Virginia Electric and Power Company Subsection A 4 Rate Adjustment Clause. Direct Testimony and Exhibits

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2 Virginia Electric and Power Company Subsection A 4 Rate Adjustment Clause Table of Contents Direct Testimony and Exhibits David M. Wilkinson James D. Jackson, Jr. Paul B. Haynes Filing Schedule 46 Filing Schedule 46A Filing Schedule 46B Filing Schedule 46C

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4 COMMONWEALTH OF VIRGINIA STATE CORPORATION COMMISSION APPLICATION OF VIRGINIA ELECTRIC AND POWER COMPANY For approval of a rate adjustment clause pursuant to A 4 of the Code of Virginia Case No. PUE APPLICATION Virginia Electric and Power Company, d/b/a Dominion Virginia Power ("Dominion Virginia Power" or the "Company"), by counsel, pursuant to A 4 ("Subsection A 4") of the Code of Virginia ("Va. Code") and 20 VAC ,20 VAC , and 20 VAC of the Commission's Rules Governing Utility Rate Applications and Annual Informational Filings, 20 VAC , et seq. (the "Rate Case Rules"), respectfully files its Application 1 with the State Corporation Commission of Virginia (the "Commission") for approval of a revised increment/decrement RAC, designated as Rider T1, for an adjustment to the Company's recovery of costs recoverable under Subsection A 4, described in detail below and currently being recovered through a combination of the Subsection A 4 component of base rates and current Rider Tl. Approval of this revised Rider T1 will assure the timely and current recovery of the Company's Subsection A 4 revenue requirement for the rate year September 1, August 31,2015 ("Rate Year"), including (i) costs charged to the Company by PJM 1 In its initial Subsection A 4 rate adjustment clause ("RAC") filing in Case No. PUE , the Company styled its initial pleading as a petition, consistent with the language of Subsection A 4 stating that "[u]pon petition of a utility... the Commission shall approve a rate adjustment clause" under that subsection. In its April21, 2009 Order for Notice and Hearing, and throughout that proceeding, the Commission described that filing as an application, consistent with Rule 80 of its Rules of Practice and Procedure, 5 V AC , and Rules and 60 of its Rate Case Rules, 20 VAC and -60, respectively. To avoid potential confusion, this filing is styled as an application consistent with the Commission's approach in Case No. PUE

5 Interconnection, L.L.C. ("PJM") for transmission services provided to the Company by PJM, as determined under applicable rates, terms, and conditions approved by the Federal Energy Regulatory Commission ("FERC"); and (ii) costs charged to the Company by PJM associated with demand response programs approved by FERC and administered by PJM. In support of its Application, the Company respectfully shows the following: I. GENERAL INFORMATION 1. Dominion Virginia Power is a public service corporation organized under the laws of the Commonwealth of Virginia furnishing electric service to the public within its certificated service territory. The Company also supplies electric service to nonjurisdictional customers in Virginia and to the public in portions of North Carolina. The Company is engaged in the business of generating, transmitting, distributing, and selling electric power and energy to the public for compensation. The Company is also a public utility under the Federal Power Act, and certain of its operations are subject to the jurisdiction of the FER C. The Company is an operating subsidiary of Dominion Resources, Inc. The Company's name and post office address are: Virginia Electric and Power Company 120 Tredegar Street Richmond, Virginia The addresses and telephone numbers of the attorneys for the Company are: Lisa S. Booth William H. Baxter ll Dominion Resources Services, Inc. 120 Tredegar Street, RS-2 Richmond, Virginia (804) (804) [email protected] [email protected] 2

6 Stephen H. Watts, II Joseph K. Reid, III Lisa R. Crabtree McGuire Woods LLP One James Center 901 East Cary Street Richmond, Virginia (804) (804) (804) mcguirewoods. com mcguirewoods. mcguirewoods. com II. BACKGROUND, SUMMARY AND BASIS FOR SUBSECTION A 4 RAC 3. Subsection A 4, adopted during the 2007 Session of the Virginia General Assembly as part of what is now known as the Virginia Electric Utility Regulation Act (the "Act"), provides that the following costs incurred by an investor-owned incumbent electric utility, 2 such as the Company, "shall be deemed reasonable and prudent": "(i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission" ("A 4(i) Costs"); and "(ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member" ("A 4(ii) Costs"). Subsection A 4 provides further that "[u]pon petition of a utility at any time after the expiration or termination of capped rates, but not more than once in any 12-month period, the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service, charges for new and existing transmission facilities, administrative charges, and ancillary service charges designed to recover 2 The term "incumbent electric utility" is defined for purposes of to mean "each electric utility in the Commonwealth that, prior to July 1, 1999, supplied electric energy to retail customers located in an exclusive service territory established by the Commission." Va. Code

7 transmission costs, shall be recovered on a timely and current basis from customers." Finally, Subsection A 4 states that "[r]etail rates to recover these costs shall be designed using the appropriate billing determinants in the retail rate schedules." 4. Effective May 1, 2005, the Company became a member of PJM, a regional transmission entity that has been approved as a regional transmission organization ("RTO") by FERC, at which time PJM assumed operational control of the Company's electric transmission facilities, and the Company gained direct access to the PJM capacity and energy markets. Accordingly, PJM is "the regional transmission entity of which the [Company] is a member" for the purposes of Subsection A 4. As an integrated electric utility member of PJM, the Company obtains transmission service from PJM and pays PJM charges for such service at the rates contained in PJM's Open Access Transmission Tariff ("PJM OATT") approved by FERC. These charges constitute A 4(i) Costs and include: A. Network Integrated Transmission Service ("NITS") charges in accordance with the PJM OATT, Attachment H-16, Annual Transmission Charges- Virginia Electric and Power Company, based on PJM rates for calendar years 2013 and 2014; B. Annual PJM charges under the PJM OATT, Schedule 12, Transmission Enhancement Charges, (which are based upon the latest data available through PJM) for net transmission service enhancement costs/credits; C. PJM administrative charges calculated under the PJM OATT, Schedule 9, Administrative Services; and D. PJM charges under the PJM OATT, Schedule la for Scheduling, System Control, and Dispatch Service ancillary services. 3 3 The Company currently recovers these costs through its NITS rate and, therefore, does not have a separately stated rate in the PJM tariff for these ancillary services. 4

