Ex 99.1 for 8-K 5/12/14



AE	Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
ATSI	American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilities.
FE	FirstEnergy Corp., a public utility holding company
FES	FirstEnergy Solutions Corp., which provides energy-related products and services
FET	FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, a subsidiary of AE, which is the parent of ATSI and TrAILCo and has a joint venture in PATH.
FG	FirstEnergy Generation, LLC, a subsidiary of FES, which owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
PATH	Potomac-Appalachian Transmission Highline, LLC, a joint venture between FET and a subsidiary of AEP
PATH-Allegheny	PATH Allegheny Transmission Company, LLC
PATH-WV	PATH West Virginia Transmission Company, LLC
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
TrAILCo	Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
WP	West Penn Power Company, a Pennsylvania electric utility operating subsidiary of AE

The following abbreviations and acronyms are used to identify frequently used terms in this report.
AEP	American Electric Power Company, Inc.
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ERO	Electric Reliability Organization
FERC	Federal Energy Regulatory Commission
FPA	Federal Power Act
GAAP	Accounting Principles Generally Accepted in the United States of America
IRS	Internal Revenue Service
kV	Kilovolt
LSE	Load Serving Entity
MISO	Midcontinent Independent System Operator, Inc.
MVP	Multi-Value Project
NERC	North American Electric Reliability Corporation
NYISO	New York Independent System Operator, Inc.
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection, L.L.C.
PPUC	Pennsylvania Public Utility Commission
RFC	ReliabilityFirst Corporation
RMR	Reliability Must-Run
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
SERTP	Southeastern Regional Transmission Planning
SVC	Static Var Compensator
VSCC	Virginia State Corporation Commission
WVPSC	Public Service Commission of West Virginia



	Three Months Ended March 31
(In thousands)	2014			2013

REVENUES	$	106,927		$	100,579

OPERATING EXPENSES:
Operation and maintenance expenses	15,660			13,753
Provision for depreciation	19,585			17,393
Amortization of regulatory assets, net	2,998			3,154
General taxes	15,741			10,745
Total operating expenses	53,984			45,045

OPERATING INCOME	52,943			55,534

OTHER INCOME (EXPENSE):
AFUDC equity	5,485			346
Miscellaneous income	1,614			4,654
Interest expense	(15,753		)	(15,816		)
Capitalized interest	1,553			314
Total other expense	(7,101		)	(10,502		)

INCOME BEFORE INCOME TAXES	45,842			45,032

INCOME TAXES	15,632			17,377

NET INCOME	30,210			27,655

Income attributable to noncontrolling interest	6			10

EARNINGS AVAILABLE TO FET	$	30,204		$	27,645

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	30,210		$	27,655

OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(85		)	(82		)
Other comprehensive loss	(85		)	(82		)
Income tax benefits on other comprehensive loss	(31		)	(29		)
Other comprehensive loss, net of tax	(54		)	(53		)

COMPREHENSIVE INCOME	30,156			27,602

Comprehensive income attributable to noncontrolling interest	6			10

COMPREHENSIVE INCOME AVAILABLE TO FET	$	30,150		$	27,592



(In thousands, except share amounts)	March 31, 2014		December 31, 2013

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	47,527	$	42,680
Receivables-
Affiliated companies	49,147		84,277
Other	24,998		25,683
Notes receivable from affiliated companies	82,943		682,276
Deferred tax assets	111,851		103,183
Prepayments and other	12,537		13,067
	329,003		951,166
PROPERTY, PLANT AND EQUIPMENT:
In service	3,393,956		3,405,831
Less - Accumulated provision for depreciation	904,870		890,965
	2,489,086		2,514,866
Construction work in progress	450,913		198,594
	2,939,999		2,713,460
OTHER PROPERTY AND INVESTMENTS:
Investment in non-affiliated companies	25,149		25,384
Other	6,417		6,411
	31,566		31,795
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	122,008		126,678
Property taxes	39,375		56,650
Other	7,980		7,826
	169,363		191,154
	$	3,469,931	$	3,887,575

