—		(7.5	)		—			(7.5	)
Taxes other than income		4.8		2.5			—			7.3

Operating income (loss)	$	15.2	$	43.5		$	—		$	58.7

Total assets	$	1,950.3	$	1,574.1		$	(1,182.6	)	$	2,341.8

12.

Commitments and Contingencies

Except as set forth in Note 13 below, the circumstances set forth in Notes 15 and 16 to Enogex’s Consolidated Financial Statements for the year ended December 31, 2012 appropriately represent, in all material respects, the current status of Enogex’s material commitments and contingent liabilities.

Other

In the normal course of business, Enogex 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, Enogex 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 Enogex’s Condensed Consolidated Financial Statements. At the present time, based on currently available information, except as otherwise stated in Note 13 below and in Notes 15 and 16 of Notes to Consolidated

Financial Statements for the year ended December 31, 2012 , Enogex 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 Enogex’s consolidated financial position, results of operations or cash flows.

13.

Regulation

Except as set forth below, the circumstances set forth in Note 16 to Enogex’s Consolidated Financial Statements for the year ended December 31, 2012 appropriately represent, in all material respects, the current status of Enogex’s regulatory matters.

Pending Regulatory Matter

2013 Fuel Filing

On March 1, 2013, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2013 through March 31, 2014). The deadline for interventions and protests on the filing was March 18, 2013 and no protests were filed. On June 25, 2013, the FERC accepted Enogex’s proposed zonal fuel percentages.

EX-99.2

Exhibit 99.2

LOGO

ENOGEX LLC Financial Report

LOGO

ENOGEX LLC

2012 FINANCIAL REPORT

TABLE OF CONTENTS


	Page
GLOSSARY OF TERMS		ii

FORWARD-LOOKING STATEMENTS		1

Financial Statements
Consolidated Statements of Income		2
Consolidated Statements of Comprehensive Income		3
Consolidated Statements of Cash Flows		4
Consolidated Balance Sheets		5
Consolidated Statements of Capitalization		7
Consolidated Statements of Changes in Member’s Interest		8
Notes to Consolidated Financial Statements		9

Report of Independent Auditors		45

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this report.


Abbreviation		Definition
401(k) Plan		Qualified defined contribution retirement plan

ArcLight group		Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively

Atoka		Atoka Midstream LLC joint venture

Chesapeake		Chesapeake Energy Marketing, Inc. and Chesapeake Exploration L.L.C.

Code		Internal Revenue Code of 1986

Cordillera		Cordillera Energy Partners III, LLC

EER		Enogex Energy Resources LLC, wholly-owned subsidiary of Enogex (prior to June 30, 2012, the legal name was OGE Energy Resources LLC)

Enogex		Enogex LLC, collectively with its subsidiaries

Enogex Holdings		Enogex Holdings LLC, the parent company of Enogex and a majority-owned subsidiary of OGE Holdings

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States

MEP		Midcontinent Express Pipeline, LLC

MMBtu		Million British thermal unit

MMcf/d		Million cubic feet per day

NGLs		Natural gas liquids

NYMEX		New York Mercantile Exchange

OG&E		Oklahoma Gas and Electric Company

OGE Energy		OGE Energy Corp., parent company of OGE Holdings

OGE Holdings		OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings

Oxbow		Oxbow Midstream, LLC

Pension Plan		Qualified defined benefit retirement plan

PHMSA		U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration

PRM		Price risk management

Restoration of Retirement Income Plan		Supplemental retirement plan to the Pension Plan

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Report 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. 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, actions of rating agencies and their impact on capital expenditures;

•

the ability of Enogex, Enogex Holdings and OGE Energy to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

•

prices and availability of natural gas and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee;

•

business conditions in the energy and natural gas midstream industries;

•

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

•

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 the energy and natural gas midstream industries;

•

environmental laws and regulations that may impact Enogex’s operations;

•

changes in accounting standards, rules or guidelines;

•

the cost of protecting assets against, or damage due to, terrorism or cyber attacks and other catastrophic events;

•

advances in technology; and

•

creditworthiness of suppliers, customers and other contractual parties.

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

Financial Statements

ENOGEX LLC

CONSOLIDATED STATEMENTS OF INCOME


Year ended December 31 (In millions)	2012			2011			2010
OPERATING REVENUES	$	1,608.6		$	1,787.1		$	1,707.7
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)		1,120.1			1,346.6			1,285.1

Gross margin on revenues		488.5			440.5			422.6

OPERATING EXPENSES
Other operation and maintenance		172.9			162.5			145.3
Depreciation and amortization		108.8			77.6			71.3
Impairment of assets		0.4			6.3			1.1
Gain on insurance proceeds		(7.5	)		(3.0	)		—
Taxes other than income		28.3			22.0			20.6

Total operating expenses		302.9			265.4			238.3

OPERATING INCOME		185.6			175.1			184.3

OTHER INCOME (EXPENSE)
Interest income		—			—			0.1
Other income		1.0			3.9			0.2
Other expense		(4.5	)		(1.3	)		(0.3	)

Net other income (expense)		(3.5	)		2.6			—

INTEREST EXPENSE
Interest on long-term debt		29.1			21.8			29.0
Other interest charges		3.5			1.1			1.4

Interest expense		32.6			22.9			30.4

INCOME BEFORE TAXES		149.5			154.8			153.9
INCOME TAX EXPENSE (BENEFIT)		0.2			0.2			(325.1	)

NET INCOME		149.3			154.6			479.0
Less: Net income (loss) attributable to noncontrolling interest		1.5			(1.3	)		2.9

NET INCOME ATTRIBUTABLE TO ENOGEX LLC	$	147.8		$	155.9		$	476.1

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

ENOGEX LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


Year ended December 31 (In millions)	2012			2011			2010 (A)
Net income	$	149.3		$	154.6		$	479.0
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.2 in 2010		2.2			1.4			0.8
Net gain (loss) arising during the period		(10.0	)		(12.7	)		6.3
Amortization of prior service cost, net of tax of $0.1 in 2010		(0.1	)		(0.1	)		(0.1	)
Postretirement plans:
Amortization of deferred net loss, net of tax of $0.3 in 2010		1.6			1.3			0.7
Net loss arising during the period		(3.0	)		(2.8	)		(2.8	)
Amortization of deferred net transition obligation		0.1			0.2			0.1
Amortization of prior service cost		(1.2	)		(1.2	)		—
Prior service credit arising during the period		—			7.0			—
Deferred commodity contracts hedging (gains) losses reclassified in net income, net of tax of $8.5 in 2010		(5.1	)		40.2			19.9
Deferred commodity contracts hedging gains (losses)		0.5			(5.5	)		(16.4	)

Other comprehensive income (loss), net of tax		(15.0	)		27.8			8.5

Comprehensive income (loss)		134.3			182.4			487.5

Less: Comprehensive income attributable to noncontrolling interest		1.5			(1.3	)		2.9

Total comprehensive income (loss) attributable to Enogex LLC	$	132.8		$	183.7		$	484.6

(A)	As of November 1, 2010, Enogex’s earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level.

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

ENOGEX LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year ended December 31 (In millions)	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	149.3		$	154.6		$	479.0
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization		112.6			78.2			71.3
Impairment of assets		0.4			6.3			1.1
Deferred income taxes, net		—			—			(352.7	)
(Gain) loss on disposition and abandonment of assets		4.2			(2.7	)		0.3
Gain on insurance proceeds		(7.5	)		(3.0	)		—
Stock-based compensation expense		1.7			4.1			—
Price risk management assets		5.2			(2.0	)		1.0
Price risk management liabilities		(5.0	)		18.5			8.1
Other assets		2.0			(6.5	)		(2.7	)
Other liabilities		6.5			14.7			7.2
Change in certain current assets and liabilities
Accounts receivable, net		5.3			(8.0	)		11.8
Accounts receivable—affiliates		0.6			3.1			0.2
Natural gas, natural gas liquids, materials and supplies inventories		6.1			(0.1	)		(7.0	)
Gas imbalance assets		(7.2	)		0.7			0.6
Other current assets		0.2			(0.2	)		0.5
Accounts payable		29.7			15.3			8.0
Income taxes payable—affiliates		—			—			76.5
Gas imbalance liabilities		(4.7	)		3.0			(5.3	)
Other current liabilities		6.6			(10.9	)		22.7

Net Cash Provided from Operating Activities		306.0			265.1			320.6

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(427.9	)		(412.1	)		(234.2	)
Acquisition of gathering assets		(78.6	)		(200.4	)		—
Reimbursement of capital expenditures		—			—			3.3
Proceeds from sale of assets		0.9			17.5			0.9
Proceeds from insurance		7.6			7.4			—

Net Cash Used in Investing Activities		(498.0	)		(587.6	)		(230.0	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		250.0			—			—
Contributions from parent		91.2			285.5			—
Changes in advances with parent		71.4			47.3			227.4
Proceeds from line of credit		—			150.0			115.0
Distributions to noncontrolling interest partner		—			—			(4.0	)
Retirement of long-term debt		—			—			(289.2	)
Purchase of OGE Energy treasury stock		(5.9	)		—			—
Distributions to parent		(67.5	)		(133.0	)		(49.4	)
Repayment of line of credit		(150.0	)		(25.0	)		(90.0	)

Net Cash Provided from (Used in) Financing Activities		189.2			324.8			(90.2	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2.8	)		2.3			0.4
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		4.6			2.3			1.9

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1.8		$	4.6		$	2.3

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

ENOGEX LLC

CONSOLIDATED BALANCE SHEETS


December 31 (In millions)	2012		2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1.8	$	4.6
Accounts receivable, less reserve of less than $0.1 each		134.7		140.1
Accounts receivable—affiliates		0.7		1.3
Natural gas and natural gas liquids inventories		16.5		23.7
Materials and supplies, at average cost		4.9		3.8
Price risk management		2.6		5.7
Gas imbalances		9.0		1.8
Assets held for sale		25.5		—
Other		3.7		3.9

Total current assets		199.4		184.9

OTHER PROPERTY AND INVESTMENTS, at cost		1.5		1.5
PROPERTY, PLANT AND EQUIPMENT
In service		2,869.4		2,386.5
Construction work in progress		130.7		160.6

Total property, plant and equipment		3,000.1		2,547.1
Less accumulated depreciation		738.3		658.0

Net property, plant and equipment		2,261.8		1,889.1

DEFERRED CHARGES AND OTHER ASSETS
Intangible assets, net		127.4		137.0
Goodwill		39.4		39.4
Price risk management		—		2.1
Other		21.8		23.3

Total deferred charges and other assets		188.6		201.8

TOTAL ASSETS	$	2,651.3	$	2,277.3

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

ENOGEX LLC

CONSOLIDATED BALANCE SHEETS (Continued)


December 31 (In millions)	2012			2011
LIABILITIES AND MEMBER’S INTEREST
CURRENT LIABILITIES
Accounts payable	$	200.2		$	170.5
Advances from parent		137.5			66.2
Customer deposits		1.8			1.9
Ad valorem taxes		12.9			8.5
Accrued interest		11.2			11.0
Accrued compensation due to OGE Holdings		10.7			12.2
Price risk management		0.3			0.4
Gas imbalances		5.0			9.7
Other		14.0			10.4

Total current liabilities		393.6			290.8

LONG-TERM DEBT		698.4			598.1
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations due to OGE Holdings		79.4			60.1
Deferred revenues		37.7			40.8
Price risk management		—			0.1
Other		5.1			4.5

Total deferred credits and other liabilities		122.2			105.5

Total liabilities		1,214.2			994.4

COMMITMENTS AND CONTINGENCIES (NOTE 15)
MEMBER’S INTEREST
Member’s interest		1,461.8			1,295.3
Accumulated other comprehensive loss		(45.0	)		(30.0	)

Total Enogex LLC member’s interest		1,416.8			1,265.3
Noncontrolling interest		20.3			17.6

Total member’s interest		1,437.1			1,282.9

TOTAL LIABILITIES AND MEMBER’S INTEREST	$	2,651.3		$	2,277.3

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

ENOGEX LLC

CONSOLIDATED STATEMENTS OF CAPITALIZATION


December 31 (In millions)		2012			2011
MEMBER’S INTEREST
Member’s interest		$	1,461.8		$	1,295.3
Accumulated other comprehensive loss			(45.0	)		(30.0	)

Total Enogex LLC member’s interest			1,416.8			1,265.3
Noncontrolling interest			20.3			17.6

Total member’s interest			1,437.1			1,282.9


LONG-TERM DEBT

SERIES	DUE DATE
6.875%	Senior Notes, Series Due July 15, 2014		200.0			200.0
1.72%	Term Loan Agreement, Due August 2, 2015		250.0			—
— %	Revolving Credit Agreement Due December 13, 2016		—			150.0
6.25%	Senior Notes, Series Due March 15, 2020		250.0			250.0
Unamortized discount			(1.6	)		(1.9	)

Total long-term debt			698.4			598.1

Total Capitalization		$	2,135.5		$	1,881.0

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

ENOGEX LLC

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S INTEREST


(In millions)	Member’s Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance at December 31, 2009	$	521.7		$	(41.1	)	$	20.0		$	500.6
Contribution of income taxes to parent		34.4			(25.2	)		—			9.2
Comprehensive income (loss)
Net income		476.1			—			2.9			479.0
Other comprehensive income (loss)		—			8.5			—			8.5

Comprehensive income (loss)		476.1			8.5			2.9			487.5

Distributions to parent		(49.4	)		—			—			(49.4	)
Distributions to noncontrolling interest partner		—			—			(4.0	)		(4.0	)

Balance at December 31, 2010	$	982.8		$	(57.8	)	$	18.9		$	943.9

Comprehensive income (loss)
Net income (loss)		155.9			—			(1.3	)		154.6
Other comprehensive income (loss)		—			27.8			—			27.8

Comprehensive income (loss)		155.9			27.8			(1.3	)		182.4

Contributions from parent		285.5			—			—			285.5
Distributions to parent		(133.0	)		—			—			(133.0	)
Contribution of OGE Energy stock compensation		4.1			—			—			4.1

Balance at December 31, 2011	$	1,295.3		$	(30.0	)	$	17.6		$	1,282.9

Comprehensive income (loss)
Net income		147.8			—			1.5			149.3
Other comprehensive income (loss)		—			(15.0	)		—			(15.0	)

Comprehensive income (loss)		147.8			(15.0	)		1.5			134.3

Contributions from parent		90.0			—			—			90.0
Contribution from noncontrolling interest partner		—			—			1.2			1.2
Distributions to parent		(67.5	)		—			—			(67.5	)
Contribution of OGE Energy stock compensation		2.1			—			—			2.1
Purchase of OGE Energy treasury stock		(5.9	)		—			—			(5.9	)

Balance at December 31, 2012	$	1,461.8		$	(45.0	)	$	20.3		$	1,437.1

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

ENOGEX LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization

Enogex is a Delaware single-member limited liability company, which is wholly-owned by Enogex Holdings, a partnership between OGE Energy and the ArcLight group. Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. During the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. This new organization is intended to facilitate the execution of Enogex’s strategy through an enhanced focus on asset optimization and active management of its growing natural gas, NGLs and condensate positions. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented. Enogex’s operations are now organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. Also, Enogex holds a 50 percent ownership interest in Atoka. Enogex consolidates Atoka in its Consolidated Financial Statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka.

