FirstEnergy (FE) 8-K Regulation FD Disclosure

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED

UNAUDITED INTERIM FINANCIAL STATEMENTS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014 AND 2013

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

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
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET	FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC which is the parent of ATSI and TrAIL and has a joint venture in PATH.
FG	FirstEnergy Generation, LLC, a wholly-owned subsidiary of FES, which owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
PATH	Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
TrAIL	Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
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
CWIP	Construction Work in Progress
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
ERO	Electric Reliability Organization
FERC	Federal Energy Regulatory Commission
FPA	Federal Power Act
GAAP	Accounting Principles Generally Accepted in the United States of America
kV	Kilovolt
MISO	Midcontinent Independent Transmission System Operator, Inc. (formerly known as Midwest Independent Transmission System Operator, Inc.)
Moody’s	Moody’s Investors Service, Inc.
MVP	Multi-value Project
NERC	North American Electric Reliability Corporation
NYISO	New York Independent System Operator, Inc.
OATT	Open Access Transmission Tariff
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection, L.L.C.
RFC	ReliabilityFirst Corporation
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SEC	United States Securities and Exchange Commission
SERTP	Southeastern Regional Transmission Planning
Seventh Circuit	United States Court of Appeals for the Seventh Circuit

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30						Six Months Ended June 30
(In thousands)	2014			2013			2014			2013
STATEMENTS OF INCOME
REVENUES	$	57,185		$	50,575		$	109,749		$	98,856
OPERATING EXPENSES:
Operation and maintenance expenses	12,431			12,055			25,764			25,134
Provision for depreciation	12,596			10,830			25,072			21,377
General taxes	13,278			9,875			26,548			18,794
Total operating expenses	38,305			32,760			77,384			65,305
OPERATING INCOME	18,880			17,815			32,365			33,551
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)	8			(11		)	161			218
Interest expense	(6,094		)	(5,821		)	(12,068		)	(11,573		)
Capitalized financing costs	11,241			1,233			15,421			1,802
Total other income (expense)	5,155			(4,599		)	3,514			(9,553		)
INCOME BEFORE INCOME TAXES	24,035			13,216			35,879			23,998
INCOME TAXES	5,979			3,852			8,574			7,690
NET INCOME	$	18,056		$	9,364		$	27,305		$	16,308
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	18,056		$	9,364		$	27,305		$	16,308
OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(84		)	(89		)	(169		)	(171		)
Other comprehensive loss	(84		)	(89		)	(169		)	(171		)
Income tax benefits on other comprehensive loss	(29		)	(33		)	(60		)	(62		)
Other comprehensive loss, net of tax	(55		)	(56		)	(109		)	(109		)
COMPREHENSIVE INCOME	$	18,001		$	9,308		$	27,196		$	16,199

The accompanying Notes to Financial Statements are an integral part of these financial statements.

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED

BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)	June 30, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Receivables-
Affiliated companies	$	834	$	14,889
Other	8,655		7,960
Notes receivable from affiliated companies	7,315		—
Accumulated deferred income taxes	4,933		9,789
Prepayments and other	2,082		2,076
	23,819		34,714
UTILITY PLANT:
In service	2,086,999		2,087,776
Less — Accumulated provision for depreciation	841,351		839,042
	1,245,648		1,248,734
Construction work in progress	531,675		89,651
	1,777,323		1,338,385
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	26,000		52,500
Other	5,029		4,936
	31,029		57,436
	$	1,832,171	$	1,430,535
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Accounts payable to affiliated companies	$	6,086	$	4,408
Short-term borrowings - affiliated companies	—		537
Accrued taxes	43,102		38,718
Accrued interest	9,625		9,625
Other	905		1,154
	59,718		54,442
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 850 shares - 1 share outstanding	1		1
Other paid-in capital	926,154		533,719
Accumulated other comprehensive income	345		454
Retained earnings	95,867		68,562
Total common stockholder's equity	1,022,367		602,736
Long-term debt and other long-term obligations	399,785		399,771
	1,422,152		1,002,507
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	223,174		212,055
Accumulated deferred investment tax credits	5,830		6,158
Property taxes	26,000		52,500
Regulatory liabilities	74,289		81,620
Other	21,008		21,253
	350,301		373,586
	$	1,832,171	$	1,430,535

The accompanying Notes to Financial Statements are an integral part of these financial statements.

