Robert A. Weishaar, Jr. Direct Dial: 202.898.0688 Direct Fax: 717.260.1765 bweishaar@mcneeslaw.com

June 27, 2017

The Honorable Kimberly D. Bose Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426

Re: Southern Maryland Electric Cooperative, Inc., Docket No. ER17-1916-000 Submission of Transmission Revenue Requirement for Southern Maryland Electric Cooperative, Inc.

Dear Secretary Bose:

Pursuant to Section 205 of the Federal Power Act ("FPA"), 16 U.S.C. § 824d, and Section 35.13 of the Federal Energy Regulatory Commission's ("Commission" or "FERC") regulations, 18 C.F.R. § 35.13, Southern Maryland Electric Cooperative, Inc. ("SMECO") submits this filing to the Commission in connection with its formal integration into PJM Interconnection, L.L.C. ("PJM") as a Transmission Owner, effective January 1, 2017. In this filing, SMECO submits revisions to the PJM Open Access Transmission Tariff ("PJM Tariff")1

to add a stated Transmission Revenue Requirement ("TRR") for transmission service involving the 230 kilovolt ("kV") facilities of SMECO over which PJM now has operational control.2 As indicated in Section IV of this filing, SMECO requests that the effective date of its TRR align with the effective date for SMECO's new distribution rates. SMECO expects to be filing distribution rate changes with the Maryland Public Service Commission (“PSC”) on or about August 1, 2017 and anticipates that the changes to those rates will be effective in February 2018. In addition, through this filing, SMECO proposes to modify Schedule 1A to the PJM Tariff to establish a charge to recover costs associated with FERC Account 561 (Control Center Costs) that are allocated to SMECO's 230 kV facilities.

1 PJM Interconnection, L.L.C., Open Access Transmission Tariff (available at http://www.pjm.com/media/documents/merged-tariffs/oatt.pdf). References in this filing to "PJM Tariff" refer to the version of PJM's Tariff currently in effect. Any references to the "Proposed Tariff" refer to the modifications proposed in this filing. 2 Pursuant to Order No. 714, this filing is submitted by PJM on behalf of SMECO as part of an XML filing package that conforms with the Commission's regulations. PJM has agreed to make all filings on behalf of the PJM Transmission Owners in order to retain administrative control over the PJM Tariff. Thus, SMECO has requested PJM submit this proposed revision to the PJM Tariff in the eTariff system as part of PJM's electronic Intra PJM Tariff.

The Honorable Kimberly D. Bose June 27, 2017 Page 2 of 8

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While the Commission does not have jurisdiction over SMECO under Sections 205 and 206 of the FPA, as SMECO is not a FERC-jurisdictional public utility, the Commission does retain jurisdiction over PJM's rates. In this regard, the Commission must have adequate information to ensure that the integration of SMECO's TRR does not cause PJM's rates to become unjust or unreasonable. For this reason, SMECO hereby submits the attached materials for filing with the Commission. The enclosed testimony and exhibits substantiate the justness and reasonableness of the TRR proposed herein and were prepared by and provided by SMECO.

I. Background

a. PJM

PJM is a FERC-approved Regional Transmission Organization ("RTO") tasked with operating a competitive wholesale electricity market and managing the reliability of its transmission grid.3 PJM oversees open access transmission service over transmission lines covering all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.4 PJM's Tariff specifies a TRR for each PJM transmission zone.5 The TRR for each pricing zone used in the calculation of Network Integration Transmission Service ("NITS") rates is set forth in Attachment H to the PJM Tariff. Pursuant to Section 9.1(b) of the PJM Tariff and Article 7.3.2 of PJM's Consolidated Transmission Owners Agreement ("TOA"), PJM, as the Administrator of the PJM Tariff, has agreed to submit on behalf of Transmission Owners filings for which the Transmission Owners have exclusive FPA Section 205 filing rights. That protocol was adopted to coincide with the effective date of PJM's electronic baseline filing in compliance with Order No. 714 (124 F.E.R.C. ¶ 61,270) issued September 19, 2008.

b. SMECO

SMECO is a customer-owned rural electric cooperative organized as a not-for-profit Maryland corporation, with headquarters in Hughesville, Maryland, and a regional office in Leonardtown, Maryland. SMECO serves approximately 160,000 customers located in all or a portion of the following four counties in Maryland: Prince George's County, Charles County, St. Mary's County, and Calvert County.6 Because SMECO is a rural electric cooperative with annual sales of less than 4,000,000 MWhs, SMECO is not currently FERC-jurisdictional.7

SMECO's transmission facilities consist of 90.4 miles of 230 kV line and associated facilities. All of SMECO's interconnections with the PJM system are through Potomac Electric Power Company ("PEPCO") and are located wholly within the PEPCO Zone. Four of those interconnections (Burches Hill Switching Station, Farmington Switching Station, PEPCO Morgantown Switching Station, and Chalk Point Switching Station) serve as interconnection points with SMECO’s 69 kV system, which is not the subject of this filing, and the other three

3 https://www.ferc.gov/market-oversight/mkt-electric/pjm/elec-pjm-glance.pdf 4 http://www.pjm.com/~/media/about-pjm/newsroom/fact-sheets/pjm-statistics.ashx 5 http://www.pjm.com/~/media/about-pjm/pjm-zones.ashx 6 SMECO has a 1,150 square mile service territory. 7 SMECO does not receive financing under the Rural Electrification Act.

The Honorable Kimberly D. Bose June 27, 2017 Page 3 of 8

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interconnection points (Hawkins Gate Switching Station, Aquasco Switching Station, and Ryceville Switching Station) are at 230 kV.

In 2016, the North American Electric Reliability Corporation ("NERC") determined that SMECO's 230 kV facilities should be considered part of the Bulk Electric System ("BES") and, therefore, subject to BES obligations.8 As a result, NERC required SMECO to register as a Transmission Owner. On January 23, 2017, SMECO registered as a Transmission Owner with NERC.

NERC requires a Transmission Operator to operate and control BES facilities, which are, in this case, SMECO’s 230 kV facilities. As SMECO is not a Transmission Operator, it needed to contract with an entity to perform Transmission Operator ("TOP") functions. PJM performs TOP functions for nearly all transmission owners and for nearly all the transmission facilities in the PJM Region. PJM requires all entities for which it is performing TOP functions to execute the TOA. PJM determined that SMECO's 230 kV facilities meet the definition of transmission facilities under Section 1.27 of the TOA. Accordingly, SMECO executed the TOA, placed its 230 kV facilities under PJM operational control,9 and became a PJM Transmission Owner as of January 1, 2017. Letter Order, PJM Interconnection, L.L.C., FERC Docket Nos. ER17-282-000, ER17-283-000 (Nov. 30, 2016).

SMECO is considered a "Zero Revenue Requirement" PJM Transmission Owner at this time. SMECO currently recovers the cost of its 230 kV facilities from only SMECO members, under a Maryland PSC-jurisdictional tariff. However, under the PJM construct, SMECO is entitled to recover its cost of owning, operating, and maintaining its 230 kV facilities, which NERC has determined to be integrated with other transmission facilities in the PEPCO Zone, from all load in the PEPCO Zone. Recovery of SMECO's 230 kV facility cost from all load in the PEPCO Zone requires that SMECO make filings with and obtain approval from FERC to recover annual revenue requirements from load in the PEPCO Zone for SMECO's 230 kV facilities.10

II. Standard of Review

SMECO is not a public utility within the meaning of Section 201 of the FPA because SMECO has not yet reached 4,000,000 MWh in annual sales. As a result, SMECO is not subject to the Commission's ratemaking jurisdiction under FPA Sections 205 and 206. However, FERC does have jurisdiction under Sections 205 and 206 of the FPA over the rates for transmission service provided by PJM because RTOs are considered public utilities. When a non-jurisdictional transmission owner, such as SMECO, voluntarily joins a RTO, the Commission

8 SMECO's 230 kV facilities are the only SMECO facilities that NERC considers to be part of the BES. 9 The only facilities for which operational control was transferred to PJM are SMECO's 230 kV facilities, consistent with NERC’s classification of those facilities as being part of the BES. 10 As discussed in Section IV of this transmittal letter, SMECO will also be making a distribution rate filing with the Maryland PSC to update its distribution revenue requirement and to remove all costs of SMECO’s 230 kV facilities from SMECO’s Maryland PSC-jurisdictional rates. SMECO’s retail distribution customers will pay the rate for SMECO’s 230 kV facilities that is established in this proceeding.

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has statutory authority to review the non-jurisdictional utility's transmission revenue requirement "to the extent necessary to ensure that the [RTO's] rates are just and reasonable."11

FERC has defined the standard of review that applies when a non-jurisdictional entity submits its transmission revenue requirement as a component of an RTO's jurisdictional rate. The Commission has held that the non-jurisdictional entity's transmission revenue requirement is "subject to a full and complete Section 205 review as part of our section 205 review of that jurisdictional rate."12 The U.S. Court of Appeals for the District of Columbia has held that subjecting the transmission revenue requirements of non-jurisdictional utilities to a full section 205 review is "the only way to ensure that [the RTO's] rate is just and reasonable."13

III. Description of Filing And Justification for Tariff Revisions

Pursuant to Article 7.3.1 of the TOA and Section 9.1(a) of the PJM Tariff, PJM Transmission Owners have the exclusive and unilateral rights to file, pursuant to Section 205 of the FPA and the Commission's rules and regulations thereunder, for any changes in or relating to the establishment and recovery of the Transmission Owners' transmission revenue requirements or the transmission rate design under the PJM Tariff; such filing rights shall also encompass any provisions of the PJM Tariff governing the recovery of transmission-related costs incurred by the Transmission Owners. Article 7.3.2 of the TOA and Section 9.1(b) of the PJM Tariff provide that Transmission Owners may request that PJM, as the Administrator of the PJM Tariff, make the Transmission Owners' Section 205 filings with the Commission on behalf of those Transmission Owners. Accordingly, SMECO has requested that PJM electronically file the PJM Tariff changes proposed herein, with testimonial support for SMECO's TRR provided by SMECO's witnesses. With this filing, PJM is not independently supporting or justifying SMECO's TRR, but is merely revising the PJM Tariff to accommodate SMECO's recovery of transmission service revenues for SMECO's 230 kV transmission facilities, in accordance with PJM's obligations under Article 7.3 of the TOA and Section 9.1 of the PJM Tariff.

SMECO intends to recover under the PJM Tariff the cost of its 230 kV transmission facilities that are interconnected with the PJM system from all customers in the PEPCO Zone. Upon FERC approval of this filing, PJM will recover SMECO's revenue requirement in accordance with the PJM Tariff and distribute the transmission service revenues to SMECO. In order to accommodate SMECO's recovery of the transmission service revenues, SMECO submits revisions to Attachment H-9 of the PJM Tariff, and to the table of contents of the PJM Tariff, reflecting the inclusion of a new Attachment H-9C. Clean and redlined versions of SMECO's proposed modifications to Attachment H-9 are attached as Exhibits B-1 and C-1,

11 Pac. Gas & Elec. Co. v. FERC, 306 F.3d 1112, 1117 (D.C. Cir. 2002); see also Southwest Power Pool, Inc., 137 F.E.R.C. ¶ 61,197, P 15 (2011); Southwest Power Pool, Inc., 147 F.E.R.C. ¶ 61,003, P 18 (2014). 12 Sw. Power Pool, Inc., 153 F.E.R.C. ¶ 61,366, P 37 (2015) (quoting City of Vernon, Cal., Opinion No. 479, 111 F.E.R.C. ¶ 61,092, at P 44, order on reh'g, Opinion No. 479-A, 112 F.E.R.C. ¶ 61,207 (2005), reh'g denied, Opinion No. 479-B 115 F.E.R.C. ¶ 61,297 (2006)). 13 Transmission Agency of N. Cal. v. FERC, 495 F.3d 663, 672 (D.C. Cir. 2007) (citing Opinion No. 479 at P 35).

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respectively. In particular, SMECO's proposed revision to Attachment H-9 would specify a TRR of $17,134,115 and a rate for Network Integration Transmission Service ("NITS") in the amount of $2,638.40 per megawatt per year. Mr. Smith's testimony and exhibits, attached hereto as Exhibit Nos. SME-01 through SME-08, and Ms. Cox’s testimony, attached hereto as Exhibit No. SME-09, provide support for SMECO's proposed TRR and NITS rate. Furthermore, SMECO proposes to modify Schedule 1A to PJM’s Tariff to establish a charge of $0.00942/MWh to recover costs associated in FERC Account 561 (Control Center Costs) that are allocated to SMECO's 230 kV facilities. Clean and redlined versions of SMECO’s proposed modifications to Schedule 1A are attached as Exhibits B-2 and C-2, respectively. Support for SMECO’s proposed Schedule 1A charge may also be found in Mr. Smith’s testimony and exhibits.

IV. Effective Date

On or about August 1, 2017, SMECO will file a distribution rate case with the Maryland PSC in order to update SMECO's distribution revenue requirement and remove from SMECO's distribution rates the costs associated with SMECO’s 230 kV facilities for which rate recovery is being sought in this proceeding. SMECO anticipates the PSC will initially suspend the effective date of those new rates for a period of 150 days pursuant to Md. Code Ann. § 4-204(b)(2)(i). The PSC also retains the right to suspend rates for an additional 30 days to accommodate proceedings.14 At this time, it is not possible to predict whether SMECO's distribution rate proceeding will be fully litigated. If other parties contest SMECO's distribution rate filing, then new distribution rates will likely go into effect on or about February 27, 2018. If, however, SMECO settles its distribution rate case, then rates may become effective earlier than 180 days after the requested effective date – meaning that SMECO's new distribution rates could become effective as early as January 2018.15

16 U.S.C. § 824d(d) indicates that unless FERC indicates otherwise, "no change shall be made by any public utility in any such rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, except after sixty days' notice to the Commission and to the public." However, "[t]he Commission, for good cause shown, may allow changes to take effect without requiring the sixty days' notice herein provided for by an order specifying the changes to be made and the time when they shall take effect and the manner in which they shall be filed and published."16

14 Md. Code Ann. § 4-204(b)(2)(ii). 15 SMECO's three previous distribution rate cases have settled. In 2015, SMECO's distribution rates took effect 135 days after the requested date. In the Matter of the Application of Southern Maryland Electric Cooperative, Inc. for Authority to Revise its Rates and Charges for Electric Service and Certain Rate Design Charges, Case No. 9396 (2015). In 2010, SMECO's distribution rates became effective 172 days after the requested date. In the Matter of the Application of Southern Maryland Electric Cooperative, Inc. for Authority to Revise its Rates and Charges for Electric Service and for Certain Rate Design Charges, Case No. 9234 (2010). And in 2007, SMECO's distribution rates took effect 124 days after the requested date. In the Matter of the Application of Southern Maryland Electric Cooperative, Inc. for Authority to Revise its Rates and Charges for Electric Service and for Certain Rate Design Charges, Case No. 9106 (2007). 16 16 U.S.C. § 824d(d).

The Honorable Kimberly D. Bose June 27, 2017 Page 6 of 8

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Accordingly, pursuant to 18 C.F.R. § 35.3, SMECO requests waiver of the 60-day notice provided by 16 U.S.C. § 824d(d) so that SMECO may align the effective date of its TRR with the effective date of its proposed changes to distribution rates, which SMECO presently anticipates will be on or about February 27, 2018. Good cause exists for granting this request for waiver. Alignment of the effective dates for SMECO's distribution rate changes and the TRR will ease administrative burdens for the Commission, the PSC, SMECO, PJM, and other entities involved in these parallel proceedings. Furthermore, aligning the effective dates for these rates will reduce or eliminate the potential for over-recovery or under-recovery that could result from any difference between the effective date of SMECO's proposed distribution rate and the final, FERC-approved TRR. SMECO will provide at least thirty (30) days’ prior notice to this Commission of the specific effective date that SMECO requests.

Notwithstanding the request for a deferred effective date of the rate change, SMECO respectfully requests that the Commission act on this filing within the 60-day period.

V. Additional Information

a. Documents Submitted with this Filing

In addition to this transmittal letter, the following items are included:

1) Attachment A – Draft Notice of Filing 2) Attachment B – Clean Versions of Proposed PJM Tariff Revisions

a. Exhibit B-1: Clean Version of Proposed PJM Tariff Attachment H-9C

b. Exhibit B-2: Clean Version of Proposed PJM Tariff Attachment 1A c. Exhibit B-3: Clean Version of Proposed PJM Tariff, Table of

Contents 3) Attachment C – Redlined Versions of Proposed PJM Tariff Revisions

a. Exhibit C-1: Redlined Version of Proposed PJM Tariff Attachment H-9C

b. Exhibit C-2: Redlined Version of Proposed PJM Tariff Attachment 1A

c. Exhibit C-3: Redlined Version of Proposed PJM Tariff, Table of Contents

4) Attachment D – SMECO's Cost of Service Analysis and Supporting Testimony

a. Exhibit Nos. SME-01 through SME-08: Direct Testimony and Exhibits of Robert C. Smith

b. Exhibit No. SME-09: Direct Testimony of Sonja Cox c. Exhibit No. SME-10: Attestation

The Honorable Kimberly D. Bose June 27, 2017 Page 7 of 8

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b. Request for Waiver of Certain Filing Requirements

The information provided in this filing is intended to contain sufficient information for the Commission to determine that PJM's rates, inclusive of SMECO's TRR, are just and reasonable.

To the extent necessary, SMECO requests a waiver of any provisions of Section 35.13 of the Commission's regulations, 18 C.F.R. § 35.13, that may be deemed to require additional cost support in the form of cost-of-service statements for the enclosed revisions.

c. Service

PJM has served a copy of this filing on all PJM Members and on all state utility regulatory commissions in the PJM Region by posting this filing electronically. In accordance with the Commission's regulations,17 PJM will post a copy of this filing to the FERC filings section of its internet site, located at the following link: http://www.pjm.com/documents/ferc-manuals/ferc-filings.aspx with a specific link to the newly-filed document, and will send an email on the same date as this filing to all PJM Members and all state utility regulatory commissions in the PJM Region18 alerting them that this filing has been made by PJM and is available by following such link. If the document is not immediately available by using the referenced link, the document will be available through the referenced link within 24 hours of the filing. Also, a copy of this filing will be available on the Commission's eLibrary website located at the following link: https://www.ferc.gov/docs-filing/elibrary.asp in accordance with the Commission's regulations and Order No. 714.

d. Requisite Agreement

These revisions to the PJM Tariff do not require any contracts or agreements.

e. Communications

Correspondence and communications with respect to this filing should be sent to the following individuals:19

Robert A. Weishaar, Jr. McNees Wallace & Nurick LLC 1200 G Street, N.W. Suite 800 Washington, D.C. 20005 Telephone: (202) 898-0688 Fax: (717) 260-1765 bweishaar@mcneeslaw.com

17 See 18 C.F.R. §§ 35.2(e) and 385.2010(f)(3). 18 PJM already maintains, updates, and regularly uses e-mail lists for all PJM Members and affected state commissions. 19 SMECO requests a waiver of Rule 203(b)(3), 18 C.F.R. § 385.203(b)(3), to permit more than two persons to be on the service list.

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Alessandra L. Hylander McNees Wallace & Nurick LLC 100 Pine Street Harrisburg, PA 17101 Telephone: (717) 237-5435 Fax: (717) 260-1689 ahylander@mcneeslaw.com

Attorneys for Southern Maryland Electric Cooperative, Inc.

Steven R. Pincus, Esq. Associate General Counsel PJM Interconnection, LLC 2750 Monroe Blvd. Audubon, PA 19403 Telephone: (610) 666-4370 Fax: (610) 666-8211 Steven.Pincus@pjm.com

Attorney for PJM Interconnection, LLC

VI. Conclusion

For all of the foregoing reasons, SMECO respectfully requests that the Commission accept the PJM Tariff revisions proposed herein as just and reasonable, with the effective date of those revisions to be aligned with the effective date of the to-be-filed changes to SMECO's distribution rates.

Respectfully submitted,

McNees Wallace & Nurick LLC

By: _____________________________________

Robert A. Weishaar, Jr.

Counsel to Southern Maryland Electric Cooperative, Inc.

ATTACHMENT A

DRAFT NOTICE OF FILING

UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

Southern Maryland Electric Cooperative, Inc. ) Docket No. ER17-___-000

NOTICE OF FILING

Take notice that on June 27, 2017, pursuant to Section 205 of the Federal Power Act, 16 U.S.C. § 824d, and Section 35.13 of the Commission's regulations, 18 C.F.R. § 35.13, Southern Maryland Electric Cooperative, Inc. ("SMECO"), filed a request with the Federal Energy Regulatory Commission ("FERC" or "Commission") to add a stated Transmission Revenue Requirement ("TRR") to PJM Interconnection L.L.C.'s ("PJM") Open Access Transmission Tariff ("PJM Tariff"). The proposed stated TRR will enable SMECO to recover costs associated with transmission service involving SMECO's 230 kilovolt facilities. In addition, in this filing SMECO included modifications to Schedule 1A of the PJM Tariff to reflect establishment of a charge to recover costs associated with Scheduling, System Control, and Dispatch Service.

Pursuant to Order No. 714, 124 F.E.R.C. ¶ 61,270, this filing was electronically filed by PJM on behalf of SMECO as part of an XML filing package that conforms with the Commission's regulations. PJM has agreed to make all filings on behalf of the PJM Transmission Owners in order to retain administrative control over the PJM Tariff. Thus, SMECO has requested PJM submit this proposed revision to the PJM Tariff in the eTariff system as part of PJM's electronic Intra PJM Tariff. Accordingly, PJM has served copies of this filing upon all PJM Members and upon all state utility regulatory commissions in the PJM Region by posting this filing electronically. Any person desiring to protest this filing must file in accordance with Rule 211 and Rule 214 of the Commission's Rules of Practice and Procedure (18 C.F.R. §§ 385.211 and 385.214). Protests to this filing will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Such protests must be filed in accordance with the provisions of Section 154.210 of the Commission's regulations (18 C.F.R. § 154.210). Anyone filing a protest must serve a copy of that document upon the applicant and upon all the parties to the proceeding.

The Commission encourages electronic submission of protests in lieu of paper using the "eFiling" link at http://www.ferc.gov. Persons unable to file electronically should submit an original and 14 copies of the protest to the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426.

This filing is accessible online at http://www.ferc.gov, using the "eLibrary" link and is available for review in the Commission's Public Reference Room in Washington, D.C. There is an "eSubscription" link on the website that enables subscribers to receive an email notification when a document is added to a subscribed docket. For assistance with any FERC Online service, please email FERCOnlineSupport@ferc.gov, or call (866) 208-3676 (toll free). For TTY call (202) 502-8659.

Kimberly D. Bose, Secretary

Date: _____________________, 2017

ATTACHMENT B

CLEAN VERSIONS OF PROPOSED PJM TARIFF REVISIONS

EXHIBIT B-1: CLEAN VERSION OF PROPOSED PJM TARIFF ATTACHMENT H-9C

Page 1

ATTACHMENT H-9C

Annual Transmission Rate – Southern Maryland Electric Cooperative, Inc.

For Network Integration Transmission Service

1. The annual transmission revenue requirement is $17,134,115 and the rate for Network

Integration Transmission Service is $2,638.4 per megawatt per year, which reflects the

facilities within the Zone of 230 kV and higher voltage for Southern Maryland Electric

Cooperative, Inc.

2. The rate in (1) shall be effective until amended by the Transmission Owner(s) within the

Zone or modified by the Commission.

3. In addition to the rate set forth in section 1 of this Attachment H-9C, the Network

Customer purchasing Network Integration Transmission Service shall pay for

transmission congestion charges, in accordance with the provisions of the Tariff, and any

amounts necessary to reimburse the Transmission Owners for any amounts payable by

them as sales, excuse, "Btu," carbon, value-added or similar taxes (other than taxes based

upon or measured by net income) with respect to the amounts payable pursuant to the

Tariff.

EXHIBIT B-2: CLEAN VERSION OF PROPOSED PJM TARIFF SCHEDULE 1A

Page 2

SCHEDULE 1A

Transmission Owner Scheduling, System Control and Dispatch Service

Scheduling, System Control and Dispatch Service is provided directly by the Transmission

Provider under Schedule 1. The Transmission Customer must purchase this service from the

Transmission Provider. Certain control center facilities of the Transmission Owners also are

required to provide this service. This Schedule 1A sets forth the charges for Scheduling, System

Control and Dispatch Service based on the cost of operating the control centers of the

Transmission Owners. The Transmission Provider shall administer the provision of

Transmission Owner Scheduling, System Control and Dispatch Service. PJMSettlement shall be

the Counterparty to the purchases of Transmission Owner Scheduling, System Control and

Dispatch Service.