On October 1, 2010, OGE Energy formed Enogex Holdings as a Delaware single-member limited liability company. On October 5, 2010, OGE Energy contributed its equity interest in Enogex to Enogex Holdings.

On October 5, 2010, OGE Energy entered into an investment agreement with the ArcLight group, whereby the ArcLight group contributed $183,150,000 in exchange for a membership interest in Enogex Holdings. As a result of this transaction, the ArcLight group acquired an indirect interest in Enogex and OGE Energy retained an indirect interest in Enogex. The investment agreement provides the ArcLight group the opportunity to increase its ownership interest by providing equity funding for capital expenditures associated with Enogex’s business plan. The transaction closed on November 1, 2010. As a result of the investment agreement described above and subsequent disproportionate contributions by the ArcLight group, at December 31, 2012, OGE Energy indirectly owns a 79.9 percent membership interest in Enogex Holdings. See Note 2 for a further discussion.

Upon formation of Enogex Holdings, Enogex’s earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level. As a result of the conversion of Enogex to a partnership, all deferred income tax assets and liabilities were eliminated by recording an income tax benefit and OGE Energy assumed $34.4 million of outstanding current income tax liabilities of Enogex equal to the September 2010 distribution to OGE Energy. Also, the Consolidated Statements of Income does not include an income tax provision for income earned on or after November 1, 2010 other than Texas state margin taxes.

At December 31, 2012, Enogex had six wholly-owned active subsidiaries, including Enogex Gathering & Processing LLC, EER, Enogex Products LLC, Enogex Gas Gathering LLC, Enogex Atoka LLC and Roger Mills Gas Gathering, LLC.

Principles of Consolidation

The Consolidated Financial Statements include the accounts and operations of Enogex and its subsidiaries. All significant intercompany transactions have been eliminated in consolidation.

Basis of Presentation

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of Enogex at December 31, 2012 and 2011 and the results of its operations and cash flows for the years ended December 31, 2012, 2011 and 2010, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of subsequent events for inclusion in Enogex’s Consolidated Financial Statements occurring after December 31, 2012 through February 27, 2013, the date Enogex’s financial statements were available to be issued, and, in the opinion of management, Enogex’s Consolidated Financial Statements and Notes contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates

In preparing the Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on Enogex’s Consolidated Financial Statements. However, Enogex believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to Enogex that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of Enogex where the most significant judgment is exercised includes the determination of Pension Plan assumptions, impairment estimates of long-lived assets (including intangible assets), contingency reserves, asset retirement obligations, fair value and cash flow hedges, the allowance for uncollectible accounts receivable, the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill.

Cash and Cash Equivalents

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

Allowance for Uncollectible Accounts Receivable

The allowance for uncollectible accounts receivable for Enogex is calculated based on outstanding accounts receivable balances over 180 days old. In addition, other outstanding accounts receivable balances less than 180 days old are reserved on a case-by-case basis when Enogex believes the collection of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable was less than $0.1 million at December 31, 2012 and 2011.

Credit risk is the risk of financial loss to Enogex if counterparties fail to perform their contractual obligations. Enogex maintains credit policies with regard to its counterparties that management believes minimize overall credit risk. These policies include the evaluation of a potential counterparty’s financial position (including credit rating, if available), collateral requirements under certain circumstances, the use of standardized agreements which provide for the netting of cash flows associated with a single counterparty and the monitoring of the financial position of existing counterparties on an ongoing basis.

Natural Gas Inventories

Natural gas inventory is held by Enogex, through its transportation and storage business, to provide operational support for its pipeline deliveries and to manage its leased storage capacity. In an effort to mitigate market price exposures, Enogex may enter into contracts or hedging instruments to protect the cash flows associated with its inventory. All natural gas inventory held by Enogex is valued using moving average cost and is recorded at the lower of cost or market. As part of its asset management activity, Enogex injects and withdraws natural gas into and out of inventory under the terms of its storage capacity contracts. During the years ended December 31, 2012, 2011 and 2010, Enogex recorded write-downs to market value related to natural gas storage inventory of $5.5 million, $4.8 million and $0.3 million, respectively. The cost of gas associated with sales of natural gas storage inventory is presented in Cost of Goods Sold on the Consolidated Statements of Income.

Gas Imbalances

Gas imbalances occur when the actual amounts of natural gas delivered from or received by Enogex’s pipeline system differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or made up in-kind depending on contractual terms. Enogex values all imbalances at an average of current market indices applicable to Enogex’s operations, not to exceed net realizable value.

Property, Plant and Equipment

All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and removal costs are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.

Cox City Plant Fire

On December 8, 2010, a fire occurred at Enogex’s Cox City natural gas processing plant destroying major components of one of the four processing trains, representing 120 MMcf/d of the total 180 MMcf/d of capacity, at that facility. The damaged train was replaced and the facility was returned to full service in September 2011. The total cost necessary to return the facility back to full service was $29.6 million. In the fourth quarter of 2011, Enogex received a partial insurance reimbursement of $7.4 million and recognized a gain of $3.0 million on insurance proceeds. In March 2012, Enogex reached a settlement agreement with its insurers in this matter. As a result of the settlement agreement, Enogex received additional reimbursements of $7.6 million and recognized a gain of $7.5 million on insurance proceeds in 2012.

In a period in which Enogex has an event that results in the recognition of a material gain or loss on an event that is covered by insurance proceeds, Enogex records an impairment loss for the book value of the damaged asset and an offsetting gain for insurance proceeds if recovery of the loss is considered probable. To the extent proceeds from an insurance settlement exceed recognized losses, Enogex records a gain on insurance proceeds in earnings as the receipts of proceeds are determined to be probable.

Enogex’s property, plant and equipment and related accumulated depreciation are divided into the following major classes at:

December 31, 2012 (In millions)

Total
Property,
Plant and
Equipment

Accumulated
Depreciation

Net
Property,
Plant and
Equipment

Natural gas transportation and storage assets

988.6

292.7

695.9

Natural gas gathering and processing assets

2,011.5

445.6

1,565.9

Total property, plant and equipment

3,000.1

738.3

2,261.8


December 31, 2011 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
Natural gas transportation and storage assets	$	967.0	$	277.0	$	690.0
Natural gas gathering and processing assets		1,580.1		381.0		1,199.1

Total property, plant and equipment	$	2,547.1	$	658.0	$	1,889.1

The unamortized computer software costs were $3.9 million and $4.4 million at December 31, 2012 and 2011, respectively. In 2012, 2011 and 2010, amortization expense for computer software costs was $3.1 million, $1.0 million and $2.2 million, respectively.

Intangible Assets

The following table below summarizes Enogex’s intangible assets and related accumulated amortization at:


(In millions)	Total Intangible Assets		Accumulated Amortization		Net Intangible Assets
December 31, 2012
Customer Contract / Acreage Dedication	$	141.9	$	14.5	$	127.4
December 31, 2011
Customer Contract / Acreage Dedication	$	141.9	$	4.9	$	137.0

In 2012, 2011 and 2010, amortization expense for intangible assets was $9.6 million, $2.1 million and $0.6 million, respectively, including amortization of certain customer-based intangible assets associated with the acquisition from Cordillera in November 2011, which is included in gross margin for financial reporting purposes.

The following table summarizes Enogex’s expected amortization of intangible assets for each of the next five years.


(In millions)	2013		2014		2015		2016		2017
Expected amortization of intangible assets	$	9.5	$	9.5	$	9.5	$	9.5	$	9.1

Depreciation and Amortization

Depreciation is computed principally on the straight-line method using estimated useful lives of three to 83 years for transportation and storage assets, three to 30 years for gathering and processing assets and three to 15 years for general plant assets. Amortization of intangible assets other than debt costs is computed using the straight-line method over the respective lives of the intangible assets ranging up to 20 years.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.

Asset Retirement Obligations

Enogex has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from three months to 50 years. Enogex also has certain asset retirement obligations primarily related to Enogex’s processing plants and compression sites that have not been recorded because Enogex cannot determine when these obligations will be incurred. Asset retirement obligations and related expense recognized during 2011 were less than $0.1 million.

The following table summarizes changes to Enogex’s asset retirement obligations during the year ended December 31, 2012.


(In millions)
Balance at January 1	$	—
Liabilities incurred (A)		0.4

Balance at December 31	$	0.4

(A)	Due to certain Enogex compression assets.

Assessing Impairment of Long-Lived Assets (Including Intangible Assets) and Goodwill

Enogex assesses its long-lived assets, including intangible assets with finite useful lives, for impairment when there is evidence that events or changes in circumstances require an analysis of the recoverability of an asset’s carrying amount. Estimates of future cash flows used to test the recoverability of long-lived assets and intangible assets shall include only the future cash flows (cash inflows less associated cash outflows) that are directly associated with and that are expected to arise as a direct result of the use and eventual disposition of the asset. The fair value of these assets is based on third-party evaluations, prices for similar assets, historical data and projected cash flows. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset. In 2011, Enogex recorded an impairment loss of $5.0 million, of which $2.5 million was the noncontrolling interest portion (see Note 5), related to the Atoka processing plant. Enogex recorded no other material impairments in 2012, 2011 or 2010.

As a result of the gas gathering acquisitions in November 2011, Enogex recorded goodwill of $39.4 million. Enogex assesses its goodwill for impairment at least annually as of October 1 by comparing the fair value of the reporting unit with its book value, including goodwill. Enogex utilizes the income approach (generally accepted valuation approach) to estimate the fair value of the reporting unit, also giving consideration to alternative methods such as the market and cost approaches. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. Enogex performs its goodwill impairment testing at the natural gas gathering and processing segment reporting unit level. Enogex recorded no impairments of goodwill in 2012.

Revenue Recognition

Operating revenues for gathering, processing, transportation and storage services for Enogex are recorded each month based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Operating revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated operating revenues are reflected in Accounts Receivable on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income. Enogex’s key natural gas producer customers in 2012 included Chesapeake Energy Marketing Inc., Apache Corporation and Devon Energy Production Company, L.P. In 2012, these customers accounted for 19.6 percent, 17.8 percent and 10.6 percent, respectively, of Enogex’s gathering and processing volumes. In 2012, Enogex’s top 10 natural gas producer customers accounted for 73.0 percent of Enogex’s gathering and processing volumes.

Enogex recognizes revenue from natural gas gathering, processing, transportation and storage services to third parties as services are provided. Revenue associated with NGLs is recognized when the production is sold. Enogex depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities. Additionally, one third party purchases 50 percent of the NGLs delivered to its system, which accounted for $297.3 million (43.3 percent), $285.4 million (38.8 percent) and $279.8 million (46.0 percent), respectively, of Enogex’s total NGLs sales for the years ended December 31, 2012, 2011 and 2010.

Enogex records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP. In August 2010, Enogex completed construction of transportation and compression facilities necessary to provide gas delivery service to a new natural gas-fired electric generation facility near Pryor, Oklahoma. Aid in Construction payments of $36.4 million received in excess of construction costs were recognized as Deferred Revenues on Enogex’s Consolidated Balance Sheet and are being amortized on a straight-line basis of $1.2 million per year over the life of the related firm transportation service agreement under which service commenced in June 2011. Also, in August 2011, Enogex and one of its five largest customers entered into new agreements, effective July 1, 2011, relating to the customer’s natural gas gathering and processing volumes on the Oklahoma portion of Enogex’s system. As a result, Enogex has recorded $7.1 million in Deferred Revenues on Enogex’s Consolidated Balance Sheet at December 31, 2012, which are expected to be recognized based on the estimated average fee per MMBtu processed by the end of 2014. Enogex has also recorded $1.5 million in Deferred Revenues on Enogex’s Consolidated Balance Sheet at December 31, 2012 in connection with other gathering and processing agreements.