8 5. The Company also pays PJM charges for the costs of PJM demand response programs- i.e., the Economic Load Response Program and the Emergency Load Response Program- determined in accordance with Section 3.3A of Attachment K of the PJM OATT, the last section of Attachment K (labeled Emergency Load Response Program), and Attachments D and DD-1 of the PJM OATT. Both are demand response programs approved by PERC and administered by PJM and, as such, constitute A 4(ii) Costs. Accordingly, the Company has incurred, and will continue to incur, these A 4(i) and A 4(ii) Costs (collectively, the "Subsection A 4 Costs"), which are deemed by Subsection A 4 to be reasonable and prudent. 6. The Company made its initial filing for Commission approval of a Subsection A 4 RAC, designated Rider T, on March 31,2009 in Case No. PUE ("2009 Rider T Case"), seeking recovery of a total revenue requirement of $227.3 million for the rate year of September 1, 2009 through August 31, 20, partially offset by a $149.4 million reduction in base rates due to the removal of transmission rates then included in base rates, for an annual net increase in Rider T of $77.9 million. On June 29, 2009, the Commission issued its Final Order in that proceeding ("2009 Rider T Order") approving the proposed initial Rider T, with certain modifications. The Commission approved: the Company's proposed formula methodology for determining the revenue requirement for the next Rider T application; the Company's proposed deferral and true-up methodologies and proposed rate design; and the Company's recovery of Interruptible Load for Reliability ("ILR") costs. 4 The Commission excluded from Rider T recovery of five PJM administrative charges and the Company's proposed carrying costs on the deferred balance of Rider T. The Commission also directed certain modifications to the 4 The Commission also approved the recovery of deferred RTO costs approved by FERC in Docket No. ER and billed to the Company under PJM's Rate Schedule DRC ("DRC Costs"). However, as discussed in Paragraph 7, infra, consistent with the Commission's March 11, 20 Order Approving Stipulation and Addendum in Case Nos. PUE , et al. (including the 2009 Rider T Case), the Company agreed, and was directed, to waive recovery of the DRC Costs after December 31, 20 I 0. 5

9 Company's proposed rates applicable to Section customers ("Special Contract Rates"). 5 On July 24, 2009, the Company timely made its compliance filing with the Commission's Division of Energy Regulation (the "Division"), including the final initial Rider T designed to recover a revenue requirement of $217.4 million over the September 1, 2009 August 31, 20 rate year, which the Division accepted by letter dated August 14, On March 11, 20, the Commission entered its Order Approving Stipulation and Addendum in Case Nos. PUE , et al. (including the 2009 Rider T Case), under which, among other things, the Company was directed, as it had agreed, to waive recovery of DRC Costs after December 31, On March 31, 20, the Company made its first revised Subsection A 4 RAC filing in Case No. PUE ("20 Rider T Case"), seeking recovery of a total revenue requirement of $339 million, representing an annual revenue increase of $119 million for the rate year beginning September 1, 20. In addition to the formula methodology and deferral and true-up mechanisms approved in the 2009 Rider T Order, the Company proposed the updating of certain Subsection A 4 Costs that would be incurred by the Company for the period January 1 through August 31, 20 based upon known changes from corresponding components of the cost of service used to develop the Rider T rates then currently in effect. The Company and the Commission Staff agreed that the revenue requirement should be reduced to $337.9 million. In its Final Order issued June 29, 20 ("20 Rider T Order"), the Commission approved the agreed revised revenue requirement of $337.9 million and the methodologies and mechanisms proposed by the Company to develop it, including the update of certain Subsection A 4 Costs for known changes, as well as the Company's proposed cost allocation and rate design. On July 29, 5 The Commission found it reasonable to require the Company to (i) assess the energy-allocated cost of transmission as a per kilowatt-hour ("kwh") rate, and (ii) design the unit rate by dividing the energy-allocated transmission cost by the kwh consumption figure used in allocating that cost to the Special Contract Rates. 6

10 20, the Company timely made its compliance filing with the Division, including the final initial Rider T (including DRC Costs effective September 1, 20) and final revised Rider T (excluding DRC Costs effective January 1, 2011) designed to recover a revenue requirement of $337.9 million for the September 1, 20- August 31, 2011 rate year. The Division accepted the initial Rider Ton August 16, 20 and stated that the revised Rider T would be accepted for filing closer to its effective date. On December, 20, the Company resubmitted the revised Rider T, which the Division accepted on December 27, On May 2, 2011, the Company made its second revised Subsection A 4 RAC filing in Case No. PUB ("2011 Rider T Case"), seeking recovery of a total revenue requirement of $480.7 million, representing an annual revenue increase of $143.7 million for the rate year September 1, August 31, The Company's proposed revenue requirement used the same methodology as approved in the 20 Rider T Order with three exceptions. First, the DRC cost calculation (previously Formula Schedule 7) was removed from the revenue requirement formula, consistent with the discussion in footnote 4 and paragraph 7 above. Second, the 2009 true-up was adjusted to reflect a recalculation of the 2008 and 2009 demand allocation factors, which reduced the revenue requirement. Finally, the Company requested canying costs with respect to the cumulative monthly under- or over-recovery deferral balance under the true-up mechanism for Rider T. In its Final Order issued July 19, 2011 ("2011 Rider T Order"), the Commission approved a revenue requirement of $466.4 million, the removal of the DRC cost calculation, and the correction to the jurisdictional allocation factors, but denied the request for carrying costs. The Commission further approved the Company's proposed rate design and allocation of costs. On August 4, 2011, the Company timely made its compliance filing with the Division, including a revised Rider T designed to recover a revenue requirement 7