The charges for operation of the control centers of the Transmission Owners shall be determined

by multiplying the applicable rate as follows times the Transmission Customer’s use of the

Transmission System (including losses) on a megawatt hour basis:

(A) For a Transmission Customer serving Zone Load in:

Zone Rate ($/MWh)

Atlantic City Electric Company 0.0781

Baltimore Gas and Electric Company 0.0430

Delmarva Power & Light Company 0.0743

PECO Energy Company 0.1189

PP&L, Inc. Group 0.0618

Potomac Electric Power Company 0.0186

Public Service Electric and Gas Company 0.1030

Jersey Central Power & Light Company Rate updated annually

Per Attachment H-4

Metropolitan Edison Company Rate updated annually

Per Attachment H-28

Pennsylvania Electric Company Rate updated annually

Per Attachment H-28

Rockland Electric Company 0.5351

Commonwealth Edison Company 0.2223

AEP East Operating Companies Rate updated annually

Per Attachment H-14

The Dayton Power and Light Company1

0.0797

Duquesne Light Company 0.0520

American Transmission Systems, Incorporated (“ATSI”) Rate updated annually

Per Attachment H-21

_______________________ 1 Charges for service under this schedule to customers of The Dayton Power and Light Company that are

subject to the provisions of the October 14, 2003 Stipulation and Agreement of Settlement approved in

FERC Docket No. EL03-56-000 shall be governed by such settlement.

Page 3

Duke Energy Ohio, Inc., and

Duke Energy Kentucky, Inc. (“DEOK”)

East Kentucky Power Cooperative, Inc. (“EKPC”)

Southern Maryland Electric Cooperative, Inc. ("SMECO")

Rate updated annually

Per Attachment H-22

Per Attachment H-24

0.00942

(B) For a Transmission Customer serving Non-Zone Load (a Network Customer serving

Non-Zone Network Load or a Transmission Customer taking Point-to-Point service where the

Point of Delivery is at the boundary of the PJM Region):

$.0912//MWh

Each month, PJMSettlement shall pay to each Transmission Owner an amount equal to the

charges billed for that Transmission Owner’s zone pursuant to (A) above, plus that Transmission

Owner’s share as stated below of the charges billed to Transmission Customers serving Non-

Zone Network Load pursuant to (B) above:

Transmission Owner Share (%)

Atlantic City Electric Company 1.41

Baltimore Gas and Electric Company 2.28

Delmarva Power & Light Company 2.17

PECO Energy Company 7.57

PP&L, Inc. Group 3.88

Potomac Electric Power Company 0.92

Public Service Electric and Gas Company 7.55

Jersey Central Power & Light Company 3.71

Mid-Atlantic Interstate Transmission, LLC 3.12

Rockland Electric Company 0.57

Commonwealth Edison Company 41.42

AEP East Operating Companies 14.56

The Dayton Power and Light Company 2.41

Duquesne Light Company 1.20

American Transmission Systems, Incorporated (“ATSI”) 3.05

Duke Energy Ohio, Inc., and Duke Energy Kentucky, Inc. (“DEOK”) 4.172

East Kentucky Power Cooperative, Inc. (“EKPC”) 0.0

2 Any change to this share must be made as a tariff filing under Section 205 of the Federal Power Act.

EXHIBIT B-3: CLEAN VERSION OF PROPOSED PJM TARIFF TABLE OF CONTENTS

Page 4

TABLE OF CONTENTS

I. COMMON SERVICE PROVISIONS

1 Definitions

OATT Definitions – A – B

OATT Definitions – C – D

OATT Definitions – E – F

OATT Definitions – G – H

OATT Definitions – I – J – K

OATT Definitions – L – M – N

OATT Definitions – O – P – Q

OATT Definitions – R – S

OATT Definitions - T – U – V

OATT Definitions – W – X – Y - Z

2 Initial Allocation and Renewal Procedures

3 Ancillary Services

3B PJM Administrative Service

3C Mid-Atlantic Area Council Charge

3D Transitional Market Expansion Charge

3E Transmission Enhancement Charges

3F Transmission Losses

4 Open Access Same-Time Information System (OASIS)

5 Local Furnishing Bonds

6 Reciprocity

6A Counterparty

7 Billing and Payment

8 Accounting for a Transmission Owner’s Use of the Tariff

9 Regulatory Filings

10 Force Majeure and Indemnification

11 Creditworthiness

12 Dispute Resolution Procedures

12A PJM Compliance Review

II. POINT-TO-POINT TRANSMISSION SERVICE

Preamble

13 Nature of Firm Point-To-Point Transmission Service

14 Nature of Non-Firm Point-To-Point Transmission Service

15 Service Availability

16 Transmission Customer Responsibilities

17 Procedures for Arranging Firm Point-To-Point Transmission

Service

18 Procedures for Arranging Non-Firm Point-To-Point Transmission

Service

19 Initial Study Procedures For Long-Term Firm Point-To-Point

Transmission Service Requests

20 [Reserved]

Page 5

21 [Reserved]

22 Changes in Service Specifications

23 Sale or Assignment of Transmission Service

24 Metering and Power Factor Correction at Receipt and Delivery

Points(s)

25 Compensation for Transmission Service

26 Stranded Cost Recovery

27 Compensation for New Facilities and Redispatch Costs

27A Distribution of Revenues from Non-Firm Point-to-Point

Transmission Service

III. NETWORK INTEGRATION TRANSMISSION SERVICE

Preamble

28 Nature of Network Integration Transmission Service

29 Initiating Service

30 Network Resources

31 Designation of Network Load

32 Initial Study Procedures For Network Integration Transmission

Service Requests

33 Load Shedding and Curtailments

34 Rates and Charges

35 Operating Arrangements

IV. INTERCONNECTIONS WITH THE TRANSMISSION SYSTEM

Preamble

Subpart A –INTERCONNECTION PROCEDURES

36 Interconnection Requests

37 Additional Procedures

38 Service on Merchant Transmission Facilities

39 Local Furnishing Bonds

40-108 [Reserved]

Subpart B – [Reserved]

Subpart C – [Reserved]

Subpart D – [Reserved]

Subpart E – [Reserved]

Subpart F – [Reserved]

Subpart G – SMALL GENERATION INTERCONNECTION PROCEDURE

Preamble

109 Pre-application Process

110 Permanent Capacity Resource Additions Of 20 MW Or Less

111 Permanent Energy Resource Additions Of 20 MW Or Less but Greater than

2 MW (Synchronous) or Greater than 5 MW(Inverter-based)

112 Temporary Energy Resource Additions Of 20 MW Or Less But

Greater Than 2 MW

112A Screens Process for Permanent or Temporary Energy Resources of 2 MW or

less (Synchronous) or 5 MW (Inverter-based)

Page 6

112B Certified Inverter-Based Small Generating Facilities No Larger than 10 kW

112C Alternate Queue Process

V. GENERATION DEACTIVATION

Preamble

113 Notices

114 Deactivation Avoidable Cost Credit

115 Deactivation Avoidable Cost Rate

116 Filing and Updating of Deactivation Avoidable Cost Rate

117 Excess Project Investment Required

118 Refund of Project Investment Reimbursement

118A Recovery of Project Investment

119 Cost of Service Recovery Rate

120 Cost Allocation

121 Performance Standards

122 Black Start Units

123-199 [Reserved]

VI. ADMINISTRATION AND STUDY OF NEW SERVICE REQUESTS; RIGHTS

ASSOCIATED WITH CUSTOMER-FUNDED UPGRADES

Preamble

200 Applicability

201 Queue Position

Subpart A – SYSTEM IMPACT STUDIES AND FACILITIES STUDIES

FOR NEW SERVICE REQUESTS

202 Coordination with Affected Systems

203 System Impact Study Agreement

204 Tender of System Impact Study Agreement

205 System Impact Study Procedures

206 Facilities Study Agreement

207 Facilities Study Procedures

208 Expedited Procedures for Part II Requests

209 Optional Interconnection Studies

210 Responsibilities of the Transmission Provider and Transmission

Owners

Subpart B– AGREEMENTS AND COST REPONSIBILITY FOR

CUSTOMER- FUNDED UPGRADES

211 Interim Interconnection Service Agreement

212 Interconnection Service Agreement

213 Upgrade Construction Service Agreement

214 Filing/Reporting of Agreement

215 Transmission Service Agreements

216 Interconnection Requests Designated as Market Solutions

217 Cost Responsibility for Necessary Facilities and Upgrades

218 New Service Requests Involving Affected Systems

219 Inter-queue Allocation of Costs of Transmission Upgrades

Page 7

220 Advance Construction of Certain Network Upgrades

221 Transmission Owner Construction Obligation for Necessary Facilities

And Upgrades

222 Confidentiality

223 Confidential Information

224 – 229 [Reserved]

Subpart C – RIGHTS RELATED TO CUSTOMER-FUNDED UPGRADES

230 Capacity Interconnection Rights

231 Incremental Auction Revenue Rights

232 Transmission Injection Rights and Transmission Withdrawal

Rights

233 Incremental Available Transfer Capability Revenue Rights

234 Incremental Capacity Transfer Rights

235 Incremental Deliverability Rights

236 Interconnection Rights for Certain Transmission Interconnections

237 IDR Transfer Agreements

SCHEDULE 1

Scheduling, System Control and Dispatch Service

SCHEDULE 1A

Transmission Owner Scheduling, System Control and Dispatch Service

SCHEDULE 2

Reactive Supply and Voltage Control from Generation Sources Service

SCHEDULE 3

Regulation and Frequency Response Service

SCHEDULE 4

Energy Imbalance Service

SCHEDULE 5

Operating Reserve – Synchronized Reserve Service

SCHEDULE 6

Operating Reserve - Supplemental Reserve Service

SCHEDULE 6A

Black Start Service

SCHEDULE 7

Long-Term Firm and Short-Term Firm Point-To-Point Transmission Service

SCHEDULE 8

Non-Firm Point-To-Point Transmission Service

SCHEDULE 9

PJM Interconnection L.L.C. Administrative Services

SCHEDULE 9-1

Control Area Administration Service

SCHEDULE 9-2

Financial Transmission Rights Administration Service

SCHEDULE 9-3

Market Support Service

SCHEDULE 9-4

Page 8

Regulation and Frequency Response Administration Service

SCHEDULE 9-5

Capacity Resource and Obligation Management Service

SCHEDULE 9-6

Management Service Cost

SCHEDULE 9-FERC

FERC Annual Charge Recovery

SCHEDULE 9-OPSI

OPSI Funding

SCHEDULE 9-CAPS

CAPS Funding

SCHEDULE 9-FINCON

Finance Committee Retained Outside Consultant

SCHEDULE 9-MMU

MMU Funding

SCHEDULE 9 – PJM SETTLEMENT

SCHEDULE 10 - [Reserved]

SCHEDULE 10-NERC

North American Electric Reliability Corporation Charge

SCHEDULE 10-RFC

Reliability First Corporation Charge

SCHEDULE 11

[Reserved for Future Use]

SCHEDULE 11A

Additional Secure Control Center Data Communication Links and Formula Rate

SCHEDULE 12

Transmission Enhancement Charges

SCHEDULE 12 APPENDIX

SCHEDULE 12-A

SCHEDULE 13

Expansion Cost Recovery Change (ECRC)

SCHEDULE 14

Transmission Service on the Neptune Line

SCHEDULE 14 - Exhibit A

SCHEDULE 15

Non-Retail Behind The Meter Generation Maximum Generation Emergency

Obligations

SCHEDULE 16

Transmission Service on the Linden VFT Facility

SCHEDULE 16 Exhibit A

SCHEDULE 16 – A

Transmission Service for Imports on the Linden VFT Facility

SCHEDULE 17

Transmission Service on the Hudson Line

SCHEDULE 17 - Exhibit A

ATTACHMENT A

Page 9

Form of Service Agreement For Firm Point-To-Point Transmission Service

ATTACHMENT A-1

Form of Service Agreement For The Resale, Reassignment or Transfer of Point-to-

Point Transmission Service

ATTACHMENT B

Form of Service Agreement For Non-Firm Point-To-Point Transmission Service

ATTACHMENT C

Methodology To Assess Available Transfer Capability

ATTACHMENT C-1

Conversion of Service in the Dominion and Duquesne Zones

ATTACHMENT C-2

Conversion of Service in the Duke Energy Ohio, Inc. and Duke Energy Kentucky,

Inc, (“DEOK”) Zone

ATTACHMENT D

Methodology for Completing a System Impact Study

ATTACHMENT E

Index of Point-To-Point Transmission Service Customers

ATTACHMENT F

Service Agreement For Network Integration Transmission Service

ATTACHMENT F-1

Form of Umbrella Service Agreement for Network Integration Transmission

Service Under State Required Retail Access Programs

ATTACHMENT G

Network Operating Agreement

ATTACHMENT H-1

Annual Transmission Rates -- Atlantic City Electric Company for Network

Integration Transmission Service

ATTACHMENT H-1A

Atlantic City Electric Company Formula Rate Appendix A

ATTACHMENT H-1B

Atlantic City Electric Company Formula Rate Implementation Protocols

ATTACHMENT H-2

Annual Transmission Rates -- Baltimore Gas and Electric Company for Network

Integration Transmission Service

ATTACHMENT H-2A

Baltimore Gas and Electric Company Formula Rate

ATTACHMENT H-2B

Baltimore Gas and Electric Company Formula Rate Implementation Protocols

ATTACHMENT H-3

Annual Transmission Rates -- Delmarva Power & Light Company for Network

Integration Transmission Service

ATTACHMENT H-3A

Delmarva Power & Light Company Load Power Factor Charge Applicable to

Service the Interconnection Points

ATTACHMENT H-3B

Page 10

Delmarva Power & Light Company Load Power Factor Charge Applicable to

Service the Interconnection Points

ATTACHMENT H-3C

Delmarva Power & Light Company Under-Frequency Load Shedding Charge

ATTACHMENT H-3D

Delmarva Power & Light Company Formula Rate – Appendix A

ATTACHMENT H-3E

Delmarva Power & Light Company Formula Rate Implementation Protocols

ATTACHMENT H-3F

Old Dominion Electric Cooperative Formula Rate – Appendix A

ATTACHMENT H-3G

Old Dominion Electric Cooperative Formula Rate Implementation Protocols

ATTACHMENT H-4

Annual Transmission Rates -- Jersey Central Power & Light Company for Network

Integration Transmission Service

ATTACHMENT H-4A

Jersey Central Power & Light Company Formula Rate Template

ATTACHMENT H-4B

Jersey Central Power & Light Company Formula Rate Implementation Protocols

ATTACHMENT H-5

Annual Transmission Rates -- Metropolitan Edison Company for Network

Integration Transmission Service

ATTACHMENT H-5A

Other Supporting Facilities -- Metropolitan Edison Company

ATTACHMENT H-6

Annual Transmission Rates -- Pennsylvania Electric Company for Network

Integration Transmission Service

ATTACHMENT H-6A

Other Supporting Facilities Charges -- Pennsylvania Electric Company

ATTACHMENT H-7

Annual Transmission Rates -- PECO Energy Company for Network Integration

Transmission Service

ATTACHMENT H-7A

PECO Energy Company Formula Rate Template

ATTACHMENT H-7B

PECO Energy Company Monthly Deferred Tax Adjustment Charge

ATTACHMENT H-7C

PECO Energy Company Formula Rate Implementation Protocols

ATTACHMENT H-8

Annual Transmission Rates – PPL Group for Network Integration Transmission

Service

ATTACHMENT H-8A

Other Supporting Facilities Charges -- PPL Electric Utilities Corporation

ATTACHMENT 8C

UGI Utilities, Inc. Formula Rate – Appendix A

ATTACHMENT 8D

Page 11

UGI Utilities, Inc. Formula Rate Implementation Protocols

ATTACHMENT 8E

UGI Utilities, Inc. Formula Rate – Appendix A

ATTACHMENT H-8G

Annual Transmission Rates – PPL Electric Utilities Corp.

ATTACHMENT H-8H

Formula Rate Implementation Protocols – PPL Electric Utilities Corp.

ATTACHMENT H-9

Annual Transmission Rates -- Potomac Electric Power Company for Network

Integration Transmission Service

ATTACHMENT H-9A

Potomac Electric Power Company Formula Rate – Appendix A

ATTACHMENT H-9B

Potomac Electric Power Company Formula Rate Implementation Protocols

ATTACHMENT H-9C

Annual Transmission Rate – Southern Maryland Electric Cooperative, Inc. for

Network Integration Transmission Service

ATTACHMENT H-10

Annual Transmission Rates -- Public Service Electric and Gas Company

for Network Integration Transmission Service

ATTACHMENT H-10A

Formula Rate -- Public Service Electric and Gas Company

ATTACHMENT H-10B

Formula Rate Implementation Protocols – Public Service Electric and Gas

Company

ATTACHMENT H-11

Annual Transmission Rates -- Allegheny Power for Network Integration

Transmission Service

ATTACHMENT 11A

Other Supporting Facilities Charges - Allegheny Power

ATTACHMENT H-12

Annual Transmission Rates -- Rockland Electric Company for Network Integration

Transmission Service

ATTACHMENT H-13

Annual Transmission Rates – Commonwealth Edison Company for Network

Integration Transmission Service

ATTACHMENT H-13A

Commonwealth Edison Company Formula Rate – Appendix A

ATTACHMENT H-13B

Commonwealth Edison Company Formula Rate Implementation Protocols

ATTACHMENT H-14

Annual Transmission Rates – AEP East Operating Companies for Network

Integration Transmission Service

ATTACHMENT H-14A

AEP East Operating Companies Formula Rate Implementation Protocols

ATTACHMENT H-14B Part 1

Page 12

ATTACHMENT H-14B Part 2

ATTACHMENT H-15

Annual Transmission Rates -- The Dayton Power and Light Company

for Network Integration Transmission Service

ATTACHMENT H-16

Annual Transmission Rates -- Virginia Electric and Power Company

for Network Integration Transmission Service

ATTACHMENT H-16A

Formula Rate - Virginia Electric and Power Company

ATTACHMENT H-16B

Formula Rate Implementation Protocols - Virginia Electric and Power Company

ATTACHMENT H-16C

Virginia Retail Administrative Fee Credit for Virginia Retail Load Serving

Entities in the Dominion Zone

ATTACHMENT H-16D – [Reserved]

ATTACHMENT H-16E – [Reserved]

ATTACHMENT H-16AA

Virginia Electric and Power Company

ATTACHMENT H-17

Annual Transmission Rates -- Duquesne Light Company for Network Integration

Transmission Service

ATTACHMENT H-17A

Duquesne Light Company Formula Rate – Appendix A

ATTACHMENT H-17B

Duquesne Light Company Formula Rate Implementation Protocols

ATTACHMENT H-17C

Duquesne Light Company Monthly Deferred Tax Adjustment Charge

ATTACHMENT H-18

Annual Transmission Rates – Trans-Allegheny Interstate Line Company

ATTACHMENT H-18A

Trans-Allegheny Interstate Line Company Formula Rate – Appendix A

ATTACHMENT H-18B

Trans-Allegheny Interstate Line Company Formula Rate Implementation Protocols

ATTACHMENT H-19

Annual Transmission Rates – Potomac-Appalachian Transmission Highline, L.L.C.

ATTACHMENT H-19A

Potomac-Appalachian Transmission Highline, L.L.C. Summary

ATTACHMENT H-19B

Potomac-Appalachian Transmission Highline, L.L.C. Formula Rate

Implementation Protocols

ATTACHMENT H-20

Annual Transmission Rates – AEP Transmission Companies (AEPTCo) in the AEP

Zone

ATTACHMENT H-20A

AEP Transmission Companies (AEPTCo) in the AEP Zone - Formula Rate

Implementation Protocols

Page 13

ATTACHMENT H-20A APPENDIX A

Transmission Formula Rate Settlement for AEPTCo

ATTACHMENT H-20B - Part I

AEP Transmission Companies (AEPTCo) in the AEP Zone – Blank Formula Rate

Template

ATTACHMENT H-20B - Part II

AEP Transmission Companies (AEPTCo) in the AEP Zone – Blank Formula Rate

TemplateATTACHMENT H-21

Annual Transmission Rates – American Transmission Systems, Inc. for Network

Integration Transmission Service

ATTACHMENT H-21A - ATSI

ATTACHMENT H-21A Appendix A - ATSI

ATTACHMENT H-21A Appendix B - ATSI

ATTACHMENT H-21A Appendix C - ATSI

ATTACHMENT H-21A Appendix C - ATSI [Reserved]

ATTACHMENT H-21A Appendix D – ATSI

ATTACHMENT H-21A Appendix E - ATSI

ATTACHMENT H-21A Appendix F – ATSI [Reserved]

ATTACHMENT H-21A Appendix G - ATSI

ATTACHMENT H-21A Appendix G – ATSI (Credit Adj)

ATTACHMENT H-21B ATSI Protocol

ATTACHMENT H-22

Annual Transmission Rates – DEOK for Network Integration Transmission Service

and Point-to-Point Transmission Service

ATTACHMENT H-22A

Duke Energy Ohio and Duke Energy Kentucky (DEOK) Formula Rate Template

ATTACHMENT H-22B

DEOK Formula Rate Implementation Protocols

ATTACHMENT H-22C

Additional provisions re DEOK and Indiana

ATTACHMENT H-23

EP Rock springs annual transmission Rate

ATTACHMENT H-24

EKPC Annual Transmission Rates

ATTACHMENT H-24A APPENDIX A

EKPC Schedule 1A

ATTACHMENT H-24A APPENDIX B

EKPC RTEP

ATTACHMENT H-24A APPENDIX C

EKPC True-up

ATTACHMENT H-24A APPENDIX D

EKPC Depreciation Rates

ATTACHMENT H-24-B

EKPC Implementation Protocols

ATTACHMENT H-25

Page 14

Annual Transmission Rates – Rochelle Municipal Utiliites for Network Integration

Transmission Service and Point-to-Point Transmission Service in the ComEd Zone

ATTACHMENT H-25A

Formula Rate Protocols for Rochelle Municipal Utilities Using a Historical Formula

Rate Template

ATTACHMENT H-25B

Rochelle Municipal Utilities Transmission Cost of Service Formula Rate – Appendix

A – Transmission Service Revenue Requirement

ATTACHMENT H-26

Transource West Virginia, LLC Formula Rate Template

ATTACHMENT H-26A

Transource West Virginia, LLC Formula Rate Implementation Protocols

ATTACHMENT H-27

Annual Transmission Rates – Northeast Transmission Development, LLC

ATTACHMENT H-27A

Northeast Transmission Development, LLC Formula Rate Template

ATTACHMENT H-27B

Northeast Transmission Development, LLC Formula Rate Implementation

Protocols

ATTACHMENT H-28

Annual Transmission Rates – Mid-Atlantic Interstate Transmission, LLC for

Network Integration Transmission Service

ATTACHMENT H-28A

Mid-Atlantic Interstate Transmission, LLC Formula Rate Template

ATTACHMENT H-28B

Mid-Atlantic Interstate Transmission, LLC Formula Rate Implementation

Protocols

ATTACHMENT H-29

Annual Transmission Rates – Transource Pennsylvania, LLC

ATTACHMENT H-29A

Transource Pennsylvania, LLC Formula Rate Template

ATTACHMENT H-29B

Transource Pennsylvania, LLC Formula Rate Implementation Protocols

ATTACHMENT H-30

Annual Transmission Rates – Transource Maryland, LLC

ATTACHMENT H-30A

Transource Maryland, LLC Formula Rate Template

ATTACHMENT H-30B

Transource Maryland, LLC Formula Rate Implementation Protocols

ATTACHMENT H-A

Annual Transmission Rates -- Non-Zone Network Load for Network Integration

Transmission Service

ATTACHMENT I

Index of Network Integration Transmission Service Customers

ATTACHMENT J

PJM Transmission Zones

Page 15

ATTACHMENT K

Transmission Congestion Charges and Credits

Preface

ATTACHMENT K -- APPENDIX

Preface

1. MARKET OPERATIONS

1.1 Introduction

1.2 Cost-Based Offers

1.2A Transmission Losses

1.3 [Reserved for Future Use]

1.4 Market Buyers

1.5 Market Sellers

1.5A Economic Load Response Participant

1.6 Office of the Interconnection

1.6A PJM Settlement

1.7 General

1.8 Selection, Scheduling and Dispatch Procedure Adjustment Process

1.9 Prescheduling

1.10 Scheduling

1.11 Dispatch

1.12 Dynamic Transfers

2. CALCULATION OF LOCATIONAL MARGINAL PRICES

2.1 Introduction

2.2 General

2.3 Determination of System Conditions Using the State Estimator

2.4 Determination of Energy Offers Used in Calculating

2.5 Calculation of Real-time Prices

2.6 Calculation of Day-ahead Prices

2.6A Interface Prices

2.7 Performance Evaluation

3. ACCOUNTING AND BILLING

3.1 Introduction

3.2 Market Buyers

3.3 Market Sellers

3.3A Economic Load Response Participants

3.4 Transmission Customers

3.5 Other Control Areas

3.6 Metering Reconciliation 3.7 Inadvertent Interchange

4. [Reserved For Future Use]

5. CALCULATION OF CHARGES AND CREDITS FOR TRANSMISSION

CONGESTION AND LOSSES

5.1 Transmission Congestion Charge Calculation

5.2 Transmission Congestion Credit Calculation

5.3 Unscheduled Transmission Service (Loop Flow)

5.4 Transmission Loss Charge Calculation

5.5 Distribution of Total Transmission Loss Charges

Page 16

6. “MUST-RUN” FOR RELIABILITY GENERATION

6.1 Introduction

6.2 Identification of Facility Outages

6.3 Dispatch for Local Reliability

6.4 Offer Price Caps

6.5 [Reserved]

6.6 Minimum Generator Operating Parameters –

Parameter-Limited Schedules

6A. [Reserved]

6A.1 [Reserved]

6A.2 [Reserved]

6A.3 [Reserved]

7. FINANCIAL TRANSMISSION RIGHTS AUCTIONS

7.1 Auctions of Financial Transmission Rights

7.1A Long-Term Financial Transmission Rights Auctions

7.2 Financial Transmission Rights Characteristics

7.3 Auction Procedures

7.4 Allocation of Auction Revenues

7.5 Simultaneous Feasibility

7.6 New Stage 1 Resources

7.7 Alternate Stage 1 Resources

7.8 Elective Upgrade Auction Revenue Rights

7.9 Residual Auction Revenue Rights

7.10 Financial Settlement

7.11 PJMSettlement as Counterparty

8. EMERGENCY AND PRE-EMERGENCY LOAD RESPONSE PROGRAM

8.1 Emergency Load Response and Pre-Emergency Load Response Program Options

8.2 Participant Qualifications

8.3 Metering Requirements

8.4 Registration

8.5 Pre-Emergency Operations

8.6 Emergency Operations

8.7 Verification

8.8 Market Settlements

8.9 Reporting and Compliance

8.10 Non-Hourly Metered Customer Pilot

8.11 Emergency Load Response and Pre-Emergency Load Response Participant

Aggregation

ATTACHMENT L

List of Transmission Owners

ATTACHMENT M

PJM Market Monitoring Plan

ATTACHMENT M – APPENDIX

PJM Market Monitor Plan Attachment M Appendix

I Confidentiality of Data and Information

II Development of Inputs for Prospective Mitigation

Page 17

III Black Start Service

IV Deactivation Rates

V Opportunity Cost Calculation

VI FTR Forfeiture Rule

VII Forced Outage Rule

VIII Data Collection and Verification

ATTACHMENT M-1 (FirstEnergy)

Energy Procedure Manual for Determining Supplier Total Hourly Energy

Obligation

ATTACHMENT M-2 (First Energy)

Energy Procedure Manual for Determining Supplier Peak Load Share

Procedures for Load Determination

ATTACHMENT M-2 (ComEd)

Determination of Capacity Peak Load Contributions and Network Service Peak

Load Contributions

ATTACHMENT M-2 (PSE&G)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Atlantic City Electric Company)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Delmarva Power & Light Company)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Delmarva Power & Light Company)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Duke Energy Ohio, Inc.)