Enogex engages in asset management and hedging activities related to the purchase and sale of natural gas and NGLs. Contracts utilized in these activities generally include purchases and sales for physical delivery, over-the-counter forward swap and options contracts and exchange traded futures and options. Enogex’s transactions that qualify as derivatives are reflected at fair value with the resulting unrealized gains and losses recorded as PRM Assets or Liabilities in the Consolidated Balance Sheets, classified as current or long-term based on their anticipated settlement, or against the brokerage deposits in Other Current Assets. The offsetting unrealized gains and losses from changes in the market value of open contracts are included in Operating Revenues in the Consolidated Statements of Income or in Other Comprehensive Income for derivatives designated and qualifying as cash flow hedges. Contracts resulting in delivery of a commodity are included as sales or purchases in the Consolidated Statements of Income as Operating Revenues or Cost of Goods Sold depending on whether the contract relates to the sale or purchase of the commodity.

Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by Enogex’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by Enogex’s gathering and processing business.

Income Taxes

Prior to November 1, 2010, Enogex was a member of an affiliated group that filed consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. Income taxes were generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Effective November 1, 2010, Enogex was converted to a partnership for income tax purposes and is not subject to Federal income taxes and most state income taxes, with the exception of Texas state margin taxes. For Federal and state income tax purposes other than Texas, all income, expenses, gains, losses and tax credits generated flow through to the owners, and accordingly do not result in a provision for income taxes.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes the components of accumulated other comprehensive loss at December 31, 2012 and 2011 attributable to Enogex. At both December 31, 2012 and 2011, there was no accumulated other comprehensive loss related to Enogex’s noncontrolling interest in Atoka.


December 31 (In millions)	2012			2011
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	(36.5	)	$	(28.7	)
Prior service cost		0.4			0.5
Postretirement plans:
Net loss		(13.7	)		(12.3	)
Prior service cost		4.6			5.8
Net transition obligation		—			(0.1	)
Deferred commodity contracts hedging gains		0.2			4.8

Total accumulated other comprehensive loss	$	(45.0	)	$	(30.0	)

The amounts in accumulated other comprehensive loss at December 31, 2012 that are expected to be recognized into earnings in 2013 are as follows:


(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	2.5
Prior service cost		(0.1	)
Postretirement plans:
Net loss		1.6
Prior service cost		(1.2	)
Deferred commodity contracts hedging gains		0.2

Total	$	3.0

Environmental Costs

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where Enogex has been designated as one of several potentially responsible parties, the amount accrued represents Enogex’s estimated share of the cost. Enogex had no accrued environmental liabilities at December 31, 2012 or 2011.

Related Party Transactions

OGE Energy charged operating costs to Enogex of $28.1 million, $27.0 million and $23.0 million in 2012, 2011 and 2010, respectively. OGE Energy charges operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Included in operating costs charged by OGE Energy are $2.4 million, $2.0 million and $2.7 million in 2012, 2011 and 2010, respectively, for payroll taxes and depreciation and amortization expense directly related to Enogex’s operations. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, either as overhead based primarily on labor costs or using the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

Enogex has a transportation contract with its affiliate, OG&E, to transport natural gas to OG&E’s natural gas-fired generation facilities. In each of 2012, 2011 and 2010, Enogex recorded revenues from OG&E of $34.8 million for transporting gas to OG&E’s natural gas-fired generating facilities. In 2012, 2011 and 2010, Enogex recorded revenues from OG&E of $12.9 million, $12.7 million and $12.7 million, respectively, for natural gas storage services. In 2012, 2011 and 2010, Enogex also recorded natural gas sales to OG&E of $20.4 million, $34.7 million and $50.3 million, respectively. In 2012, 2011 and 2010, Enogex recorded an expense from OG&E of $12.4 million, $8.1 million and $6.8 million, respectively, for electricity used at Enogex’s compression sites.

On July 1, 2009, OG&E and Enogex entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority. These transactions are for 50,000 MMBtu per month from August 2009 to December 2013 (see Note 7).

In 2012 and 2011, the parent made contributions to Enogex of $90.0 million and $285.5 million, respectively. In 2012, 2011 and 2010, Enogex made distributions to the parent of $67.5 million, $133.0 million and $49.4 million, respectively.

Omnibus Agreement

On April 1, 2008, Enogex entered into an omnibus agreement with OGE Energy. The omnibus agreement memorializes Enogex’s obligation to reimburse OGE Energy for costs incurred on behalf of Enogex and its subsidiaries. Enogex reimburses OGE Energy for: (i) the performance of general and administrative services for Enogex and its subsidiaries, such as legal, accounting, treasury, finance, investor relations, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, facilities, fleet management and media services and (ii) the payment of certain operating expenses of Enogex and its subsidiaries, including for compensation and benefits of operating personnel. Pursuant to the Enogex Holdings LLC Agreement, the members agreed to negotiate in good faith to replace the omnibus agreement with a new services agreement between Enogex and OGE Energy. Until the renegotiations are complete, OGE Energy continues to provides services and allocate costs to Enogex on a basis consistent with historical practice.

Seconding Agreement

On December 28, 2010, OGE Energy, OGE Holdings and Enogex Holdings entered into a Seconding Agreement whereby all of Enogex’s employees were seconded on January 1, 2011 to OGE Holdings. Under the Seconding Agreement, the employees will continue to perform services for Enogex and Enogex will reimburse OGE Holdings for all employment costs, including compensation and pension obligations, paid during the time of the Seconding Agreement.

Accrued Vacation

Enogex accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned, but not taken. As discussed above, all of Enogex’s employees were seconded on January 1, 2011 to OGE Holdings. Therefore, Enogex’s vacation obligations are payable to OGE Holdings.

Reclassifications

As discussed in Note 14, during the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented to conform to the 2012 presentation.

2. Investment Agreement with ArcLight

On October 5, 2010, OGE Energy entered into an investment agreement with the ArcLight group, whereby the ArcLight group contributed $183,150,000 in exchange for a membership interest in Enogex Holdings. As part of the investment agreement, OGE Energy and the ArcLight group have agreed to indemnify each other for breaches of representations, warranties and covenants contained in the investment agreement, and, in the case of OGE Energy, for certain tax matters related to Enogex, in each case subject to customary thresholds and survival periods.

Pursuant to the Enogex Holdings LLC Agreement, OGE Holdings’ and the ArcLight group’s rights to designate directors to the Board of Directors of Enogex Holdings will be determined by percentage ownership. OGE Holdings was initially entitled to designate three directors, and the ArcLight group was initially entitled to designate one director. As its ownership position increases, the ArcLight group will be entitled to increasing board representation. The ArcLight group will also be entitled, at various ownership thresholds, to certain special board approval rights with respect to certain significant actions taken by Enogex Holdings, as well as to appoint additional directors for Enogex Holdings.

To the extent Enogex cannot fund its capital expenditures through internal cash flow and use of its line of credit, Enogex will rely on capital contributions from Enogex Holdings, which, in turn, relies on contributions from OGE Energy and the ArcLight group. Until the ArcLight group owns 50 percent of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest. If necessary, the ArcLight group will fund between 50 percent and 90 percent of required capital contributions during that period. The remainder of the required capital contributions (i.e., between 10 percent and 50 percent) will be funded by OGE Holdings. In 2011, OGE Energy and the ArcLight group made contributions to Enogex Holdings of $70.9 million and $214.6 million, respectively, to fund a portion of Enogex’s 2011 capital requirements. Effective October 1, 2012, OGE Energy and the ArcLight group made contributions to Enogex Holdings of $45.0 million each to fund a portion of Enogex’s 2012 capital requirements.

Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings will make minimum quarterly distributions equal to the amount of cash required to cover OGE Energy’s anticipated tax liabilities plus $12.5 million, to be distributed in proportion to each member’s percentage ownership interest. As Enogex Holdings’ sole investment is in Enogex, it will rely on distributions from Enogex to fund its distribution obligations to its partners.

Under the terms of the Enogex Holdings LLC Agreement, each member and its affiliates are prohibited from independently pursuing a transaction in which a portion of the relevant assets are located in a designated core operating area, subject to certain exceptions. In addition, each member and its affiliates are prohibited from independently pursuing a transaction in which a portion of the relevant assets are located in a designated area of mutual interest unless (i) in the case of the ArcLight group, the collective ownership interest of the ArcLight group is less than five percent, (ii) the transaction falls within a defined category of passive financial investments, (iii) the proposed transaction has been disapproved by Enogex Holdings or (iv) the fair market value of the assets located in the area of mutual interest constitutes less than 50 percent of the total fair market value of the assets involved in the transaction. A member permitted to pursue a transaction independently pursuant to the foregoing is not required to offer the assets associated with such transaction to Enogex Holdings.

3. Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board issued “Balance Sheet: Disclosures about Offsetting Assets and Liabilities.” The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity’s balance sheet and a description of the rights of setoff associated with these assets and liabilities. The new standard is applicable for all entities that have financial instruments and derivative instruments shown using a net presentation on an entity’s balance sheet or are subject to a master netting arrangement. On January 31, 2013, the Financial Accounting Standards Board issued an update to this standard clarifying that the scope includes derivatives, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January 1, 2013 and is required to be applied retrospectively for all periods presented. Enogex adopted this new standard effective January 1, 2013 and will provide any additional disclosures necessary to comply with the new standard in its 2013 Annual Report.

In February 2013, the Financial Accounting Standards Board issued “Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” The new standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, the new standard requires an entity to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items in net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The new standard is applicable for all entities that issue financial statements that are presented in conformity with GAAP and that report items of other comprehensive income. The new standard is effective for interim and annual reporting periods for fiscal years beginning after December 15, 2012 and is required to be applied prospectively. Enogex adopted this new standard effective January 1, 2013 and will provide any additional disclosures necessary to comply with the new standard in its 2013 Annual Report.

4. Gas Gathering and Processing Acquisitions and Divestitures

Western Oklahoma Gathering Acquisition

On September 23, 2011, Enogex entered into the following agreements: an agreement with Cordillera, Oxbow and West Canadian Midstream LLC pursuant to which Enogex agreed to acquire 100 percent of the membership interest in Roger Mills Gas Gathering, LLC, an Oklahoma limited liability company that owns an approximately 60-mile natural gas gathering system located in Roger Mills County and Ellis County, Oklahoma; an agreement with Cordillera and Oxbow pursuant to which Enogex agreed to acquire an approximately 30-mile natural gas gathering system located in Roger Mills County, Oklahoma; and agreements with Cordillera and other producers pursuant to which such producers agreed to provide Enogex with long-term acreage dedication in the area served by the gathering systems encompassing approximately 100,000 net acres. The gathering systems are located in the Granite Wash area. The aggregate purchase price for these transactions was $200.4 million which was paid in cash primarily from contributions from OGE Energy and the ArcLight group as well as cash generated from operations and bank borrowings. The transactions closed on November 1, 2011.

The acquisition described above was accounted for as a business combination. The following table summarizes the purchase price allocation for this acquisition.


(In millions)
Current assets	$	5.4
Net property, plant and equipment		24.3
Intangible assets		136.3
Goodwill		39.4
Current liabilities assumed		(5.0	)

Total	$	200.4

The goodwill recognized from this acquisition primarily related to the benefits associated with combining the acquired assets with Enogex’s existing assets and operations. All of the goodwill is deductible for tax purposes. The transactions have provided Enogex with key new opportunities in the Granite Wash area. The goodwill has been recorded in the natural gas gathering and processing segment. At December 31, 2012 and 2011, there were no changes in the recognized amount of goodwill resulting from this acquisition, as discussed in Note 1.

Intangible assets consist of identifiable customer contracts and relationships. The acquired intangible assets are being amortized on a straight-line basis over the estimated useful life of 15 years. The net amount of intangible assets and related accumulated amortization was $125.7 million and $10.6 million at December 31, 2012 and $134.8 million and $1.5 million at December 31, 2011, respectively.

Granite Wash Gathering Acquisition

On August 1, 2012, Enogex entered into agreements with Chesapeake Midstream Gas Services, L.L.C. and Mid-America Midstream Gas Services, L.L.C., wholly-owned subsidiaries of Access Midstream Partners, L.P. and Chesapeake Midstream Development, L.P., respectively, pursuant to which Enogex agreed to acquire approximately 235 miles of natural gas gathering pipelines, right-of-ways and certain other midstream assets that provide natural gas gathering services in the greater Granite Wash area. The transactions closed on August 31, 2012. The aggregate purchase price for these transactions was approximately $78.6 million including reimbursement for certain permitted capital expenditures incurred during the period beginning June 1, 2012 and ending August 31, 2012. Enogex utilized cash generated from operations and bank borrowings to fund the purchase. In addition, Enogex also incurred acquisition-related costs of $3.5 million for sales taxes on acquired assets, which are included in taxes other than income.

The acquisition described above was accounted for as a business combination. The purchase price is preliminary and has been allocated to property, plant and equipment based on the estimated fair values at the acquisition date using a third-party valuation expert. This allocation may change in subsequent financial statements. Enogex is currently evaluating the preliminary purchase price allocation, which will be adjusted as additional information relative to the fair value of assets becomes available. Enogex expects the purchase price allocations to be completed by the end of the first quarter of 2013.

In connection with these agreements, Enogex entered into a gas gathering and processing agreement with Chesapeake effective September 1, 2012 pursuant to which Enogex began providing fee-based natural gas gathering, compression, processing and transportation services to Chesapeake with respect to certain acreage dedicated by Chesapeake.