11 of $466.4 million over the September 1, August 31, 2012 rate year. The Division accepted the revised Rider T on August 18, On July 29, 2011, in Case No. PUE ("Standby Charge Proceeding"), the Company sought approval, pursuant to Va. Code F, 6 of a standby charge and methodology to be applicable to residential eligible customer-generators who engage in net energy metering under Va. Code and have a capacity that exceeds kilowatts ("kw"), but is not greater than 20 kw. As pertinent to this Application, with respect to the recovery of transmission-related costs, the Company proposed that the applicable eligible customergenerators pay the greater of the usage-based (per kwh) Rider T charge or an alternative Rider T demand-based (per kw) charge, resulting in a standby charge comprising the difference between the demand-based charge and the usage charge, but not less than zero. On November 23, 2011, Commission issued a Final Order which, among other things, approved the transmission-related standby charge as a component of Rider T to be effective on and after April1, On December 13, 2011, the Company submitted the approved revisions to the Rider T tariff, which were filed with the Clerk of the Commission and sent to the Division on December 14, On December 14, 2011, the Division accepted the revised tariffs. 6 Va. Code F currently provides: Any residential eligible customer-generator or eligible agricultural customergenerator who owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility with a capacity that exceeds kilowatts shall pay to its supplier, in addition to any other charges authorized by law, a monthly standby charge. The amount ofthe standby charge and the terms and conditions under which it is assessed shall be in accordance with a methodology developed by the supplier and approved by the Commission. The Commission shall approve a supplier's proposed standby charge methodology if it finds that the standby charges collected from all such eligible customergenerators and eligible agricultural customer-generators allow the supplier to recover only the portion ofthe supplier's infrastructure costs that are properly associated with serving such eligible customer-generators or eligible agricultural customer-generators. Such an eligible customer-generator or eligible agricultural customer-generator shall not be liable for a standby charge until the date specified in an order of the Commission approving its supplier's methodology. 8

12 11. On May 2, 2012, the Company made its third revised Subsection A 4 RAC filing in Case No. PUE ("2012 Rider T1 Case") seeking recovery of a total revenue requirement under Subsection A 4 of $372,900,596, representing an annual revenue decrease of $99,556,568 for the rate year September 1, August 31, In its application, the Company also requested an ongoing limited waiver of filing Schedule 46 as to FERC rulings and Schedule 46B materials that had been previously filed as part of Company applications in previous Subsection A 4 RAC proceedings, which was granted by the Commission in its May 9, 2012 Order for Notice and Hearing in the 2012 Rider T1 Case. The Company requested the implementation of Rider T1 to be an increment/decrement rider adjusting the recovery of Subsection A 4 costs that were combined into base rates as a result of the Company's 2011 Biennial Review. In its Final Order issued August 2, 2012 ("2012 Rider T1 Order"), the Commission approved implementation of Rider T1 as an increment/decrement rider. Subsection A 4 revenues and costs were also approved to be tracked separately in base rates, and the continued use of deferral accounting and true-ups of all Subsection A 4 revenues and costs was affirmed. The 2012 Rider T1 order approved Rider T1 in the decrement revenue requirement amount of ($99,556,568) to be effective for service rendered on and after September 1, On August 9, 2012, the Company timely made its compliance filing with the Division including Rider T1 designed to recover a decrement revenue requirement of ($99,556,568) over the September 1, August 31,2013 rate year. On August 17,2012, the Division accepted the revised tariffs. 12. On May 2, 2013, the Company made its fourth revised Subsection A 4 RAC filing in Case No. PUE ("2013 Rider T1 Case"), seeking recovery of a total revenue requirement under Subsection A 4 of $404,390,704, representing a $21,708,898 increase from the projected revenues associated with then-effective Subsection A 4 base rates determined for 9

13 the rate year and then-effective Rider Tl. Consistent with the approach approved by the Commission in the 2012 Rider T1 Case, the Company sought approval of a revised increment/decrement Rider T1 in the amount of ($80,967,667). The Staff recommended approval of the application, and on July 22, 2013, the Commission issued its Final Order ("2013 Rider T1 Order") approving the revised Rider T1 in the amount proposed by the Company. On August 13, 2013, the Company timely made its compliance filing with the Commission, including Rider T1 designed to recover a decrement revenue requirement of ($80,967,667). On August 22, 2013, the Division accepted the revised tariffs. 13. Consistent with the methodology approved in the 2012 and 2013 Rider T1 Cases, in order to recover its Subsection A 4 Costs on a timely and current basis from customers, as required by Subsection A 4, the Company seeks Commission approval in this Application of a Subsection A 4 revenue requirement for the Rate Year to be recovered through a combination of base rates and a revised increment/decrement Rider Tl. Rider T1 is designed to recover the increment/decrement between the revenues produced from the Subsection A 4 component of base rates and the new revenue requirement developed from the Company's Subsection A 4 costs for the Rate Year. 14. For the purposes of developing the revenue requirement for consideration in this proceeding, the Company has assumed an effective date of September 1, The Company proposes Rider T1 be effective for usage during the Rate Year, consistent with the rate year approved in the previous Rider T/T1 cases. The total Subsection A 4 revenue requirement to be recovered over the Rate Year is $538,019,256. This represents a $131,695,526 increase over the projected revenues associated with current Subsection A 4 base rates determined for the rate year and current Rider Tl. Consistent with the approach approved by the Commission in the 2012 and 2013 Rider T1 Cases, this Application seeks approval in this proceeding of a