Procedures for Determination of Peak Load Contributions, Network Service Peak

Load and Hourly Load Obligations for Retail Customers

ATTACHMENT M-3

Additional Procedures for Planning of Supplemental Projects

ATTACHMENT N

Form of Generation Interconnection Feasibility Study Agreement

ATTACHMENT N-1

Form of System Impact Study Agreement

ATTACHMENT N-2

Form of Facilities Study Agreement

ATTACHMENT N-3

Form of Optional Interconnection Study Agreement

ATTACHMENT O

Form of Interconnection Service Agreement

1.0 Parties

2.0 Authority

3.0 Customer Facility Specifications

4.0 Effective Date

Page 18

5.0 Security

6.0 Project Specific Milestones

7.0 Provision of Interconnection Service

8.0 Assumption of Tariff Obligations

9.0 Facilities Study

10.0 Construction of Transmission Owner Interconnection Facilities

11.0 Interconnection Specifications

12.0 Power Factor Requirement

12.0A RTU

13.0 Charges

14.0 Third Party Benefits

15.0 Waiver

16.0 Amendment

17.0 Construction With Other Parts Of The Tariff

18.0 Notices

19.0 Incorporation Of Other Documents

20.0 Addendum of Non-Standard Terms and Conditions for Interconnection Service

21.0 Addendum of Interconnection Customer’s Agreement

to Conform with IRS Safe Harbor Provisions for Non-Taxable Status

22.0 Addendum of Interconnection Requirements for a Wind Generation Facility

23.0 Infrastructure Security of Electric System Equipment and Operations and Control

Hardware and Software is Essential to Ensure Day-to-Day Reliability and

Operational Security

Specifications for Interconnection Service Agreement

1.0 Description of [generating unit(s)] [Merchant Transmission Facilities] (the

Customer Facility) to be Interconnected with the Transmission System in the PJM

Region

2.0 Rights

3.0 Construction Responsibility and Ownership of Interconnection Facilities

4.0 Subject to Modification Pursuant to the Negotiated Contract Option

4.1 Attachment Facilities Charge

4.2 Network Upgrades Charge

4.3 Local Upgrades Charge

4.4 Other Charges

4.5 Cost of Merchant Network Upgrades

4.6 Cost breakdown

4.7 Security Amount Breakdown

ATTACHMENT O APPENDIX 1: Definitions

ATTACHMENT O APPENDIX 2: Standard Terms and Conditions for Interconnections

1 Commencement, Term of and Conditions Precedent to

Interconnection Service

1.1 Commencement Date

1.2 Conditions Precedent

1.3 Term

1.4 Initial Operation

1.4A Limited Operation

Page 19

1.5 Survival

2 Interconnection Service

2.1 Scope of Service

2.2 Non-Standard Terms

2.3 No Transmission Services

2.4 Use of Distribution Facilities

2.5 Election by Behind The Meter Generation

3 Modification Of Facilities

3.1 General

3.2 Interconnection Request

3.3 Standards

3.4 Modification Costs

4 Operations

4.1 General

4.2 Operation of Merchant Network Upgrades

4.3 Interconnection Customer Obligations

4.4 [Reserved.]

4.5 Permits and Rights-of-Way

4.6 No Ancillary Services

4.7 Reactive Power

4.8 Under- and Over-Frequency Conditions

4.9 Protection and System Quality

4.10 Access Rights

4.11 Switching and Tagging Rules

4.12 Communications and Data Protocol

4.13 Nuclear Generating Facilities

5 Maintenance

5.1 General

5.2 Maintenance of Merchant Network Upgrades

5.3 Outage Authority and Coordination

5.4 Inspections and Testing

5.5 Right to Observe Testing

5.6 Secondary Systems

5.7 Access Rights

5.8 Observation of Deficiencies

6 Emergency Operations

6.1 Obligations

6.2 Notice

6.3 Immediate Action

6.4 Record-Keeping Obligations

7 Safety

7.1 General

7.2 Environmental Releases

8 Metering

8.1 General

8.2 Standards

Page 20

8.3 Testing of Metering Equipment

8.4 Metering Data

8.5 Communications

9 Force Majeure

9.1 Notice

9.2 Duration of Force Majeure

9.3 Obligation to Make Payments

9.4 Definition of Force Majeure

10 Charges

10.1 Specified Charges

10.2 FERC Filings

11 Security, Billing And Payments

11.1 Recurring Charges Pursuant to Section 10

11.2 Costs for Transmission Owner Interconnection

Facilities and/or Merchant Network Upgrades

11.3 No Waiver

11.4 Interest

12 Assignment

12.1 Assignment with Prior Consent

12.2 Assignment Without Prior Consent

12.3 Successors and Assigns

13 Insurance

13.1 Required Coverages for Generation Resources Of More

Than 20 Megawatts and Merchant Transmission Facilities

13.1A Required Coverages for Generation Resources Of

20 Megawatts Or Less

13.2 Additional Insureds

13.3 Other Required Terms

13.3A No Limitation of Liability

13.4 Self-Insurance

13.5 Notices; Certificates of Insurance

13.6 Subcontractor Insurance

13.7 Reporting Incidents

14 Indemnity

14.1 Indemnity

14.2 Indemnity Procedures

14.3 Indemnified Person

14.4 Amount Owing

14.5 Limitation on Damages

14.6 Limitation of Liability in Event of Breach

14.7 Limited Liability in Emergency Conditions

15 Breach, Cure And Default

15.1 Breach

15.2 Continued Operation

15.3 Notice of Breach

15.4 Cure and Default

Page 21

15.5 Right to Compel Performance

15.6 Remedies Cumulative

16 Termination

16.1 Termination

16.2 Disposition of Facilities Upon Termination

16.3 FERC Approval

16.4 Survival of Rights

17 Confidentiality

17.1 Term

17.2 Scope

17.3 Release of Confidential Information

17.4 Rights

17.5 No Warranties

17.6 Standard of Care

17.7 Order of Disclosure

17.8 Termination of Interconnection Service Agreement

17.9 Remedies

17.10 Disclosure to FERC or its Staff

17.11 No Interconnection Party Shall Disclose Confidential Information

17.12 Information that is Public Domain

17.13 Return or Destruction of Confidential Information

18 Subcontractors

18.1 Use of Subcontractors

18.2 Responsibility of Principal

18.3 Indemnification by Subcontractors

18.4 Subcontractors Not Beneficiaries

19 Information Access And Audit Rights

19.1 Information Access

19.2 Reporting of Non-Force Majeure Events

19.3 Audit Rights

20 Disputes

20.1 Submission

20.2 Rights Under The Federal Power Act

20.3 Equitable Remedies

21 Notices

21.1 General

21.2 Emergency Notices

21.3 Operational Contacts

22 Miscellaneous

22.1 Regulatory Filing

22.2 Waiver

22.3 Amendments and Rights Under the Federal Power Act

22.4 Binding Effect

22.5 Regulatory Requirements

23 Representations And Warranties

23.1 General

Page 23

24 Tax Liability

24.1 Safe Harbor Provisions

24.2. Tax Indemnity

24.3 Taxes Other Than Income Taxes

24.4 Income Tax Gross-Up

24.5 Tax Status

ATTACHMENT O - SCHEDULE A

Customer Facility Location/Site Plan

ATTACHMENT O - SCHEDULE B

Single-Line Diagram

ATTACHMENT O - SCHEDULE C

List of Metering Equipment

ATTACHMENT O - SCHEDULE D

Applicable Technical Requirements and Standards

ATTACHMENT O - SCHEDULE E

Schedule of Charges

ATTACHMENT O - SCHEDULE F

Schedule of Non-Standard Terms & Conditions

ATTACHMENT O - SCHEDULE G

Interconnection Customer’s Agreement to Conform with IRS Safe Harbor

Provisions for Non-Taxable Status

ATTACHMENT O - SCHEDULE H

Interconnection Requirements for a Wind Generation Facility

ATTACHMENT O-1

Form of Interim Interconnection Service Agreement

ATTACHMENT P

Form of Interconnection Construction Service Agreement

1.0 Parties

2.0 Authority

3.0 Customer Facility

4.0 Effective Date and Term

4.1 Effective Date

4.2 Term

4.3 Survival

5.0 Construction Responsibility

6.0 [Reserved.]

7.0 Scope of Work

8.0 Schedule of Work

9.0 [Reserved.]

10.0 Notices

11.0 Waiver

12.0 Amendment

13.0 Incorporation Of Other Documents

14.0 Addendum of Interconnection Customer’s Agreement

to Conform with IRS Safe Harbor Provisions for Non-Taxable Status

15.0 Addendum of Non-Standard Terms and Conditions for Interconnection Service

Page 24

16.0 Addendum of Interconnection Requirements for a Wind Generation Facility

17.0 Infrastructure Security of Electric System Equipment and Operations and Control

Hardware and Software is Essential to Ensure Day-to-Day Reliability and

Operational Security

ATTACHMENT P - APPENDIX 1 – DEFINITIONS

ATTACHMENT P - APPENDIX 2 – STANDARD CONSTRUCTION TERMS AND

CONDITIONS

Preamble

1 Facilitation by Transmission Provider

2 Construction Obligations

2.1 Interconnection Customer Obligations

2.2 Transmission Owner Interconnection Facilities and Merchant

Network Upgrades

2.2A Scope of Applicable Technical Requirements and Standards

2.3 Construction By Interconnection Customer

2.4 Tax Liability

2.5 Safety

2.6 Construction-Related Access Rights

2.7 Coordination Among Constructing Parties

3 Schedule of Work

3.1 Construction by Interconnection Customer

3.2 Construction by Interconnected Transmission Owner

3.2.1 Standard Option

3.2.2 Negotiated Contract Option

3.2.3 Option to Build

3.3 Revisions to Schedule of Work

3.4 Suspension

3.4.1 Costs

3.4.2 Duration of Suspension

3.5 Right to Complete Transmission Owner Interconnection

Facilities

3.6 Suspension of Work Upon Default

3.7 Construction Reports

3.8 Inspection and Testing of Completed Facilities

3.9 Energization of Completed Facilities

3.10 Interconnected Transmission Owner’s Acceptance of

Facilities Constructed by Interconnection Customer

4 Transmission Outages

4.1 Outages; Coordination

5 Land Rights; Transfer of Title

5.1 Grant of Easements and Other Land Rights

5.2 Construction of Facilities on Interconnection Customer Property

5.3 Third Parties

5.4 Documentation

5.5 Transfer of Title to Certain Facilities Constructed By

Interconnection Customer

Page 25

5.6 Liens

6 Warranties

6.1 Interconnection Customer Warranty

6.2 Manufacturer Warranties

7 [Reserved.]

8 [Reserved.]

9 Security, Billing And Payments

9.1 Adjustments to Security

9.2 Invoice

9.3 Final Invoice

9.4 Disputes

9.5 Interest

9.6 No Waiver

10 Assignment

10.1 Assignment with Prior Consent

10.2 Assignment Without Prior Consent

10.3 Successors and Assigns

11 Insurance

11.1 Required Coverages For Generation Resources Of More Than 20

Megawatts and Merchant Transmission Facilities

11.1A Required Coverages For Generation Resources of

20 Megawatts Or Less

11.2 Additional Insureds

11.3 Other Required Terms

11.3A No Limitation of Liability

11.4 Self-Insurance

11.5 Notices; Certificates of Insurance

11.6 Subcontractor Insurance

11.7 Reporting Incidents

12 Indemnity

12.1 Indemnity

12.2 Indemnity Procedures

12.3 Indemnified Person

12.4 Amount Owing

12.5 Limitation on Damages

12.6 Limitation of Liability in Event of Breach

12.7 Limited Liability in Emergency Conditions

13 Breach, Cure And Default

13.1 Breach

13.2 Notice of Breach

13.3 Cure and Default

13.3.1 Cure of Breach

13.4 Right to Compel Performance

13.5 Remedies Cumulative

14 Termination

14.1 Termination

Page 26

14.2 [Reserved.]

14.3 Cancellation By Interconnection Customer

14.4 Survival of Rights

15 Force Majeure

15.1 Notice

15.2 Duration of Force Majeure

15.3 Obligation to Make Payments

15.4 Definition of Force Majeure

16 Subcontractors

16.1 Use of Subcontractors

16.2 Responsibility of Principal

16.3 Indemnification by Subcontractors

16.4 Subcontractors Not Beneficiaries

17 Confidentiality

17.1 Term

17.2 Scope

17.3 Release of Confidential Information

17.4 Rights

17.5 No Warranties

17.6 Standard of Care

17.7 Order of Disclosure

17.8 Termination of Construction Service Agreement

17.9 Remedies

17.10 Disclosure to FERC or its Staff

17.11 No Construction Party Shall Disclose Confidential Information of Another

Construction Party 17.12 Information that is Public Domain

17.13 Return or Destruction of Confidential Information

18 Information Access And Audit Rights

18.1 Information Access

18.2 Reporting of Non-Force Majeure Events

18.3 Audit Rights

19 Disputes

19.1 Submission

19.2 Rights Under The Federal Power Act

19.3 Equitable Remedies

20 Notices

20.1 General

20.2 Operational Contacts

21 Miscellaneous

21.1 Regulatory Filing

21.2 Waiver

21.3 Amendments and Rights under the Federal Power Act

21.4 Binding Effect

21.5 Regulatory Requirements

22 Representations and Warranties

22.1 General

Page 27

ATTACHMENT P - SCHEDULE A

Site Plan

ATTACHMENT P - SCHEDULE B

Single-Line Diagram of Interconnection Facilities

ATTACHMENT P - SCHEDULE C

Transmission Owner Interconnection Facilities to be Built by Interconnected

Transmission Owner

ATTACHMENT P - SCHEDULE D

Transmission Owner Interconnection Facilities to be Built by Interconnection

Customer Pursuant to Option to Build

ATTACHMENT P - SCHEDULE E

Merchant Network Upgrades to be Built by Interconnected Transmission Owner

ATTACHMENT P - SCHEDULE F

Merchant Network Upgrades to be Built by Interconnection Customer

Pursuant to Option to Build

ATTACHMENT P - SCHEDULE G

Customer Interconnection Facilities

ATTACHMENT P - SCHEDULE H

Negotiated Contract Option Terms

ATTACHMENT P - SCHEDULE I

Scope of Work

ATTACHMENT P - SCHEDULE J

Schedule of Work

ATTACHMENT P - SCHEDULE K

Applicable Technical Requirements and Standards

ATTACHMENT P - SCHEDULE L

Interconnection Customer’s Agreement to Confirm with IRS Safe Harbor

Provisions For Non-Taxable Status

ATTACHMENT P - SCHEDULE M

Schedule of Non-Standard Terms and Conditions

ATTACHMENT P - SCHEDULE N

Interconnection Requirements for a Wind Generation Facility

ATTACHMENT Q

PJM Credit Policy

ATTACHMENT R

Lost Revenues Of PJM Transmission Owners And Distribution of Revenues

Remitted By MISO, SECA Rates to Collect PJM Transmission Owner Lost

Revenues Under Attachment X, And Revenues From PJM Existing Transactions

ATTACHMENT S

Form of Transmission Interconnection Feasibility Study Agreement

ATTACHMENT T

Identification of Merchant Transmission Facilities

ATTACHMENT U

Independent Transmission Companies

ATTACHMENT V

Form of ITC Agreement

Page 28

ATTACHMENT W

COMMONWEALTH EDISON COMPANY

ATTACHMENT X

Seams Elimination Cost Assignment Charges

NOTICE OF ADOPTION OF NERC TRANSMISSION LOADING RELIEF

PROCEDURES

NOTICE OF ADOPTION OF LOCAL TRANSMISSION LOADING REIEF

PROCEDURES

SCHEDULE OF PARTIES ADOPTING LOCAL TRANSMISSION LOADING

RELIEF PROCEDURES

ATTACHMENT Y

Forms of Screens Process Interconnection Request (For Generation Facilities of 2

MW or less)

ATTACHMENT Z

Certification Codes and Standards

ATTACHMENT AA

Certification of Small Generator Equipment Packages

ATTACHMENT BB

Form of Certified Inverter-Based Generating Facility No Larger Than 10 kW

Interconnection Service Agreement

ATTACHMENT CC

Form of Certificate of Completion

(Small Generating Inverter Facility No Larger Than 10 kW)

ATTACHMENT DD

Reliability Pricing Model

ATTACHMENT EE

Form of Upgrade Request

ATTACHMENT FF

Form of Initial Study Agreement

ATTACHMENT GG

Form of Upgrade Construction Service Agreement

Article 1 – Definitions And Other Documents

1.0 Defined Terms

1.1 Incorporation of Other Documents

Article 2 – Responsibility for Direct Assignment Facilities or Customer-Funded

Upgrades

2.0 New Service Customer Financial Responsibilities

2.1 Obligation to Provide Security

2.2 Failure to Provide Security

2.3 Costs

2.4 Transmission Owner Responsibilities

Article 3 – Rights To Transmission Service

3.0 No Transmission Service

Article 4 – Early Termination

4.0 Termination by New Service Customer

Article 5 – Rights

Page 29

5.0 Rights

5.1 Amount of Rights Granted

5.2 Availability of Rights Granted

5.3 Credits

Article 6 – Miscellaneous

6.0 Notices

6.1 Waiver

6.2 Amendment

6.3 No Partnership

6.4 Counterparts

ATTACHMENT GG - APPENDIX I –

SCOPE AND SCHEDULE OF WORK FOR DIRECT ASSIGNMENT

FACILITIES OR CUSTOMER-FUNDED UPGRADES TO BE BUILT BY

TRANSMISSION OWNER

ATTACHMENT GG - APPENDIX II - DEFINITIONS

1 Definitions

1.1 Affiliate

1.2 Applicable Laws and Regulations

1.3 Applicable Regional Reliability Council

1.4 Applicable Standards

1.5 Breach

1.6 Breaching Party

1.7 Cancellation Costs

1.8 Commission

1.9 Confidential Information

1.10 Constructing Entity

1.11 Control Area

1.12 Costs

1.13 Default

1.14 Delivering Party

1.15 Emergency Condition

1.16 Environmental Laws

1.17 Facilities Study

1.18 Federal Power Act

1.19 FERC

1.20 Firm Point-To-Point

1.21 Force Majeure

1.22 Good Utility Practice

1.23 Governmental Authority

1.24 Hazardous Substances

1.25 Incidental Expenses

1.26 Local Upgrades

1.27 Long-Term Firm Point-To-Point Transmission Service

1.28 MAAC

1.29 MAAC Control Zone

1.30 NERC

Page 30

1.31 Network Upgrades

1.32 Office of the Interconnection

1.33 Operating Agreement of the PJM Interconnection, L.L.C. or Operating

Agreement

1.34 Part I

1.35 Part II

1.36 Part III

1.37 Part IV

1.38 Part VI

1.39 PJM Interchange Energy Market

1.40 PJM Manuals

1.41 PJM Region

1.42 PJM West Region

1.43 Point(s) of Delivery

1.44 Point(s) of Receipt

1.45 Project Financing

1.46 Project Finance Entity

1.47 Reasonable Efforts

1.48 Receiving Party

1.49 Regional Transmission Expansion Plan

1.50 Schedule and Scope of Work

1.51 Security

1.52 Service Agreement

1.53 State

1.54 Transmission System

1.55 VACAR

ATTACHMENT GG - APPENDIX III – GENERAL TERMS AND CONDITIONS

1.0 Effective Date and Term

1.1 Effective Date

1.2 Term

1.3 Survival

2.0 Facilitation by Transmission Provider

3.0 Construction Obligations

3.1 Direct Assignment Facilities or Customer-Funded Upgrades

3.2 Scope of Applicable Technical Requirements and Standards

4.0 Tax Liability

4.1 New Service Customer Payments Taxable

4.2 Income Tax Gross-Up

4.3 Private Letter Ruling

4.4 Refund

4.5 Contests

4.6 Taxes Other Than Income Taxes

4.7 Tax Status

5.0 Safety

5.1 General

5.2 Environmental Releases

Page 31

6.0 Schedule Of Work

6.1 Standard Option

6.2 Option to Build

6.3 Revisions to Schedule and Scope of Work

6.4 Suspension

7.0 Suspension of Work Upon Default

7.1 Notification and Correction of Defects

8.0 Transmission Outages

8.1 Outages; Coordination

9.0 Security, Billing and Payments

9.1 Adjustments to Security

9.2 Invoice

9.3 Final Invoice

9.4 Disputes

9.5 Interest

9.6 No Waiver

10.0 Assignment

10.1 Assignment with Prior Consent

10.2 Assignment Without Prior Consent

10.3 Successors and Assigns

11.0 Insurance

11.1 Required Coverages

11.2 Additional Insureds

11.3 Other Required Terms

11.4 No Limitation of Liability

11.5 Self-Insurance

11.6 Notices: Certificates of Insurance

11.7 Subcontractor Insurance

11.8 Reporting Incidents

12.0 Indemnity

12.1 Indemnity

12.2 Indemnity Procedures

12.3 Indemnified Person

12.4 Amount Owing

12.5 Limitation on Damages

12.6 Limitation of Liability in Event of Breach

12.7 Limited Liability in Emergency Conditions

13.0 Breach, Cure And Default

13.1 Breach

13.2 Notice of Breach

13.3 Cure and Default

13.4 Right to Compel Performance

13.5 Remedies Cumulative

14.0 Termination

14.1 Termination

14.2 Cancellation By New Service Customer

Page 32

14.3 Survival of Rights

14.4 Filing at FERC

15.0 Force Majeure

15.1 Notice

15.2 Duration of Force Majeure

15.3 Obligation to Make Payments

16.0 Confidentiality

16.1 Term

16.2 Scope

16.3 Release of Confidential Information

16.4 Rights

16.5 No Warranties

16.6 Standard of Care

16.7 Order of Disclosure

16.8 Termination of Upgrade Construction Service Agreement

16.9 Remedies

16.10 Disclosure to FERC or its Staff

16.11 No Party Shall Disclose Confidential Information of Party 16.12

Information that is Public Domain

16.13 Return or Destruction of Confidential Information

17.0 Information Access And Audit Rights

17.1 Information Access

17.2 Reporting of Non-Force Majeure Events

17.3 Audit Rights

17.4 Waiver

17.5 Amendments and Rights under the Federal Power Act

17.6 Regulatory Requirements

18.0 Representation and Warranties

18.1 General

19.0 Inspection and Testing of Completed Facilities

19.1 Coordination

19.2 Inspection and Testing

19.3 Review of Inspection and Testing by Transmission Owner

19.4 Notification and Correction of Defects

19.5 Notification of Results

20.0 Energization of Completed Facilities

21.0 Transmission Owner’s Acceptance of Facilities Constructed

by New Service Customer

22.0 Transfer of Title to Certain Facilities Constructed By New Service Customer

23.0 Liens

ATTACHMENT HH – RATES, TERMS, AND CONDITIONS OF SERVICE FOR

PJMSETTLEMENT, INC.