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	452,064	$	—
Short-term borrowings-
Affiliated companies	3,746		193,124
Other	750,000		1,000,000
Accounts payable-
Affiliated companies	55,156		46,566
Other	246		143
Accrued taxes	76,237		63,017
Accrued interest	8,933		18,991
Other	724		1,157
	1,347,106		1,322,998
CAPITALIZATION:
Member's equity	906,087		906,066
Accumulated other comprehensive income	400		454
Retained earnings	170,299		140,095
Total member's equity	1,076,786		1,046,615
Noncontrolling interest	318		312
Total equity	1,077,104		1,046,927
Long-term debt and other long-term obligations	399,778		852,489
	1,476,882		1,899,416
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	508,143		493,431
Accumulated deferred investment tax credits	5,994		6,158
Property taxes	26,250		56,650
Regulatory liabilities	79,320		81,620
Other	26,236		27,302
	645,943		665,161
	$	3,469,931	$	3,887,575



	Three Months Ended March 31
(In thousands)	2014			2013

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	30,210		$	27,655
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	19,585			17,393
Amortization of regulatory assets, net	2,998			3,154
Deferred income taxes and investment tax credits, net	(515		)	8,211
Transmission revenue collections, net	(1,411		)	13,831
Changes in current assets and liabilities-
Receivables	35,815			3,882
Prepayments and other current assets	1,693			(4,352		)
Accounts payable	(9,388		)	(96,654		)
Accrued taxes	3,125			3,427
Accrued interest	(10,058		)	(9,711		)
Other	(2,916		)	513
Net cash provided from (used for) operating activities	69,138			(32,651		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings-
Affiliated companies	(189,378		)	86,057
Other	(250,000		)	—
Common stock dividend payments	—			(15,000		)
Other	(709		)	—
Net cash provided from (used for) financing activities	(440,087		)	71,057

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(218,761		)	(72,654		)
Loans to affiliated companies, net	599,333			41,203
Other	(4,776		)	(2,670		)
Net cash provided from (used for) investing activities	375,796			(34,121		)

Net change in cash and cash equivalents	4,847			4,285
Cash and cash equivalents at beginning of period	42,680			23,020
Cash and cash equivalents at end of period	$	47,527		$	27,305

FET follows GAAP and its operating subsidiaries comply with the regulations, orders, policies and practices prescribed by FERC and applicable state regulatory authorities. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. FET has evaluated events and transactions for potential recognition or disclosure through May 13, 2014, the issuance date of the financial statements.

The fair values of long-term debt reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FET. FET classified long-term debt as Level 2 in the fair value hierarchy as of March 31, 2014 and December 31, 2013.

Federally-enforceable mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on ATSI and TrAILCo. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. ATSI and TrAILCo actively participate in the NERC and RFC stakeholder processes, and otherwise monitor and manage their assets in response to the ongoing development, implementation and enforcement of the reliability standards.

ATSI and TrAILCo believe that they are in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating their extensive electric utility systems and facilities, ATSI and TrAILCo occasionally learn of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, ATSI and TrAILCo develop information about the item and a remedial response to the specific circumstances, including in appropriate cases self-reporting an item to RFC. NERC, RFC and FERC continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

ATSI and TrAILCo are required to build transmission lines and transmission facilities if and when PJM makes certain findings about the need for transmission expansion to preserve reliability on the transmission grid. In recent years, PJM has found that certain upgrades to ATSI's transmission system are necessary and, as a consequence, ATSI applied to the Ohio Power Siting Board for authorization to construct these lines and facilities. On March 11, 2013, the Ohio Power Siting Board issued orders approving construction of two separate transmission line projects and related facilities, including substations: the 138 kV "East Springfield-London-Tangy" line, which is approximately 60 miles long, and the 345 kV Bruce Mansfield-Glenwillow line, which is approximately 103.5 miles long. With these authorizations in hand, ATSI initiated construction of these projects in 2013.