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30
(In thousands)	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	27,305		$	16,308
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	25,072			21,377
Deferred income taxes and investment tax credits, net	5,673			22,516
Allowance for funds used during construction - equity	(12,525		)	(1,130		)
Changes in current assets and liabilities -
Receivables	13,360			(2,972		)
Prepayments and other current assets	(5		)	(1,295		)
Accounts payable	4,708			15,957
Accrued taxes	4,384			(10,634		)
Other	(347		)	(301		)
Net cash provided from operating activities	67,625			59,826
CASH FLOWS FROM FINANCING ACTIVITIES:
Equity contribution from parent	392,400			—
Common stock dividend payments	—			(15,000		)
Short-term borrowings, net	(537		)	31,538
Other	(405		)	(377		)
Net cash provided by financing activities	391,458			16,161
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(437,700		)	(123,400		)
Loans to affiliated companies, net	(7,315		)	49,161
Asset removal costs	(14,068		)	(1,748		)
Net cash used for investing activities	(459,083		)	(75,987		)
Net change in cash and cash equivalents	—			—
Cash and cash equivalents at beginning of period	—			—
Cash and cash equivalents at end of period	$	—		$	—

The accompanying Notes to Financial Statements are an integral part of these financial statements.

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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

1. ORGANIZATION AND BASIS OF PRESENTATION

ATSI is a wholly owned subsidiary of FET. ATSI owns high-voltage transmission facilities consisting of approximately 7,525 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. Effective October 1, 2003, ATSI transferred operational control of its transmission facilities to MISO. On December 17, 2009, FERC authorized ATSI to transfer operational control of its facilities to PJM. On June 1, 2011, ATSI successfully integrated into PJM. ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, ATSI follows GAAP and complies with the regulations, orders, policies and practices prescribed by FERC and applicable state regulatory authorities.

Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted. These interim financial statements should be read in conjunction with the financial statements and notes included in ATSI's audited financial statements for the year ended December 31, 2013.

For the three months ended June 30, 2014 and 2013, capitalized financing costs on ATSI's Consolidated Statements of Income includes $9 million and $1 million, respectively, of AFUDC-equity and $2 million of capitalized interest for the three months ended June 30, 2014. For the six months ended June 30, 2014 and 2013, capitalized financing costs on ATSI's Consolidated Statements of Income includes $12 million and $1 million, respectively, of AFUDC-equity, and $3 million and $1 million, respectively, of capitalized interest.

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. ATSI has evaluated events and transactions for potential recognition or disclosure through September 22, 2014, the issuance date of the financial statements.

New Accounting Pronouncements

New accounting pronouncements not yet effective are not expected to have a material effect on ATSI's financial statements.

2. TAXES

ATSI’s interim effective tax rates reflect the estimated annual effective tax rates for 2014 and 2013, adjusted for tax expense associated with certain discrete items that may occur in any given period, but are not consistent from period to period.

ATSI’s effective tax rates for the three months ended June 30, 2014 and 2013 were 24.9% and 29.1%, respectively. ATSI’s effective tax rates for the six months ended June 30, 2014 and 2013 were 23.9% and 32.0%, respectively. The decrease in the effective tax rates for the three and six months ended June 30, 2014 is primarily due to an increase in the benefit of AFUDC equity flow-through in 2014.

For federal income tax purposes, ATSI files as a member of the FE consolidated group. In April 2014, the Internal Revenue Service completed its examination of FE’s 2011 and 2012 federal income tax returns and issued Revenue Agent Reports for these years, which did not result in a material impact to ATSI’s effective tax rate.