ATTACHMENT II – MTEP PROJECT COST RECOVERY FOR ATSI ZONE

ATTACHMENT JJ – MTEP PROJECT COST RECOVERY FOR DEOK ZONE

Page 33

ATTACHMENT KK - FORM OF DESIGNATED ENTITY AGREEMENT

ATTACHMENT LL - FORM OF INTERCONNECTION COORDINATION

AGREEMENT

ATTACHMENT C

REDLINED VERSIONS OF PROPOSED PJM TARIFF REVISIONS

EXHIBIT C-1: REDLINED VERSION OF PROPOSED PJM TARIFF ATTACHMENT H-9C

Page 1

ATTACHMENT H-9C

Annual Transmission Rate – Southern Maryland Electric Cooperative, Inc.

For Network Integration Transmission Service

1. The annual transmission revenue requirement is $17,134,115 and the rate for Network

Integration Transmission Service is $2,638.4 per megawatt per year, which reflects the

facilities within the Zone of 230 kV and higher voltage for Southern Maryland Electric

Cooperative, Inc.

2. The rate in (1) shall be effective until amended by the Transmission Owner(s) within the

Zone or modified by the Commission.

3. In addition to the rate set forth in section 1 of this Attachment H-9C, the Network

Customer purchasing Network Integration Transmission Service shall pay for

transmission congestion charges, in accordance with the provisions of the Tariff, and any

amounts necessary to reimburse the Transmission Owners for any amounts payable by

them as sales, excuse, "Btu," carbon, value-added or similar taxes (other than taxes based

upon or measured by net income) with respect to the amounts payable pursuant to the

Tariff.

EXHIBIT C-2: REDLINED VERSION OF PROPOSED PJM TARIFF SCHEDULE 1A

Page 2

SCHEDULE 1A

Transmission Owner Scheduling, System Control and Dispatch Service

Scheduling, System Control and Dispatch Service is provided directly by the Transmission

Provider under Schedule 1. The Transmission Customer must purchase this service from the

Transmission Provider. Certain control center facilities of the Transmission Owners also are

required to provide this service. This Schedule 1A sets forth the charges for Scheduling, System

Control and Dispatch Service based on the cost of operating the control centers of the

Transmission Owners. The Transmission Provider shall administer the provision of

Transmission Owner Scheduling, System Control and Dispatch Service. PJMSettlement shall be

the Counterparty to the purchases of Transmission Owner Scheduling, System Control and

Dispatch Service.

The charges for operation of the control centers of the Transmission Owners shall be determined

by multiplying the applicable rate as follows times the Transmission Customer’s use of the

Transmission System (including losses) on a megawatt hour basis:

(A) For a Transmission Customer serving Zone Load in:

Zone Rate ($/MWh)

Atlantic City Electric Company 0.0781

Baltimore Gas and Electric Company 0.0430

Delmarva Power & Light Company 0.0743

PECO Energy Company 0.1189

PP&L, Inc. Group 0.0618

Potomac Electric Power Company 0.0186

Public Service Electric and Gas Company 0.1030

Jersey Central Power & Light Company Rate updated annually

Per Attachment H-4

Metropolitan Edison Company Rate updated annually

Per Attachment H-28

Pennsylvania Electric Company Rate updated annually

Per Attachment H-28

Rockland Electric Company 0.5351

Commonwealth Edison Company 0.2223

AEP East Operating Companies Rate updated annually

Per Attachment H-14

The Dayton Power and Light Company1

0.0797

Duquesne Light Company 0.0520

American Transmission Systems, Incorporated (“ATSI”) Rate updated annually

Per Attachment H-21

_______________________ 1 Charges for service under this schedule to customers of The Dayton Power and Light Company that are

subject to the provisions of the October 14, 2003 Stipulation and Agreement of Settlement approved in

FERC Docket No. EL03-56-000 shall be governed by such settlement.

Page 3

Duke Energy Ohio, Inc., and

Duke Energy Kentucky, Inc. (“DEOK”)

East Kentucky Power Cooperative, Inc. (“EKPC”)

Southern Maryland Electric Cooperative, Inc. ("SMECO")

Rate updated annually

Per Attachment H-22

Per Attachment H-24

0.00942

(B) For a Transmission Customer serving Non-Zone Load (a Network Customer serving

Non-Zone Network Load or a Transmission Customer taking Point-to-Point service where the

Point of Delivery is at the boundary of the PJM Region):

$.0912//MWh

Each month, PJMSettlement shall pay to each Transmission Owner an amount equal to the

charges billed for that Transmission Owner’s zone pursuant to (A) above, plus that Transmission

Owner’s share as stated below of the charges billed to Transmission Customers serving Non-

Zone Network Load pursuant to (B) above:

Transmission Owner Share (%)

Atlantic City Electric Company 1.41

Baltimore Gas and Electric Company 2.28

Delmarva Power & Light Company 2.17

PECO Energy Company 7.57

PP&L, Inc. Group 3.88

Potomac Electric Power Company 0.92

Public Service Electric and Gas Company 7.55

Jersey Central Power & Light Company 3.71

Mid-Atlantic Interstate Transmission, LLC 3.12

Rockland Electric Company 0.57

Commonwealth Edison Company 41.42

AEP East Operating Companies 14.56

The Dayton Power and Light Company 2.41

Duquesne Light Company 1.20

American Transmission Systems, Incorporated (“ATSI”) 3.05

Duke Energy Ohio, Inc., and Duke Energy Kentucky, Inc. (“DEOK”) 4.172

East Kentucky Power Cooperative, Inc. (“EKPC”) 0.0

2 Any change to this share must be made as a tariff filing under Section 205 of the Federal Power Act.

EXHIBIT C-3: REDLINED VERSION OF PROPOSED PJM TARIFF TABLE OF CONTENTS

Page 4

TABLE OF CONTENTS

I. COMMON SERVICE PROVISIONS

1 Definitions

OATT Definitions – A – B

OATT Definitions – C – D

OATT Definitions – E – F

OATT Definitions – G – H

OATT Definitions – I – J – K

OATT Definitions – L – M – N

OATT Definitions – O – P – Q

OATT Definitions – R – S

OATT Definitions - T – U – V

OATT Definitions – W – X – Y - Z

2 Initial Allocation and Renewal Procedures

3 Ancillary Services

3B PJM Administrative Service

3C Mid-Atlantic Area Council Charge

3D Transitional Market Expansion Charge

3E Transmission Enhancement Charges

3F Transmission Losses

4 Open Access Same-Time Information System (OASIS)

5 Local Furnishing Bonds

6 Reciprocity

6A Counterparty

7 Billing and Payment

8 Accounting for a Transmission Owner’s Use of the Tariff

9 Regulatory Filings

10 Force Majeure and Indemnification

11 Creditworthiness

12 Dispute Resolution Procedures

12A PJM Compliance Review

II. POINT-TO-POINT TRANSMISSION SERVICE

Preamble

13 Nature of Firm Point-To-Point Transmission Service

14 Nature of Non-Firm Point-To-Point Transmission Service

15 Service Availability

16 Transmission Customer Responsibilities

17 Procedures for Arranging Firm Point-To-Point Transmission

Service

18 Procedures for Arranging Non-Firm Point-To-Point Transmission

Service

19 Initial Study Procedures For Long-Term Firm Point-To-Point

Transmission Service Requests

20 [Reserved]

Page 5

21 [Reserved]

22 Changes in Service Specifications

23 Sale or Assignment of Transmission Service

24 Metering and Power Factor Correction at Receipt and Delivery

Points(s)

25 Compensation for Transmission Service

26 Stranded Cost Recovery

27 Compensation for New Facilities and Redispatch Costs

27A Distribution of Revenues from Non-Firm Point-to-Point

Transmission Service

III. NETWORK INTEGRATION TRANSMISSION SERVICE

Preamble

28 Nature of Network Integration Transmission Service

29 Initiating Service

30 Network Resources

31 Designation of Network Load

32 Initial Study Procedures For Network Integration Transmission

Service Requests

33 Load Shedding and Curtailments

34 Rates and Charges

35 Operating Arrangements

IV. INTERCONNECTIONS WITH THE TRANSMISSION SYSTEM

Preamble

Subpart A –INTERCONNECTION PROCEDURES

36 Interconnection Requests

37 Additional Procedures

38 Service on Merchant Transmission Facilities

39 Local Furnishing Bonds

40-108 [Reserved]

Subpart B – [Reserved]

Subpart C – [Reserved]

Subpart D – [Reserved]

Subpart E – [Reserved]

Subpart F – [Reserved]

Subpart G – SMALL GENERATION INTERCONNECTION PROCEDURE

Preamble

109 Pre-application Process

110 Permanent Capacity Resource Additions Of 20 MW Or Less

111 Permanent Energy Resource Additions Of 20 MW Or Less but Greater than

2 MW (Synchronous) or Greater than 5 MW(Inverter-based)

112 Temporary Energy Resource Additions Of 20 MW Or Less But

Greater Than 2 MW

112A Screens Process for Permanent or Temporary Energy Resources of 2 MW or

less (Synchronous) or 5 MW (Inverter-based)

Page 6

112B Certified Inverter-Based Small Generating Facilities No Larger than 10 kW

112C Alternate Queue Process

V. GENERATION DEACTIVATION

Preamble

113 Notices

114 Deactivation Avoidable Cost Credit

115 Deactivation Avoidable Cost Rate

116 Filing and Updating of Deactivation Avoidable Cost Rate

117 Excess Project Investment Required

118 Refund of Project Investment Reimbursement

118A Recovery of Project Investment

119 Cost of Service Recovery Rate

120 Cost Allocation

121 Performance Standards

122 Black Start Units

123-199 [Reserved]

VI. ADMINISTRATION AND STUDY OF NEW SERVICE REQUESTS; RIGHTS

ASSOCIATED WITH CUSTOMER-FUNDED UPGRADES

Preamble

200 Applicability

201 Queue Position

Subpart A – SYSTEM IMPACT STUDIES AND FACILITIES STUDIES

FOR NEW SERVICE REQUESTS

202 Coordination with Affected Systems

203 System Impact Study Agreement

204 Tender of System Impact Study Agreement

205 System Impact Study Procedures

206 Facilities Study Agreement

207 Facilities Study Procedures

208 Expedited Procedures for Part II Requests

209 Optional Interconnection Studies

210 Responsibilities of the Transmission Provider and Transmission

Owners

Subpart B– AGREEMENTS AND COST REPONSIBILITY FOR

CUSTOMER- FUNDED UPGRADES

211 Interim Interconnection Service Agreement

212 Interconnection Service Agreement

213 Upgrade Construction Service Agreement

214 Filing/Reporting of Agreement

215 Transmission Service Agreements

216 Interconnection Requests Designated as Market Solutions

217 Cost Responsibility for Necessary Facilities and Upgrades

218 New Service Requests Involving Affected Systems

219 Inter-queue Allocation of Costs of Transmission Upgrades

Page 7

220 Advance Construction of Certain Network Upgrades

221 Transmission Owner Construction Obligation for Necessary Facilities

And Upgrades

222 Confidentiality

223 Confidential Information

224 – 229 [Reserved]

Subpart C – RIGHTS RELATED TO CUSTOMER-FUNDED UPGRADES

230 Capacity Interconnection Rights

231 Incremental Auction Revenue Rights

232 Transmission Injection Rights and Transmission Withdrawal

Rights

233 Incremental Available Transfer Capability Revenue Rights

234 Incremental Capacity Transfer Rights

235 Incremental Deliverability Rights

236 Interconnection Rights for Certain Transmission Interconnections

237 IDR Transfer Agreements

SCHEDULE 1

Scheduling, System Control and Dispatch Service

SCHEDULE 1A

Transmission Owner Scheduling, System Control and Dispatch Service

SCHEDULE 2

Reactive Supply and Voltage Control from Generation Sources Service

SCHEDULE 3

Regulation and Frequency Response Service

SCHEDULE 4

Energy Imbalance Service

SCHEDULE 5

Operating Reserve – Synchronized Reserve Service

SCHEDULE 6

Operating Reserve - Supplemental Reserve Service

SCHEDULE 6A

Black Start Service

SCHEDULE 7

Long-Term Firm and Short-Term Firm Point-To-Point Transmission Service

SCHEDULE 8

Non-Firm Point-To-Point Transmission Service

SCHEDULE 9

PJM Interconnection L.L.C. Administrative Services

SCHEDULE 9-1

Control Area Administration Service

SCHEDULE 9-2

Financial Transmission Rights Administration Service

SCHEDULE 9-3

Market Support Service

SCHEDULE 9-4

Page 8

Regulation and Frequency Response Administration Service

SCHEDULE 9-5

Capacity Resource and Obligation Management Service

SCHEDULE 9-6

Management Service Cost

SCHEDULE 9-FERC

FERC Annual Charge Recovery

SCHEDULE 9-OPSI

OPSI Funding

SCHEDULE 9-CAPS

CAPS Funding

SCHEDULE 9-FINCON

Finance Committee Retained Outside Consultant

SCHEDULE 9-MMU

MMU Funding

SCHEDULE 9 – PJM SETTLEMENT

SCHEDULE 10 - [Reserved]

SCHEDULE 10-NERC

North American Electric Reliability Corporation Charge

SCHEDULE 10-RFC

Reliability First Corporation Charge

SCHEDULE 11

[Reserved for Future Use]

SCHEDULE 11A

Additional Secure Control Center Data Communication Links and Formula Rate

SCHEDULE 12

Transmission Enhancement Charges

SCHEDULE 12 APPENDIX

SCHEDULE 12-A

SCHEDULE 13

Expansion Cost Recovery Change (ECRC)

SCHEDULE 14

Transmission Service on the Neptune Line

SCHEDULE 14 - Exhibit A

SCHEDULE 15

Non-Retail Behind The Meter Generation Maximum Generation Emergency

Obligations

SCHEDULE 16

Transmission Service on the Linden VFT Facility

SCHEDULE 16 Exhibit A

SCHEDULE 16 – A

Transmission Service for Imports on the Linden VFT Facility

SCHEDULE 17

Transmission Service on the Hudson Line

SCHEDULE 17 - Exhibit A

ATTACHMENT A

Page 9

Form of Service Agreement For Firm Point-To-Point Transmission Service

ATTACHMENT A-1

Form of Service Agreement For The Resale, Reassignment or Transfer of Point-to-

Point Transmission Service

ATTACHMENT B

Form of Service Agreement For Non-Firm Point-To-Point Transmission Service

ATTACHMENT C

Methodology To Assess Available Transfer Capability

ATTACHMENT C-1

Conversion of Service in the Dominion and Duquesne Zones

ATTACHMENT C-2

Conversion of Service in the Duke Energy Ohio, Inc. and Duke Energy Kentucky,

Inc, (“DEOK”) Zone

ATTACHMENT D

Methodology for Completing a System Impact Study

ATTACHMENT E

Index of Point-To-Point Transmission Service Customers

ATTACHMENT F

Service Agreement For Network Integration Transmission Service

ATTACHMENT F-1

Form of Umbrella Service Agreement for Network Integration Transmission

Service Under State Required Retail Access Programs

ATTACHMENT G

Network Operating Agreement

ATTACHMENT H-1

Annual Transmission Rates -- Atlantic City Electric Company for Network

Integration Transmission Service

ATTACHMENT H-1A

Atlantic City Electric Company Formula Rate Appendix A

ATTACHMENT H-1B

Atlantic City Electric Company Formula Rate Implementation Protocols

ATTACHMENT H-2

Annual Transmission Rates -- Baltimore Gas and Electric Company for Network

Integration Transmission Service

ATTACHMENT H-2A

Baltimore Gas and Electric Company Formula Rate

ATTACHMENT H-2B

Baltimore Gas and Electric Company Formula Rate Implementation Protocols

ATTACHMENT H-3

Annual Transmission Rates -- Delmarva Power & Light Company for Network

Integration Transmission Service

ATTACHMENT H-3A

Delmarva Power & Light Company Load Power Factor Charge Applicable to

Service the Interconnection Points

ATTACHMENT H-3B

Page 10

Delmarva Power & Light Company Load Power Factor Charge Applicable to

Service the Interconnection Points

ATTACHMENT H-3C

Delmarva Power & Light Company Under-Frequency Load Shedding Charge

ATTACHMENT H-3D

Delmarva Power & Light Company Formula Rate – Appendix A

ATTACHMENT H-3E

Delmarva Power & Light Company Formula Rate Implementation Protocols

ATTACHMENT H-3F

Old Dominion Electric Cooperative Formula Rate – Appendix A

ATTACHMENT H-3G

Old Dominion Electric Cooperative Formula Rate Implementation Protocols

ATTACHMENT H-4

Annual Transmission Rates -- Jersey Central Power & Light Company for Network

Integration Transmission Service

ATTACHMENT H-4A

Jersey Central Power & Light Company Formula Rate Template

ATTACHMENT H-4B

Jersey Central Power & Light Company Formula Rate Implementation Protocols

ATTACHMENT H-5

Annual Transmission Rates -- Metropolitan Edison Company for Network

Integration Transmission Service

ATTACHMENT H-5A

Other Supporting Facilities -- Metropolitan Edison Company

ATTACHMENT H-6

Annual Transmission Rates -- Pennsylvania Electric Company for Network

Integration Transmission Service

ATTACHMENT H-6A

Other Supporting Facilities Charges -- Pennsylvania Electric Company

ATTACHMENT H-7

Annual Transmission Rates -- PECO Energy Company for Network Integration

Transmission Service

ATTACHMENT H-7A

PECO Energy Company Formula Rate Template

ATTACHMENT H-7B

PECO Energy Company Monthly Deferred Tax Adjustment Charge

ATTACHMENT H-7C

PECO Energy Company Formula Rate Implementation Protocols

ATTACHMENT H-8

Annual Transmission Rates – PPL Group for Network Integration Transmission

Service

ATTACHMENT H-8A

Other Supporting Facilities Charges -- PPL Electric Utilities Corporation

ATTACHMENT 8C

UGI Utilities, Inc. Formula Rate – Appendix A

ATTACHMENT 8D

Page 11

UGI Utilities, Inc. Formula Rate Implementation Protocols

ATTACHMENT 8E

UGI Utilities, Inc. Formula Rate – Appendix A

ATTACHMENT H-8G

Annual Transmission Rates – PPL Electric Utilities Corp.

ATTACHMENT H-8H

Formula Rate Implementation Protocols – PPL Electric Utilities Corp.

ATTACHMENT H-9

Annual Transmission Rates -- Potomac Electric Power Company for Network

Integration Transmission Service

ATTACHMENT H-9A

Potomac Electric Power Company Formula Rate – Appendix A

ATTACHMENT H-9B

Potomac Electric Power Company Formula Rate Implementation Protocols

ATTACHMENT H-9C

Annual Transmission Rate – Southern Maryland Electric Cooperative, Inc. for

Network Integration Transmission Service

ATTACHMENT H-10

Annual Transmission Rates -- Public Service Electric and Gas Company

for Network Integration Transmission Service

ATTACHMENT H-10A

Formula Rate -- Public Service Electric and Gas Company

ATTACHMENT H-10B

Formula Rate Implementation Protocols – Public Service Electric and Gas

Company

ATTACHMENT H-11

Annual Transmission Rates -- Allegheny Power for Network Integration

Transmission Service

ATTACHMENT 11A

Other Supporting Facilities Charges - Allegheny Power

ATTACHMENT H-12

Annual Transmission Rates -- Rockland Electric Company for Network Integration

Transmission Service

ATTACHMENT H-13

Annual Transmission Rates – Commonwealth Edison Company for Network

Integration Transmission Service

ATTACHMENT H-13A

Commonwealth Edison Company Formula Rate – Appendix A

ATTACHMENT H-13B

Commonwealth Edison Company Formula Rate Implementation Protocols

ATTACHMENT H-14

Annual Transmission Rates – AEP East Operating Companies for Network

Integration Transmission Service

ATTACHMENT H-14A

AEP East Operating Companies Formula Rate Implementation Protocols

ATTACHMENT H-14B Part 1

Page 12

ATTACHMENT H-14B Part 2

ATTACHMENT H-15

Annual Transmission Rates -- The Dayton Power and Light Company

for Network Integration Transmission Service

ATTACHMENT H-16

Annual Transmission Rates -- Virginia Electric and Power Company

for Network Integration Transmission Service

ATTACHMENT H-16A

Formula Rate - Virginia Electric and Power Company

ATTACHMENT H-16B

Formula Rate Implementation Protocols - Virginia Electric and Power Company

ATTACHMENT H-16C

Virginia Retail Administrative Fee Credit for Virginia Retail Load Serving

Entities in the Dominion Zone

ATTACHMENT H-16D – [Reserved]

ATTACHMENT H-16E – [Reserved]

ATTACHMENT H-16AA

Virginia Electric and Power Company

ATTACHMENT H-17

Annual Transmission Rates -- Duquesne Light Company for Network Integration

Transmission Service

ATTACHMENT H-17A

Duquesne Light Company Formula Rate – Appendix A

ATTACHMENT H-17B

Duquesne Light Company Formula Rate Implementation Protocols

ATTACHMENT H-17C

Duquesne Light Company Monthly Deferred Tax Adjustment Charge

ATTACHMENT H-18

Annual Transmission Rates – Trans-Allegheny Interstate Line Company

ATTACHMENT H-18A

Trans-Allegheny Interstate Line Company Formula Rate – Appendix A

ATTACHMENT H-18B

Trans-Allegheny Interstate Line Company Formula Rate Implementation Protocols

ATTACHMENT H-19

Annual Transmission Rates – Potomac-Appalachian Transmission Highline, L.L.C.