14 revised increment/decrement Rider T1, in the increment amount of $49,752,283 for the Rate Year. 15. The Company does not propose for revised Rider T1 any changes from the cost allocation and rate design methodologies previously approved for Subsection A 4 RACs. III. DIRECT TESTIMONY AND SUPPORTING EVIDENCE 16. In support of its Application, the Company hereby files the direct testimony of three witnesses. A. David M. Wilkinson, Manager - Regulation in the Regulatory Accounting Department for the Company, will present the Company's revenue requirement for recovery of Subsection A 4 Costs for the Rate Year, including the increment/decrement to be recovered through Rider T 1; the formula mechanism and protocol for developing this revenue requirement for appropriate recovery of Subsection A 4 Costs; the update of certain Subsection A 4 Costs for known changes during the Update Period of January 1, 2014 through August 31, 2014; and the annual deferral and true-up mechanisms - all to assure timely and current recovery of Subsection A 4 Costs reflected in this revenue requirement, and to insure that customers will be charged only actual costs incurred, all consistent with the Commission's previous 2009, 20, and 2011 Rider T Orders and 2012 and 2013 Rider T1 Orders. B. James D. Jackson, Jr., Regulatory Consultant in the Company's Electric Transmission Policy Group, will provide an overview and description of PJM and the specific FERC-approved Subsection A 4 Costs reflected in the revenue requirement presented by Mr. Wilkinson. C. Paul B. Haynes, Director- Regulation for the Company, will present the Company's proposed methodology for design and calculation of retail rates for recovery of such Subsection A 4 Costs, including the Rider T 1 rates to be approved in this proceeding, using the 11

15 appropriate billing determinants as directed by Subsection A 4. IV. SUPPORTING SCHEDULE 46 AND REQUESTS FOR WAIVER OF SCHEDULE Rule 60 of the Rate Case Rules, 20 VAC , provides that an application filed pursuant to Subsection A 4 "shall include Schedules 45 and 46 as identified and described in 20 VAC , and which shall be submitted with the utility's direct testimony." 18. Filing Schedule 46 is divided into three sections: A. Filing Schedule 46A, sponsored by Company Witness Wilkinson, provides: a schedule of all projected costs by type of cost and year associated with Subsection A 4 costs for the Rate Year, including the increment for this proceeding, for which the Company is seeking Commission approval in this proceeding; all documents, contracts, studies, investigations, or correspondence that support such Subsection A 4 costs; the annual revenue requirement over the duration of the proposed Rate Year; 7 and a detailed description of all significant accounting procedures and internal controls that the Company will institute to identify all such Subsection A 4 costs. B. Consistent with the grant of an ongoing and limited waiver in the 2012 Rider T1 Case, Filing Schedule 46B, sponsored by Company Witness Jackson, provides an index offerc rulings, issued since the Company filed its application in the 2013 Rider T1 Case, approving the wholesale rates and costs for which the Company is now seeking recovery approval under Subsection A 4, including the docket/case number(s) of each such ruling. C. Filing Schedule 46C, sponsored by Company Witness Haynes, provides both the annual revenue requirement over the duration of the proposed RAC allocated by class, 7 Consistent with past practice, the Company has provided only one annual revenue requirement because it expects to update its Subsection A 4 RAC on an annual basis. 12

16 and detailed information relative to the Company's methodology for allocating the Rider T1 increment among rate classes, as well as the design of the class rates. D. The Company, for good cause shown, and pursuant to 20 VAC E, respectfully requests that the Commission waive, in part, the requirements of Rules 60 and 90 of the Rate Case Rules with respect to Filing Schedule 45 (Return on Equity Peer Group). Specifically, the Company does not herein request treatment of any costs that would require the Commission to determine an applicable return on equity and accordingly, the Company respectfully requests that the Commission waive, for good cause shown, the requirements of 20 VAC and 20 VAC with respect to submission of Filing Schedule 45 with this Application. Similar waiver requests from the requirements of Filing Schedule 45 were granted in the Company's 2009, 20, and 2011 Rider T cases and the 2012 and 2013 Rider T1 cases. 19. In the event that the Commission denies these waiver requests as they relate to Filing Schedule 45, the Company respectfully requests that the Commission (1) refrain from making a determination, as is its right under Rule D of the Rate Case Rules, 20 V AC D, that this filing is not in full compliance with the requirements of the Rate Case Rules; (2) allow the case to proceed according to the timetable established by this May 2, 2014 filing; (3) permit the Company to submit the required information within 15 business days, and (4) grant the Company such further relief as may be necessary or appropriate. V. COMPLIANCE WITH COMMISSION RULE 20. The Company's Rider T1 Application complies with the requirements contained in Rule of the Rate Case Rules, 20 VAC ("Rule "). In accordance with Rule A, the Company filed with the Commission on March 3, 2014 a notice of intent to file this Application under Subsection A 4. Copies of this Application, to the extent required by Rule J, along with the additional information required by Rule J, have been served upon the 13

17 persons addressed in that Rule. A complete copy of this Application has been served upon the Division of Consumer Counsel of the Office of the Attorney General, in conformity with Rule J. Also included with and following this Application, pursuant to Rule, is a table of contents of this filing, including exhibits and schedules. WHEREFORE, the Company requests the Commission to: (1) schedule this matter for hearing; (2) approve proposed revised Rider T1, for an adjustment to the recovery of Subsection A 4 Costs under base rates to allow for the Company's timely and current recovery of costs recoverable under Subsection A 4; (3) grant the Company's requests for waiver regarding Filing Schedule 45; and ( 4) grant the Company such further relief as may be necessary or appropriate. 14