Texas Panhandle Gathering Divestiture

On January 2, 2013, Enogex and one of its five largest customers entered into new agreements, effective January 1, 2013, relating to the customer’s gathering and processing volumes on the Texas portion of Enogex’s system. The effects of this new arrangement are (i) a fixed fee processing agreement replaces the previous keep-whole agreement, (ii) the acreage dedicated by the customer to Enogex for gathering and processing in Texas has been increased for an extended term and (iii) the sale by Enogex of certain gas gathering assets in the Texas Panhandle portion of Enogex’s system to this customer for cash proceeds of approximately $35 million. The sale of these assets was approved by Enogex’s Board of Directors in November 2012, therefore these assets were classified as held for sale on Enogex’s Consolidated Balance Sheet at December 31, 2012. Enogex expects to recognize a pre-tax gain of approximately $10 million in the first quarter of 2013 in its natural gas gathering and processing segment from the sale of these assets.

Harrah Gathering and Processing Divestiture

On April 1, 2011, Enogex completed the sale of its Harrah processing plant (38 MMcf/d of capacity) and the associated Wellston and Davenport gathering assets. The proceeds from the sale were $15.9 million and Enogex recorded a pre-tax gain in the second quarter of 2011 of $3.7 million in its natural gas gathering and processing segment.

5. Impairment of Assets

Atoka previously operated a 20 MMcf/d refrigeration processing plant which processed gas gathered in the Atoka area. The processing plant was leased on a month-to-month basis. In August 2011, management made a decision to use third-party processing exclusively for gathered volumes dedicated to Atoka and, therefore, to take the processing plant out of service and return it to the lessor in accordance with the rental agreement. As a result, in August 2011, Enogex recorded an impairment loss of $5.0 million in the natural gas gathering and processing segment associated with the cost it had capitalized in connection with the installation of the leased plant as it will not be able to recover the remaining value of the assets through future cash flows. The noncontrolling interest portion of the impairment loss was $2.5 million which was included in Net Income Attributable to Noncontrolling Interests in Enogex’s Consolidated Statement of Income.

6. Fair Value Measurements

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

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheets. Enogex has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize Enogex’s assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012 and 2011 as well as reconcile Enogex’s commodity contracts fair value to PRM Assets and Liabilities on Enogex’s Consolidated Balance Sheets at December 31, 2012 and 2011. There were no Level 3 investments held at December 31, 2012 or 2011.

December 31, 2012


	Commodity Contracts						Gas Imbalances (A)
(In millions)	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	5.0		$	5.0		$	—	$	—
Significant other observable inputs (Level 2)		2.6			0.5			3.1		3.8

Total fair value		7.6			5.5			3.1		3.8
Netting adjustments		(5.0	)		(5.2	)		—		—

Total	$	2.6		$	0.3		$	3.1	$	3.8


December 31, 2011

	Commodity Contracts						Gas Imbalances (A)
(In millions)	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	57.1		$	52.3		$	—	$	—
Significant other observable inputs (Level 2)		8.2			1.2			1.8		7.7

Total fair value		65.3			53.5			1.8		7.7
Netting adjustments		(57.5	)		(53.0	)		—		—

Total	$	7.8		$	0.5		$	1.8	$	7.7

(A)	Enogex uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B)

Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012 with no comparable item at December 31, 2011, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(C)

Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million and $2.0 million at December 31, 2012 and 2011, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes Enogex’s assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during 2011. There were no Level 3 investments held at December 31, 2012 or 2011.


	Commodity Contracts Assets
(In millions)	2011
Balance at January 1	$	13.3
Total gains or losses included in other comprehensive income		(5.4	)
Settlements		(7.9	)

Balance at December 31	$	—

The following table summarizes the fair value and carrying amount of Enogex’s financial instruments, including derivative contracts related to Enogex’s PRM activities, at:


	2012				2011
December 31 (In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
PRM Assets
Energy Derivative Contracts	$	2.6	$	2.6	$	7.8	$	7.8
PRM Liabilities
Energy Derivative Contracts	$	0.3	$	0.3	$	0.5	$	0.5
Long-Term Debt
Senior Notes	$	448.4	$	493.4	$	448.1	$	497.9
Revolving Credit Agreement		—		—		150.0		150.0
Term Loan		250.0		250.0		—		—

The carrying value of the financial instruments included in the Consolidated Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of Enogex’s energy derivative contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties. The fair value of Enogex’s long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

7. Derivative Instruments and Hedging Activities

Enogex is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivatives instruments is commodity price risk. Enogex is also exposed to credit risk in its business operations.

Commodity Price Risk

•

NGLs put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;

•

Enogex recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Consolidated Balance Sheets.

Credit Risk

Cash Flow Hedges

Enogex designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing operations and natural gas transportation and storage operations (operational gas hedges). Enogex also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex’s cash flow hedges at December 31, 2012 mature by the end of the first quarter of 2013.

Fair Value Hedges

At December 31, 2012 and 2011, Enogex had no derivative instruments that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

Quantitative Disclosures Related to Derivative Instruments

At December 31, 2012, Enogex had the following derivative instruments that were designated as cash flow hedges.


(In millions)	2012 Gross Notional Volume (A)
Enogex hedges
Natural gas sales		3.7

(A)	Natural gas in MMBtu’s.

At December 31, 2012, Enogex had the following derivative instruments that were not designated as hedging instruments.


(In millions)	Gross Notional Volume (A)
(In millions)	Purchases		Sales
Natural gas (B)
Physical (C)(D)		7.0		30.1
Fixed Swaps/Futures		16.2		18.5
Basis Swaps		7.3		6.7

(A)	Natural gas in MMBtu’s.

(B)	95.1 percent of the natural gas contracts have durations of one year or less, 2.9 percent have durations of more than one year and less than two years and 2.0 percent have durations of more than two years.

(C)	Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

(D)	Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex’s processing contracts, which are not derivative instruments and are excluded from the table above.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in Enogex’s Consolidated Balance Sheet at December 31, 2012 are as follows:


		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
Instrument	Balance Sheet Location	(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	—	$	0.5

Total		$	—	$	0.5

Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	2.2	$	—
	Other Current Assets		5.0		4.7
Physical Purchases/Sales	Current PRM		0.4		0.3

Total		$	7.6	$	5.0

Total Gross Derivatives (A)		$	7.6	$	5.5

(A)	See Note 6 for a reconciliation of Enogex’s total derivatives fair value to Enogex’s Consolidated Balance Sheet at December 31, 2012.

The fair value of the derivative instruments that are presented in Enogex’s Consolidated Balance Sheet at December 31, 2011 are as follows:


		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
Instrument	Balance Sheet Location	(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	5.2	$	0.3

Total		$	5.2	$	0.3

Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	4.4	$	—
	Other Current Assets		49.9		49.9
Physical Purchases/Sales	Current PRM		3.1		0.4
	Non-Current PRM		0.3		0.1
Financial Options	Other Current Assets		2.4		2.8

Total		$	60.1	$	53.2

Total Gross Derivatives (A)		$	65.3	$	53.5

(A)	See Note 6 for a reconciliation of Enogex’s total derivatives fair value to Enogex’s Consolidated Balance Sheet at December 31, 2011.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on Enogex’s Consolidated Statement of Income in 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)

Amount
Recognized in
Other
Comprehensive
Income (A)

Amount
Reclassified
from
Accumulated
Other
Comprehensive
Income (Loss)
into Income

Amount
Recognized
in Income

Natural Gas Financial Futures/Swaps

0.5

5.2

—

Total

0.5

5.2

—

(A)	The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income (Loss) at December 31, 2012 that is expected to be reclassified into income within the next 12 months is a gain of $0.2 million.

Derivatives Not Designated as Hedging Instruments


(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(11.7	)
Natural Gas Financial Futures/Swaps		0.5

Total	$	(11.2	)

The following tables present the effect of derivative instruments on Enogex’s Consolidated Statement of Income in 2011.

Derivatives in Cash Flow Hedging Relationships


(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
NGLs Financial Options	$	(8.4	)	$	(9.8	)	$	—
Natural Gas Financial Futures/Swaps		2.9			(30.4	)		—

Total	$	(5.5	)	$	(40.2	)	$	—

Derivatives Not Designated as Hedging Instruments


(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(10.0	)
Natural Gas Financial Futures/Swaps		2.4

Total	$	(7.6	)

The following tables present the effect of derivative instruments on Enogex’s Consolidated Statement of Income in 2010.

Derivatives in Cash Flow Hedging Relationships


(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
NGLs Financial Options	$	(9.7	)	$	1.2		$	—
NGLs Financial Futures/Swaps		1.7			(3.7	)		—
Natural Gas Financial Futures/Swaps		(14.9	)		(25.9	)		0.2

Total	$	(22.9	)	$	(28.4	)	$	0.2

Derivatives Not Designated as Hedging Instruments


(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(11.7	)
Natural Gas Financial Futures/Swaps		4.0

Total	$	(7.7	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income (Loss) into income (effective portion) and amounts recognized in income (ineffective portion) for the years ended December 31, 2012, 2011 and 2010, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2012, 2011 and 2010, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, at December 31, 2012, Enogex would have been required to post $0.2 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at December 31, 2012. In addition, Enogex could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

8. Stock-Based Compensation

In 2008, OGE Energy adopted, and its shareowners approved, the 2008 Stock Incentive Plan. Under the 2008 Stock Incentive Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to 2,750,000 shares under the 2008 Stock Incentive Plan.

The following table summarizes Enogex’s compensation expense for the years ended December 31, 2012 and 2011 and Enogex’s pre-tax compensation expense and related income tax benefit for the year ended December 31, 2010 related to performance units and restricted stock for Enogex employees.


Year ended December 31 (In millions)	2012		2011		2010
Performance units
Total shareholder return	$	2.3	$	2.1	$	1.6
Earnings per share		1.1		1.4		0.6

Total performance units		3.4		3.5		2.2
Restricted stock		0.5		0.6		0.6

Total compensation expense	$	3.9	$	4.1	$	2.8

Income tax benefit (A)	$	—	$	—	$	0.9

(A)	As of November 1, 2010, Enogex’s earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level.

OGE Energy has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. In 2012, Enogex purchased 117,368 shares of OGE Energy’s treasury stock to satisfy the payout of earned performance units and restricted stock grants. Enogex records treasury stock purchases from OGE Energy at cost. Purchased treasury stock is included in Member’s Interest in Enogex’s Consolidated Balance Sheet. In 2012, 2011 and 2010, there were 12,969 shares, 74,447 shares and 18,559 shares, respectively, of new common stock issued to Enogex’s employees pursuant to OGE Energy’s stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. In 2012, there were 5,199 shares of restricted stock returned to OGE Energy to satisfy tax liabilities.

Performance Units

Under the 2008 Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of OGE Energy’s common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the 2008 Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant’s number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle.

The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of OGE Energy’s common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a three-year award cycle (i.e., three-year cliff vesting period) is dependent on OGE Energy’s total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of OGE Energy’s common stock based on OGE Energy’s earnings per share growth over a three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy’s Board of Directors. All of these performance units are classified as equity in OGE Energy’s Consolidated Balance Sheet. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of OGE Energy’s Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.

Performance Units – Total Shareholder Return

The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are not accrued or paid during the performance period and, therefore, are not included in the fair value calculation. Expected price volatility is based on the historical volatility of OGE Energy’s common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to OGE Energy’s performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.


	2012			2011			2010
Number of units granted to Enogex employees		46,944			59,914			47,355
Fair value of units granted	$	51.82		$	46.09		$	39.43
Expected dividend yield		3.0	%		3.2	%		3.9	%
Expected price volatility		22.0	%		33.0	%		34.0	%
Risk-free interest rate		0.38	%		1.40	%		1.42	%
Expected life of units (in years)		2.87			2.87			2.87

Performance Units – Earnings Per Share

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


	2011		2010
Number of units granted to Enogex employees		19,971		15,784
Fair value of units granted	$	41.61	$	32.44

In 2012, the performance unit grant for Enogex employees that was previously based on earnings per share was changed to a cash payment that entitles Enogex employees to receive from 0 percent to 200 percent of the performance units granted based on the growth in Enogex’s EBITDA over a three-year award cycle (i.e., three-year cliff vesting period) compared to a growth target set by the Compensation Committee of OGE Energy’s Board of Directors.

Restricted Stock

Under the 2008 Stock Incentive Plan and beginning in 2008, OGE Energy issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted stock was based on the closing market price of OGE Energy’s common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a three-year vesting period. Also, Enogex treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the restricted stock is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to OGE Energy’s restricted stock. The number of shares of restricted stock granted related to Enogex’s employees and the grant date fair value are shown in the following table.


	2012		2011		2010
Shares of restricted stock granted to Enogex employees		2,891		14,526		24,615
Fair value of restricted stock granted	$	51.73	$	49.27	$	40.43

A summary of the activity for OGE Energy’s performance units and restricted stock applicable to Enogex’s employees at December 31, 2012 and changes in 2012 are shown in the following table.


	Performance Units
	Total Shareholder Return					Earnings Per Share					Restricted Stock
(dollars in millions)	Number of Units			Aggregate Intrinsic Value		Number of Units			Aggregate Intrinsic Value		Number of Shares			Aggregate Intrinsic Value
Units/Shares Outstanding at 12/31/11		185,266					61,755					32,268
Granted (A)		46,944					—					2,891
Converted (B)		(70,544	)	$	7.4		(23,515	)	$	2.5		N/A
Vested		N/A					N/A					(13,928	)	$	0.7
Forfeited		(19,551	)				(5,139	)				(1,876	)

Units/Shares Outstanding at 12/31/12		142,115		$	12.1		33,101		$	3.7		19,355		$	1.1

Units/Shares Fully Vested at 12/31/12		44,232		$	5.0		14,743		$	1.7

(A)	For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(B)	These amounts represent performance units that vested at December 31, 2011 which were settled in February 2012.