ATTACHMENT H-19A

Potomac-Appalachian Transmission Highline, L.L.C. Summary

ATTACHMENT H-19B

Potomac-Appalachian Transmission Highline, L.L.C. Formula Rate

Implementation Protocols

ATTACHMENT H-20

Annual Transmission Rates – AEP Transmission Companies (AEPTCo) in the AEP

Zone

ATTACHMENT H-20A

AEP Transmission Companies (AEPTCo) in the AEP Zone - Formula Rate

Implementation Protocols

Page 13

ATTACHMENT H-20A APPENDIX A

Transmission Formula Rate Settlement for AEPTCo

ATTACHMENT H-20B - Part I

AEP Transmission Companies (AEPTCo) in the AEP Zone – Blank Formula Rate

Template

ATTACHMENT H-20B - Part II

AEP Transmission Companies (AEPTCo) in the AEP Zone – Blank Formula Rate

TemplateATTACHMENT H-21

Annual Transmission Rates – American Transmission Systems, Inc. for Network

Integration Transmission Service

ATTACHMENT H-21A - ATSI

ATTACHMENT H-21A Appendix A - ATSI

ATTACHMENT H-21A Appendix B - ATSI

ATTACHMENT H-21A Appendix C - ATSI

ATTACHMENT H-21A Appendix C - ATSI [Reserved]

ATTACHMENT H-21A Appendix D – ATSI

ATTACHMENT H-21A Appendix E - ATSI

ATTACHMENT H-21A Appendix F – ATSI [Reserved]

ATTACHMENT H-21A Appendix G - ATSI

ATTACHMENT H-21A Appendix G – ATSI (Credit Adj)

ATTACHMENT H-21B ATSI Protocol

ATTACHMENT H-22

Annual Transmission Rates – DEOK for Network Integration Transmission Service

and Point-to-Point Transmission Service

ATTACHMENT H-22A

Duke Energy Ohio and Duke Energy Kentucky (DEOK) Formula Rate Template

ATTACHMENT H-22B

DEOK Formula Rate Implementation Protocols

ATTACHMENT H-22C

Additional provisions re DEOK and Indiana

ATTACHMENT H-23

EP Rock springs annual transmission Rate

ATTACHMENT H-24

EKPC Annual Transmission Rates

ATTACHMENT H-24A APPENDIX A

EKPC Schedule 1A

ATTACHMENT H-24A APPENDIX B

EKPC RTEP

ATTACHMENT H-24A APPENDIX C

EKPC True-up

ATTACHMENT H-24A APPENDIX D

EKPC Depreciation Rates

ATTACHMENT H-24-B

EKPC Implementation Protocols

ATTACHMENT H-25

Page 14

Annual Transmission Rates – Rochelle Municipal Utiliites for Network Integration

Transmission Service and Point-to-Point Transmission Service in the ComEd Zone

ATTACHMENT H-25A

Formula Rate Protocols for Rochelle Municipal Utilities Using a Historical Formula

Rate Template

ATTACHMENT H-25B

Rochelle Municipal Utilities Transmission Cost of Service Formula Rate – Appendix

A – Transmission Service Revenue Requirement

ATTACHMENT H-26

Transource West Virginia, LLC Formula Rate Template

ATTACHMENT H-26A

Transource West Virginia, LLC Formula Rate Implementation Protocols

ATTACHMENT H-27

Annual Transmission Rates – Northeast Transmission Development, LLC

ATTACHMENT H-27A

Northeast Transmission Development, LLC Formula Rate Template

ATTACHMENT H-27B

Northeast Transmission Development, LLC Formula Rate Implementation

Protocols

ATTACHMENT H-28

Annual Transmission Rates – Mid-Atlantic Interstate Transmission, LLC for

Network Integration Transmission Service

ATTACHMENT H-28A

Mid-Atlantic Interstate Transmission, LLC Formula Rate Template

ATTACHMENT H-28B

Mid-Atlantic Interstate Transmission, LLC Formula Rate Implementation

Protocols

ATTACHMENT H-29

Annual Transmission Rates – Transource Pennsylvania, LLC

ATTACHMENT H-29A

Transource Pennsylvania, LLC Formula Rate Template

ATTACHMENT H-29B

Transource Pennsylvania, LLC Formula Rate Implementation Protocols

ATTACHMENT H-30

Annual Transmission Rates – Transource Maryland, LLC

ATTACHMENT H-30A

Transource Maryland, LLC Formula Rate Template

ATTACHMENT H-30B

Transource Maryland, LLC Formula Rate Implementation Protocols

ATTACHMENT H-A

Annual Transmission Rates -- Non-Zone Network Load for Network Integration

Transmission Service

ATTACHMENT I

Index of Network Integration Transmission Service Customers

ATTACHMENT J

PJM Transmission Zones

Page 15

ATTACHMENT K

Transmission Congestion Charges and Credits

Preface

ATTACHMENT K -- APPENDIX

Preface

1. MARKET OPERATIONS

1.1 Introduction

1.2 Cost-Based Offers

1.2A Transmission Losses

1.3 [Reserved for Future Use]

1.4 Market Buyers

1.5 Market Sellers

1.5A Economic Load Response Participant

1.6 Office of the Interconnection

1.6A PJM Settlement

1.7 General

1.8 Selection, Scheduling and Dispatch Procedure Adjustment Process

1.9 Prescheduling

1.10 Scheduling

1.11 Dispatch

1.12 Dynamic Transfers

2. CALCULATION OF LOCATIONAL MARGINAL PRICES

2.1 Introduction

2.2 General

2.3 Determination of System Conditions Using the State Estimator

2.4 Determination of Energy Offers Used in Calculating

2.5 Calculation of Real-time Prices

2.6 Calculation of Day-ahead Prices

2.6A Interface Prices

2.7 Performance Evaluation

3. ACCOUNTING AND BILLING

3.1 Introduction

3.2 Market Buyers

3.3 Market Sellers

3.3A Economic Load Response Participants

3.4 Transmission Customers

3.5 Other Control Areas

3.6 Metering Reconciliation 3.7 Inadvertent Interchange

4. [Reserved For Future Use]

5. CALCULATION OF CHARGES AND CREDITS FOR TRANSMISSION

CONGESTION AND LOSSES

5.1 Transmission Congestion Charge Calculation

5.2 Transmission Congestion Credit Calculation

5.3 Unscheduled Transmission Service (Loop Flow)

5.4 Transmission Loss Charge Calculation

5.5 Distribution of Total Transmission Loss Charges

Page 16

6. “MUST-RUN” FOR RELIABILITY GENERATION

6.1 Introduction

6.2 Identification of Facility Outages

6.3 Dispatch for Local Reliability

6.4 Offer Price Caps

6.5 [Reserved]

6.6 Minimum Generator Operating Parameters –

Parameter-Limited Schedules

6A. [Reserved]

6A.1 [Reserved]

6A.2 [Reserved]

6A.3 [Reserved]

7. FINANCIAL TRANSMISSION RIGHTS AUCTIONS

7.1 Auctions of Financial Transmission Rights

7.1A Long-Term Financial Transmission Rights Auctions

7.2 Financial Transmission Rights Characteristics

7.3 Auction Procedures

7.4 Allocation of Auction Revenues

7.5 Simultaneous Feasibility

7.6 New Stage 1 Resources

7.7 Alternate Stage 1 Resources

7.8 Elective Upgrade Auction Revenue Rights

7.9 Residual Auction Revenue Rights

7.10 Financial Settlement

7.11 PJMSettlement as Counterparty

8. EMERGENCY AND PRE-EMERGENCY LOAD RESPONSE PROGRAM

8.1 Emergency Load Response and Pre-Emergency Load Response Program Options

8.2 Participant Qualifications

8.3 Metering Requirements

8.4 Registration

8.5 Pre-Emergency Operations

8.6 Emergency Operations

8.7 Verification

8.8 Market Settlements

8.9 Reporting and Compliance

8.10 Non-Hourly Metered Customer Pilot

8.11 Emergency Load Response and Pre-Emergency Load Response Participant

Aggregation

ATTACHMENT L

List of Transmission Owners

ATTACHMENT M

PJM Market Monitoring Plan

ATTACHMENT M – APPENDIX

PJM Market Monitor Plan Attachment M Appendix

I Confidentiality of Data and Information

II Development of Inputs for Prospective Mitigation

Page 17

III Black Start Service

IV Deactivation Rates

V Opportunity Cost Calculation

VI FTR Forfeiture Rule

VII Forced Outage Rule

VIII Data Collection and Verification

ATTACHMENT M-1 (FirstEnergy)

Energy Procedure Manual for Determining Supplier Total Hourly Energy

Obligation

ATTACHMENT M-2 (First Energy)

Energy Procedure Manual for Determining Supplier Peak Load Share

Procedures for Load Determination

ATTACHMENT M-2 (ComEd)

Determination of Capacity Peak Load Contributions and Network Service Peak

Load Contributions

ATTACHMENT M-2 (PSE&G)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Atlantic City Electric Company)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Delmarva Power & Light Company)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Delmarva Power & Light Company)

Procedures for Determination of Peak Load Contributions and Hourly Load

Obligations for Retail Customers

ATTACHMENT M-2 (Duke Energy Ohio, Inc.)

Procedures for Determination of Peak Load Contributions, Network Service Peak

Load and Hourly Load Obligations for Retail Customers

ATTACHMENT M-3

Additional Procedures for Planning of Supplemental Projects

ATTACHMENT N

Form of Generation Interconnection Feasibility Study Agreement

ATTACHMENT N-1

Form of System Impact Study Agreement

ATTACHMENT N-2

Form of Facilities Study Agreement

ATTACHMENT N-3

Form of Optional Interconnection Study Agreement

ATTACHMENT O

Form of Interconnection Service Agreement

1.0 Parties

2.0 Authority

3.0 Customer Facility Specifications

4.0 Effective Date

Page 18

5.0 Security

6.0 Project Specific Milestones

7.0 Provision of Interconnection Service

8.0 Assumption of Tariff Obligations

9.0 Facilities Study

10.0 Construction of Transmission Owner Interconnection Facilities

11.0 Interconnection Specifications

12.0 Power Factor Requirement

12.0A RTU

13.0 Charges

14.0 Third Party Benefits

15.0 Waiver

16.0 Amendment

17.0 Construction With Other Parts Of The Tariff

18.0 Notices

19.0 Incorporation Of Other Documents

20.0 Addendum of Non-Standard Terms and Conditions for Interconnection Service

21.0 Addendum of Interconnection Customer’s Agreement

to Conform with IRS Safe Harbor Provisions for Non-Taxable Status

22.0 Addendum of Interconnection Requirements for a Wind Generation Facility

23.0 Infrastructure Security of Electric System Equipment and Operations and Control

Hardware and Software is Essential to Ensure Day-to-Day Reliability and

Operational Security

Specifications for Interconnection Service Agreement

1.0 Description of [generating unit(s)] [Merchant Transmission Facilities] (the

Customer Facility) to be Interconnected with the Transmission System in the PJM

Region

2.0 Rights

3.0 Construction Responsibility and Ownership of Interconnection Facilities

4.0 Subject to Modification Pursuant to the Negotiated Contract Option

4.1 Attachment Facilities Charge

4.2 Network Upgrades Charge

4.3 Local Upgrades Charge

4.4 Other Charges

4.5 Cost of Merchant Network Upgrades

4.6 Cost breakdown

4.7 Security Amount Breakdown

ATTACHMENT O APPENDIX 1: Definitions

ATTACHMENT O APPENDIX 2: Standard Terms and Conditions for Interconnections

1 Commencement, Term of and Conditions Precedent to

Interconnection Service

1.1 Commencement Date

1.2 Conditions Precedent

1.3 Term

1.4 Initial Operation

1.4A Limited Operation

Page 19

1.5 Survival

2 Interconnection Service

2.1 Scope of Service

2.2 Non-Standard Terms

2.3 No Transmission Services

2.4 Use of Distribution Facilities

2.5 Election by Behind The Meter Generation

3 Modification Of Facilities

3.1 General

3.2 Interconnection Request

3.3 Standards

3.4 Modification Costs

4 Operations

4.1 General

4.2 Operation of Merchant Network Upgrades

4.3 Interconnection Customer Obligations

4.4 [Reserved.]

4.5 Permits and Rights-of-Way

4.6 No Ancillary Services

4.7 Reactive Power

4.8 Under- and Over-Frequency Conditions

4.9 Protection and System Quality

4.10 Access Rights

4.11 Switching and Tagging Rules

4.12 Communications and Data Protocol

4.13 Nuclear Generating Facilities

5 Maintenance

5.1 General

5.2 Maintenance of Merchant Network Upgrades

5.3 Outage Authority and Coordination

5.4 Inspections and Testing

5.5 Right to Observe Testing

5.6 Secondary Systems

5.7 Access Rights

5.8 Observation of Deficiencies

6 Emergency Operations

6.1 Obligations

6.2 Notice

6.3 Immediate Action

6.4 Record-Keeping Obligations

7 Safety

7.1 General

7.2 Environmental Releases

8 Metering

8.1 General

8.2 Standards

Page 20

8.3 Testing of Metering Equipment

8.4 Metering Data

8.5 Communications

9 Force Majeure

9.1 Notice

9.2 Duration of Force Majeure

9.3 Obligation to Make Payments

9.4 Definition of Force Majeure

10 Charges

10.1 Specified Charges

10.2 FERC Filings

11 Security, Billing And Payments

11.1 Recurring Charges Pursuant to Section 10

11.2 Costs for Transmission Owner Interconnection

Facilities and/or Merchant Network Upgrades

11.3 No Waiver

11.4 Interest

12 Assignment

12.1 Assignment with Prior Consent

12.2 Assignment Without Prior Consent

12.3 Successors and Assigns

13 Insurance

13.1 Required Coverages for Generation Resources Of More

Than 20 Megawatts and Merchant Transmission Facilities

13.1A Required Coverages for Generation Resources Of

20 Megawatts Or Less

13.2 Additional Insureds

13.3 Other Required Terms

13.3A No Limitation of Liability

13.4 Self-Insurance

13.5 Notices; Certificates of Insurance

13.6 Subcontractor Insurance

13.7 Reporting Incidents

14 Indemnity

14.1 Indemnity

14.2 Indemnity Procedures

14.3 Indemnified Person

14.4 Amount Owing

14.5 Limitation on Damages

14.6 Limitation of Liability in Event of Breach

14.7 Limited Liability in Emergency Conditions

15 Breach, Cure And Default

15.1 Breach

15.2 Continued Operation

15.3 Notice of Breach

15.4 Cure and Default

Page 21

15.5 Right to Compel Performance

15.6 Remedies Cumulative

16 Termination

16.1 Termination

16.2 Disposition of Facilities Upon Termination

16.3 FERC Approval

16.4 Survival of Rights

17 Confidentiality

17.1 Term

17.2 Scope

17.3 Release of Confidential Information

17.4 Rights

17.5 No Warranties

17.6 Standard of Care

17.7 Order of Disclosure

17.8 Termination of Interconnection Service Agreement

17.9 Remedies

17.10 Disclosure to FERC or its Staff

17.11 No Interconnection Party Shall Disclose Confidential Information

17.12 Information that is Public Domain

17.13 Return or Destruction of Confidential Information

18 Subcontractors

18.1 Use of Subcontractors

18.2 Responsibility of Principal

18.3 Indemnification by Subcontractors

18.4 Subcontractors Not Beneficiaries

19 Information Access And Audit Rights

19.1 Information Access

19.2 Reporting of Non-Force Majeure Events

19.3 Audit Rights

20 Disputes

20.1 Submission

20.2 Rights Under The Federal Power Act

20.3 Equitable Remedies

21 Notices

21.1 General

21.2 Emergency Notices

21.3 Operational Contacts

22 Miscellaneous

22.1 Regulatory Filing

22.2 Waiver

22.3 Amendments and Rights Under the Federal Power Act

22.4 Binding Effect

22.5 Regulatory Requirements

23 Representations And Warranties

23.1 General

Page 22

24 Tax Liability

24.1 Safe Harbor Provisions

24.2. Tax Indemnity

24.3 Taxes Other Than Income Taxes

24.4 Income Tax Gross-Up

24.5 Tax Status

ATTACHMENT O - SCHEDULE A

Customer Facility Location/Site Plan

ATTACHMENT O - SCHEDULE B

Single-Line Diagram

ATTACHMENT O - SCHEDULE C

List of Metering Equipment

ATTACHMENT O - SCHEDULE D

Applicable Technical Requirements and Standards

ATTACHMENT O - SCHEDULE E

Schedule of Charges

ATTACHMENT O - SCHEDULE F

Schedule of Non-Standard Terms & Conditions

ATTACHMENT O - SCHEDULE G

Interconnection Customer’s Agreement to Conform with IRS Safe Harbor

Provisions for Non-Taxable Status

ATTACHMENT O - SCHEDULE H

Interconnection Requirements for a Wind Generation Facility

ATTACHMENT O-1

Form of Interim Interconnection Service Agreement

ATTACHMENT P

Form of Interconnection Construction Service Agreement

1.0 Parties

2.0 Authority

3.0 Customer Facility

4.0 Effective Date and Term

4.1 Effective Date

4.2 Term

4.3 Survival

5.0 Construction Responsibility

6.0 [Reserved.]

7.0 Scope of Work

8.0 Schedule of Work

9.0 [Reserved.]

10.0 Notices

11.0 Waiver

12.0 Amendment

13.0 Incorporation Of Other Documents

14.0 Addendum of Interconnection Customer’s Agreement

to Conform with IRS Safe Harbor Provisions for Non-Taxable Status

15.0 Addendum of Non-Standard Terms and Conditions for Interconnection Service

Page 23

16.0 Addendum of Interconnection Requirements for a Wind Generation Facility

17.0 Infrastructure Security of Electric System Equipment and Operations and Control

Hardware and Software is Essential to Ensure Day-to-Day Reliability and

Operational Security

ATTACHMENT P - APPENDIX 1 – DEFINITIONS

ATTACHMENT P - APPENDIX 2 – STANDARD CONSTRUCTION TERMS AND

CONDITIONS

Preamble

1 Facilitation by Transmission Provider

2 Construction Obligations

2.1 Interconnection Customer Obligations

2.2 Transmission Owner Interconnection Facilities and Merchant

Network Upgrades

2.2A Scope of Applicable Technical Requirements and Standards

2.3 Construction By Interconnection Customer

2.4 Tax Liability

2.5 Safety

2.6 Construction-Related Access Rights

2.7 Coordination Among Constructing Parties

3 Schedule of Work

3.1 Construction by Interconnection Customer

3.2 Construction by Interconnected Transmission Owner

3.2.1 Standard Option

3.2.2 Negotiated Contract Option

3.2.3 Option to Build

3.3 Revisions to Schedule of Work

3.4 Suspension

3.4.1 Costs

3.4.2 Duration of Suspension

3.5 Right to Complete Transmission Owner Interconnection

Facilities

3.6 Suspension of Work Upon Default

3.7 Construction Reports

3.8 Inspection and Testing of Completed Facilities

3.9 Energization of Completed Facilities

3.10 Interconnected Transmission Owner’s Acceptance of

Facilities Constructed by Interconnection Customer

4 Transmission Outages

4.1 Outages; Coordination

5 Land Rights; Transfer of Title

5.1 Grant of Easements and Other Land Rights

5.2 Construction of Facilities on Interconnection Customer Property

5.3 Third Parties

5.4 Documentation

5.5 Transfer of Title to Certain Facilities Constructed By

Interconnection Customer

Page 24

5.6 Liens

6 Warranties

6.1 Interconnection Customer Warranty

6.2 Manufacturer Warranties

7 [Reserved.]

8 [Reserved.]

9 Security, Billing And Payments

9.1 Adjustments to Security

9.2 Invoice

9.3 Final Invoice

9.4 Disputes

9.5 Interest

9.6 No Waiver

10 Assignment

10.1 Assignment with Prior Consent

10.2 Assignment Without Prior Consent

10.3 Successors and Assigns

11 Insurance

11.1 Required Coverages For Generation Resources Of More Than 20

Megawatts and Merchant Transmission Facilities

11.1A Required Coverages For Generation Resources of

20 Megawatts Or Less

11.2 Additional Insureds

11.3 Other Required Terms

11.3A No Limitation of Liability

11.4 Self-Insurance

11.5 Notices; Certificates of Insurance

11.6 Subcontractor Insurance

11.7 Reporting Incidents

12 Indemnity

12.1 Indemnity

12.2 Indemnity Procedures

12.3 Indemnified Person

12.4 Amount Owing

12.5 Limitation on Damages

12.6 Limitation of Liability in Event of Breach

12.7 Limited Liability in Emergency Conditions

13 Breach, Cure And Default

13.1 Breach

13.2 Notice of Breach

13.3 Cure and Default

13.3.1 Cure of Breach

13.4 Right to Compel Performance

13.5 Remedies Cumulative

14 Termination

14.1 Termination

Page 25

14.2 [Reserved.]

14.3 Cancellation By Interconnection Customer

14.4 Survival of Rights

15 Force Majeure

15.1 Notice

15.2 Duration of Force Majeure

15.3 Obligation to Make Payments

15.4 Definition of Force Majeure

16 Subcontractors

16.1 Use of Subcontractors

16.2 Responsibility of Principal

16.3 Indemnification by Subcontractors

16.4 Subcontractors Not Beneficiaries

17 Confidentiality

17.1 Term

17.2 Scope

17.3 Release of Confidential Information

17.4 Rights

17.5 No Warranties

17.6 Standard of Care

17.7 Order of Disclosure

17.8 Termination of Construction Service Agreement

17.9 Remedies

17.10 Disclosure to FERC or its Staff

17.11 No Construction Party Shall Disclose Confidential Information of Another

Construction Party 17.12 Information that is Public Domain

17.13 Return or Destruction of Confidential Information

18 Information Access And Audit Rights

18.1 Information Access

18.2 Reporting of Non-Force Majeure Events

18.3 Audit Rights

19 Disputes

19.1 Submission

19.2 Rights Under The Federal Power Act

19.3 Equitable Remedies

20 Notices

20.1 General

20.2 Operational Contacts

21 Miscellaneous

21.1 Regulatory Filing

21.2 Waiver

21.3 Amendments and Rights under the Federal Power Act

21.4 Binding Effect

21.5 Regulatory Requirements

22 Representations and Warranties

22.1 General

Page 26

ATTACHMENT P - SCHEDULE A

Site Plan

ATTACHMENT P - SCHEDULE B

Single-Line Diagram of Interconnection Facilities

ATTACHMENT P - SCHEDULE C

Transmission Owner Interconnection Facilities to be Built by Interconnected

Transmission Owner

ATTACHMENT P - SCHEDULE D

Transmission Owner Interconnection Facilities to be Built by Interconnection

Customer Pursuant to Option to Build

ATTACHMENT P - SCHEDULE E

Merchant Network Upgrades to be Built by Interconnected Transmission Owner

ATTACHMENT P - SCHEDULE F

Merchant Network Upgrades to be Built by Interconnection Customer

Pursuant to Option to Build

ATTACHMENT P - SCHEDULE G

Customer Interconnection Facilities

ATTACHMENT P - SCHEDULE H

Negotiated Contract Option Terms

ATTACHMENT P - SCHEDULE I

Scope of Work

ATTACHMENT P - SCHEDULE J

Schedule of Work

ATTACHMENT P - SCHEDULE K

Applicable Technical Requirements and Standards

ATTACHMENT P - SCHEDULE L

Interconnection Customer’s Agreement to Confirm with IRS Safe Harbor

Provisions For Non-Taxable Status

ATTACHMENT P - SCHEDULE M

Schedule of Non-Standard Terms and Conditions

ATTACHMENT P - SCHEDULE N

Interconnection Requirements for a Wind Generation Facility

ATTACHMENT Q

PJM Credit Policy

ATTACHMENT R

Lost Revenues Of PJM Transmission Owners And Distribution of Revenues

Remitted By MISO, SECA Rates to Collect PJM Transmission Owner Lost

Revenues Under Attachment X, And Revenues From PJM Existing Transactions

ATTACHMENT S

Form of Transmission Interconnection Feasibility Study Agreement

ATTACHMENT T

Identification of Merchant Transmission Facilities

ATTACHMENT U

Independent Transmission Companies

ATTACHMENT V

Form of ITC Agreement

Page 27

ATTACHMENT W

COMMONWEALTH EDISON COMPANY

ATTACHMENT X

Seams Elimination Cost Assignment Charges

NOTICE OF ADOPTION OF NERC TRANSMISSION LOADING RELIEF

PROCEDURES

NOTICE OF ADOPTION OF LOCAL TRANSMISSION LOADING REIEF

PROCEDURES

SCHEDULE OF PARTIES ADOPTING LOCAL TRANSMISSION LOADING

RELIEF PROCEDURES

ATTACHMENT Y

Forms of Screens Process Interconnection Request (For Generation Facilities of 2

MW or less)

ATTACHMENT Z

Certification Codes and Standards

ATTACHMENT AA

Certification of Small Generator Equipment Packages

ATTACHMENT BB

Form of Certified Inverter-Based Generating Facility No Larger Than 10 kW

Interconnection Service Agreement

ATTACHMENT CC

Form of Certificate of Completion

(Small Generating Inverter Facility No Larger Than 10 kW)

ATTACHMENT DD

Reliability Pricing Model

ATTACHMENT EE

Form of Upgrade Request

ATTACHMENT FF

Form of Initial Study Agreement

ATTACHMENT GG

Form of Upgrade Construction Service Agreement

Article 1 – Definitions And Other Documents

1.0 Defined Terms

1.1 Incorporation of Other Documents

Article 2 – Responsibility for Direct Assignment Facilities or Customer-Funded

Upgrades

2.0 New Service Customer Financial Responsibilities

2.1 Obligation to Provide Security

2.2 Failure to Provide Security

2.3 Costs

2.4 Transmission Owner Responsibilities

Article 3 – Rights To Transmission Service

3.0 No Transmission Service

Article 4 – Early Termination

4.0 Termination by New Service Customer

Article 5 – Rights

Page 28

5.0 Rights

5.1 Amount of Rights Granted

5.2 Availability of Rights Granted

5.3 Credits

Article 6 – Miscellaneous

6.0 Notices

6.1 Waiver

6.2 Amendment

6.3 No Partnership

6.4 Counterparts

ATTACHMENT GG - APPENDIX I –

SCOPE AND SCHEDULE OF WORK FOR DIRECT ASSIGNMENT

FACILITIES OR CUSTOMER-FUNDED UPGRADES TO BE BUILT BY

TRANSMISSION OWNER

ATTACHMENT GG - APPENDIX II - DEFINITIONS

1 Definitions

1.1 Affiliate

1.2 Applicable Laws and Regulations

1.3 Applicable Regional Reliability Council

1.4 Applicable Standards

1.5 Breach

1.6 Breaching Party

1.7 Cancellation Costs

1.8 Commission

1.9 Confidential Information

1.10 Constructing Entity

1.11 Control Area

1.12 Costs

1.13 Default

1.14 Delivering Party

1.15 Emergency Condition

1.16 Environmental Laws

1.17 Facilities Study

1.18 Federal Power Act

1.19 FERC

1.20 Firm Point-To-Point

1.21 Force Majeure

1.22 Good Utility Practice

1.23 Governmental Authority

1.24 Hazardous Substances

1.25 Incidental Expenses

1.26 Local Upgrades

1.27 Long-Term Firm Point-To-Point Transmission Service

1.28 MAAC

1.29 MAAC Control Zone

1.30 NERC

Page 29

1.31 Network Upgrades

1.32 Office of the Interconnection

1.33 Operating Agreement of the PJM Interconnection, L.L.C. or Operating

Agreement

1.34 Part I

1.35 Part II

1.36 Part III

1.37 Part IV

1.38 Part VI

1.39 PJM Interchange Energy Market

1.40 PJM Manuals

1.41 PJM Region

1.42 PJM West Region

1.43 Point(s) of Delivery

1.44 Point(s) of Receipt

1.45 Project Financing

1.46 Project Finance Entity

1.47 Reasonable Efforts

1.48 Receiving Party

1.49 Regional Transmission Expansion Plan

1.50 Schedule and Scope of Work

1.51 Security

1.52 Service Agreement

1.53 State

1.54 Transmission System

1.55 VACAR

ATTACHMENT GG - APPENDIX III – GENERAL TERMS AND CONDITIONS

1.0 Effective Date and Term

1.1 Effective Date

1.2 Term

1.3 Survival

2.0 Facilitation by Transmission Provider

3.0 Construction Obligations

3.1 Direct Assignment Facilities or Customer-Funded Upgrades

3.2 Scope of Applicable Technical Requirements and Standards

4.0 Tax Liability

4.1 New Service Customer Payments Taxable

4.2 Income Tax Gross-Up

4.3 Private Letter Ruling

4.4 Refund

4.5 Contests

4.6 Taxes Other Than Income Taxes

4.7 Tax Status

5.0 Safety

5.1 General

5.2 Environmental Releases

Page 30

6.0 Schedule Of Work

6.1 Standard Option

6.2 Option to Build

6.3 Revisions to Schedule and Scope of Work

6.4 Suspension

7.0 Suspension of Work Upon Default

7.1 Notification and Correction of Defects

8.0 Transmission Outages

8.1 Outages; Coordination

9.0 Security, Billing and Payments

9.1 Adjustments to Security

9.2 Invoice

9.3 Final Invoice

9.4 Disputes

9.5 Interest

9.6 No Waiver

10.0 Assignment

10.1 Assignment with Prior Consent

10.2 Assignment Without Prior Consent

10.3 Successors and Assigns

11.0 Insurance

11.1 Required Coverages

11.2 Additional Insureds

11.3 Other Required Terms

11.4 No Limitation of Liability

11.5 Self-Insurance

11.6 Notices: Certificates of Insurance

11.7 Subcontractor Insurance

11.8 Reporting Incidents

12.0 Indemnity

12.1 Indemnity

12.2 Indemnity Procedures

12.3 Indemnified Person

12.4 Amount Owing

12.5 Limitation on Damages

12.6 Limitation of Liability in Event of Breach

12.7 Limited Liability in Emergency Conditions

13.0 Breach, Cure And Default

13.1 Breach

13.2 Notice of Breach

13.3 Cure and Default

13.4 Right to Compel Performance

13.5 Remedies Cumulative

14.0 Termination

14.1 Termination

14.2 Cancellation By New Service Customer

Page 31

14.3 Survival of Rights

14.4 Filing at FERC

15.0 Force Majeure

15.1 Notice

15.2 Duration of Force Majeure

15.3 Obligation to Make Payments

16.0 Confidentiality

16.1 Term

16.2 Scope

16.3 Release of Confidential Information

16.4 Rights

16.5 No Warranties

16.6 Standard of Care

16.7 Order of Disclosure

16.8 Termination of Upgrade Construction Service Agreement

16.9 Remedies

16.10 Disclosure to FERC or its Staff

16.11 No Party Shall Disclose Confidential Information of Party 16.12

Information that is Public Domain

16.13 Return or Destruction of Confidential Information

17.0 Information Access And Audit Rights

17.1 Information Access

17.2 Reporting of Non-Force Majeure Events

17.3 Audit Rights

17.4 Waiver

17.5 Amendments and Rights under the Federal Power Act

17.6 Regulatory Requirements

18.0 Representation and Warranties

18.1 General

19.0 Inspection and Testing of Completed Facilities

19.1 Coordination

19.2 Inspection and Testing

19.3 Review of Inspection and Testing by Transmission Owner

19.4 Notification and Correction of Defects

19.5 Notification of Results

20.0 Energization of Completed Facilities

21.0 Transmission Owner’s Acceptance of Facilities Constructed

by New Service Customer

22.0 Transfer of Title to Certain Facilities Constructed By New Service Customer

23.0 Liens

ATTACHMENT HH – RATES, TERMS, AND CONDITIONS OF SERVICE FOR

PJMSETTLEMENT, INC.