18 Respectfully submitted, VIRGINIA ELECTRIC AND POWER COMPANY Lisa S. Booth William H. Baxter II Dominion Resources Services, Inc. 120 Tredegar Street, RS-2 Richmond, Virginia (804) (804) com Stephen H. Watts, II Joseph K. Reid, III Lisa R. Crabtree McGuire Woods LLP One James Center 901 East Cary Street Richmond, Virginia (804) (804) (804) mcguirewoods. com mcguirewoods. com mcguirewoods. com Counsel for Virginia Electric and Power Company May 2,

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20 DIRECT TESTIMONY OF DAVID M. WILKINSON ON BEHALF OF VIRGINIA ELECTRIC AND POWER COMPANY BEFORE THE STATE CORPORATION COMMISSION OF VIRGINIA CASE NO. PUE I. INTRODUCTION 2 Q. 3 4 A Please state your name, business address, and position with Virginia Electric and Power Company ("Dominion Virginia Power" or the "Company"). My name is David M. Wilkinson. I am a Manager- Regulation in the Regulatory Accounting Department for the Company. My business address is 701 East Cary Street, Richmond, Virginia A statement of my background and qualifications is attached as Appendix A. 8 Q. 9 A. 11 Please describe your areas of responsibility with the Company. I am responsible for the development of revenue requirement analyses and calculations used for rate setting purposes in rate proceedings before the State Corporation Commission of Virginia (the "Commission") and in other jurisdictions. 12 Q. Will you be introducing any exhibits with your testimony? 13 A. Yes. Company Exhibit No._, DMW, consisting of Schedule 1 Formula Schedules through and Schedule 2 - Formula Schedule 11, was prepared under my supervision and direction, and is accurate and complete to the best of my knowledge and belief. I am also sponsoring Filing Schedule 46A, Statements 1 through 13, included with the Company's Application pursuant to the Commission's Rules

21 1 2 Governing Utility Rate Applications and Annual Informational Filings, 20 V AC , et seq. 3 Q. 4 A Will Dominion Virginia Power present any other witnesses in this proceeding? Yes. Company Witness James D. Jackson, Jr. will discuss PJM Interconnection, L.L.C. ("PJM") and the Company's activities as a member of PJM. Additionally, Mr. Jackson will describe the nature of the charges and credits billed to the Company by PJM, as well as the rates and tariffs approved by the Federal Energy Regulatory Commission ("FERC") used to develop the costs under the Virginia Electric Utility Regulation Act (the "Act"), A 4 ("A 4" or "Subsection A 4") of the Code of Virginia ("Va. Code"), included for recovery under Subsection A 4. Company Witness Paul B. Haynes will testify regarding the allocation of the rate adjustment clause ("RAC"), Rider T1, the revenue requirement among the customer classes, and the rate design for recovering the revenue requirement through retail rates. 14 Q. 15 A Please describe the purpose of your testimony in this proceeding. My testimony will present the total revenue requirement of $538,019,256 that the Company is seeking to recover through a combination of base rates and Rider T 1 from Virginia jurisdictional retail customers under Subsection A 4, for the twelvemonth rate year beginning September 1, 2014 and ending August 31, 2015 (the "Rate Year"). This total revenue requirement includes an increment Rider T1 of $49,752,283, which will be discussed later in my testimony. The requested total revenue requirement of $538,019,256 represents an increase of $131,695,526 over the revenues projected to be produced during the Rate Year by the combination of the 2

22 1 2 base rate component of Subsection A 4 (the Company's former Rider T) and the Rider T1 rates currently in effect Q. A. Does your testimony include a discussion of the primary drivers of the increase of $133.6 million in the total revenue requirement requested in this Application over that approved in the previous Rider Tl Case? Yes, a detailed discussion is provided in my conclusion, beginning on page 41 below. The requested total revenue requirement in this Application of $538,019,256 also represents an increase of $133,628,552 over the total revenue requirement approved in Case No. PUE (the "2013 Rider T1 Case"). In summary, the increase in the total revenue requirement requested in this Application is primarily due to a significant increase in the cost of net investment in plant included in the Network Integrated Transmission Service ("NITS") charges billed by PJM, the Company's regional transmission entity, and based on PERC-approved tariffs. The increased charges associated with plant investment included in the NITS rate are partially offset by net transmission enhancement credits ("Transmission Enhancement Credits") from PJM, which represent amounts recovered for transmission projects from other members of PJM through shared cost responsibility. The increased charges for net investment in plant are found in the projected Subsection A 4 cost of service (the net of the NITS charges on Schedule 1, Formula Schedule 2, Page 1, Line 1 and net Transmission Enhancement Credits on Schedule 1, Formula Schedule 2, Page 1, Lines 16 and 18) and a component of the Update Period adjustment (discussed later in this testimony) on Schedule 1, Formula Schedule, Page 1, Line 15. 3