A summary of the activity for OGE Energy’s non-vested performance units and restricted stock applicable to Enogex’s employees at December 31, 2012 and changes in 2012 are shown in the following table.


	Performance Units
	Total Shareholder Return					Earnings Per Share					Restricted Stock
	Number of Units			Weighted- Average Grant Date Fair Value		Number of Units			Weighted- Average Grant Date Fair Value		Number of Shares			Weighted- Average Grant Date Fair Value
Units/Shares Non-Vested at 12/31/11		114,722		$	43.08		38,240		$	37.47		32,268		$	43.99
Granted		46,944	(A)	$	51.82		—		$	—		2,891		$	51.73
Vested		(44,232	)	$	39.43		(14,743	)	$	32.44		(13,928	)	$	42.50
Forfeited		(19,551	)	$	44.71		(5,139	)	$	37.08		(1,876	)	$	43.82

Units/Shares Non-Vested at 12/31/12		97,883		$	48.60		18,358		$	41.61		19,355		$	46.24

Units/Shares Expected to Vest		88,126					16,860					19,355

(A)	For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

Fair Value of Vested Performance Units and Restricted Stock

A summary of Enogex’s fair value for its vested performance units and restricted stock is shown in the following table.


Year ended December 31 (In millions)	2012		2011		2010
Performance units
Total shareholder return	$	1.7	$	1.8	$	1.2
Earnings per share		1.0		0.9		0.4
Restricted stock		0.6		0.5		0.1

Unrecognized Compensation Cost

A summary of Enogex’s unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.


December 31, 2012	Unrecognized Compensation Cost (in millions)		Weighted Average to be Recognized (in years)
Performance units
Total shareholder return	$	2.1		1.64
Earnings per share		0.9		1.14

Total performance units		3.0
Restricted stock		0.3		1.74

Total	$	3.3

Stock Options

OGE Energy last issued stock options in 2004 and as of December 31, 2006, all stock options were fully vested and expensed. All stock options have a contractual life of 10 years. A summary of the activity for OGE Energy’s stock options applicable to Enogex’s employees at December 31, 2012 and changes during 2012 are shown in the following table.


(dollars in millions)	Number of Options			Weighted-Average Exercise Price		Aggregate Intrinsic Value		Weighted-Average Remaining Contractual Term
Options Outstanding at 12/31/11		4,200		$	23.57
Exercised		(2,600	)	$	23.57	$	0.1

Options Outstanding at 12/31/12		1,600		$	23.57	$	0.1		1.06 years

Options Fully Vested and Exercisable at 12/31/12		1,600		$	23.57	$	0.1		1.06 years

A summary of the activity for Enogex’s exercised stock options in 2012, 2011 and 2010 are shown in the following table.


Year ended December 31 (In millions)	2012		2011		2010
Intrinsic value (A)	$	0.1	$	0.2	$	—

(A)	The difference between the market value on the date of exercise and the option exercise price.

9. Supplemental Cash Flow Information

During 2012, 2011 and 2010, there were no investing or financing activities for Enogex that affected recognized assets and liabilities which did not result in cash receipts or payments. The following table discloses information about cash flow activities that include cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.


Year ended December 31 (In millions)	2012		2011		2010
SUPPLEMENTAL CASH FLOW INFORMATION
Cash Paid During the Period for
Interest (net of interest capitalized) (A)	$	31.0	$	24.2	$	38.1
Income taxes (net of income tax refunds) (B)		0.2		0.2		(32.4	)

(A)	Net of interest capitalized of $4.5 million, $8.7 million and $2.5 million in 2012, 2011 and 2010, respectively.

(B)	As of November 1, 2010, Enogex’s earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level.

10. Income Taxes

The items comprising income tax expense are as follows:


Year ended December 31 (In millions)	2012		2011		2010
Provision for Current Income Taxes
Federal	$	—	$	—	$	27.0
State		0.2		0.2		0.6

Total Provision for Current Income Taxes		0.2		0.2		27.6

Benefit for Deferred Income Taxes, net
Federal		—		—		(327.8	)
State		—		—		(24.9	)

Total Benefit for Deferred Income Taxes, net		—		—		(352.7	)

Total Income Tax Expense (Benefit)	$	0.2	$	0.2	$	(325.1	)

The following schedule reconciles the statutory Federal tax rate to the effective income tax rate:


Year ended December 31	2012			2011			2010
Statutory Federal tax rate		—	%		—	%		35.0	%
State income taxes, net of Federal income tax benefit		0.1			0.1			2.8
Medicare Part D subsidy		—			—			1.5
Income attributable to noncontrolling interest		—			—			(1.0	)
Partnership earnings not subject to income tax		—			—			(5.4	)
Conversion to partnership		—			—			(244.4	)
Other		—			—			0.3

Effective income tax rate		0.1	%		0.1	%		(211.2	)%

At December 31, 2012 and 2011, Enogex had no material unrecognized tax benefits related to uncertain tax positions.

As a result of the conversion to a partnership in 2010, all deferred income tax assets and liabilities were eliminated by recording a provision for income tax benefit of $376.3 million. Therefore, there are no deferred income tax assets and liabilities balances at December 31, 2012 and 2011.

11. Long-Term Debt

A summary of Enogex’s long-term debt is included in the Consolidated Statements of Capitalization. At December 31, 2012, Enogex was in compliance with all of its debt agreements.

Enogex has a $400 million revolving credit agreement which expires December 13, 2016. At December 31, 2012, there were no outstanding borrowings under Enogex’s revolving credit agreement.

Maturities of Enogex’s long-term debt during the next five years consist of $200 million and $250 million in years 2014 and 2015, respectively. There are no maturities of Enogex’s long-term debt in years 2013, 2016 or 2017.

Enogex has previously incurred costs related to debt refinancings. Unamortized debt expense is classified as Deferred Charges and Other Assets and the unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Consolidated Balance Sheets and are being amortized over the life of the respective debt.

12. Intercompany Agreements

At December 31, 2012 and 2011, there were $137.5 million and $66.2 million, respectively, in outstanding advances from OGE Energy.

Enogex has an intercompany borrowing agreement with OGE Energy whereby Enogex has access to up to $350 million of OGE Energy’s revolving credit amount. This agreement has a termination date of April 1, 2015. At December 31, 2012 and 2011, there were $128.1 million and $52.1 million, respectively, in outstanding intercompany borrowings under this agreement, which are included in the outstanding advances from OGE Energy above.

OGE Energy’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy’s credit facility could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy’s and Enogex’s short-term borrowings, but a reduction in OGE Energy’s or Enogex’s credit rating would not result in any defaults or accelerations. Any future downgrade of OGE Energy or Enogex could also lead to higher long-term borrowing costs and, if below investment grade, would require Enogex to post collateral or letters of credit.

13. Retirement Plans and Postretirement Benefit Plans

Pension Plan and Restoration of Retirement Income Plan

Enogex’s employees participate in OGE Energy’s Pension Plan and Restoration of Retirement Income Plan. In October 2009, OGE Energy’s Pension Plan and OGE Energy’s 401(k) Plan were amended, effective January 1, 2010 to provide eligible employees a choice to select a future retirement benefit combination from OGE Energy’s Pension Plan and OGE Energy’s 401(k) Plan.

Employees hired or rehired on or after December 1, 2009 do not participate in the Pension Plan but are eligible to participate in the 401(k) Plan where, for each pay period, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant’s contributions up to five percent of compensation.

It is OGE Energy’s policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by OGE Energy’s actuarial consultants. During 2012 and 2011, OGE Energy made contributions to its Pension Plan of $35 million and $50 million, respectively, none of which was Enogex’s portion, to help ensure that the Pension Plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. During 2013, OGE Energy expects to contribute up to $35 million to its Pension Plan, none of which is expected to be Enogex’s portion. The expected contribution to the Pension Plan during 2013 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

OGE Energy provides a Restoration of Retirement Income Plan to those participants in OGE Energy’s Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under OGE Energy’s Pension Plan in the absence of limitations imposed by the Federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.

The following table presents the status of Enogex’s portion of OGE Energy’s Pension Plan and Restoration of Retirement Income Plan at December 31, 2012 and 2011. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss in Enogex’s Consolidated Balance Sheet. The amounts in Accumulated Other Comprehensive Loss represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods.


	Pension Plan						Restoration of Retirement Income Plan
December 31 (In millions)	2012			2011			2012			2011
Benefit obligations	$	(81.8	)	$	(68.4	)	$	(1.2	)	$	(0.9	)
Fair value of plan assets		35.1			36.0			—			—

Funded status at end of year	$	(46.7	)	$	(32.4	)	$	(1.2	)	$	(0.9	)

The following table summarizes the benefit payments Enogex expects to pay related to its Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure OGE Energy’s benefit obligation at the end of the year and include benefits attributable to estimated future employee service.


(In millions)	Projected Benefit Payments
2013	$	5.4
2014		7.8
2015		7.5
2016		7.7
2017		7.9
After 2017		40.0

Plan Investments, Policies and Strategies

The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan’s funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.


Projected Benefit Obligation Funded Status Thresholds	<90%			95%			100%			105%			110%			115%			120%
Fixed income		50	%		58	%		65	%		73	%		80	%		85	%		90	%
Equity		50	%		42	%		35	%		27	%		20	%		15	%		10	%

Total		100	%		100	%		100	%		100	%		100	%		100	%		100	%

Within the portfolio’s overall allocation to equities, the funds are allocated according to the guidelines in the table below.


Asset Class	Target Allocation			Minimum			Maximum
Domestic All-Cap/Large Cap Equity		50	%		50	%		60	%
Domestic Mid-Cap Equity		15	%		5	%		25	%
Domestic Small-Cap Equity		15	%		5	%		25	%
International Equity		20	%		10	%		30	%

OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of Enogex’s members and OGE Energy’s Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager’s respective portfolio.

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

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors’ investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:


Asset Class		Comparative Benchmark(s)
Core Fixed Income		Barclays Capital Aggregate Index
Interest Rate Sensitive Fixed Income		Barclays Capital Aggregate Index
Long Duration Fixed Income		Barclays Long Government/Credit
Equity Index		Standard & Poor’s 500 Index
All-Cap Equity		Russell 3000 Index
		Russell 3000 Value Index
Mid-Cap Equity		Russell Midcap Index
		Russell Midcap Value Index
Small-Cap Equity		Russell 2000 Index
		Russell 2000 Value Index
International Equity		Morgan Stanley Capital Investment ACWI ex-US

The fixed income manager is expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody’s Investors Services, Standard & Poor’s Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio’s market value in convertible bonds as long as the securities purchased meet the quality guidelines. The purchase of any of OGE Energy’s equity, debt or other securities is prohibited.

The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-US Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-US Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the United States. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (10 percent for mid-cap and small-cap equity managers) after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of OGE Energy’s Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of OGE Energy’s equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager’s organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

Plan Investments

The following tables summarize Enogex’s portion of OGE Energy’s Pension Plan’s investments that are measured at fair value on a recurring basis at December 31, 2012 and 2011. There were no Level 3 investments held by the Pension Plan at December 31, 2012 and 2011.

(In millions)

December 31, 2012

Level 1

Level 2

Common stocks

U.S. common stocks

232.2

—

Foreign common stocks

39.9

—

U.S. Government obligations

U.S. treasury notes and bonds (A)

138.6

—

Mortgage-backed securities

55.8

—

55.8

Bonds, debentures and notes (B)

Corporate fixed income and other securities

98.4

—

98.4

Mortgage-backed securities

13.5

—

13.5

Commingled fund (C)

34.9

—

34.9

Common/collective trust (D)

25.6

—

25.6

Foreign government bonds

3.9

—

3.9

U.S. municipal bonds

0.8

—

0.8

Interest-bearing cash

0.2

—

Forward contracts

Receivable (foreign currency)

0.4

—

0.4

Payable (foreign currency)

(0.4

)

—

(0.4

)

Total Plan investments

643.8

410.9

232.9

Receivable from broker for securities sold

0.8

Interest and dividends receivable

2.8

Payable to broker for securities purchased

(21.4

)

Plan investments attributable to affiliates

(590.9

)

Total Plan assets

35.1


(In millions)	December 31, 2011			Level 1		Level 2
Common stocks
U.S. common stocks	$	179.7		$	179.7	$	—
Foreign common stocks		59.5			59.5		—
U.S. Government obligations
U.S. treasury notes and bonds (A)		118.8			118.8		—
Mortgage-backed securities		72.0			—		72.0
Other securities		1.0			—		1.0
Bonds, debentures and notes (B)
Corporate fixed income and other securities		95.3			—		95.3
Mortgage-backed securities		17.2			—		17.2
Commingled fund (E)		38.5			—		38.5
Common/collective trust (D)		29.6			—		29.6
Foreign government bonds		2.9			—		2.9
Interest-bearing cash		2.1			2.1		—
U.S. municipal bonds		1.7			—		1.7
Preferred stocks (foreign)		0.6			0.6		—
Forward contracts
Receivable (foreign currency)		4.1			—		4.1
Payable (foreign currency)		(4.1	)		—		(4.1	)

Total Plan investments	$	618.9		$	360.7	$	258.2

Receivable from broker for securities sold		4.8
Interest and dividends receivable		3.1
Payable to broker for securities purchased		(37.0	)
Plan investments attributable to affiliates		(553.8	)

Total Plan assets	$	36.0

(A)	This category represents U.S. treasury notes and bonds with a Moody’s Investors Services rating of Aaa and Government Agency Bonds with a Moody’s Investors Services rating of A1 or higher.