ATTACHMENT II – MTEP PROJECT COST RECOVERY FOR ATSI ZONE

ATTACHMENT JJ – MTEP PROJECT COST RECOVERY FOR DEOK ZONE

Page 32

ATTACHMENT KK - FORM OF DESIGNATED ENTITY AGREEMENT

ATTACHMENT LL - FORM OF INTERCONNECTION COORDINATION

AGREEMENT

ATTACHMENT D

SMECO'S COST OF SERVICE ANALYSIS AND SUPPORTING TESTIMONY

EXHIBIT NO. SME-01: DIRECT TESTIMONY OF ROBERT C. SMITH

Exhibit No. SME-01

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern Maryland Electric Cooperative, Inc. Docket No. ER17-____-000

PREPARED DIRECT TESTIMONY AND EXHIBITS OF

ROBERT C. SMITH

On Behalf of

SOUTHERN MARYLAND ELECTRIC COOPERATIVE, INC.

Transmission Revenue Requirements in PJM

June 27, 2017

Exhibit No. SME-01 Page i

TABLE OF CONTENTS

I. INTRODUCTION................................................................................................ 1

II. PURPOSE OF TESTIMONY AND BACKGROUND ..................................... 4

III. TRANSMISSION COST OF SERVICE ........................................................... 6

Exhibit No. SME-01 Page ii

LIST OF EXHIBITS

Exhibit No. Description

SME-02 Testimony Experience of Robert C. Smith

SME-03 Calculation of Revenue Requirements and Rate

SME-04 Original Cost Investment in 230 kV System

SME-05 Development of Projected 13-Month Average Plant-In-Service

SME-06 Development of Wages & Salaries by Function

SME-07 Capital Structure of Potomac Electric Power Company

SME-08 PEPCO Historical Zonal 1-CPs

Exhibit No. SME-01Page 1 of 15

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern Maryland Electric Cooperative, Inc. | Docket No. ER17-____-000

Prepared Direct Testimony and Exhibits Of

Robert C. Smith

On Behalf of Southern Maryland Electric Cooperative, Inc.

I. INTRODUCTION 1

Q. Please state your name and business address. 2

A. My name is Robert C. Smith. My business address is 1850 Parkway Place, Suite 3

800, Marietta, Georgia 30067. 4

Q. By whom are you employed and in what capacity? 5

A. I am a Vice President at GDS Associates, Inc. (“GDS” or “GDS Associates”), a 6

multi-disciplinary engineering and consulting firm that serves primarily electric, 7

gas and water utilities. I have been with GDS since its founding in 1986. 8

Q. Please describe GDS Associates, Inc. 9

A. GDS Associates’ primary consulting activities are related to power supply 10

planning, pricing of electric service transactions (both purchases and sales at 11

wholesale and retail), energy efficiency and demand response analyses, and 12

regulatory matters pertaining to all facets of electric utility operations. During its 13

31-year history, our firm has grown to roughly 170 consultants and support staff 14

that have served over 250 clients located in 47 states. 15

16

Exhibit No. SME-01Page 2 of 15

Q. Please outline your formal education. 1

A. I received a Bachelor of Science in Industrial Management degree from the Georgia 2

Institute of Technology in 1982. 3

Q. Are you a member of any professional organizations? 4

A. Yes. I am a senior member of the Institute of Electrical and Electronic Engineers 5

(“IEEE”). 6

Q. What are your duties and responsibilities at GDS Associates? 7

A. My primary responsibilities involve providing rate and regulatory consulting 8

services related to electric utility industry matters including rate design, cost of 9

service and related revenue requirements, transmission revenue requirements and 10

formula rates, determination of proper levels of return on equity (“ROE”) and 11

power supply planning. 12

Q. Please briefly describe your professional experience. 13

A. I have been a consultant in the electric utility industry for my entire career spanning 14

approximately thirty-five (35) years. My primary responsibilities with GDS for the 15

past thirty-one (31) years have involved assignments pertaining to the 16

determination of wholesale and retail rates for utility services, financial and power 17

supply planning for electric utilities, establishing just and reasonable terms for 18

transmission access, electric industry restructuring, and the development and 19

implementation policies relating to deregulation. Throughout my career, I have 20

provided consulting services to dozens of electric cooperatives, municipal power 21

systems, investor-owned utilities, utility customers, and various regulatory 22

agencies across the United States. I have testified before state regulatory 23

Exhibit No. SME-01Page 3 of 15

commissions, as well as the Federal Energy Regulatory Commission (“FERC” or 1

the “Commission”). My responsibilities have included the preparation of allocated 2

cost-of-service studies, retail and wholesale rate design studies, financial forecasts, 3

revenue requirement calculations, rate design, and analyses of alternative power 4

supply resources. These activities also have involved the negotiation of bulk power 5

contracts and transmission service arrangements along with review of cost of 6

service, revenue requirements and transmission formulary rates regulated by the 7

Commission. 8

Q. Have you had occasion to provide consulting services related to electric utility 9

allocated cost of service studies and revenue requirements? 10

A. Over the years, I have participated with many cost of service filings at the FERC. 11

In addition, I have provided testimony on the appropriateness of cost of service 12

studies in investor-owned utility rate cases at FERC where cost allocation and 13

revenue requirements were at issue. I am familiar with electric utility cost 14

allocation methods, GAAP Accounting, and FERC and National Association of 15

Regulatory Utility Commissioners (“NARUC”) cost of service and ratemaking 16

principles. During the past several years, my focus has been on FERC regulatory 17

matters involving wholesale transmission rates and revenue requirements. I have 18

participated in numerous proceedings (both cost-of-service and formula rate cases) 19

in which the proper level of transmission revenue requirements was at issue. 20

Q. Have you previously testified before utility regulatory commissions? 21

Exhibit No. SME-01Page 4 of 15

A. Yes. I have filed testimony and exhibits at this Commission in over sixty 1

proceedings. A list of all utility regulatory proceedings in which I have filed 2

testimony is set forth in Exhibit No. SME-02. 3

Q. On whose behalf are you presenting testimony in this proceeding? 4

A. I am presenting this testimony on behalf of the Southern Maryland Electric 5

Cooperative, Inc. (“Southern Maryland,” “SMECO” or “the Cooperative”). 6

II. PURPOSE OF TESTIMONY AND BACKGROUND7

Q. Please describe Southern Maryland. 8

A. SMECO is a rural electric cooperative that provides delivery service to 9

approximately 160,000 customers in Southern Maryland. SMECO is a PJM 10

Transmission Owner as of January 1, 2017. As relevant to this proceeding, 11

SMECO owns approximately 90 miles of 230 kV transmission lines and associated 12

facilities. 13

Q. What is the purpose of your testimony? 14

A. I was asked by SMECO to develop the transmission revenue requirement (“TRR”) 15

for its 230 kV transmission system (“230 kV system”). That system is integrated 16

with the transmission system of Potomac Electric Power Company (“PEPCO”) in 17

the PEPCO Zone of the PJM Interconnection, L.L.C (“PJM”) region. SMECO 18

executed the PJM Consolidated Transmission Owner Agreement (“CTOA”) and 19

placed the 230 kV facilities under PJM functional control as of January 1, 2017. In 20

this testimony, I describe and support the reasonableness of the proposed SMECO 21

TRR and stated transmission rate for the test year. SMECO proposes that its 22

Exhibit No. SME-01Page 5 of 15

resulting test year transmission rate in $/MW be fixed in the PJM Tariff and added 1

to the PEPCO transmission rate that is assessed to customers in the PEPCO Zone, 2

consistent with the CTOA and the PJM Tariff. Additionally, I describe in my 3

testimony how PJM assesses Schedule 1A ancillary service charges to loads in the 4

transmission zone. SMECO is proposing its own Schedule 1A charge, which was 5

developed consistent by dividing an allocated share of SMECO’s control center 6

cost by zonal MWh during the test year. Developing that charge on a $/MWh basis 7

is consistent with how other transmission owners in PJM develop that charge. 8

Q. Does the PJM Tariff1 anticipate there may be other signatories to the PJM 9

Transmission Owners Agreement that are located in its PJM transmission 10

zone? 11

A. Yes, Attachment H-9 to the PJM Tariff, which pertains to PEPCO, states: 12

In the event that any other entity in the Zone becomes a signatory to 13 the Transmission Owners Agreement, and adopts an annual 14 transmission revenue requirement (established in accordance with 15 applicable requirements, including those of the FERC to the extent 16 applicable) for inclusion in the Tariff, such revenue requirement and 17 associated rate for Network Integration Transmission Service shall 18 be stated in an appendix to this Attachment H-9 and added to the 19 annual transmission revenue requirement and rate for Network 20 Integration Transmission Service for the Zone. The foregoing shall 21 not affect such rights as any entity may have under Section 30.9 of 22 the Tariff, provided that no such entity may recover more than its 23 annual transmission revenue requirement through the combination 24 of any rights exercised pursuant to this Attachment H-9 and Section 25 30.9 of the Tariff. 26

1 http://www.pjm.com/media/documents/merged-tariffs/oatt.pdf

Exhibit No. SME-01Page 6 of 15

As shown, the PJM Tariff clearly anticipates a situation where another transmission 1

owner in the PEPCO Zone with qualifying transmission facilities can recover its 2

TRR along with PEPCO’s. 3

III. TRANSMISSION COST OF SERVICE4

Q. Please explain the overall construct of the SMECO transmission cost of service 5

study that produces the annual SMECO TRR. 6

A. As shown in Exhibit No. SME-03, the SMECO Transmission Cost of Service 7

(“TCOS”) is made up of a return on rate base for the 230 kV system and an 8

associated allocation of operations and maintenance (“O&M”) expense, 9

administrative and general (“A&G”) expense, and taxes other than income taxes. 10

Q. What is the test year you have used in developing the cost of service study? 11

A. I have used 2016 as the test year and, unless otherwise explained below, have used 12

only 2016 investment and cost. 2016 test year data is reasonably representative of 13

the expected cost on the SMECO 230 kV system for the twelve months immediately 14

following the proposed effective date and is representative of normal on-going 15

investment and expenses. SMECO does not expect any significant additions to 16

PJM qualifying transmission in the near future. 17

Q. How does the SMECO cost of service study isolate the cost to own, operate, 18

and maintain the 230 kV system? 19

A. The filing includes an analysis of the investment in SMECO’s 230 kV facilities and 20

separates that investment from other transmission investment on the SMECO’s 21

books. In undertaking that separation, SMECO engineering personnel worked with 22

Exhibit No. SME-01Page 7 of 15

the SMECO’s finance department to isolate the 230 kV system investment. For 1

transmission lines, the exercise was simple because original cost and accumulated 2

depreciation are maintained separately on each line segment. For substations that 3

serve at both 230 kV and 69 kV, SMECO engineering personnel first separated 230 4

kV-related investment from 69 kV-related investment. Then the remaining 5

common investment, such as land and foundations, was allocated equally to the 230 6

kV side of the substation and to the 69 kV side of the substation. The result of this 7

exercise was the calculation of the total investment in 230 kV equipment in the 8

looped substations and an allocation of common facilities in the substations. In 9

addition, SMECO provided me with allocations to the 230 kV system of the 10

investment in the control center, SCADA system, and Emergency Management 11

System. Exhibit No. SME-04 shows the total 230 kV system investment and 12

accumulated depreciation as of December 31, 2016. As shown on Exhibit No. 13

SME-03 line 5, approximately 48% of the transmission investment on SMECO’s 14

books at the end of 2016 is related to the 230 kV system. This 48% allocation factor 15

is used to allocate SMECO’s transmission-related O&M expense to the 230 kV 16

system or “PJM Transmission.” A&G expenses and General Plant items are 17

allocated to the 230 kV system based on the Commission’s historical preference of 18

using a functionalized wages and salaries (“W&S” or “Labor”) allocator to assign 19

A&G expense and General Plant items to the 230 kV system. These allocators 20

along with others developed in the cost of service template shown in Exhibit No. 21

SME-03 calculate a TRR related only to the SMECO 230 kV transmission facilities. 22

Q. What is the source of the data in Exhibit No. SME-03? 23

Exhibit No. SME-01Page 8 of 15

A. The test year cost data was provided to me by SMECO. The basis for the figures 1

are the 2016 audited financial statements and accounting records of the 2

Cooperative. SMECO witness Sonja Cox describes the genesis of the 2016 test 3

year accounting data. 4

Q. Please describe the inputs shown on SMECO’s 230 kV cost of service study 5

shown on Exhibit No. SME-03. 6

A. Exhibit No. SME-03 consists of three pages of calculations representing the annual 7

cost of SMECO’s 230 kV transmission system. As I mentioned before, the actual 8

2016 data is a reasonable projection of the costs of the 230 kV system for the 12-9

months immediately subsequent to the effective date (presented here as calendar 10

year 2017). The cost of service is based on a traditional 13-month average net plant 11

revenue requirement for the 230 kV transmission facilities owned by SMECO. The 12

gross revenue requirement is the sum of all expenses such as O&M expense, 13

depreciation expense, taxes other than income taxes, and return on rate base. The 14

underlying cost data included in the test year reflect SMECO’s costs as reported on 15

its books and records. 16

Q. Please describe how SMECO’s test year rate base was developed on page 1 of 17

Exhibit No. SME-03. 18

A. On page 1 of Exhibit No. SME-03, column (c), I present functionalized Total 19

Company Gross Plant in Service investment at SMECO by utility function at year-20

end 2016. I assume gross plant in service will not change in 2017 so the 2016 year-21

end balance is also assumed to be the 13-month average balance of 2017. On pages 22

1 and 2 of Exhibit No. SME-05, I show the total 13-month average gross investment 23

Exhibit No. SME-01Page 9 of 15

in the SMECO 230 kV system, plus investment in other transmission assets 1

allocable to the 230 kV system projected in the twelve months after the end of 2

2016.2 I also show projections of production, distribution, and general plant original 3

cost on Exhibit No. SME-05. Similarly, I show the 2017 13-month average balance 4

of accumulated depreciation by function on Exhibit No. SME-05, which flows to 5

lines 13 through 18 of Exhibit No. SME-03. Accumulated depreciation is deducted 6

from the Gross Plant in Service yielding Net Plant by utility function as shown on 7

lines 22 through 27 of Exhibit No. SME-03. As shown on line 5, column (d) of 8

that exhibit, investment in SMECO’s 230 kV transmission function makes up 9

approximately 48% of the Cooperative’s total system transmission 13-month 10

average Gross Plant in Service (“TP”). 11

I allocated SMECO’s General and Intangible plant and accumulated 12

depreciation to the transmission function based on a W&S allocator developed on 13

page 3, lines 99 through 102 of Exhibit No. SME-03. SMECO provided me the 14

wages and salaries expensed by utility function during 2016 as shown in Exhibit 15

No. SME-06. When total transmission wages and salaries are allocated to the 230 16

kV system as shown on Exhibit No. SME-03, page 3 line 100, the resulting 230 kV 17

system wages and salaries allocation factor is approximately 3.7% as shown on line 18

103. 19

Because the Control Center investment booked in General Plant accounts 20

was allocated specifically to the 230 kV system on Exhibit No. SME-05, I removed 21

2 Investment in the Control Center, SCADA, and EMS system allocated to the 230 kV System.

Exhibit No. SME-01Page 10 of 15

that investment from General Plant and General Plant Accumulated Depreciation 1

as shown on Exhibit No. SME-03, page 1, lines 8 and 17. 2

Once General and Intangible plant is allocated to the 230 kV transmission 3

investment, I develop a Gross Plant (“GP”) allocator as shown on line 10, column 4

(d) of page 1 of Exhibit SME-03. The GP allocator is used to allocate certain other 5

cost of service items to the PJM 230 kV system as I describe later. 6

Because SMECO is a non-taxable rural electric cooperative, it does not have 7

any accumulated deferred income taxes that are normally included as an adjustment 8

to rate base. Cash working capital is included and based on the traditional “1/8th9

O&M” calculation on line 33 of page 1. I also included balances of materials and 10

supplies and prepayments, which are sourced from SMECO’s financial statements 11

and allocated to the 230 kV system based on the GP allocator. 12

The total SMECO 230 kV test year transmission rate base is shown at the 13

bottom of page 1 on line 38, column (e) of Exhibit No. SME-03 at $122,531,995. 14

Return on the 230 kV system rate base is shown on line 40 column (e). 15

Q. Turning to page 2 of Exhibit No. SME-03, please explain how you developed 16

the test year expenses for the SMECO 230 kV transmission system. 17

A. Total system transmission O&M expense shown on page 2, line 45 comes directly 18

from the SMECO’s audited financial statements and is allocated to the 230 kV 19

system in column (e) based on Transmission Expense allocation factor (“TE”). The 20

TE allocator is developed on page 2, line 90. Account 561 costs for SMECO’s 21

control center are removed from the cost of service as those allocated costs are 22

recovered separately under PJM’s Schedule 1A ancillary service charge. These 23

Exhibit No. SME-01Page 11 of 15

scheduling costs are removed on page 2, line 46a, and are shown (added back) in 1

the derivation of the proposed Schedule 1A ancillary service charge on page 3, line 2

129 of Exhibit No. SME-03. There, I took SMECO’s allocated scheduling costs 3

for the 230 kV system of $289,165 and divided that total by the total 2016 4

megawatt-hours in the PEPCO Zone. This yields a Schedule 1A rate of 5

$0.00942/MWh. 6

Q. Please explain the development of Depreciation Expense and Taxes Other 7

Than Income Taxes. 8

A. Transmission depreciation expense on page 2 line 52 is input from Exhibit No. 9

SME-05 where annual depreciation expense is calculated directly for the 230 kV 10

system investment and other supporting investment based on depreciation rates 11

established in the SMECO’s last depreciation rate study. General and Intangible 12

plant depreciation expense for the test year comes directly from SMECO’s 2016 13

financial information shown on line 54, and is allocated to the 230 kV system based 14

on the 230 kV system W&S allocator. 15

Payroll taxes shown on line 60 are also allocated to the 230 kV system based 16

on the W&S allocator, while property taxes on line 63 and state franchise taxes on 17

line 66 are allocated based on the GP allocator as they are more properly associated 18

with plant. These taxes other than income taxes also come directly from SMECO’s 19

audited financial statements for 2016. 20

Q. Please explain how the cost of service study develops the return on rate base 21

for the SMECO 230 kV system. 22

Exhibit No. SME-01Page 12 of 15

A. Return on Rate Base (“Return”) shown on line 40 of page 1 one of Exhibit No. 1

SME-03 is the product of the overall rate of return (“ROR”) (page 3, line 112) times 2

the SMECO 230 kV rate base shown on page 1, line 38. ROR is the sum of the 3

weighted cost rates for long-term debt (“LTD”) and equity calculated on lines 110 4

through 112 on page 3. The LTD cost rate is equal to the actual debt cost incurred 5

in the year from SMECO’s financial statements divided by the outstanding balance 6

of LTD. 7

Q. What rate of return on equity (“ROE”) and capitalization ratios is SMECO 8

proposing to use in the development of return on rate base? 9

A. SMECO does not have a FERC-approved ROE. Therefore, SMECO is proposing 10

to use the Commission-approved ROE for the dominant utility in the SMECO zone 11

– PEPCO, which is currently set at 10.0% plus 50 basis points for RTO12

membership. Inclusion of the 50 basis points for RTO membership for SMECO 13

would recognize the SMECO’s transfer of operational control of its transmission 14

facilities to PJM. SMECO proposes to use PEPCO’s latest equity level posted on 15

the PJM website of 49.64% for calendar 2016, which is summarized on Exhibit No. 16

SME-07.3 This would allow SMECO to earn a return commensurate with similar 17

transmission facilities of the only other transmission owner in the PEPCO Zone 18

(i.e., PEPCO). Use of a proxy ROE and a proxy capital structure for SMECO is 19

consistent with the Commission’s acceptance of a similar request in Docket No. 20

ER16-1054-000 where the Commission allowed the use of AEP West’s approved 21

3 http://www.pjm.com/~/media/markets-ops/trans-service/2017/PEPCO-2016-formula-rate-xls.ashx

Exhibit No. SME-01Page 13 of 15

ROE and a 50/50 debt/equity capital structure for East Texas Electric Cooperative 1

(“East Texas”) in East Texas’ filing for annual transmission revenue requirements 2

in the Southwest Power Pool. There, East Texas proposed the use of the dominant 3

utility’s ROE and capital structure for use as its own in the same transmission zone, 4

which allows East Texas to earn a return commensurate with the dominant 5

transmission utility. 6

Q. Please describe the standard applicable to the rate of return submitted by a 7

non-jurisdictional entity seeking membership in an RTO.8

A. The Commission has declined to establish a formal standard of review applicable 9

to revenue requirements filed by non-jurisdictional entities transferring their 10

facilities to a Regional Transmission Organization’s (“RTO”) functional control, 11

apart from examining that the RTO’s rates will be just and reasonable. 12

Nonetheless, within its analysis of whether the RTO’s rates are just and reasonable, 13

the Commission has permitted non-jurisdictional entities to implement ROEs that 14

fall within a range of reasonable returns approved by the Commission for other 15

transmission owners. In addition, the Commission has permitted non-16

jurisdictional TOs, within RTOs, to apply to their own revenue requirement the 17

same overall rate of return as that applied by the zone’s dominant transmission 18

owner.419

4 Pac. Gas & Elec. Co. v. FERC, 306 F.3d 1112, 1116 &1120 (D.C. Cir. 2002) (indicating use of a surrogate capital structure or ROE may be appropriate for a non-jurisdictional utility); City of Vernon, Cal., 109 FERC ¶ 63,057, at P 126 (2004) (stating, “Vernon's ROE should be set at the level set by the Commission in Opinion 445 for SCE”); Opinion No. 479, 111 FERC ¶ 61,092, P 109 (requiring an ROE update since substantial time had elapsed), reh’g granted in part and denied in part, 112 FERC ¶ 61,207 (2005) reh’g denied, 115 FERC ¶ 61,297 (2006). See also, Southwest Power Pool, Docket No, ER11-2309-000 (Jan. 31, 2011) (letter order) (approving Midwest Energy’s transmission formula rate and protocols on the basis of

Exhibit No. SME-01Page 14 of 15

Q. In your opinion, is the proposed rate of return on equity consistent with 1

Commission precedent? 2

A. Yes. 3

Q. Is SMECO seeking incentive rate treatments for any transmission projects? 4

A. No. In this proceeding, SMECO is not seeking incentive rate treatments for any 5

transmission projects, but reserves the right to seek authorization for certain 6

incentive rate treatments in future filings before the Commission. 7

Q. In your opinion, does the cost of service developed by you conform to 8

Commission precedent with respect to transmission rates? 9

A. Yes. The classification, functionalization and allocation factors used for the cost 10

items reflect standard Commission ratemaking. The data used in the cost of service 11

study is taken directly out of SMECO’s audited financial records. The discreet 12

investment in the SMECO 230 kV transmission system is the basis for the revenue 13

requirements developed in the cost of service. 14

Q. How have you developed the rate in $/MW-year for use in the PEPCO 15

transmission zone? 16

A. PJM sets the Network Service Peak Load (“NSPL”) for each transmission zone 17

based on the highest peak in the zone in the year (the “1-CP”). SMECO’s load is 18

embedded in the PEPCO transmission zonal load, which has fluctuated 19

significantly over the past several years. Because 2016 PEPCO Zone load data is 20

not necessarily representative of typical load in the PEPCO Zone, and because 21

testimony of Michael Volker that indicated “This stipulated ROE . . . falls within the range of reasonable returns approved by the FERC.”).