23 1 Q A. What is the primary reason for the increase in net investment in the transmission plant referenced in the response to the previous question? As discussed in the direct testimony of Company Witness Jackson, the Company has projected an increase in investment in transmission plant from December 31, 2013 to December 31, 2014 of over $800 million. More than $724 million of the projects are deemed to be either PJM Regional Transmission Expansion Plan ("RTEP") baseline reliability projects or other reliability projects. The Company is contractually obligated though the PJM Consolidated Transmission Owners Agreement to construct any reliability upgrade assigned to Dominion Virginia Power through the RTEP process by PJM. Also, PERC-approved and North American Electric Reliability Corporation ("NERC")-enforced reliability standards require that transmission owners ("TOs") remedy any potential reliability violation or face penalties up to one million dollars per day per violation. The Company is required to maintain the reliability of the transmission system. 15 Q A Would you provide an overview of the recovery mechanism that the Company is requesting in this proceeding? Consistent with the methodology approved in Case No. PUE (the "2012 Rider T1 Case") and the 2013 Rider T1 Case, the Company is requesting approval of a revised increment/decrement RAC, Rider T1, under Subsection A 4 to adjust the combination of the existing Subsection A 4 component of base rates and the current! y existing Rider Tl. The Rider T1 presented in this case is designed to recover the increment/decrement between the revenues produced from the current Subsection A 4 component of base rates and the new revenue requirement developed from the 4

24 Company's Subsection A 4 costs for the Rate Year presented in this Application. The Company will continue to identify and track separately Subsection A 4 costs and the revenues derived from both the Subsection A 4 component of base rates and Rider T 1, thus maintaining the dollar-for-dollar recovery of these costs and the associated deferral accounting consistent with Commission approval in prior Subsection A 4 cases. The Company proposes the approval of this revised Rider T 1 to recover the increment/decrement of total Subsection A 4 costs relative to the Subsection A 4 component of base rates. 9 Q. 11 A Please describe the Company's proposed mechanism for determining the revenue requirement associated with the revised Rider Tl RAC. As presented in my Schedule 2, Formula Schedule 11, the revenue requirement proposed to be recovered through the revised Rider T1 RAC in this proceeding is $49,752,283. This amount is determined by comparing: (1) the Company's total proposed revenue requirement of $538,019,256 for recovery of Subsection A 4 costs during the Rate Year; and (2) the $488,266,973 of revenues projected to be produced by the current Subsection A 4 component of base rates during the Rate Year. I will discuss the revenue requirement calculations in detail in Section III of my testimony Q. Are the Subsection A 4 costs that the Company proposes to recover in this case consistent with those approved by the Commission in the Company's previous Rider T and Rider Tl cases? 21 A Yes, consistent with Subsection A 4 and the Commission's Final Orders dated June 29, 2009 in Case No. PUE (the "2009 Rider T Case"); June 29, 20 in Case No. PUE (the "20 Rider T Case"); July 19, 2011 in Case No. 5

25 PUE (the "2011 Rider T Case"); August 2, 2012 in the 2012 Rider T1 Case; and July 22, 2013 in the 2013 Rider T1 Case, Dominion Virginia Power's Subsection A 4 revenue requirement in this proceeding is based upon: ( 1) costs for transmission services provided to the Company by PJM, the regional transmission entity of which the Company is a member, according to applicable rates, terms, and conditions approved by the PERC; and (2) costs charged to the Company associated with demand response programs approved by the PERC and administered by PJM. I will refer to all of these costs collectively as "Subsection A 4 costs" in my testimony. 9 In particular, I will define and discuss how the following categories of costs were utilized to determine the revenue requirement in this proceeding: 11 Current Subsection A 4 Costs These are the forecasted Subsection A 4 costs for the Rate Year sought to be recovered from Virginia retail customers. 14 True-up of Subsection A 4 Costs This is the difference between the actual revenues received from Virginia retail customers for the recovery of Subsection A 4 costs and the actual Subsection A 4 costs incurred during calendar year Update of Subsection A 4 Costs This is an update of certain Subsection A 4 costs that will be incurred by the Company during the period January 1, August 31, 2014 (the "Update Period") 6

26 1 2 based upon known changes to components of the cost of service used to develop the Subsection A 4 rates currently in effect. 3 Q. 4 5 A. Is Schedule 1, consisting of Formula Schedules 1 through, consistently numbered with that presented in the 2013 Rider T1 Case? Yes, it is. 6 Q A Please briefly describe key issues resolved by the Commission in its Final Orders in the 2009, 20, and 2012 Rider T/T1 cases, and reflected in the Company's current Application. In its Final Order in the 2009 Rider T Case, the Commission authorized three key components of Subsection A 4 recovery on a prospective basis. The first such component relates to the scope and types of costs recoverable at the retail level through Subsection A 4 tariff rates as provided by Subsection A 4. These costs, based on PERC-approved rates and billed by PJM, include: costs for transmission services; charges for new and existing transmission facilities; administrative charges; ancillary service charges designed to recover transmission costs; and costs associated with demand response programs. Second, the Commission authorized the deferral and true-up of Subsection A 4 costs incurred after the expiration of capped rates pursuant to Va. Code A 7 ("Subsection A 7"). Third, the Commission approved the use of a formula mechanism to develop the revenue requirement proposed to recover Subsection A 4 costs in future Subsection A 4 filings, including this current proceeding. 7

27 In addition to the three components noted above, this Application includes an update to certain Subsection A 4 costs for the Update Period based on known changes in certain components of the cost of service used to develop the Subsection A 4 rates currently in effect. The Commission first approved a revenue requirement change for an Update Period in its Final Order in the 20 Rider T Case. The change in the revenue requirement associated with the Update Period allows for recovery in rates of current cost levels arising from changes in FERC-approved rates and billing determinants that are known to occur during the Update Period. The resulting change in the revenue requirement associated with the Update Period allows for a more timely recovery of these known costs during the Rate Year consistent with the "timely and current" cost recovery provision of Subsection A Finally, in its Final Order in the 2012 Rider T1 Case, the Commission approved the implementation of Rider T1 to be an increment/decrement rider adjusting the recovery of Subsection A 4 costs in coordination with the Subsection A 4 component of base rates. Additionally, the Commission approved the separate tracking of Subsection A 4 revenues and costs in base rates and the continued use of deferral accounting and true-ups of all Subsection A 4 revenues and costs. 18 Q A. Is the Company requesting the same recovery mechanism in this proceeding as that approved in the 2012 and 2013 Rider T1 Cases? Yes, it is. 8