3. FAIR VALUE MEASUREMENTS

The following table provides the approximate fair value and related carrying amounts of long-term debt, excluding capital lease obligations and net unamortized premiums and discounts as of June 30, 2014 and December 31, 2013.

	June 30, 2014				December 31, 2013
(In millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	400	$	441	$	400	$	422

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 ATSI.

On March 31, 2014, FET, ATSI and TrAIL entered into extensions and amendments to their existing multi-year syndicated revolving credit facility. The facility was extended until March 31, 2019 and amended to increase ATSI's individual borrower sublimit to $500 million from $100 million. The lending banks' commitments under the revolving credit facility remain at $1 billion.

4. REGULATORY MATTERS

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on ATSI. NERC is the ERO designated by FERC under Section 215 of the FPA to establish and enforce these reliability standards. 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 actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its assets and operations in response to the ongoing development, implementation and enforcement of the reliability standards.

ATSI believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, ATSI may 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 will develop information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. NERC and FERC continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Any inability on ATSI's part to comply with the reliability standards for its transmission systems 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.

Since 2010, RFC has conducted two compliance audits and two spot check audits, each of which included ATSI. ATSI was substantially compliant as only minor findings, which had minimal or no impact on reliability, were identified during the audits. ATSI does not expect any material adverse financial impact as a result of these audits.

ATSI is required to build 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 has applied to the Ohio Power Siting Board for authorization to construct these upgrades. 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 obtained any remaining real property that was needed and initiated construction of these projects in 2013.

FERC MATTERS

PJM Transmission Rates

PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities that were approved through PJM’s RTEP process before 2008. While FirstEnergy and other parties advocated for a traditional “beneficiary pays” approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer would pay based on its total usage of energy within PJM. On August 6, 2009, 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 Seventh Circuit, and the case subsequently was consolidated with several other cases before that court. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from the new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines by means of a postage-stamp rate. The majority also found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from them, and not based on a load ratio share in PJM as a whole. The majority again remanded the case back to FERC for further proceedings to implement its findings and ruling. On September 5, 2014, the Seventh Circuit denied the request of Virginia Electric and Power Company, or VEPCO, for rehearing and rehearing en banc of the panel’s decision, which is a procedural path to ask the full Seventh Circuit to reconsider the panel’s decision.

Order No. 1000, issued by FERC on July 21, 2011, announced new policies regarding transmission planning and transmission cost allocation. Order No. 1000 also 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. Numerous parties, including ATSI and other FE affiliates, sought judicial review of Order No. 1000 before the D.C. Circuit. On August 15, 2014, the D.C. Circuit issued an order affirming FERC’s rulings in Order No. 1000 in every respect. Relevant here is that ATSI, certain of ATSI's affiliates, and certain other PJM transmission owners appealed FERC’s requirement that transmission tariffs eliminate any language that provided a “right of first refusal” for incumbent transmission owners to construct and own new transmission projects that come out of the Order No. 1000 transmission planning processes. In its opinion, the D.C. Circuit affirmed FERC’s decision to eliminate the “right of first refusal.” However, the court noted that the question of whether or how Mobile-Sierra clauses apply is not yet ripe for judicial review because FERC committed to consider such Mobile-Sierra arguments when reviewing transmission providers’ Order No. 1000 compliance filings. FERC did so with regard to PJM and appeals of its findings are pending in separate proceedings before the D.C. Circuit. The Mobile-Sierra doctrine establishes a higher burden for challenges-even by FERC-to rates, terms, and conditions established by contract, as opposed to those established in unilateral tariff filings. Under the Mobile-Sierra doctrine, rates arising from freely negotiated contracts, such as the PJM CTOA, are presumed to be just and reasonable under the FPA and may be abrogated only if the challenger rebuts that presumption with evidence that the contract rate is detrimental to the public interest.