Exhibit No. SME-01Page 15 of 15

SMECO is proposing a fixed or “stated” transmission rate in this proceeding, it is 1

appropriate to use an average of the PEPCO 1-CP loads over several years to 2

smooth out the fluctuations. To that end I have used the five-year average of the 3

PEPCO zonal 1-CP loads, for the years 2012 through 2016, of 6,494 MW as shown 4

on Exhibit No. SME-08 as the basis for developing the SMECO transmission 5

annual rate charge. As shown on that Exhibit, the PEPCO zonal 1-CP load has 6

fluctuated from year to year over the five-year period from an increase of 5% to a 7

decrease of 3% a year. The SMECO revenue requirement of $17,134,115 is divided 8

by the five-year average zonal 1-CP of 6,494 MW to yield a rate of 9

$2,638.40/MW/year as shown on Exhibit No. SME-03, page 3, line 127. 10

Q. Does this conclude your testimony at this time? 11

A. Yes. 12

[Next page is signature page.] 13

EXHIBIT NO. SME-02: TESTIMONY EXPERIENCE OF ROBERT C. SMITH

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern Maryland ElectricCooperative, Inc.

Docket No. ER17-____-000

Proceedings in which direct testimony was filed by Robert C. Smith

Federal Energy Regulatory Commission

Gulf States Utilities Co., Docket No. ER84-568 Gulf States Utilities Co., Docket No. ER85-355

Carolina Power & Light Co., Docket No. EL91-28-000

Delmarva Power & Light Co., Docket No. ER93-96-000

East Texas Electric Cooperative, Inc., Docket No. ER95-1175-000

Detroit Edison Co., Docket No. OA96-78-000

East Texas Electric Cooperative, Inc., Docket No. ER96-485-000

International Transmission Company, Docket No. ER00-3295-003.

Entergy Services, Inc., Docket No. ER07-956

Wolverine Power Supply Cooperative, Inc. Triennial Market Analysis Update, Docket No. ER98-411

Wolverine Power Supply Cooperative, Inc., Docket No. ER04-132-000

Wolverine Power Supply Cooperative, Inc., Docket No. EL04-38-000

City of Anaheim, California, Docket No. EL05-131-000

Southern California Edison Company, Docket No. ER09-1534

Old Dominion Electric Cooperative Triennial Market Analysis Update, Docket No. ER97-4314-

010

New Dominion Energy Cooperative Triennial Market Analysis Update, Docket No. ER05-20

TEC Trading, Inc. Triennial Market Analysis Update, Docket No. ER01-2783-000

Entergy Services, Inc., Docket No. ER07-956 City of Riverside, California, Docket No. EL09-52-000

City of Pasadena, California, Docket No. EL09-67

Prairie Power, Inc. Docket No. EL11-16

Wolverine Power Supply Cooperative, Inc., Docket No. ER11-3480-000

City of Anaheim, California, Docket No. ER11-3594

City of Banning, California, Docket No. ER11-3962

Exhibit No. SME-02

Page 1 of 3

Federal Energy Regulatory Commission Continued City of Riverside, California, Docket No. ER11-3984

City of Pasadena, California, Docket No. ER11-4375

City of Azusa, California, Docket No. ER12-489

City of Colton, California, Docket No. ER13-207

Public Service Company of New Mexico, Docket No. ER11-1915

PJM Interconnection, L.L.C., Docket No ER12-2177

PJM Interconnection, L.L.C., Docket No ER12-2183

EP Rock Springs, LLC, Docket No. ER13-488

Municipal Electric Utilities Association of New York v. Niagara Mohawk Power, Docket No. EL13-16

Hillman Power Company, L.L.C., Docket No ER13-2076

Lakewood Cogeneration LP, Docket No. ER14-199

City of Anaheim, et al. v. Trans Bay Cable LLC, Docket No. EL14-15 and ER13-2412

East Texas Electric Cooperative, Inc. et. al., Docket No. ER14-1458

East Texas Electric Cooperative, Inc. et. al, Complainants v. Entergy Texas, Inc. Respondent,

Docket No. EL14-43-000

Homer City Generation, L.P., Docket No. ER14-2281

Occidental Power Services, Inc. Docket No. ER15-878

Arkansas Electric Cooperative Corporation, Docket No. ER15-953

PJM Interconnection L.L.C. and Old Dominion Electric Cooperative, Docket No. ER15-967

City of Alexandria, Louisiana, Docket No. EL15-49

East Texas Electric Cooperative, Inc., Docket No. EL15-54

The Empire District Electric Company, Docket No. ER15-1405

Midcontinent Independent System Operator, Inc., Cleco Power LLC, Docket No. ER15-1440

Municipal Energy Agency of Mississippi, Docket No. NJ15-13-000

PJM Interconnection L.L.C. and North Carolina Electric Membership Corporation, Docket No.

ER15-1715

PJM Interconnection L.L.C. and Old Dominion Electric Cooperative, Docket No. ER15-1937

Southwest Power Pool, Inc., Docket No. ER15-1976 Southwest Power Pool, Inc., Docket No. ER15-2028 Southwest Power Pool, Inc., Docket No. ER15-2115 Midcontinent ISO and Prairie Power, Inc., Docket No. ER15-2364 Southwest Power Pool, Inc., Docket No. ER16-204 Southwest Power Pool, Inc., Docket No. ER16-209 Missouri Joint Municipal Electric Utility Commission, Docket No. EL16-26 Southwest Power Pool, Inc., Docket No. ER16-1054 Southwest Power Pool, Inc., Docket No. ER16-1774 Midcontinent Independent System Operator, Inc., Docket No. ER15-277-005 and ER14-2154-006 East Texas Electric Cooperative, Inc., Docket No. ER17-289 City of Pasadena, California, Docket No. ER17-392 Southwest Power Pool, Inc., Docket No. ER17-1610

Exhibit No. SME-02

Page 2 of 3

Public Utility Commission of Texas

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 6440

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 6797

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 7991

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 8595

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 9447

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 10982

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 12552

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 14893

Sam Rayburn G&T Electric Cooperative, Inc., Docket No. 16620

Tex-La Electric Cooperative of Texas, Inc., Docket No. 7279

Tex-La Electric Cooperative of Texas, Inc., Docket No. 10462

Tex-La Electric Cooperative of Texas, Inc., Docket No. 12289

Tex-La Electric Cooperative of Texas, Inc., Docket No. 12552

Tex-La Electric Cooperative of Texas, Inc., Docket No. 19875

Northeast Texas Electric Cooperative, Inc., Docket No. 11384

Northeast Texas Electric Cooperative, Inc., Docket No. 19642

East Texas Electric Cooperative, Inc., Docket No. 15133

Virginia State Corporation Commission

Appalachian Power Co., Case No. PUE900026

Appalachian Power Co., Case No. PUE2006-00065

Indiana Utility Regulatory Commission

Application of PSI Energy, Inc. Cause No. 38707-FAC50 Application of PSI Energy, Inc. Cause No. 38707-FAC67 Petition of Duke Energy Indiana, Inc., Cause No. 43955 Petition of Mishawaka Utilities, et.al, Cause No. 44080 Maryland Public Service Commission

Potomac Electric Power Company Case No. 9092

Public Utilities Commission of Ohio

Monongahela Power Co. in Case No. 04-880-EL-UNC

District of Columbia Public Service Commission

Potomac Electric Power Company, Formal Case No. 1076.

Potomac Electric Power Company, Formal Case No. 1116.

Exhibit No. SME-02

Page 3 of 3

EXHIBIT NO. SME-03: CALCULATION OF REVENUE REQUIREMENTS AND RATE

So

uth

ern

Ma

ryla

nd

Ele

ctri

c C

oo

per

ati

ve, I

nc.

Ca

lcu

lati

on

of

Rev

enu

e R

equ

irem

ents

an

d R

ate

Yea

r E

nd

ed 1

2/3

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01

6

To

tal

PJ

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23

0 k

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eQ

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lify

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.C

ost

of

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mC

om

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ny

To

tal

All

oca

tor

Tra

nsm

issi

on

No

tes

(a)

(b)

(c)

(d)

(e)

(g)

(c)

x (

d)

1R

ate

Base

2 3G

RO

SS

PL

AN

T I

N S

ER

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E

- 1

3 M

on

th A

vg

4

Pro

du

ctio

n4

63

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5

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nsm

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2

98

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7,9

30

$

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P4

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75

%1

43

,35

8,1

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$

Sp

ecif

ic f

or

23

0kV

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op

ed f

acil

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ee 0

4 -

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0 k

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m A

llo

c ta

b)

6

Dis

trib

uti

on

63

9,4

14

,24

5$

N/A

-

$

7

Gen

eral

& I

nta

ngi

ble

16

3,1

45

,78

5$

W&

S3

.70

4%

6,0

42

,85

6$

al

loca

ted

on

W&

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8

Co

ntr

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Cen

ter

and

Map

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ard

all

oca

ted

to

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ns

(in

Gen

Pla

nt)

(1,5

04

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6)

$

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4%

(55

,72

1)

$

allo

cate

d o

n W

&S

9

Oth

er

77

6,0

34

$

N/A

-$

10

TO

TA

L G

RO

SS

PL

AN

T

(su

m l

ines

4-9

)1

,10

1,1

12

,80

3$

GP

=1

3.5

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%1

49

,34

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38

$

11

12

AC

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MU

LA

TE

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- 1

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rod

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3,2

53

,82

4$

NA

-

$

14

T

ran

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sio

n

74

,34

0,5

77

$

D/A

26

,24

5,0

57

$

T

ota

l A

llo

c to

23

0 k

V S

yste

m r

rom

05

- R

ate

Bas

e ta

b

15

D

istr

ibu

tio

n2

45

,92

2,7

66

$

N

/A

-$

16

G

ener

al &

In

tan

gib

le6

1,5

47

,74

8$

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&S

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%2

,27

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$

allo

cate

d o

n W

&S

17

C

on

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d M

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d t

o T

ran

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n G

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(8,6

10

)$

allo

cate

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n W

&S

18

O

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N

/A-

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19

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(su

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84

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62

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2

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16

,15

1$

20

21

NE

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NT

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23

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(lin

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24

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39

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91

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0$

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25

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7 -

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7$

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d M

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$

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28

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29

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WO

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7$

calc

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66

$

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ted

34

M

ater

ials

& S

up

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35

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37

38

RA

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(s

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41

[R

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e *

Rat

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f R

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42

Exhibit No. SME-03

Page 1 of 3

So

uth

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Ma

ryla

nd

Ele

ctri

c C

oo

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ve, I

nc.

Ca

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nti

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ran

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Les

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on

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nt

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nci

llar

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PJM

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43

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79

80

Per

cen

tage

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on

pla

nt

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n C

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ine

75

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P=

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75

81

82

83

84

85

86

87

88

Exhibit No. SME-03

Page 2 of 3

So

uth

ern

Ma

ryla

nd

Ele

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c C

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per

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nc.

Ca

lcu

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ents

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90

91

92

93

94

95

96

97

98

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3

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tal

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m l

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00

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qu

ity

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ota

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sum

lin

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OR

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00

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e o

f R

etu

rn (

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R)

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SS

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VE

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ITS

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t as

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wit

h 2

30

kV l

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p

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ran

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nal

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m s

ervi

ce p

rovi

ded

by

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VE

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E C

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ET

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EQ

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EN

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ine

11

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ne

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3)

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12

6

12

7A

vera

ge

1-C

P i

n P

EP

Co

zo

ne

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MW

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/MW

/Yr

12

8

12

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cch

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le 1

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vers

e o

f li

ne

46

a2

89

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5$

3

0,7

00

,84

2

M

Wh

0.0

09

42

$

/MW

h

Exhibit No. SME-03

Page 3 of 3

EXHIBIT NO. SME-04: ORIGINAL COST INVESTMENT IN 230 KV SYSTEM

Sou

ther

n M

ary

lan

d E

lect

ric

Coo

per

ativ

e, I

nc.

Ori

gin

al

Cos

t In

vest

men

t in

230

kV

Sy

stem

Yea

r E

nd

ed 1

2/31

/201

6

Allo

catio

n of

230

kV

Stat

ions

Tota

lSt

atio

nSt

atio

nO

ne-h

alf o

fSt

atio

n23

0 kV

plu

sCo

mpo

site

Line

Inve

stm

ent

Low

er V

olta

geCo

mm

onCo

mm

on23

0 kV

shar

e of

Accu

mul

ated

Depr

ecia

tion

No.

STAT

ION

in S

tatio

nIn

vest

men

tIn

vest

men

tIn

vest

men

tIn

vest

men

tCo

mm

on (F

ERC)

Depr

ecia

tion

Rate

(a)

(b)

(c)

(e)

(f)(g

)(h

)(i)

(j)

1Aq

uasc

o4,

871,

625

$

-$

-$

-$

4,87

1,62

5$

4,

871,

625

$

1,05

8,95

5$

2

Haw

kins

Gat

e13

,723

,068

$

7,

666,

334

$

3,66

0,71

8$

1,

830,

359

$

2,39

6,01

6$

4,

226,

374

$

1,06

8,05

8$

3

Hew

itt R

oad

21,0

39,0

65$

8,04

5,20

6$

10

,255

,693

$

5,

127,

847

$

2,73

8,16

6$

7,

866,

013

$

3,58

1,90

2$

4

Holla

nd C

liff

14,0

82,5

74$

6,20

9,90

9$

6,

149,

077

$

3,07

4,53

8$

1,

723,

587

$

4,79

8,12

6$

1,

161,

553

$

5Ry

cevi

lle3,

430,

505

$

-$

-$

-$

3,43

0,50

5$

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430,

505

$

1,06

1,00

9$

6

Solla

rs W

harf

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44,2

70$

4,91

6,34

4$

6,

937,

573

$

3,46

8,78

7$

1,

590,

353

$

5,05

9,14

0$

73

8,26

9$

7 8Su

btot

al S

tatio

ns70

,591

,106

$

26

,837

,793

$

27

,003

,061

$

13

,501

,531

$

16

,750

,252

$

30

,251

,782

$

8,

669,

746

$

2.60

%9

% o

f Sub

stat

ion

allo

c to

230

kV

syst

em42

.9%

10 1123

0 kV

Tra

nsm

issi

on L

ines

12

Tota

lCo

mpo

site

13In

vest

men

tAc

cum

ulat

edN

et T

rans

Lin

eDe

prec

iatio

n14

Line

Seg

men

tin

230

kV

Line

Depr

ecia

tion

Plan

t in

Serv

ice

Rate

15(c

)16 17

2320

- Ry

cevi

lle -

Hew

itt R

oad

12,5

44,0

27$

7,16

5,03

4$

5,

378,

993

$

1823

30 -

Solla

rs W

harf

- He

witt

Roa

d12

,602

,688

$

58

9,42

5$

12,0

13,2

63$

1923

30 -

Solle

rs W

harf

- He

witt

Roa

d32

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,721

$

1,

726,

412

$

30,8

07,3

09$

2023

40 -

Holla

nd C

liffs

- So

llers

Wha

rf48

,458

,489

$

3,

679,

768

$

44,7

78,7

21$

2123

45 -

Holla

nd C

liffs

- So

llers

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rf24

,469

$

90

0$

23,5

69$

2223

50 -

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sco

- Hol

land

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fs1,

619,

697

$

517,

050

$

1,

102,

647

$

2323

55 -

Aqua

sco

- Hol

land

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fs1,

316,

696

$

425,

303

$

89

1,39

3$

2467

31 -

Chal

k Pt

- Aq

uasc

o1,

839,

482

$

1,23

4,83

9$

60

4,64

3$

25 26Su

btot

al 2

30 k

V Tr

ans L

ine

Inve

stm

ent

110,

939,

269

$

15,3

38,7

31$

95,6

00,5

38$

2.60

%27

Exhibit No. SME-04

Page 1 of 2

Sou

ther

n M

ary

lan

d E

lect

ric

Coo

per

ativ

e, I

nc.

Ori

gin

al

Cos

t In

vest

men

t in

230

kV

Sy

stem

Yea

r E

nd

ed 1

2/31

/201

6

28Co

ntro

l Cen

ters

- Al

loca

ted

amou

nt to

230

kV

syst

em29 30

Cont

rol C

ente

rs1,

009,

000

$

76,1

37$

932,

863

$

2.

60%

31M

apBo

ard

495,

366

$

13

6,75

8$

358,

608

$

2.

60%

32 33 34SC

ADA

and

EMS

- Allo

cate

d am

ount

to 2

30 k

V sy

stem

35To

tal

36SC

ADA

Accu

mul

ated

Net

Depr

ecia

tion

37ST

ATIO

Nin

Sta

tion

Depr

ecia

tion

Plan

tRa

te38

(b)

(c)

39 40SC

ADA

Inve

stm

ent -

for 2

30 k

V sy

stem

41 42Aq

uasc

o11

5,30

3$

30,2

15$

85,0

88$

43Ha

wki

ns G

ate

141,

352

$

44

,358

$

96

,994

$

44

Hew

itt R

oad

88,5

49$

34,3

58$

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91$

45Ho

lland

Clif

f91

,940

$

24

,093

$

67

,847

$

46

Ryce

ville

45,2

04$

26,2

49$

18,9

55$

47So

llars

Wha

rf45

4,38

7$

57,1

21$

397,

266

$

48 49

Subt

otal

Sta

tions

SCA

DA93

6,73

5$

216,

394

$

72

0,34

1$

50Al

loca

tion

to 2

30 k

V Sy

stem

401,

437

$

92

,736

$

30

8,70

2$

10.5

4%51 52 53

Tota

l54

EMS

Accu

mul

ated

Net

Depr

ecia

tion

55EM

S Sy

stem

Inve

stm

ent

Depr

ecia

tion

Plan

tRa

te56

(b)

(c)

57 58EM

S Sy

stem

(NER

C St

anda

rds f

or 2

30 k

V)26

1,24

9$

40,9

85$

220,

264

$

10

.54%

59 60To

tal 2

30 k

V in

vest

men

t14

3,35

8,10

4$

L

ine

8 co

l (i),

line

26,

line

30

and

31, l

ine

49 a

nd li

ne 5

8

Exhibit No. SME-04

Page 2 of 2

EXHIBIT NO. SME-05: DEVELOPMENT OF PROJECTED 13-MONTH AVERAGE PLANT-IN-SERVICE

Sou

ther

n M

aryl

and

Ele

ctri

c C

oop

erat

ive,

In

c.De

velo

pmen

t of P

roje

cted

13-

Mon

th A

vera

ge P

lant

-in-S

ervi

ceAs

sum

es Y

ear-

end

2016

Val

ues a

re re

ason

able

est

imat

es o

f mon

thly

val

ues i

n th

e 12

mon

ths s

ubse

quen

t to

the

effe

ctiv

e da

te

Tota

l Com

pany

Tra

nsm

issi

onTo

tal C

ompa

ny G

ener

alM

onth

ly2

Mon

thly

2

Proj

TY

Tran

s YE

201

6 Tr

ans

Tran

s Plt

Proj

TY

Tran

sPr

oj T

Y Ge

nYE

201

6 Ge

nGe

nera

l Plt

Proj

TY

Gen

Plt

Line

Plan

t in

Accu

mua

lted

Depr

ecia

tion

Accu

mua

lted

Plan

t in

Accu

mua

lted

Depr

ecia

tion

Accu

mua

lted

No.

Mon

thSe

rvic

e1De

prec

iatio

nEx

pens

eDe

prec

iatio

nSe

rvic

e1De

prec

iatio

nEx

pens

eDe

prec

iatio

n(a

)(b

)(c

)(d

)(e

)(f)

(g)

(h)

(i)

1De

c-16

298,

817,

930

$

69,9

88,9

60$

16

3,14

5,78

5$

59

,092

,444

$

2

Jan-

1729

8,81

7,93

0$

66

9,48

0$

70,6

58,4

40$

16

3,14

5,78

5$

37

7,73

9$

59

,470

,183

$

3

Feb-

1729

8,81

7,93

0$

66

9,48

0$

71,3

27,9

19$

16

3,14

5,78

5$

37

7,73

9$

59

,847

,922

$

4

Mar

-17

298,

817,

930

$

669,

480

$

71

,997

,399

$

163,

145,

785

$

377,

739

$

60,2

25,6

61$

5Ap

r-17

298,

817,

930

$

669,

480

$

72

,666

,878

$

163,

145,

785

$

377,

739

$

60,6

03,4

01$

6M

ay-1

729

8,81

7,93

0$

66

9,48

0$

73,3

36,3

58$

16

3,14

5,78

5$

37

7,73

9$

60

,981

,140

$

7

Jun-

1729

8,81

7,93

0$

66

9,48

0$

74,0

05,8

37$

16

3,14

5,78

5$

37

7,73

9$

61

,358

,879

$

8

Jul-1

729

8,81

7,93

0$

66

9,48

0$

74,6

75,3

17$

16

3,14

5,78

5$

37

7,73

9$

61

,736

,618

$

9

Aug-

1729

8,81

7,93

0$

66

9,48

0$

75,3

44,7

96$

16

3,14

5,78

5$

37

7,73

9$

62

,114

,357

$

10

Sep-

1729

8,81

7,93

0$

66

9,48

0$

76,0

14,2

76$

16

3,14

5,78

5$

37

7,73

9$

62

,492

,096

$

11

Oct

-17

298,

817,

930

$

669,

480

$

76

,683

,755

$

163,

145,

785

$

377,

739

$

62,8

69,8

35$

12N

ov-1

729

8,81

7,93

0$

66

9,48

0$

77,3

53,2

35$

16

3,14

5,78

5$

37

7,73

9$

63

,247

,574

$

13

Dec-

1729

8,81

7,93

0$

66

9,48

0$

78,0

22,7

14$

16

3,14

5,78

5$

37

7,73

9$

63

,625

,314

$

14 15

13-M

onth

A29

8,81

7,93

0$

69

,988

,960

$

669,

480

$

74

,340

,577

$

163,

145,

785

$

59,0

92,4

44$

377,

739

$

61,5

47,7

48$

16 17N

otes

: 1.

SM

ECo

assu

mes

that

tota

l com

pany

Tra

nsm

issio

n Pl

ant a

nd G

ener

al P

lant

inve

stm

ent w

ill n

ot c

hang

e in

the

12 m

onth

s pre

ceed

ing

the

effe

ctiv

e da

te

182.

1/1

2th

of 2

016

annu

al d

epre

ciat

ion

expe

nse

for t

otal

com

pany

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nsm

issio

n an

d G

ener

al P

lant

19 20 21To

tal C

ompa

ny P

rodu

ctio

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ompa

ny D

istr

ibut

ion

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onth

ly3

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thly

4

23Pr

oj T

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oj T

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nse

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ecia

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nse

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ecia

tion

26(a

)(b

)(c

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(g)

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(i)27 28

Dec-

1646

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5$

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898,

371

$

2,

898,

371

$

63

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5$

23

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8,50

0$

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4,95

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0$

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n-17

463,

175

$

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957,

613

$

63

9,41

4,24

5$

1,

827,

378

$

23

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8$

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b-17

463,

175

$

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016,

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$

63

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378

$

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5$

31M

ar-1

746

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5$

59

,242

$

3,07

6,09

7$

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414,

245

$

1,82

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8$

240,

440,

633

$

32

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1746

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59

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$

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242,

268,

010

$

33

May

-17

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175

$

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194,

581

$

63

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378

$

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n-17

463,

175

$

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253,

824

$

63

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1,

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378

$

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6$

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l-17

463,

175

$

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42$

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313,

066

$

63

9,41

4,24

5$

1,

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378

$

24

7,75

0,14

3$

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g-17

463,

175

$

59,2

42$

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372,

308

$

63

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378

$

24

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p-17

463,

175

$

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42$

3,

431,

550

$

63

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4,24

5$

1,

827,

378

$

25

1,40

4,89

8$

38O

ct-1

746

3,17

5$

59

,242

$

3,49

0,79

2$

639,

414,

245

$

1,82

7,37

8$

253,

232,

276

$

39

Nov

-17

463,

175

$

59,2

42$

3,

550,

034

$

63

9,41

4,24

5$

1,

827,

378

$

25

5,05

9,65

3$

40De

c-17

463,

175

$

59,2

42$

3,

609,

276

$

63

9,41

4,24

5$

1,

827,

378

$

25

6,88

7,03

1$

41 4213

-Mon

th A

463,

175

$

2,89

8,37

1$

59,2

42$

3,

253,

824

$

63

9,41

4,24

5$

23

4,95

8,50

0$

1,

827,

378

$

24

5,92

2,76

6$

43 44N

otes

: 3.