(B)	This category primarily represents U.S. corporate bonds with an investment grade rating at or above Baa3 or BBB- by Moody’s Investors Services, Standard & Poor’s Ratings Services or Fitch Ratings.

(C)	This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

(D)

This category represents units of participation in an investment pool which primarily invests in foreign or domestic bonds, debentures, mortgages, equipment or other trust certificates, notes, obligations issued or guaranteed by the U.S. Government or its agencies, bank certificates of deposit, bankers’ acceptances and repurchase agreements, high grade commercial paper and other instruments with money market characteristics with a fixed or variable interest rate. There are no restrictions on redemptions in the common/collective trust.

(E)	This category represents units of participation in a commingled fund that primarily invest in stocks and bonds of U.S. companies.

The three levels defined in the fair value hierarchy and examples of each are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common and preferred stocks, U.S. treasury notes and bonds, mutual funds and interest-bearing cash.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage-backed securities, other U.S. Government obligations, commingled fund, a common/collective trust, U.S. municipal bonds, foreign government bonds, a repurchase agreement, money market fund and forward contracts.

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan’s own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Postretirement Benefit Plans

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

In January 2011, OGE Energy adopted several amendments to its retiree medical plan. Effective January 1, 2012, OGE Energy’s contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level and OGE Energy covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. Also, effective January 1, 2012, Medicare-eligible retirees are no longer eligible to participate in the retiree medical plan. Instead, OGE Energy began providing Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to OGE Energy’s sponsored health reimbursement arrangement. The contribution was determined based on OGE Energy’s expected average 2011 premium for medical and drug coverage. Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses. The effect of these plan amendments was reflected in OGE Energy’s 2011 Consolidated Balance Sheet as a reduction to the accumulated postretirement benefit obligation of $6.9 million and an increase in other comprehensive income of $6.9 million.

Plan Investments

The following tables summarize Enogex’s portion of OGE Energy’s postretirement benefit plans investments that are measured at fair value on a recurring basis at December 31, 2012 and 2011. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2012 and 2011.

(In millions)

December 31, 2012

Level 1

Level 3

Group retiree medical insurance contract (A)

53.3

—

53.3

Mutual funds investment

U.S. equity investments

6.0

—

Money market funds investment

0.3

—

Total Plan investments

59.6

6.3

53.3

Plan investments attributable to affiliates

(59.6

)

Total Plan assets

—


(In millions)	December 31, 2011			Level 1		Level 3
Group retiree medical insurance contract (A)	$	54.3		$	—	$	54.3
Mutual funds investment
U.S. equity investments		5.3			5.3		—
Money market funds investment		0.7			0.7		—
Cash		0.7			0.7		—

Total Plan investments	$	61.0		$	6.7	$	54.3

Plan investments attributable to affiliates		(61.0	)

Total Plan assets	$	—

(A)	This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities.

The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans pro-rata share of the total assets in the contract.

The following table summarizes the postretirement benefit plans investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).


Year ended December 31 (In millions)	2012
Group retiree medical insurance contract
Beginning balance	$	54.3
Net unrealized gains related to instruments held at the reporting date		5.5
Interest income		1.2
Dividend income		0.6
Realized gains		0.6
Administrative expenses and charges		(0.1	)
Claims paid		(8.8	)

Ending balance	$	53.3

The following table presents the status of Enogex’s portion of OGE Energy’s postretirement benefit plans at December 31, 2012 and 2011. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss in Enogex’s Consolidated Balance Sheet. The amounts in Accumulated Other Comprehensive Loss represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods.


December 31 (In millions)	2012			2011
Benefit obligations	$	(31.3	)	$	(26.5	)
Fair value of plan assets		—			—

Funded status at end of year	$	(31.3	)	$	(26.5	)

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 8.55 percent in 2013 with the rates trending downward to 4.48 percent by 2028. A one-percentage point change in the assumed health care cost trend rate would have the following effects:

ONE-PERCENTAGE POINT INCREASE


Year ended December 31 (In millions)	2012		2011		2010
Effect on aggregate of the service and interest cost components	$	—	$	—	$	0.3
Effect on accumulated postretirement benefit obligations		—		—		0.1

ONE-PERCENTAGE POINT DECREASE



Year ended December 31 (In millions)	2012		2011		2010
Effect on aggregate of the service and interest cost components	$	—	$	—	$	0.3
Effect on accumulated postretirement benefit obligations		0.1		0.1		0.2

Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments Enogex expects to pay related to its postretirement benefit plans, including prescription drug benefits.


(In millions)	Gross Projected Postretirement Benefit Payments
2013	$	1.1
2014		1.2
2015		1.3
2016		1.5
2017		1.6
After 2017		9.4

Obligations and Funded Status

The following table presents the status of Enogex’s portion of OGE Energy’s Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for Enogex’s portion of the benefit obligation for OGE Energy’s Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for OGE Energy’s Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2012 was $73.4 million and $1.2 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2011 was $60.7 million and $0.8 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:


	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
December 31 (In millions)	2012			2011			2012			2011			2012			2011
Change in Benefit Obligation
Beginning obligations	$	(68.4	)	$	(54.0	)	$	(0.9	)	$	(0.8	)	$	(26.5	)	$	(29.1	)
Service cost		(4.1	)		(3.8	)		(0.1	)		(0.1	)		(0.8	)		(0.6	)
Interest cost		(3.1	)		(3.2	)		—			—			(1.2	)		(1.1	)
Plan amendments		—			—			—			—			—			6.9
Participants’ contributions		—			—			—			—			(0.2	)		(0.4	)
Medicare subsidies received		—			—			—			—			—			(0.1	)
Actuarial gains (losses)		(10.9	)		(10.1	)		(0.2	)		—			(3.0	)		(2.8	)
Benefits paid		4.7			2.7			—			—			0.4			0.7

Ending obligations	$	(81.8	)	$	(68.4	)	$	(1.2	)	$	(0.9	)	$	(31.3	)	$	(26.5	)

Change in Plans’ Assets
Beginning fair value	$	36.0		$	38.2		$	—		$	—		$	—		$	—
Actual return on plans’ assets		3.8			0.5			—			—			—			—
Employer contributions		—			—			—			—			0.2			0.2
Participants’ contributions		—			—			—			—			0.2			0.4
Medicare subsidies received		—			—			—			—			—			0.1
Benefits paid		(4.7	)		(2.7	)		—			—			(0.4	)		(0.7	)

Ending fair value	$	35.1		$	36.0		$	—		$	—		$	—		$	—

Funded status at end of year	$	(46.7	)	$	(32.4	)	$	(1.2	)	$	(0.9	)	$	(31.3	)	$	(26.5	)

Net Periodic Benefit Cost


	Pension Plan									Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year ended December 31 (In millions)	2012			2011			2010			2012		2011		2010		2012			2011			2010
Service cost	$	4.1		$	3.8		$	3.3		$	0.1	$	0.1	$	0.1	$	0.8		$	0.6		$	0.7
Interest cost		3.1			3.2			2.6			—		—		—		1.2			1.1			1.4
Expected return on plan assets		(2.7	)		(3.2	)		(2.9	)		—		—		—		—			—			—
Amortization of transition obligation		—			—			—			—		—		—		0.1			0.1			0.1
Amortization of net loss		2.3			1.4			1.3			—		—		—		1.6			1.3			0.9
Amortization of unrecognized prior service cost (A)		(0.1	)		(0.1	)		(0.1	)		—		—		—		(1.2	)		(1.2	)		—

Net periodic benefit cost (B)	$	6.7		$	5.1		$	4.2		$	0.1	$	0.1	$	0.1	$	2.5		$	1.9		$	3.1

(A)	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B)

The capitalized portion of the net periodic pension benefit cost was $0.8 million, $0.7 million and $0.6 million at December 31, 2012, 2011 and 2010, respectively. The capitalized portion of the net periodic postretirement benefit cost was $0.7 million, $0.4 million and $0.6 million at December 31, 2012, 2011 and 2010, respectively.

Rate Assumptions


	Pension Plan and Restoration of Retirement Income Plan									Postretirement Benefit Plans
Year ended December 31	2012			2011			2010			2012			2011			2010
Discount rate		3.70	%		4.50	%		5.30	%		3.60	%		4.50	%		5.30	%
Rate of return on plans’ assets		8.00	%		8.00	%		8.50	%		N/A			N/A			N/A
Compensation increases		4.20	%		4.40	%		4.40	%		N/A			N/A			N/A
Assumed health care cost trend:
Initial trend		N/A			N/A			N/A			8.55	%		8.75	%		8.99	%
Ultimate trend rate		N/A			N/A			N/A			4.48	%		4.48	%		5.00	%
Ultimate trend year		N/A			N/A			N/A			2028			2028			2020

N/A—not applicable

The overall expected rate of return on plan assets assumption remained at 8.00 percent in 2011 and 2012 in determining net periodic benefit cost due to recent returns on OGE Energy’s long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans’ current and expected asset allocation.

Post-Employment Benefit Plan

Disabled employees receiving benefits from OGE Energy’s Group Long-Term Disability Plan are entitled to continue participating in OGE Energy’s Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in OGE Energy’s Group Long-Term Disability Plan and their dependents, as defined in OGE Energy’s Medical Plan.

The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from OGE Energy’s Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. Enogex’s post-employment benefit obligation was $0.2 million and $0.3 million at December 31, 2012 and 2011, respectively.

401(k) Plan

OGE Energy provides a 401(k) Plan. Each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as “Catch-Up Contributions,” subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; or (ii) a contribution made on an after-tax basis. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election.

The 401(k) Plan was amended in October 2009, as discussed previously, whereby participants could select from the options below.


Employment Date	Option 1	Option 2	Option 3
Before February 1, 2000	< 20 years of service—50% Company match up to 6% of compensation	200% Company match up to 5% of compensation	100% Company match up to 6% of compensation

	> 20 years of service—75% Company match up to 6% of compensation	200% Company match up to 5% of compensation	100% Company match up to 6% of compensation

After February 1, 2000 and before December 1, 2009	100% Company match up to 6% of compensation	200% Company match up to 5% of compensation	N/A

After December 1, 2009	200% Company match up to 5% of compensation	N/A	N/A

No OGE Energy contributions are made with respect to a participant’s Catch-Up Contributions, rollover contributions, or with respect to a participant’s contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, OGE Energy’s contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by OGE Energy or its affiliates. Enogex contributed $3.6 million, $3.0 million and $2.5 million in 2012, 2011 and 2010, respectively, to the 401(k) Plan.

Deferred Compensation Plan

OGE Energy provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan’s primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of OGE Energy and to supplement such employees’ 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.

Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors’ meeting fees and annual retainers. OGE Energy matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on the option the participant elected under the choice provided to eligible employees in the qualified 401(k) Plan discussed above, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of OGE Energy or termination of the plan. Deferrals, plus any OGE Energy match, are credited to a recordkeeping account in the participant’s name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2012, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy’s Common Stock, and various money market, bond and equity funds.

Supplemental Executive Retirement Plan

OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy’s Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy’s Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code.

14. Report of Business Segments

Previously, Enogex’s business was divided into three segments as follows: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. During the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented. As a result of this change, Enogex’s business is now divided into two segments for financial reporting purposes as follows: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. In reviewing its segment operating results, Enogex focuses on operating income as its measure of segment profit and loss, and, therefore, has presented this information below. The following tables summarize the results of Enogex’s business segments for the years ended December 31, 2012, 2011 and 2010.

2012

Natural Gas
Transportation

Natural Gas
Gathering

(In millions)

and Storage

and Processing

Eliminations

Total

Operating revenues

639.5

1,222.6

(253.5

)

1,608.6

Cost of goods sold

504.9

868.7

(253.5

)

1,120.1

Gross margin on revenues

134.6

353.9

—

488.5

Other operation and maintenance

49.8

123.1

—

172.9

Depreciation and amortization

24.0

84.8

—

108.8

Impairment of assets

—

0.4

—

0.4

Gain on insurance proceeds

—

(7.5

)

—

(7.5

)

Taxes other than income

15.7

12.6

—

28.3

Operating income

45.1

140.5

—

185.6

Total assets

2,330.8

1,868.6

(1,548.1

)

2,651.3

Capital expenditures (A)

32.0

475.4

(0.9

)

506.5

(A)	Includes $78.6 million related to the acquisition of certain gas gathering assets as discussed in Note 4.


2011	Natural Gas Transportation		Natural Gas Gathering
(In millions)	and Storage		and Processing			Eliminations			Total
Operating revenues	$	880.1	$	1,167.1		$	(260.1	)	$	1,787.1
Cost of goods sold		736.0		870.7			(260.1	)		1,346.6

Gross margin on revenues		144.1		296.4			—			440.5
Other operation and maintenance		50.7		111.8			—			162.5
Depreciation and amortization		22.0		55.6			—			77.6
Impairment of assets		—		6.3			—			6.3
Gain on insurance proceeds		—		(3.0	)		—			(3.0	)
Taxes other than income		15.0		7.0			—			22.0

Operating income	$	56.4	$	118.7		$	—		$	175.1

Total assets	$	1,836.9	$	1,483.8		$	(1,043.4	)	$	2,277.3
Capital expenditures (A)	$	41.1	$	572.0		$	(0.6	)	$	612.5

(A)	Includes $200.4 million related to the acquisition of certain gas gathering assets as discussed in Note 4.