To demonstrate compliance with the regional cost allocation principles of Order No. 1000, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid cost allocation method of 50% beneficiary pays and 50% “postage stamp” or socialization of certain project costs 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 again accepted the hybrid method. Certain parties sought rehearing of parts of FERC’s March 22, 2013 order. 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 New York Independent System Operator, Inc., or NYISO, region; and (2) the PJM region and the FERC-jurisdictional members of the Southeastern Regional Transmission Planning, or 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 the SERTP region participants’ 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 May 15, 2014, FERC issued an order denying rehearing of its March 22, 2013 order and accepting in part revisions to the PJM OA and OATT proposed by PJM and the PJM transmission owners, including FirstEnergy. FERC also directed PJM and the PJM transmission owners to submit a further compliance filing by July 15, 2014, which they did on July 14, 2014. On May 27, 2014, FirstEnergy filed a petition for review of FERC’s March 22, 2013 and May 15, 2014 orders with the D.C. Circuit. The court consolidated FirstEnergy’s appeal with another case before that court and stayed the consolidated proceedings pending the resolution of the appeals of FERC’s Order No. 1000, which the D.C. Circuit upheld in its entirety on August 15, 2014. On September 12, 2014, FERC conditionally accepted PJM’s July 14, 2014 compliance filing pursuant to FERC’s May 15, 2014 order, subject to a further compliance filing to be filed by October 13, 2014. Other parties’ requests for rehearing of certain aspects of the May 15, 2014 order, the appeals of the March 22, 2013 and May 15, 2014 orders, and the PJM transmission owners’ compliance filing pursuant to the May 15, 2014 order, are pending.

The outcome of the still-pending proceedings and their impact, if any, on ATSI cannot be predicted at this time.

RTO Realignment

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 PJM. 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. FirstEnergy’s request for rehearing of FERC’s order remains pending.

In September 2011, the MISO submitted a written demand letter seeking payment from ATSI of transmission costs for legacy MISO transmission projects. ATSI declined to make payments pending further legal proceedings as described above. Following FERC’s rejection of the settlement agreement described above, the MISO again demanded payment of the legacy transmission cost allocation charges. ATSI is considering its response to MISO’s demand.

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 multi-value project, or 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, ATSI 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 approved before ATSI joined 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 D.C. Circuit. On July 18, 2014, the court denied ATSI’s petition for review, finding that FERC properly determined that the ATSI zone is responsible for an allocation of the “legacy RTEP” project costs and affirming FERC’s orders. However, the amount to be paid is pending before FERC as a result of the June 25, 2014 order from the Seventh Circuit that is described under “-PJM Transmission Rates” above.

The outcome of those proceedings that address the remaining open issues related to ATSI’s move into PJM cannot be predicted at this time.

Buckeye Power Complaint

In 2011, Buckeye Power, Inc. filed a FPA Section 206 complaint at FERC alleging that ATSI’s dual-voltage rate design is unjust and unreasonable because it unfairly imposes additional transmission charges on lower-voltage customers. On January 11, 2013, a FERC Administrative Law Judge, or ALJ, issued an Initial Decision concluding that ATSI’s dual-voltage transmission rate design, which provides for a separate charge for the use of ATSI’s 69 kV transmission facilities, is unjust, unreasonable, unduly discriminatory and preferential. The ALJ determined that a single rolled-in rate recovering the costs of all of ATSI’s transmission facilities operating at 69 kV or above is just, reasonable and not unduly discriminatory or preferential, and should be implemented in place of ATSI’s current rate design. On September 8, 2014, FERC issued its Opinion No. 533 in which it affirmed the ALJ’s Initial Decision and directed ATSI to submit a compliance filing by October 8, 2014 converting its current dual-voltage rate design to a single-voltage rate design to be effective January 1, 2015. At this time ATSI intends to submit the compliance filing as required. The change in rate design will not change ATSI’s total revenue requirement but will change the allocation of that revenue requirement to wholesale transmission customers.

Synchronous Condensers

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 ATSI’s 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 the Eastlake Unit 4 in May 2014. The transfer of each of the remaining units and conversion to synchronous condensers will occur when the units are retired from generating service, which is anticipated to be April 15, 2015. 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 that ATSI’s 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 rate 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 RTEP to substitute the installation of a static var compensator, or 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 associated property or equipment, or any other property rights at Lakeshore 18, as contemplated by the application ATSI and FG filed with FERC requesting approval of the transfer, that it does not necessitate the acquisition of any other assets by ATSI from FG, and that, as a result, ATSI and FG will not be consummating the sale of Lakeshore 18.

5. COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate ATSI with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on ATSI's earnings and competitive position to the extent that ATSI competes 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.

OTHER LEGAL PROCEEDINGS

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to ATSI's normal business operations pending against ATSI. The loss or range of loss in these matters is not expected to be material to ATSI. The other potentially material items not otherwise discussed above are described under Note 4, Regulatory Matters of the Notes to Financial Statements.

ATSI 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 ATSI 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 ATSI has legal liability or is otherwise made subject to liability, it could have a material adverse effect on ATSI's financial condition, results of operations and cash flows.

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We were organized under the laws of the State of Ohio in 1998. We own major high-voltage transmission facilities, which consist of approximately 7,525 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV in the PJM Region as of December 31, 2013. We, together with PJM, plan, operate, and maintain our transmission system in accordance with NERC reliability standards, and other applicable regulatory requirements. In addition, we comply with the regulations, orders, policies and practices prescribed by FERC and applicable state regulatory authorities.

As a result of the challenging competitive environment, FirstEnergy has redirected its growth strategy to pursue more predictable and sustainable long-term growth opportunities in its regulated businesses. The centerpiece of this strategy is a $4.2 billion “Energizing the Future” investment program that began in 2014 and will continue through 2017 to upgrade and expand the transmission system owned by FirstEnergy’s Regulated Transmission segment, which includes us. This program is focused on projects that enhance system performance, physical security and add operating flexibility and capacity starting with our system and moving east across FirstEnergy's service territory over time. FirstEnergy expects to fund these investments through a combination of debt, previously announced equity issuances through a stock investment plan and, to the extent available, employee benefit plans, and cash. As a result of these investments, the earnings of the companies in FirstEnergy's Regulated Transmission segment are expected to grow modestly over the next two years and then accelerate as the investments are fully recognized in rates. In total, FirstEnergy has identified at least $7 billion in transmission investment opportunities across the 24,000 mile transmission system, making this a continuing platform for growth in the years beyond 2017.

We use a formula rate mechanism to calculate our annual revenue requirement. Under the FPA our formula rate will remain in effect until approval is obtained from FERC pursuant to Section 205 of the FPA to change to a different mechanism or FERC determines that the formula rate is unjust and unreasonable or is unduly discriminatory or preferential. Such a determination could result from a challenge initiated at FERC by an interested party, or by FERC on its own initiative, in a proceeding under Section 206 of the FPA. In addition, we are analyzing a future proceeding pursuant to Section 205 of the FPA to, among other things, move from a historical actual-cost-of-service period to a forward-looking estimated-cost-of-service period, and upon completion of this analysis, we could file such a case before the FERC later this year. We can provide no assurance that we will file such Section 205 proceeding in such time frame or at all and we cannot provide any assurance that it will be resolved favorably.

Summary of Results of Operations — First Six Months of 2014 Compared with First Six Months of 2013

Net income increased $11 million in the first six months of 2014, compared to the same period of 2013, as more fully described below.

Revenues

Total revenues increased $11 million reflecting cost of service and incremental rate base recovery resulting from our annual rate filings effective June 2013 and June 2014.

Operating Expenses

Total operating expenses increased $12 million in the first six months of 2014, compared to the same period of 2013. The following table presents changes from the prior period by expense category.

Operating Expenses - Changes	Increase
	(In millions)
Other operating expenses	$	—
Provision for depreciation	4
General taxes	8
Increase in Operating Expenses	$	12

Depreciation expense increased mainly due to an increase in the depreciable asset base. General taxes increased primarily due to higher property taxes associated with a higher asset base.

Other Income

Other income increased $13 million in the first six months of 2014 compared to the same period of 2013 primarily due to higher capitalized financing costs of $14 million resulting from increased construction work in progress, or CWIP, associated with the "Energizing the Future" investment program noted above, partially offset by increased interest expense.