28 1 II. SUBSECTION A 4 COSTS 2 Q A Before discussing the development of the Company's proposed revenue requirement, please describe the nature of the Subsection A 4 costs sought to be recovered from Virginia jurisdictional retail customers in this proceeding. Subsection A 4 provides that certain costs incurred by the Company are deemed to be reasonable and prudent. This statutory provision also establishes broad guidelines for the recovery of these costs through retail rates. It reads in part as follows: The following costs incurred by the utility shall be deemed reasonable and prudent: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission, and (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member. Subsection A 4 also provides additional detail regarding specific costs that are recoverable through a RAC by directing that, upon petition by a public utility, "the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service, charges for new and existing transmission facilities, administrative charges, and ancillary service charges designed to recover transmission costs, shall be recovered on a timely and current basis from customers." The types of costs included in this filing are consistent with those previously approved for recovery in the Commission's Final Orders in the Company's 2009, 20, 2011, 2012, and 2013 Rider T/T1 cases The costs for services described in Subsection A 4 are derived from the FERCapproved tariff rates contained in the PJM Open Access Transmission Tariff ("PJM 9

29 OATT"). PJM applies these rates to billing determinants as detailed on Formula Schedule 2. PJM billing determinants are defined as the units of measure used as PJM' s bases for charging customers, including Dominion Virginia Power, for services. Examples of billing determinants include megawatts ("MW"), megawatthours ("MWh"), etc. The resulting costs incurred by the Company are then allocated to the Virginia jurisdiction based on a one coincident peak ("1CP") allocation factor, or the energy allocation factor, consistent with PJM's respective bases for charging the Company. The results of the foregoing calculations are the estimated current Subsection A 4 costs set forth in Formula Schedule 2. These resulting costs are the bases for the revenue requirement to be recovered through retail rates pursuant to Subsection A 4. Company Witness Jackson provides a more detailed explanation of how these Subsection A 4 costs are developed at PJM Listed below are the five components of costs approved by the Commission for recovery in the Company's previous Rider T and T1 cases, and the related PERCapproved PJM services associated with those costs. Formula Schedule 2 elaborates on these components and demonstrates how they are used to derive the cost of service and, ultimately, the revenue requirement for recovery of Subsection A 4 costs to be incurred during the Rate Year. Formula Schedules 3 through 8 provide support for the data utilized in Formula Schedule 2. Formula Schedule 9 calculates the cost of service and the revenue requirement for the true-up component of all Subsection A 4 costs incurred during calendar year 2013, and reports the revenues intended to recover those costs. Finally, Formula Schedule determines the cost of service and, ultimately, the revenue requirement for updating to certain known Subsection A 4

30 costs or rate changes incurred by the Company during the Update Period. The changes in the Update Period costs are included in this filing because the difference between the level of costs currently being billed by PJM, and the level of costs used to determine rates currently in effect, is now known for the Update Period. 5 The costs being recovered through this Subsection A 4 RAC include: ( 1) Costs for Transmission Service - The FERC-approved Annual Transmission Revenue Requirement ("ATRR") uses the NITS tariff rate that PJM charges Dominion Virginia Power as a transmission customer to determine its share of the costs associated with operation of, and investment in, the transmission system owned by Dominion Virginia Power and operated by PJM, less offsetting revenue credits for Firm and Non-Firm Point-to-Point Transmission Service, plus a Dominion Settlement Charge associated with FERC Docket No. EL (2) Charges for New and Existing Transmission Facilities - Transmission enhancement charges ("Transmission Enhancement Charges") from PJM to Dominion Virginia Power are for transmission projects approved in the PJM RTEP, whereby PJM identifies and directs the construction of enhancement or expansion projects, as required, to meet the demands for firm transmission service in the PJM region. Such projects often benefit customers of more than one utility. Therefore, the revenue requirements resulting from these designated projects are shared with other utilities based upon the benefits respectively provided. Net Transmission Enhancement Charges included on PJM's invoices include the allocated portion of other utilities' RTEP construction project revenue requirements for which Dominion Virginia Power is responsible, and provide credits for Dominion's own RTEP construction project revenue requirements for 11

31 which other TOs are responsible. Other Charges, which are presented in the Transmission Enhancement section of Formula Schedule 2, Page 1 of 2, Lines 20 and 21, include the Generation Deactivation charge and the Michigan - Ontario Interface PARs charge described in more detail by Company Witness Jackson. (3) Administrative Charges- These charges are billed to Dominion Virginia Power by PJM to recover the costs associated with operating PJM, and for funding various organizations through schedules included in the PJM OATT ( 4) Ancillary Service Charges Designed to Recover Transmission Costs- These charges are billed by PJM to recover Dominion Virginia Power's costs of Scheduling, System Control, and Dispatch Services. Dominion Virginia Power currently recovers these costs through its NITS rate and, therefore, does not have a separately stated rate in the PJM tariff for these ancillary services (5) Costs Associated with Demand Response Programs Approved by the FERC -The PJM Emergency Load Response Program is designed to provide a method by which curtailment service providers ("CSPs") may be compensated by PJM for customers' load reduction during an emergency event, while the PJM Economic Load Response Program is designed to provide an incentive for customers of CSPs to reduce consumption when PJM energy market prices are high. The PJM Economic Load Response Program offers customers of CSPs the opportunity to participate in the PJM Energy Interchange Market, and to receive energy payments by curtailing load or self-generating, based on the locational marginal price ("LMP"), at their discretion. 12