2010	Natural Gas Transportation		Natural Gas Gathering
(In millions)	and Storage		and Processing		Eliminations			Total
Operating revenues	$	984.8	$	1,005.6	$	(282.7	)	$	1,707.7
Cost of goods sold		834.5		733.3		(282.7	)		1,285.1

Gross margin on revenues		150.3		272.3		—			422.6
Other operation and maintenance		53.8		91.5		—			145.3
Depreciation and amortization		21.2		50.1		—			71.3
Impairment of assets		0.7		0.4		—			1.1
Taxes other than income		14.2		6.4		—			20.6

Operating income	$	60.4	$	123.9	$	—		$	184.3

Total assets	$	1,316.6	$	973.8	$	(533.1	)	$	1,757.3
Capital expenditures	$	72.6	$	164.0	$	(2.4	)	$	234.2

15. Commitments and Contingencies

Operating Lease Obligations

Enogex has operating lease obligations expiring at various dates. Future minimum payments for noncancellable operating leases are as follows:


Year ended December 31 (In millions)	2013		2014		2015		2016		2017		After 2017		Total
Noncancellable operating leases	$	5.2	$	3.7	$	3.5	$	3.4	$	0.7	$	—	$	16.5

Payments for operating lease obligations were $7.9 million, $6.2 million and $4.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Noncancellable Operating Leases

Enogex currently occupies 134,219 square feet of office space at its executive offices under a lease that expires March 31, 2017. The lease payments are $11.3 million over the lease term which began April 1, 2012. This lease has rent escalations which increase after five and 10 years if the lease is renewed.

Enogex currently has 17 compression service agreements, of which 10 agreements are on a month-to-month basis, three agreements will expire in 2013, two agreements will expire in 2016 and two agreements will expire in 2017. Enogex also has eight gas treating agreements, of which six agreements are on a month-to-month basis, one agreement will expire in 2013 and one agreement will expire in 2014.

Other Purchase Obligations and Commitments

Enogex’s other future purchase obligations and commitments estimated for the next five years are as follows:


(In millions)	2013		2014		2015		2016		2017		Total
Other purchase obligations and commitments
EER commitments	$	11.9	$	10.8	$	4.7	$	0.8	$	—	$	28.2

Total other purchase obligations and commitments	$	11.9	$	10.8	$	4.7	$	0.8	$	—	$	28.2

EER Commitments

In 2004, EER entered into a firm transportation service agreement with Cheyenne Plains, who operates the Cheyenne Plains Pipeline that provides firm transportation services in Wyoming, Colorado and Kansas, for 60,000 decatherms/day of firm capacity on the pipeline. The firm transportation service agreement was for a 10-year term beginning with the in-service date of the Cheyenne Plains Pipeline in March 2005 with an annual demand fee of $7.4 million. Effective March 1, 2007, EER and Cheyenne Plains amended the firm transportation service agreement to provide for EER to turn back 20,000 decatherms/day of its capacity beginning in January 2008 for the remainder of the term.

In 2006, Enogex entered into a firm capacity agreement with MEP for a primary term of 10 years (subject to possible extension) that gives MEP and its shippers access to capacity on Enogex’s system. The quantity of capacity subject to the MEP capacity agreement is currently 272 MMcf/d, with the quantity subject to being increased by mutual agreement pursuant to the capacity agreement. In 2009, EER entered into a firm transportation service agreement with MEP for 10,000 decatherms/day of firm capacity on the pipeline. The firm transportation service agreement was for a five-year term beginning with the in-service date of the MEP pipeline in June 2009 with an annual demand fee of $2.1 million.

Environmental Laws and Regulations

The activities of Enogex are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact Enogex’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Enogex believes that its operations are in substantial compliance with current Federal, state and local environmental standards.

Environmental regulation can increase the cost of planning, design, initial installation and operation of Enogex’s facilities. Historically, Enogex’s total expenditures for environmental control facilities and for remediation have not been significant in relation to its consolidated financial position or results of operations. Enogex believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.

Enogex is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. Enogex is unable to predict the financial impact of these matters with certainty at this time. In addition, Enogex 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, restrict or limit the output of certain facilities 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.

Pipeline Safety Legislation

On December 13, 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which the President signed into law on January 3, 2012. Among other things, the law requires additional verification of pipeline infrastructure records by Enogex and other intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. Where records are inadequate to confirm the maximum allowable operating pressure, the PHMSA will require the operator to re-confirm the maximum allowable operating pressure, a process that could cause temporary or permanent limitations on throughput for affected pipelines. This law required PHMSA to direct pipeline operators to verify the maximum allowable operating pressure of their pipelines by July 3, 2012, and to submit documentation to PHMSA by July 3, 2013. This law also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2.0 million for a related series of violations.

In addition, this law requires PHMSA to issue reports and/or, if appropriate, develop new regulations, addressing a variety of subjects, including: (1) requiring pipeline owners and operators to install excess-flow valves in certain circumstances; (2) requiring pipeline owners and operators to use automatic or remote-controlled shut-off valves in certain circumstances; (3) requiring pipeline owners and operators to test to confirm the strength of previously untested transmission lines located within high consequence areas and operating at a pressure greater than 30 percent of specified minimum yield stress; (4) requiring pipeline owners and operators to notify the National Response Center of an accident or incident at the earliest practicable moment (but not later than one hour) after confirming that an accident or incident has occurred; (5) expanding integrity management requirements beyond high consequence areas; and (6) applying the Federal pipeline safety regulations to onshore gathering lines that are not currently subject to the Federal pipeline safety regulations. This law prescribes various deadlines for PHMSA to act on these issues.

At this time, Enogex is not able to estimate the capital, operating or other costs that may be required to comply with this law and any related PHMSA regulations that may be promulgated, but such costs could be significant.

Other

In the normal course of business, Enogex 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, Enogex 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 Enogex’s Consolidated Financial Statements. At the present time, based on currently available information, except as otherwise stated above and in Note 16 below, Enogex 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 Enogex’s consolidated financial position, results of operations or cash flows.

16. Regulation

Completed Regulatory Matters

2011 Fuel Filing

On February 28, 2011, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2011 through March 31, 2012). Along with the revised fuel percentages, Enogex also requested authority to revise its statement of operating conditions to permanently change the annual filing date to February 28. On July 6, 2012, Enogex submitted a compliance filing to synchronize the 2011 fuel filing with the revised statement of operating conditions filed on May 31, 2012 in compliance with the FERC’s order approving Enogex’s 2011 Section 311 rate case settlement. In October 2012, the FERC accepted Enogex’s proposed zonal fuel percentages.

2012 Fuel Filing

On February 24, 2012, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the 2012 fuel year (April 1, 2012 through March 31, 2013). On July 6, 2012, Enogex submitted a compliance filing to synchronize the 2012 fuel filing with the revised statement of operating conditions filed on May 31, 2012 in compliance with the FERC’s order approving Enogex’s 2011 Section 311 rate case settlement. In October 2012, the FERC accepted Enogex’s proposed zonal fuel percentages.

Storage Statement of Operating Conditions Filing

On August 31, 2010, Enogex filed a new statement of operating conditions applicable to storage services with the FERC that replaced Enogex’s existing storage statement of operating conditions effective July 30, 2010. Among other things, the new storage statement of operating conditions updates the general terms and conditions for providing storage services. On December 7, 2012, the FERC issued an order approving Enogex’s revised storage statement of operating conditions, effective August 31, 2010.

FERC Section 311 2011 Rate Case

On January 28, 2011, Enogex submitted a new rate filing to the FERC to set the maximum rate for a new firm Section 311 transportation service in the West Zone of its system and to revise the currently effective maximum rates for Section 311 interruptible transportation service in the East Zone and West Zone. Along with establishing the rate for a new firm service in the West Zone, Enogex’s filing requested a decrease in the maximum interruptible zonal rates in the West Zone and to retain the currently effective rates for firm and interruptible services in the East Zone. Enogex reserved the right to implement the higher rates for firm and interruptible services in the East Zone supported by the cost of service to the extent an expeditious settlement agreement cannot be reached in the proceeding. Enogex proposed that the rates be placed into effect on March 1, 2011. On January 10, 2012, Enogex filed a settlement agreement with the FERC. On May 4, 2012, the FERC issued an order approving the settlement agreement in this matter, subject to the submission of a compliance filing to place the settlement rates into effect as of March 1, 2011, which compliance filing was subsequently filed on May 31, 2012. The FERC also requested that Enogex file a revised statement of operating conditions, which was subsequently filed on May 31, 2012. As part of the settlement agreement in this matter, Enogex made refunds of $0.2 million to affected customers on June 15, 2012 and submitted a report to the FERC on July 6, 2012 showing the refund payment calculation. On February 21, 2013, the FERC issued an order approving the refund report.

REPORT OF INDEPENDENT AUDITORS

The Member of Enogex LLC

We have audited the accompanying consolidated financial statements of Enogex LLC, which comprise the consolidated balance sheets and statements of capitalization as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and changes in member’s interest for each of the three years in the period ended December 31, 2012, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting principles used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Enogex LLC at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

LOGO

Oklahoma City, Oklahoma

February 27, 2013

EX-99.3

Exhibit 99.3

CENTERPOINT ENERGY RESOURCES CORP.

INTRODUCTION TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended March 31, 2013

And for the year ended December 31, 2012

On March 14, 2013, CenterPoint Energy, Inc. (together with its subsidiaries, “CenterPoint Energy”) entered into a Master Formation Agreement (“MFA”) with OGE Energy Corp. (“OGE”) and two affiliates of ArcLight Capital Partners, LLC, Bronco Midstream Holdings, LLC (“Bronco I”) and Bronco Midstream Holdings II, LLC (together with Bronco I, the “Bronco Group”), pursuant to which CenterPoint Energy, OGE and the Bronco Group agreed to form a partnership to own and operate the midstream businesses of CenterPoint Energy and OGE (“Midstream Partnership”). On May 1, 2013, the parties closed the formation of Midstream Partnership, which is currently structured as a private limited partnership.

In connection with the closing, CenterPoint Energy Field Services, LLC (“CEFS”), a Delaware limited liability company and direct wholly owned subsidiary of CenterPoint Energy Resources Corp. (“CERC”), a wholly owned subsidiary of CenterPoint Energy, was converted into a Delaware limited partnership that became Midstream Partnership. CERC contributed to Midstream Partnership CERC’s equity interests in each of CenterPoint Energy Gas Transmission Company, LLC (“CEGT”), CenterPoint Energy – Mississippi River Transmission, LLC (“MRT”), and certain of its other midstream subsidiaries (“Other CNP Midstream Subsidiaries”) and a 24.95 percent interest in Southeast Supply Header, LLC (“SESH” and, collectively with CEFS, CEGT, MRT and Other CNP Midstream Subsidiaries “CenterPoint Midstream”). CEGT, MRT, and SESH are all Delaware limited liability companies. OGE and the Bronco Group indirectly contributed 100 percent of their equity interests in Enogex LLC (“Enogex”), a Delaware single-member limited liability company, to Midstream Partnership.

On May 1, 2013 immediately prior to the closing and pursuant to the MFA, Midstream Partnership entered into a $1.05 billion three-year senior unsecured term loan facility (the “Term Loan”) with third parties and repaid $1.05 billion of affiliated notes payable (“Intercompany Note”) owed to CERC. CERC provided a guarantee of Midstream Partnership’s obligations under the Term Loan. The guarantee is subordinated to all senior debt of CERC. Certain of the entities contributed to Midstream Partnership by CERC are obligated on approximately $363 million of indebtedness owed to a wholly owned subsidiary of CERC that is scheduled to mature in 2017. No pro forma adjustment was made to reflect CERC’s use of the $1.05 billion proceeds CERC received at the formation of Midstream Partnership from the repayment of the Intercompany Note by Midstream Partnership.

As of the closing, CERC held approximately 58.3 percent of the limited partner interests in Midstream Partnership and OGE and the Bronco Group held approximately 28.5 and 13.2 percent, respectively, of the limited partner interests. The transfers of any limited partner interests is subject to specified conditions, including, for a period of time, rights of first offer and rights of first refusal.

The contribution of CenterPoint Midstream to Midstream Partnership by CERC has initially been considered a contribution of in-substance real estate to a joint venture. CERC considers the CenterPoint Midstream assets to be in-substance real estate as the businesses are composed of, and reliant upon, substantial real estate assets and integral equipment. Real estate assets and integral equipment primarily includes transmission pipelines, compressor station equipment, rights of way, storage and processing assets, and long-term customer contracts. Accordingly, CERC did not recognize a gain or loss upon contribution and recorded its investment in Midstream Partnership using the equity method of accounting based on the historical cost of the contributed assets and liabilities.

None of CenterPoint Energy, CERC, or Midstream Partnership has finalized its accounting treatment of the formation of Midstream Partnership. An alternative accounting treatment may significantly affect the accompanying pro forma financial statements.