Summary of Results of Operations — 2013 Compared with 2012

Net income increased $10 million in 2013, compared to 2012, as more fully described below.

Revenues

Total revenues increased $4 million principally due to the recovery associated with increased operating expenses and a higher rate base related to higher capital investment.

Operating Expenses

Total operating expenses decreased $2 million in 2013 compared to 2012. The following table presents changes from the prior period by expense category.

Operating Expenses - Changes	Increase (Decrease)
	(In millions)
Other operating expenses	$	(7	)
Pensions and OPEB mark-to-market adjustments	(1		)
Provision for depreciation	4
Amortization of other regulatory assets, net	(3		)
General taxes	5
Net Decrease in Operating Expenses	$	(2	)

Total operating expenses decreased by $2 million primarily due to a decrease in other operating expenses related to increased capital focus, resulting in less maintenance work, offset by higher depreciation and property taxes reflecting a higher asset base.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. We net regulatory assets and liabilities in accordance with FERC requirements. The following tables provide information about the composition of net regulatory assets and liabilities as of June 30, 2014 and December 31, 2013, and the changes during the six months ended June 30, 2014.

Regulatory liabilities, net, on the Balance Sheet are as follows:

Regulatory Liabilities by Source	June 30, 2014			December 31, 2013			Increase (Decrease)
	(In millions)
MISO exit fee deferral	$	38		$	38		$	—
Customer receivables for future income taxes	16			9			7
Asset removal costs	(132		)	(133		)	1
Other	4			4			—
Total	$	(74	)	$	(82	)	$	8

Regulatory assets that do not earn a current return totaled approximately $40 million as of June 30, 2014 primarily related to the MISO exit fee deferral.

Capital Resources and Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated obligations. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments. In addition to internal sources to fund liquidity and capital requirements for 2014 and beyond, we expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt and equity contributions from FET, including $392 million of contributions in 2014 through June 30, 2014 and an additional $125 million contributed on September 15, 2014. We expect that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.

FirstEnergy's Regulated Transmission segment, of which we are a part, currently forecasts approximately $4.2 billion in transmission investments from 2014 through 2017 focused on improving system reliability and customer service along with addressing reliability requirements associated with plant deactivations or as required by NERC and PJM. These investments will initially focus on us and TrAIL, since we both recover our costs through formula rates and then move east across the remainder of FirstEnergy's service territory over time.

As of June 30, 2014, our net deficit in working capital (current assets less current liabilities) was due in large part to accrued taxes.

Our access to capital markets and costs of financing are influenced by the credit ratings of our securities. The following table displays our credit ratings as of June 30, 2014.

	S&P	Moody’s
ATSI	BBB-	Baa2

Short-Term Borrowings

As of June 30, 2014 and December 31, 2012, we had no short-term borrowings and $537 thousand of short-term borrowings as of December 31, 2013.

Revolving Credit Facility

We, along with FET and TrAIL, participate in a five-year syndicated revolving credit facility with aggregate commitments of $1.0 billion, which we refer to herein as our revolving credit facility. On March 31, 2014, we, FET and TrAIL entered into extensions and amendments to our revolving credit facility, whereby the term was extended until March 31, 2019. The lending banks’ commitments under our revolving credit facility remain at $1.0 billion. Our individual borrower sublimit was increased to $500 million from $100 million. Generally, borrowings under our revolving credit facility are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Our revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65% for ATSI and 75% for FET, measured at the end of each fiscal quarter. As of June 30, 2014, we were in compliance with the debt to total capitalization ratio under our revolving credit facility.

FirstEnergy Regulated Money Pool

We and FE's other regulated companies also have the ability to borrow from each other and FE to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FE and applicable subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2014 was 1.69% per annum for the regulated companies’ money pool.

Changes in Cash Position

As of June 30, 2014, December 31, 2013 and December 31, 2012, we had no cash and cash equivalents, as surplus funds are invested in the regulated companies' money pool as described above.