SM

ECo

assu

mes

that

the

Prod

uctio

n an

d Di

strib

utio

n Pl

ant i

nves

tmen

t will

not

cha

nge

in th

e 12

mon

ths p

rece

edin

g th

e ef

fect

ive

date

Exhibit No. SME-05

Page 1 of 2

Sou

ther

n M

aryl

and

Ele

ctri

c C

oop

erat

ive,

In

c.De

velo

pmen

t of P

roje

cted

13-

Mon

th A

vera

ge P

lant

-in-S

ervi

ceAs

sum

es Y

ear-

end

2016

Val

ues a

re re

ason

able

est

imat

es o

f mon

thly

val

ues i

n th

e 12

mon

ths s

ubse

quen

t to

the

effe

ctiv

e da

te

454.

1/1

2th

of 2

016

annu

al d

epre

ciat

ion

expe

nse

for t

otal

com

pany

Pro

duct

ion

and

Dist

ribut

ion

Plan

t

46 4723

0 kV

Tra

nsm

issi

on S

yste

m (

Stat

ions

and

Lin

es)

Cont

rol C

ente

r and

Map

Boar

d in

Con

trol

Cen

ter (

Gen

eral

Pla

nt)

48M

onth

ly6

Mon

thly

8

49Pr

oj T

Y 23

0 kV

YE 2

016

230

kV23

0 kV

Plt

Proj

TY

230

kVPr

oj T

Y CC

& M

BYE

201

6 CC

& M

BPr

oj T

Y50

Plan

t in

Accu

mua

lted

Depr

ecia

tion

Accu

mua

lted

Plan

t in

Accu

mua

lted

Depr

ecia

tion

Accu

mua

lted

51M

onth

Serv

ice5

Depr

ecia

tion

Expe

nse

Depr

ecia

tion

Mon

thSe

rvic

e7De

prec

iatio

nEx

pens

eDe

prec

iatio

n52

(a)

(b)

(c)

(d)

(e)

(a)

(b)

(c)

(d)

(e)

53 54De

c-16

141,

191,

051

$

24,0

08,4

77$

24

,008

,477

$

Dec-

161,

504,

366

$

212,

895

$

212,

895

$

55

Jan-

1714

1,19

1,05

1$

30

5,91

4$

24,3

14,3

91$

Ja

n-17

1,50

4,36

6$

3,

259

$

21

6,15

4$

56Fe

b-17

141,

191,

051

$

305,

914

$

24

,620

,305

$

Feb-

171,

504,

366

$

3,25

9$

219,

414

$

57

Mar

-17

141,

191,

051

$

305,

914

$

24

,926

,219

$

Mar

-17

1,50

4,36

6$

3,

259

$

22

2,67

3$

58Ap

r-17

141,

191,

051

$

305,

914

$

25

,232

,133

$

Apr-

171,

504,

366

$

3,25

9$

225,

933

$

59

May

-17

141,

191,

051

$

305,

914

$

25

,538

,047

$

May

-17

1,50

4,36

6$

3,

259

$

22

9,19

2$

60Ju

n-17

141,

191,

051

$

305,

914

$

25

,843

,961

$

Jun-

171,

504,

366

$

3,25

9$

232,

452

$

61

Jul-1

714

1,19

1,05

1$

30

5,91

4$

26,1

49,8

75$

Ju

l-17

1,50

4,36

6$

3,

259

$

23

5,71

1$

62Au

g-17

141,

191,

051

$

305,

914

$

26

,455

,789

$

Aug-

171,

504,

366

$

3,25

9$

238,

971

$

63

Sep-

1714

1,19

1,05

1$

30

5,91

4$

26,7

61,7

03$

Se

p-17

1,50

4,36

6$

3,

259

$

24

2,23

0$

64O

ct-1

714

1,19

1,05

1$

30

5,91

4$

27,0

67,6

17$

O

ct-1

71,

504,

366

$

3,25

9$

245,

490

$

65

Nov

-17

141,

191,

051

$

305,

914

$

27

,373

,531

$

Nov

-17

1,50

4,36

6$

3,

259

$

24

8,74

9$

66De

c-17

141,

191,

051

$

305,

914

$

27

,679

,444

$

Dec-

171,

504,

366

$

3,25

9$

252,

009

$

67 68

13-M

onth

A14

1,19

1,05

1$

24

,008

,477

$

25,8

43,9

61$

13

-Mon

th A

vg1,

504,

366

$

212,

895

$

232,

452

$

69 70

Not

es:

5. S

MEC

o as

sum

es th

at th

e 23

0kV

inve

stm

ent w

ill n

ot c

hang

e in

the

12 m

onth

s pre

ceed

ing

the

effe

ctiv

e da

te7.

SM

ECo

assu

mes

that

the

CC a

nd M

B in

vest

men

t will

not

cha

nge

in th

e 12

mon

ths p

rece

edin

g th

e ef

fect

ive

date

716.

Orig

inal

Cos

t of 2

30 k

V sy

stem

mul

tiplie

d by

Com

posit

e de

prec

iatio

n ra

te8.

Orig

inal

Cos

t of C

C &

MB

mul

tiplie

d by

Com

posit

e de

prec

iatio

n ra

te

72 73SC

ADA

and

EMS

Syst

em (A

lloc

to 2

30 k

V Sy

stem

)74

Mon

thly

10

75Pr

oj T

Y SC

ADA/

EMS

YE 2

016

SCAD

A/EM

SPr

oj T

Y76

Plan

t in

Accu

mua

lted

Depr

ecia

tion

Accu

mua

lted

77M

onth

Serv

ice9

Depr

ecia

tion

Expe

nse

Depr

ecia

tion

78(a

)(b

)(c

)(d

)(e

)79 80

Dec-

1666

2,68

6$

13

3,72

1$

13

3,72

1$

81

Jan-

1766

2,68

6$

5,

821

$

13

9,54

1$

82

Feb-

1766

2,68

6$

5,

821

$

14

5,36

2$

83

Mar

-17

662,

686

$

5,82

1$

151,

182

$

84Ap

r-17

662,

686

$

5,82

1$

157,

003

$

85M

ay-1

766

2,68

6$

5,

821

$

16

2,82

4$

86

Jun-

1766

2,68

6$

5,

821

$

16

8,64

4$

87

Jul-1

766

2,68

6$

5,

821

$

17

4,46

5$

88

Aug-

1766

2,68

6$

5,

821

$

18

0,28

5$

89

Sep-

1766

2,68

6$

5,

821

$

18

6,10

6$

90

Oct

-17

662,

686

$

5,82

1$

191,

927

$

91N

ov-1

766

2,68

6$

5,

821

$

19

7,74

7$

92

Dec-

1766

2,68

6$

5,

821

$

20

3,56

8$

93 94

13-M

onth

A66

2,68

6$

13

3,72

1$

16

8,64

4$

95 96

Not

es:

9. S

MEC

o as

sum

es th

at th

e SC

ADA

and

EMS

inve

stm

ent w

ill n

ot c

hang

e in

the

12 m

onth

s pre

ceed

ing

the

effe

ctiv

e da

te

9710

. EM

S Sy

stem

and

Allo

cate

d Co

st o

f SCA

DA sy

stem

mul

tiplie

d by

Com

posit

e de

prec

iatio

n ra

te

Exhibit No. SME-05

Page 2 of 2

EXHIBIT NO. SME-06: DEVELOPMENT OF WAGES & SALARIES BY FUNCTION

Sout

hern

Mar

ylan

d El

ectr

ic C

oope

rativ

e, I

nc.

Dev

elop

men

t of W

ages

& S

alar

ies

by F

unct

ion

Year

End

ed 1

2/31

/201

6

To

Exhi

bit N

o. S

ME-

03Ac

coun

tDe

scrip

tion

2016

Tot

alFu

nctio

nal S

ubto

tals

page

3, l

ines

99-

103

101.

20El

ectri

c Pl

ant i

n Se

rvice

- In

tang

ible

8,66

5$

Pr

oduc

tion

287,

503

$

10

7.20

Cons

truct

ion

Wor

k in

Pro

gres

s10

,863

,168

Tr

ansm

issio

n1,

760,

218

$

108.

80Re

tirem

ent W

ork

in P

rogr

ess

1,73

6,21

8

Di

strib

utio

n14

,315

,707

$

182.

30Em

pow

er M

aryl

and

Prog

ram

s18

2,92

1

Othe

r6,

435,

572

$

182.

61AM

I Sys

tem

Wid

e De

ploy

men

t46

8,52

6

A&G

11,9

04,4

38$

18

3.00

Prel

imin

ary

Surv

eys

148,

671

18

6.00

Defe

rred

Deb

it M

isc74

2,20

8

Subt

otal

w/o

A&G

22,7

99,0

00$

TO

TAL

BALA

NCE

SH

EET

14,1

50,3

78

557.

00Ot

her E

xpen

ses

- Pow

er S

uppl

y28

7,50

3

T

OTA

L PU

RCH

ASED

PO

WER

287,

503

560.

00Op

erat

ion

Supe

rvisi

on &

Eng

inee

ring

593,

432

56

1.00

Load

Disp

atch

ing

460,

020

56

3.00

Over

head

Lin

e Ex

pens

es10

,556

56

8.00

Mai

nten

ance

Sup

ervi

sion

& En

gine

erin

g57

,552

57

0.00

Mai

nten

ance

of S

tatio

n Eq

uipm

ent

439,

667

57

1.00

Mai

nten

ance

of O

verh

ead

Line

s14

3,23

5

573.

00M

aint

enan

ce o

f Tra

nsm

issio

n Pl

ant

55,7

57

T

OTA

L TR

ANSM

ISSI

ON

EXP

ENSE

1,76

0,21

8

580.

00Op

erat

ion

Supe

rvisi

on &

Eng

inee

ring

1,08

0,08

4

58

1.00

Load

Disp

atch

ing

719,

791

58

2.00

Stat

ion

Expe

nses

117,

887

58

3.00

Over

head

Lin

e Ex

pens

es43

,283

58

3.10

Over

head

Lin

e Ex

pens

es -

Join

t use

of T

renc

h86

,445

58

4.00

Unde

rgro

und

Line

Exp

ense

s25

,055

58

5.00

Stre

et L

ight

ing

and

Sign

al S

yste

m E

xpen

se10

7

586.

00M

eter

Exp

ense

s1,

479,

831

588.

00M

isc D

istrib

utio

n Ex

pens

es1,

803,

975

588.

10Pa

x Ri

ver P

rivat

izatio

n80

T

OTA

L D

ISTR

IBU

TIO

N E

XPEN

SE -

OPE

RAT

ION

S5,

356,

539

Exhibit No. SME-06

Page 1 of 3

Sout

hern

Mar

ylan

d El

ectr

ic C

oope

rativ

e, I

nc.

Dev

elop

men

t of W

ages

& S

alar

ies

by F

unct

ion

Year

End

ed 1

2/31

/201

6

Acco

unt

Desc

riptio

n20

16 T

otal

590.

00M

aint

enan

ce S

uper

visio

n &

Engi

neer

ing

299,

928

59

2.00

Mai

nten

ance

of S

tatio

n Eq

uipm

ent

493,

054

59

3.00

Mai

nten

ance

of O

verh

ead

Line

s3,

877,

519

593.

10M

aint

enan

ce o

f Ove

rhea

d Li

nes

Trim

min

g &

Clea

r75

1

593.

30M

aint

enan

ce o

f Ove

rhea

d Li

nes

Prin

ce F

rede

rick

275

59

3.50

Mai

nten

ance

of O

verh

ead

Line

s - A

ccid

ents

1,04

2

59

3.91

Mai

nten

ance

of O

verh

ead

Line

s - S

torm

Tro

uble

102,

473

59

3.92

Mai

nten

ance

of O

verh

ead

Line

s - S

torm

Tro

uble

10,2

67

593.

93M

aint

enan

ce o

f Ove

rhea

d Li

nes

- Sto

rm T

roub

le29

,058

59

3.99

Mai

nten

ance

of O

verh

ead

Line

s - S

torm

Tro

uble

180,

875

59

4.00

Mai

nten

ance

of U

nder

grou

nd L

ines

3,55

4,97

0

59

4.50

Mai

nten

ance

of U

nder

grou

nd L

ines

- Ac

ciden

ts7,

958

595.

00M

aint

enan

ce o

f Lin

e Tr

ansf

orm

ers

- Ove

rhea

d2,

127

596.

00M

aint

enan

ce o

f Stre

et L

ight

ing

& Si

gnal

Sys

tem

s17

1,48

3

596.

10M

aint

enan

ce o

f Stre

et L

ight

ing

& Si

gnal

Sys

tem

s - S

YL64

,120

59

6.20

Mai

nten

ance

of S

treet

Lig

htin

g &

Sign

al S

yste

ms

- Und

ergr

ound

25,4

39

596.

30M

aint

enan

ce o

f Stre

et L

ight

ing

& Si

gnal

Sys

tem

s - S

YL -

Unde

rgro

und

936

59

8.00

Mai

nten

ance

of M

isc D

istrib

utio

n Pl

ant

30,8

99

598.

10M

aint

enan

ce o

f Misc

Dist

ribut

ion

Plan

t - P

CB48

,191

59

8.20

Mai

nten

ance

of M

isc D

istrib

utio

n Pl

ant -

SYL

57,8

04

T

OTA

L D

ISTR

IBU

TIO

N E

XPEN

SE -

MAI

NTE

NAN

CE8,

959,

168

901.

00Su

perv

ision

1,07

6,71

9

90

2.00

Met

er R

eadi

ng E

xpen

se17

5,07

5

903.

00Cu

stom

er R

ecor

ds &

Col

lect

ion

Expe

nse

3,21

3,97

2

90

3.10

SYL

- Cus

tom

er R

ecor

ds E

xpen

se -

Cler

ical

78,2

02

903.

20Cu

stom

er R

ecor

ds &

Col

lect

ion

Expe

nse

- Lat

e Py

mt

1,29

8,30

9

90

3.26

Cust

omer

Rec

ords

& C

olle

ctio

n Ex

pens

e - U

SPP

35,2

12

T

OTA

L CU

STO

MER

ACC

OU

NTS

EXP

ENSE

5,87

7,49

0

907.

00Su

perv

ision

117,

849

90

8.00

Cust

omer

Ass

istan

ce E

xpen

se40

9,37

5

908.

10Cu

stom

er A

ssist

ance

Exp

ense

- Ke

y Ac

coun

ts24

,844

90

9.00

Info

rmat

iona

l & In

stru

ctio

nal A

dver

tisin

g Ex

pens

e6,

015

T

OTA

L CU

STO

MER

SER

VICE

& I

NFO

RM

ATIO

N E

XP55

8,08

2

Exhibit No. SME-06

Page 2 of 3

Sout

hern

Mar

ylan

d El

ectr

ic C

oope

rativ

e, I

nc.

Dev

elop

men

t of W

ages

& S

alar

ies

by F

unct

ion

Year

End

ed 1

2/31

/201

6

Acco

unt

Desc

riptio

n20

16 T

otal

920.

00Ad

min

& G

ener

al S

alar

ies

8,64

2,26

8

92

0.10

Unio

n Of

ficer

s &

Stew

ards

Com

pens

atio

n Ti

me

36,6

32

920.

50Ad

min

& G

ener

al E

xpen

se -

Dive

rsity

Pro

gram

75,7

98

920.

60Ad

min

& G

ener

al E

xpen

se -

Cont

ract

Rev

iew

17,9

45

920.

75Ad

min

& G

ener

al E

xpen

se -

Fede

ral S

mal

l Bus

ines

s57

4

920.

80Ad

min

& G

ener

al E

xpen

se -

Stat

e Di

vers

e Su

pplie

r Pro

gram

60,5

27

920.

85Ad

min

& G

ener

al E

xpen

se -

Fede

ral C

ontra

cts

574

92

1.00

Offic

e Su

pplie

s an

d Ex

pens

e27

,659

92

4.00

Prop

erty

Insu

ranc

e20

,061

92

5.10

Inju

ries

& Da

mag

es -

Lost

Tim

e Ac

ciden

t - C

urr Y

ear

38,8

21

926.

00Em

ploy

ee P

ensio

ns &

Ben

efits

1,12

9,69

5

92

6.30

Empl

oyee

Pen

sions

& B

enef

its -

Empl

oyee

Par

ty5,

010

926.

40Em

ploy

ee P

ensio

ns &

Ben

efits

- W

atts

New

s26

,300

92

6.50

Empl

oyee

Pen

sions

& B

enef

its -

Fune

ral

65,5

06

926.

60Em

ploy

ee P

ensio

ns &

Ben

efits

- Li

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Exhibit No. SME-06

Page 3 of 3

EXHIBIT NO. SME-07: CAPTIAL STRUCTURE OF POTOMAC ELECTRIC POWER COMPANY

Exhibit No. SME-07

Southern Maryland Electric Cooperative, Inc.Capital Structure of Potomac Electric Power Company

Calendar Year 2016

Line Cost WeightedNo. Item Capitalization % Rates Cost(a) (b) (c) (d) (e) (f)

1 Long Term Debt 2,331,531,895$ 50.36% 3.59% 1.81%23 Preferred 0.00% 0.00%45 Common Equity 2,298,103,780$ 49.64% 10.50% 5.21%67 Total 4,629,635,675$ 100.00% 7.02%89

10 Source:1112 http://www.pjm.com/~/media/markets-ops/trans-service/2017/pepco-2016-formula-rate-xls.ashx

EXHIBIT NO. SME-08: PEPCO HISTORICAL ZONAL 1-CPs

Southern Maryland Electric Cooperative, Inc.PEPCo Historic Zonal 1-CP's

Calendar Year 2016

PEPCo Year overYear Zonal 1CP Year Change

2013 67212014 6553 -2.5%2015 6345 -3.2%2016 6268 -1.2%2017 6584 5.0%Avg 6494

Exhibit No. SME-08

Page 1 of 1

EXHIBIT NO. SME-09: DIRECT TESTIMONY OF SONJA COX

Exhibit No. SME-09

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern Maryland Electric Cooperative, Inc. Docket No. ER17-____-000

PREPARED DIRECT TESTIMONY AND EXHIBITS OF

SONJA M. COX

On Behalf of

SOUTHERN MARYLAND ELECTRIC COOPERATIVE, INC.

Transmission Revenue Requirements in PJM

June 27, 2017

Exhibit No. SME-09Page 1 of 5

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern Maryland Electric Cooperative, Inc. | Docket No. ER17-____-000

Prepared Direct Testimony and Exhibits Of

Sonja M. Cox

On Behalf of Southern Maryland Electric Cooperative, Inc.

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

A. My name is Sonja M. Cox. My business address is Southern Maryland Electric 2

Cooperative, Inc., 15035 Burnt Store Road, Hughesville, Maryland 20637. 3

Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION? 4

A. I am Senior Vice President, Financial, Economic and Employee Services and 5

Chief Financial Officer of Southern Maryland Electric Cooperative, Inc. 6

(“SMECO” or the “Cooperative”). 7

Q. PLEASE PROVIDE YOUR EDUCATIONAL AND PROFESSIONAL 8

BACKGROUND. 9

A. I received a Master of Business Administration degree from Johns Hopkins 10

University in May 2003. I also hold a Bachelor of Science degree in Accounting 11

from the University of Maryland University College. From September 1983 to 12

February 1990, I was employed by Carolina Power and Light Company as a Cost 13

Control Specialist at the Robinson Nuclear Project Department in Hartsville, 14

South Carolina. From February 1990 until joining SMECO in January 1999, I 15

Exhibit No. SME-09Page 2 of 5

held various controller or accounting manager positions. I joined SMECO in 1

January 1999 as Financial Reporting Supervisor and was promoted in February 2

2006 to Vice President, Financial Services and Chief Financial Officer. In a 2006 3

internal reorganization, the functions of rates and economic studies and corporate 4

insurance were added to my responsibilities, and my title was changed to Vice 5

President, Financial & Economic Services and Chief Financial Officer. In 2008, 6

the functions of billing services and distributed energy and sustainability were 7

added to my responsibilities and, in early 2009, the department of Human 8

Resources was merged into the department and my title was changed to Senior 9

Vice President, Financial, Economic and Employee Services and Chief Financial 10

Officer. In this capacity, I am responsible for daily accounting, budgeting, 11

financial and tax reporting, treasury and cash management, long range financial 12

planning, capital credits, payroll, accounts payable, risk and energy procurement 13

functions, credit, internal control, short and long term debt facilities, development 14

and maintenance of sound business practices in accordance with GAAP 15

accounting directives and practices, rate design, cost of service, energy efficiency 16

programs, renewables compliance, and all employee relations and human 17

resources functions. I am also a Certified Public Accountant licensed in the State 18

of Maryland. I received this certification in February 1998. 19

Q. Have you previously testified before utility regulatory commissions? 20

A. Yes. I have provided testimony in various distribution base rate cases, several 21

power cost adjustment hearings and other proceedings before the Public Service 22

Commission of Maryland. 23

Exhibit No. SME-09Page 3 of 5

Q. On whose behalf are you presenting testimony in this proceeding? 1

A. I am presenting this testimony on behalf of the Southern Maryland Electric 2

Cooperative, Inc. (“Southern Maryland,” “SMECO” or “the Cooperative”). 3

Q. What is the purpose of your testimony? 4

A. I will describe the basis for SMECO’s 2016 test year data supporting this filing 5

and the total transmission investment and accumulated depreciation as of 6

December 31, 2016. 7

Q. Please describe the foundation for how SMECO maintains its books and 8

records. 9

A. SMECO maintains its books and records in accordance with the Federal Energy 10

Regulatory Commission’s Uniform System of Accounts. In addition, the 11

Cooperative follows Generally Accepted Accounting Principles (“GAAP”) issued 12

by the Financial Accounting Standards Board in the compilation of its financial 13

statements. 14

Q. Are SMECO’s books of account and financial statements audited? 15

A. Yes. Each year, SMECO’s books of account and consolidated financial statements 16

are audited by an independent auditing firm. The audit for the years ended 17

December 31, 2016 and 2015 was conducted by the firm of Adams, Jenkins & 18

Cheatham. It is the responsibility of the auditors to express an opinion on the 19

Company’s consolidated financial statements. In issuing their opinion, the 20

auditors stated that the Cooperative’s financial statements presented fairly, in all 21

material respects, the financial position of SMECO as of December 31, 2016 and 22

2015, and the results of the Cooperative’s operations and its cash flows for the 23

Exhibit No. SME-09Page 4 of 5

years then ended in accordance with accounting principles generally accepted in 1

the United States of America. This is referred to as an “unmodified opinion”, 2

previously known as an unqualified opinion. 3

Q. Please describe the audit process. 4

A. SMECO’s management is responsible for the preparation and fair presentation of 5

the consolidated financial statements and accompanying footnotes. This includes 6

the design, implementation and maintenance of internal controls relevant to the 7

preparation and fair presentation of the consolidated financial statements. 8

Management (the Chief Executive Officer and the Chief Financial Officer) 9

represents to the auditors that the financial statements are free from material 10

misstatement. The auditors then design procedures that allow them to obtain 11

evidence about the amounts and disclosures in the consolidated financial 12

statements. The evidence comes in many forms (various source documents, 13

appropriate approvals, observations, inventory counts, statistical analysis, etc.). 14

The audit also includes evaluating the various estimates made by management in 15

preparing the financial statements and the appropriateness of accounting policies 16

that are used. The auditors use the evidence obtained to provide a basis for their 17

opinion on the consolidated financial statements. 18

Q. What is an unmodified opinion? 19

A. An unmodified opinion is the independent auditor’s judgment that the 20

Cooperative’s financial records and statements present fairly its operations and 21

financial position according to GAAP. An unmodified opinion, previously referred 22

Exhibit No. SME-09Page 5 of 5

to as an unqualified opinion, is also more commonly known as a “clean” auditor’s 1

report. 2

Q. Did you provide SMECO witness Smith SMECO’s total transmission 3

investment and accumulated depreciation as of December 31, 2016? 4

A. Yes. When calculating SMECO’s total transmission investment and accumulated 5

depreciation, SMECO included only the investment in and accumulated 6

depreciation of SMECO’s 230 kV transmission facilities, which are the facilities 7

over which PJM Interconnection, LLC has operational control and which the 8

North American Electric Reliability Corporation determined to be part of the Bulk 9

Electric System. As of December 31, 2016, SMECO’s total transmission 10

investment was $298,817,930 and its accumulated depreciation on that investment 11

was $74,340,577. I obtained both these figures from SMECO’s books of account. 12

These numbers were subject to the audit and were provided to witness Smith. 13

Witness Smith used these numbers as well as other audited data, as a basis for his 14

230 kV system allocation and the final numbers are presented in his testimony. 15

Q. Does this conclude your testimony at this time? 16

A. Yes. 17

18

EXHIBIT NO. SME-10: ATTESTATION