The pro forma adjustments give effect only to events that are (1) directly attributable to the formation of Midstream Partnership; (2) factually supportable; and (3) expected to have a continuing effect on the consolidated income statement. The unaudited pro forma adjustments, including the pro forma equity in earnings, do not give effect to any potential cost savings or other operating efficiencies from the integration of CenterPoint Midstream and

Enogex. The following unaudited pro forma condensed consolidated financial statements have been prepared to reflect the effect of:

•

CERC’s contribution of CenterPoint Midstream to Midstream Partnership in a transaction deemed to be a contribution of in-substance real estate to a joint venture that is accounted for using the equity method of accounting;

•

the related impact of certain non-contributed entities, assets and liabilities that are included in the historical combined CenterPoint Midstream financial statements and are not contributed to Midstream Partnership at formation;

•

the related impact of surviving affiliated indebtedness and other balances that were previously eliminated in the consolidation of CERC and CenterPoint Midstream; and

•

other adjustments, required by the MFA, directly attributable to the formation of Midstream Partnership and described in the pro forma financial statements.

Midstream Partnership’s pro forma net income, which is utilized in certain pro forma adjustments to CERC’s net income, includes expenses for allocated corporate costs that were charged by CenterPoint Energy to entities contributed to Midstream Partnership. Management has determined that the method of expense allocation used is reasonable and that these charges are reasonable. However, because of certain related-party relationships and transactions, these pro forma adjustments may not necessarily be indicative of the conditions that could have existed or results of operations that could have occurred if CenterPoint Midstream or Enogex had entered into similar arrangements with non-affiliated entities during the periods presented.

The following unaudited pro forma condensed consolidated balance sheet has been prepared to reflect the effect of the contribution of CenterPoint Midstream, as described above, on CERC’s historical unaudited consolidated balance sheet as if the formation of Midstream Partnership had occurred on March 31, 2013. The following unaudited pro forma condensed consolidated financial statements of income for the year ended December 31, 2012 and the three months ended March 31, 2013 have been prepared to reflect the effect of the consummation of the MFA as if the formation had occurred on January 1, 2012, on CERC’s historical audited consolidated income statement for the year ended December 31, 2012 and unaudited consolidated income statement for the three months ended March 31, 2013.

The accompanying unaudited pro forma condensed consolidated financial statements are based on the assumptions and adjustments described in the accompanying notes and do not purport to present CERC’s or Midstream Partnership’s actual financial position or results of operations as if the transactions described above had occurred as of the dates indicated, nor are they necessarily indicative of CERC’s or Midstream Partnership’s financial position or results of operations that may be achieved in the future.

The unaudited pro forma condensed consolidated financial statements were prepared in accordance with Securities and Exchange Commission Regulation S-X, Article 11, using the contribution method of accounting, and are based on the historical financial statements of CERC after giving effect to the consummated MFA. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with CERC’s historical financial statements and related notes as of and for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013.

CENTERPOINT ENERGY RESOURCES CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

March 31, 2013


	CERC Historical		CenterPoint Midstream			Non- Contributed		Eliminations		Restructuring of Intercompany Debt			Pro Forma Adjustments				CERC Pro Forma
	(in millions)
			(A)			(B)		(C)		(D)
ASSETS
Current Assets:
Cash and cash equivalents	$	20	$	(3	)	$	—	$	—	$	—		$	1,050		(E)	$	1,021
														(6	)	(F)
														(40	)	(G)
Accounts receivable, net		630		(78	)		—		—		—			—				552
Accounts receivable — affiliated companies		25		(51	)		1		78		—			—				53
Notes receivable — affiliated companies		—		(498	)		—		895		(397	)		—				—
Accrued unbilled revenues		206		—			—		—		—			—				206
Natural gas inventory		22		—			—		—		—			—				22
Materials and supplies		84		(56	)		—		—		—			—				28
Non-trading derivative assets		18		—			—		—		—			—				18
Taxes receivable		—		(30	)		30		—		—			—				—
Pre-paid and other current assets		59		(44	)		30		—		—			—				45

Total current assets		1,064		(760	)		61		973		(397	)		1,004				1,945

Property, plant and equipment, net		7,934		(4,708	)		—		—		—			—				3,226

Other Assets:
Note receivable – affiliated companies		—		—			—		1,009		404			(1,050	)	(E)		363
Goodwill, net		1,468		(629	)		—		—		—			—				839
Non-trading derivative assets		5		—			—		—		—			—				5
Investment in unconsolidated affiliates		400		(400	)		200		—		—							200
Investment in unconsolidated Midstream Partnership		—		3,280			1,364		—		(505	)		6		(F)		4,185
														40		(G)
Other		198		(5	)		—		—		—			—				193

Total other assets		2,071		2,246			1,564		1,009		(101	)		(1,004	)			5,785

Total Assets	$	11,069	$	(3,222	)	$	1,625	$	1,982	$	(498	)	$	—			$	10,956

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET–(continued)

March 31, 2013


	CERC Historical		CenterPoint Midstream			Non- Contributed			Eliminations		Restructuring of Intercompany Debt			Pro Forma Adjustments				CERC Pro Forma
	(in millions)
			(A)			(B)			(C)		(D)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current portion of long-term debt	$	524	$	—		$	—		$	—	$	—		$	—			$	524
Accounts payable		387		(43	)		—			—		—			11		(H)		355
Accounts payable — affiliated companies		59		(54	)		2			78		—			—				85
Notes payable — affiliated companies		440		(701	)		304			397					—				440
Taxes accrued		87		(33	)		2			—		—			—				56
Interest accrued		56		—			—			—		—			—				56
Customer Deposits		80		(1	)		—			—		—			—				79
Non-trading derivative liabilities		10		—			—			—		—			—				10
Accumulated deferred income taxes, net		2		—			—			—		—			—				2
Other current liabilities		132		(24	)		—			—		—			—				108

Total current liabilities		1,777		(856	)		308			475		—			11				1,715

Other Liabilities:
Accumulated deferred income taxes, net		1,773		(1,301	)		1,301			—		—			94		(I)		1,838
															(29	)	(J)
Notes payable – affiliated companies		—		(1,009	)		—			1,507		(498	)		—				—
Non-trading derivative liabilities		2		—			—			—		—			—				2
Benefit obligations		122		(22	)		22			—		—			—				122
Regulatory liabilities		640		(16	)		—			—		—			—				624
Other liabilities		216		(24	)		—			—		—			—				192

Total other liabilities		2,753		(2,372	)		1,323			1,507		(498	)		65				2,778

Long-term Debt		2,178		—			—			—		—			—				2,178
Commitments and Contingencies
Shareholders’ Equity		4,361		6			(6	)		—		—			(11	)	(H)		4,285
															(94	)	(I)
															29		(J)

Total Liabilities and Shareholder’s Equity	$	11,069	$	(3,222	)	$	1,625		$	1,982	$	(498	)	$	—			$	10,956

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME

For the Year Ended December 31, 2012


	CERC Historical			CenterPoint Midstream			Non- Contributed			Eliminations			Pro Forma Adjustments				CERC Pro Forma
	(in millions)
				(A)			(B)			(C)
Revenues	$	4,901		$	(952	)	$	—		$	134		$	—			$	4,083

Expenses:
Natural gas		2,873			(129	)		—			134			—				2,878
Operation and maintenance		951			(267	)		—			—			—				684
Depreciation and amortization		285			(106	)		—			—			—				179
Taxes other than income taxes		146			(34	)		—			—			—				112
Goodwill impairment		252			—			—			—			—				252

Total		4,507			(536	)		—			134			—				4,105

Operating Income		394			(416	)		—			—			—				(22	)

Other (Expense) Income:
Interest income – affiliated companies		—			(21	)		—			92			(67	)	(K)		4
Interest and other finance charges		(179	)		85			(16	)		(92	)		21		(K)		(181	)
Equity in earnings of unconsolidated affiliates, net		31			(31	)		13			—			404		(L)		390
														(27	)	(M)
Step acquisition gain		136			(136	)		—			—			—				—
Other, net		1			—			—			—			—				1

Total		(11	)		(103	)		(3	)		—			331				214

Income before Income Taxes		383			(519	)		(3	)		—			331				192
Income tax expense		246			(203	)		2			—			127		(N)		172

Net Income	$	137		$	(316	)	$	(5	)	$	—		$	204			$	20

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME

For the Three Months Ended March 31, 2013


	CERC Historical			CenterPoint Midstream			Non- Contributed			Eliminations			Pro Forma Adjustments				CERC Pro Forma
	(in millions)
				(A)			(B)			(C)
Revenues	$	1,853		$	(261	)	$	—		$	39		$	—			$	1,631

Expenses:
Natural gas		1,224			(45	)		—			39			—				1,218
Operation and maintenance		251			(69	)		—			—			—				182
Depreciation and amortization		77			(30	)		—			—			—				47
Taxes other than income taxes		51			(10	)		—			—			—				41

Total		1,603			(154	)		—			39			—				1,488

Operating Income		250			(107	)		—			—			—				143

Other (Expense) Income:
Interest income – affiliated companies		—			(7	)		—			26			(17	)	(K)		2
Interest and other finance charges		(45	)		24			(5	)		(26	)		7		(K)		(45	)
Equity in earnings of unconsolidated affiliates, net		5			(5	)		3			—			75		(L)		71
														(7	)	(M)

Total		(40	)		12			(2	)		—			58				28

Income before Income Taxes		210			(95	)		(2	)		—			58				171
Income tax expense		82			(37	)		—			—			22		(N)		67

Net Income	$	128		$	(58	)	$	(2	)	$	—		$	36			$	104

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP.

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pro forma adjustments and assumptions

(A)

This column reflects the deconsolidation of CenterPoint Midstream’s historical combined financial position and results of operations, as applicable, as presented in CenterPoint Midstream’s historical combined financial statements for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013. This column also includes an adjustment to reflect CERC’s approximate 58.3 percent interest in Midstream Partnership, initially recorded as parent net investment in CenterPoint Midstream’s historical balance sheet as of March 31, 2013, accounted for under the equity method of accounting.

(B)

This column reflects adjustments to add back entities, assets and liabilities included in the historical combined CenterPoint Midstream financial statements, which were not contributed to Midstream Partnership at its formation. At formation of the Midstream Partnership, CERC retained certain balances historically held by CenterPoint Midstream combined entities, as reflected in CenterPoint Midstream’s historical combined financial statements, relating to:

•

federal income taxes;

•

benefit obligations;

•

its 25.05 percent interest in SESH; and

•

non-contributed entities that held intercompany indebtedness to CERC.

(C)

This column adjusts for affiliated transactions and balances which were previously eliminated in consolidation with CERC and which will be reflected in CERC’s consolidated financial statements subsequent to the formation of Midstream Partnership.

(D)

This column reflects an adjustment to intercompany indebtedness contributed to Midstream Partnership at its formation, as required under the MFA. At formation of Midstream Partnership, CERC contributed to Midstream Partnership (1) three notes payable by CenterPoint Midstream to CERC that were issued in 2012 and have an aggregate principal amount of $363 million, and (2) an Intercompany Note payable to CERC of $1.05 billion, which was repaid in connection with the formation of Midstream Partnership (See Note E).

(E)

This adjustment reflects Midstream Partnership’s repayment, in connection with the closing of the Midstream Partnership formation and pursuant to the MFA, of the Intercompany Note payable to CERC of $1.05 billion contributed by CERC to Midstream Partnership.

(F)

This adjustment reflects CERC’s contribution to CenterPoint Midstream of $6 million related to CERC’s payment of fees incurred by CenterPoint Midstream in connection with the arrangement of the $1.05 billion Term Loan. The MFA required CERC to be responsible for all structuring, underwriting, arrangement and upfront fees associated with the Term Loan, which approximated $6 million.

(G)

This adjustment reflects CERC’s cash contribution of $40 million to CenterPoint Midstream immediately prior to closing of the Midstream Partnership formation, as required under the MFA.

(H)

This adjustment reflects $11 million of transaction costs incurred by CERC at formation of Midstream Partnership, which were not incurred by CERC as of March 31, 2013. CERC incurred approximately $1 million in transaction related costs prior to March 31, 2013, which are included in its historical operating results for the three months ended March 31, 2013 and are, thus, not reflected as a pro forma adjustment.

(I)

This adjustment reflects CERC’s recognition of a deferred tax liability for the portion of non-deductible goodwill no longer attributable to CERC that was contributed to Midstream Partnership.

(J)

This adjustment reflects CERC’s tax benefit related to the remeasurement of state deferred tax liabilities based upon CERC’s contribution to Midstream Partnership. The state tax liability for the Midstream Partnership is based upon the combined activities of the entities contributed by CERC and OGE and is then allocated to its partners based upon their respective interest.

(K)

This adjustment reflects the impact on interest income and expense of the settlement of the intercompany notes payable and receivable between CERC and CenterPoint Midstream prior to the formation of Midstream Partnership, pursuant to the MFA. The remaining interest income in CERC’s pro forma income statements of $4 million and $2 million for the year ended December 31, 2012 and the three months ended March 31, 2013, respectively, reflects CERC’s interest income on the remaining $363 million aggregate principal amount of notes receivable from CenterPoint Midstream (see Note D).

(L)

This adjustment reflects CERC’s equity in earnings for its approximate 58.3 percent interest in Midstream Partnership’s pro forma net income for the year ended December 31, 2012 and the three months ended March 31, 2013.

(M)

This adjustment reflects CERC’s amortization of the excess of (a) the book value of its initial investment in Midstream Partnership over (b) its proportionate share of the book value of Midstream Partnership’s net assets at formation. CERC expects to amortize such excess over 30 years.

(N)

This adjustment reflects CERC’s incremental tax expense for the net pro forma adjustments to earnings before income taxes for the year ended December 31, 2012 and three months ended March 31, 2013, based on an estimated statutory rate of 38.4 percent for all jurisdictions that would have applied during the periods presented.