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FirstEnergy and other parties advocated for a traditional “beneficiary pays” approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new 500 kV and higher voltage facilities on a load-ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identified nine separate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain transmission customers in PJM bearing the majority of the costs. FirstEnergy and a number of other utilities, industrial customers and state utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load-ratio share basis. On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp (or socialized) rate based on the amount of load served in a transmission zone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order and on March 22, 2013, FERC denied rehearing. On March 29, 2013, FirstEnergy filed a petition for review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated with several other cases before that court for briefing and disposition. Briefing is complete, oral argument was held on April 22, 2014, and a decision is expected in 2014.

Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order. To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of 50% beneficiary pays and 50% postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing. On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing. On March 22, 2013, FERC granted final acceptance of the hybrid method. Certain parties sought rehearing of parts of FERC's March 22, 2013 order. These requests for rehearing are pending before FERC. On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region

and the NYISO region and; (2) the PJM region and the FERC-jurisdictional members of the SERTP region. These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region. On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000. On December 30, 2013, FERC conditionally accepted the PJM/SERTP cross-border project cost allocation filing, subject to refund and future orders in PJM's and SERTP's related Order No. 1000 interregional compliance proceedings. The PJM/NYISO and PJM/MISO cross-border project cost allocation filings remain pending before FERC. On January 16, 2014, FERC issued an order regarding the effective date of PJM's separate Order No. 1000 regional transmission planning and cost allocation compliance filing, noting that it would address the merits of the comments on and protests to that filing and related compliance filings in a future order.

On June 1, 2011, ATSI transferred functional control of its transmission facilities from MISO to PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone. While many of the matters involved with the move have been resolved, FERC denied recovery by means of ATSI's transmission rate for certain charges that collectively can be described as “exit fees” and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move. On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve the exit fee and transmission cost allocation issues. However, FERC subsequently rejected that settlement stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

Separately, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings in front of FERC and certain U.S. appellate courts. The MISO and its allied parties assert that the benefits to the ATSI zone of the Michigan Thumb project are roughly commensurate with the costs that MISO desires to charge to the ATSI zone, estimated to be as much as $16 million per year. ATSI has submitted evidence that the Michigan Thumb project provides no electric benefits to the ATSI zone and, on that basis, opposes the MISO’s efforts to impose these costs on the ATSI zone loads. The MISO and its allied parties also assert that certain language in the MISO Transmission Owners Agreement requires ATSI to pay these charges. In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek recovery of these charges through its formula rate. While FERC proceedings regarding whether the MISO can charge ATSI for MVP costs remain pending, on February 24, 2014, the U.S. Supreme Court declined to hear appeals filed by FirstEnergy and other parties of the Seventh Circuit's June 2013 decision upholding FERC's acceptance of the MISO's generic MVP cost allocation proposal.

In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM could be charged to transmission customers in the ATSI zone. ATSI sought rehearing of the question of whether the ATSI zone should pay these legacy RTEP charges and, on September 20, 2012, FERC denied ATSI's request for rehearing. ATSI subsequently filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit. Briefing is complete, oral argument was held on December 11, 2013, and a decision is expected in the second quarter of 2014.

The PATH project was proposed to be comprised of a 765 kV transmission line from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland. PJM initially authorized construction of the PATH project in June 2007. On August 24, 2012, the PJM Board of Managers canceled the PATH project, which had previously been suspended by PJM in February 2011. As a result, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. On September 28, 2012, those companies requested authorization from FERC to recover the costs with a proposed return on equity of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over the next five years. Several parties protested the request. On November 30, 2012, FERC issued an order denying the 0.5% return on equity adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to refund settlement judge procedures and hearing if the parties do not agree to a settlement. PATH, PATH-Allegheny and PATH-WV have requested rehearing of FERC's denial of the 0.5% return on equity adder for RTO membership; that request for rehearing remains pending before FERC. In addition, FERC

On March 20, 2014, the settlement judge declared an impasse in efforts to achieve settlement. On March 24, 2014, the Chief ALJ terminated settlement judge procedures and appointed an ALJ to preside over the hearing phase of the case. The hearing is scheduled to commence on November 5, 2014. The issues set for hearing include the prudence of the costs, the base return on equity and the period of recovery. Depending on the outcome of the hearing, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