Cash Flows From Operating Activities

Net cash provided from operating activities was $68 million compared to $60 million during the first six months of 2014 and 2013, respectively, as summarized in the following table.

	Six Months Ended June 30
Operating Cash Flows	2014		2013		Increase (Decrease)
	(In millions)
Net income	$	27	$	16	$	11
Non-cash charges	18		43		(25		)
Working capital and other	23		1		22
	$	68	$	60	$	8

The $8 million increase in cash flows from operations is primarily due to the timing of federal tax payments and the reduction in receivables.

Net cash provided from operating activities was $103 million and $124 million during the year ended 2013 and 2012, respectively, as summarized in the following table.

	Year Ended December 31
						Increase
Operating Cash Flows	2013			2012		(Decrease)
	(In millions)
Net income	$	49		$	39	$	10
Non-cash charges	76			70		6
Working capital and other	(22		)	15		(37		)
	$	103		$	124	$	(21	)

The $21 million decrease in cash flows from operations is primarily due to the timing of payments to vendors.

Cash Flows From Financing Activities

In the first six months of 2014, cash provided from financing activities increased $375 million to $391 million from $16 million during the first six months of 2013, primarily related to an equity contribution from FET of $392 million in the first six months of 2014 to fund property additions related to the “Energizing the Future” investment program as discussed above in "Overview".

For the year ended December 31, 2013, cash provided from financing activities increased $182 million to $135 million from $47 million of cash used for financing activities in 2012 primarily related to an equity contribution from FET of $160 million in 2013 to fund property additions and invest in the FirstEnergy regulated companies' money pool.

Cash Flows From Investing Activities

The following table summarizes investing activities for the first six months of 2014 and the comparable period of 2013.

	Six Months Ended June 30
Cash Used for Investing Activities	2014		2013			Increase
	(In millions)
Property additions	$	438	$	123		$	315
Loans to affiliated companies, net	7		(49		)	56
Other	14		2			12
	$	459	$	76		$	383

Net cash used for investing activities during the first six months of 2014 increased by $383 million compared to the same period of 2013. The increase was primarily due to property additions associated with the "Energizing the Future" investment program to improve reliability as discussed above and lower cash received from loans to affiliated companies.

The following table summarizes investing activities for 2013 and 2012.

	Year Ended December 31
Cash Used for Investing Activities	2013			2012			Increase
	(In millions)
Property additions	$	279		$	171		$	108
Loans to affiliated companies, net	(49		)	(101		)	52
Other	8			7			1
	$	238		$	77		$	161

Net cash used for investing activities during 2013 increased by $161 million compared to the same period of 2012. The increase was primarily due to property additions and lower cash received from loans to affiliated companies.

Contractual Obligations

As of December 31, 2013, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

Contractual Obligations	Total		2014		2015-2016		2017-2018		Thereafter
	(In millions)
Long-term debt(1)	$	400	$	—	$	—	$	—	$	400
Short-term borrowings	1		1		—		—		—
Interest on long-term debt	169		21		42		42		64
ATSI ground lease(2)	720		20		40		40		620
Capital expenditures	1,139		464		237		274		164
Total	$	2,429	$	506	$	319	$	356	$	1,248

⁽¹⁾  Excludes unamortized discounts and premiums, fair value accounting adjustments and capital leases.

⁽²⁾  Represents affiliated company agreements through 2049.

The table above excludes regulatory liabilities, reserves for litigation, injuries and damages, environmental remediation, and annual insurance premiums, since the amount and timing of the cash payments are uncertain. The table also excludes accumulated deferred income taxes and investment tax credits since cash payments for income taxes are determined based primarily on taxable income for each applicable fiscal year.

Credit Risk

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. We evaluate the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. We may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. We monitor the financial conditions of existing counterparties on an ongoing basis. FirstEnergy's independent risk management group oversees credit risk.

Outlook

Please see Note 5, Commitments and Contingencies, of the Notes to Financial Statements (Unaudited) included in this offering memorandum.