On December 20, 2012, FERC approved the transfer by FG to ATSI of certain deactivated generation assets associated with Eastlake Units 1 through 5 and Lakeshore Unit 18 to facilitate their conversion to synchronous condensers to provide voltage support on the ATSI transmission system. The transfer price of the assets was approximately $17.7 million and the estimated conversion cost was approximately $60 million. The transfer of Eastlake Units 4 and 5 was completed on January 31, 2013 and ATSI completed the conversion of Eastlake Unit 5 in July 2013 and is expected to complete Eastlake Unit 4 by June 1, 2014. The transfer of each of the remaining units and conversion to synchronous condensers will occur when the use of the unit for RMR purposes is no longer required. On January 22, 2013, ATSI requested clarification or, in the alternative, rehearing with respect to a statement in the FERC order authorizing the transfer that ATSI's current formula rate does not include the accounts and components necessary to allow for recovery of the costs associated with acquisition of the transferred assets and that ATSI must make a filing under Section 205 of the FPA in order to recover those costs. ATSI requested clarification from FERC noting its formula rate currently includes the necessary accounts and components to allow for such recovery and that a Section 205 filing is not required. On August 5, 2013, FERC clarified that the issue of whether the cost of the transferred facilities and any conversion costs could be included in ATSI’s formula rates is more appropriately addressed during ATSI’s yearly formula rate update process. On February 26, 2014, FG and ATSI advised FERC that PJM had revised its regional transmission expansion plan to substitute the installation of a SVC at the location of the Lakeshore units in lieu of the conversion of Lakeshore 18 to a synchronous condenser and that PJM has designated ATSI to install the SVC. FG and ATSI further advised FERC that installation of the SVC at the Lakeshore location eliminates the need for ATSI to acquire any of the power islands, associated property or equipment, or any other property rights at Lakeshore 18, as contemplated by the application ATSI and TrAILCo filed with FERC requesting approval of the transfer, that it does not necessitate the acquisition of any other assets by ATSI from FG, and as a result, the ATSI and FG will not be consummating the sale of Lakeshore 18.

Primary jurisdiction for the approval of the location and construction of new transmission lines generally lies with the utility regulatory body in each state where the line will be located. In Pennsylvania, Virginia and West Virginia, respectively, the PPUC the VSCC and the WVPSC have such jurisdiction. In Ohio, the Ohio Power Siting Board has jurisdiction over the siting and construction of transmission facilities. Our regulated operating subsidiaries, ATSI and TrAILCo, may also occasionally request approval from relevant state regulators for minor changes in existing transmission routes and facilities.

In response to a June 2013 request by Penn to locate and construct a 200-foot transmission line in western Pennsylvania to tap an ATSI 138 kV line to serve a nearby customer at transmission voltage, the PPUC in September 2013 approved the request, but questioned whether ATSI should be considered a “public utility” under the Pennsylvania Public Utility Code and directed ATSI to file a petition for declaratory order or an application for a certificate of public convenience to create a procedural vehicle for the PPUC to address the issue. On October 15, 2013, ATSI filed a Petition for Declaratory Order with the PPUC outlining why it is not a “public utility” under the Pennsylvania Public Utility Code. The matter is pending before the PPUC.

Various federal, state and local authorities regulate FET and its subsidiaries with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FET's earnings and competitive position to the extent that FET and its subsidiaries compete with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.

FET accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FET determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FET or its subsidiaries has legal liability or are otherwise made subject to liability, it could have a material adverse effect on FET's or its subsidiaries' financial condition, results of operations and cash flows.



Note Number		Page Number
1	Organization and Basis of Presentation	8
2	Taxes	8
3	Fair Value Measurements	8
4	Regulatory Matters	9
5	Commitments and Contingencies	11



	March 31, 2014				December 31, 2013
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	852	$	891	$	853	$	883