32 1 Q. 2 Does the Company expect changes during the Rate Year to any of the types of cost components and/or services previously approved for recovery through the 3 Subsection A 4 component of base rates or the Rider Tl RAC? 4 A. No, it does not. 5 III. DETERMINATION OF THE REVENUE REQUIREMENT 6 Q. How did the Company develop the revenue requirement to recover the 7 8 A Subsection A 4 costs presented in this proceeding? As stated previously and consistent with previous Rider T and T1 cases, the three main components of the revenue requirement proposed by the Company in this proceeding are: ( 1) current Subsection A 4 costs for the Rate Year of September 1, 2014 through August 31, 2015 in the amount of $448.2 million; (2) the true-up of the difference between the actual revenues received and the actual Subsection A 4 costs incurred during calendar year 2013 in the amount of $39.7 million; and (3) an update of Subsection A 4 costs for the Update Period based upon known rates, terms, and conditions applied to known billing determinants in effect during the Update Period in the amount of $50.0 million. More specifically: (1) The Subsection A 4 costs estimated to be incurred during the Rate Year are determined by populating the portion of the Commission-approved revenue requirement formula in Formula Schedule 2 with the applicable PERCapproved rates from tariffs in effect on the date of this Application. In addition, the Company has populated the Subsection A 4 formula with projected billing determinants for the Rate Year, as well as the most current 13

33 jurisdictional allocation factors for cost assignment. These annual formula inputs are further supported by Formula Schedules 3 through 8. The Subsection A 4 costs estimated to be incurred over the Rate Year are discussed in greater detail in Section IV of my testimony (2) Also included in this Application is a true-up of costs, as approved in previous Rider T and T1 cases, which compares Subsection A 4 costs actually incurred during calendar year 2013 to the Subsection A 4 revenues recovered from Virginia jurisdictional retail customers during calendar year Amounts invoiced to the Company for transmission services and demand response programs provided by PJM, the actual demand allocation factor used by PJM for assigning costs, the energy allocation factor applicable for 2013, the credit for amounts previously recovered through prior update adjustments, the remaining annual amortization of unrecovered costs at August 31, 2012 over the period January through August 2013, and the annual amortization of unrecovered costs at August 31, 2013 over the period September through December as well as the revenues intended to recover these costs incurred on behalf of Virginia jurisdictional retail customers - are all input into Formula Schedule 9 to calculate the true-up of 2013 Subsection A 4 costs. The various cost components included in Formula Schedule 9 are discussed in greater detail below in Section V of my testimony (3) The last component of the Company's revenue requirement proposal, as presented in Formula Schedule, calculates an additional revenue requirement resulting from updating certain known Subsection A 4 costs or 14

34 rate changes occurring during the Update Period. This update is necessary to facilitate the "timely and current" recovery of such costs as required by Subsection A 4. Formula Schedule reflects known changes in the levels of certain Subsection A 4 costs occurring during the Update Period by comparing the Update Period level of these costs to the levels of corresponding Subsection A 4 costs used to develop the cost of service underlying current Subsection A 4 rates from the 2013 Rider T1 Case. The Company is updating only Subsection A 4 cost changes that are known at the time of filing this Application to be in effect during the Update Period, and is not attempting to recalculate or re-estimate all Subsection A 4 costs. For this current Application, the Company proposes to recover the known Update Period cost changes for NITS and Transmission Enhancement Charges/Credits. The update of Subsection A 4 costs during the Update Period is discussed in more detail in Section VI of my testimony. 15 Q A Please summarize how the revenue requirement is developed in this proceeding for recovery of the Company's Subsection A 4 costs. The total cost of service in this proceeding is derived by applying the actual FERC tariff rates charged by PJM under the PJM OATT to the Company in its capacity as a load-serving entity- i.e., as the Dominion Load Serving Entity ("DOMLSE"), the entity that is responsible for providing electric energy to Virginia jurisdictional retail customers in Dominion Virginia Power's zone (the "Dom Zone") within PJM These FERC tariff rates are applied to billing determinants to calculate Dominion Virginia Power's Subsection A 4 costs, with five exceptions: (1) credits for Point-to- 15

35 Point Transmission Service; (2) Dominion Settlement Charges; (3) Generation Deactivation charges; (4) Michigan- Ontario Interface PARs charges; and (5) charges for PJM' s demand response programs. Due to the variable nature of these costs, the Point-to-Point Transmission Service credits, the Generation Deactivation charges, the Michigan - Ontario Interface PARs charges, and the demand response programs charges are based upon the actual billings to DOMLSE per the monthly PJM invoices for the twelve months ending January 31,2014. The Dominion Settlement Charges are a fixed monthly amount determined by the settlement approved in FERC Docket No. EL All such costs are then allocated to the Virginia jurisdiction using the appropriate demand or energy allocators The Rate Year demand allocation factor for transmission capacity is derived from a 1CP allocation methodology, which is used by PJM for calendar year 2014 billing purposes. This demand allocation factor is based on the Virginia retail jurisdiction's contribution to the Dom Zone's or to DOMLSE's annual peak load, whichever is appropriate, for PJM's fiscal year ended October 31, The estimated Rate Year energy allocation factor is consistent with the measurement of energy among all allocation methodologies and is based upon the Company's calendar year 2013 system operating results, subject to true-up. For example, NITS costs are allocated to Virginia jurisdictional customers based upon the demand allocator MW, while the majority of PJM administrative costs are allocated to Virginia retail customers based upon the energy allocator MWh. In short, the Company uses the same bases for allocation to Virginia jurisdictional retail customers that PJM uses to allocate to Dominion Virginia Power- either MW or MWh- 16

36 1 2 consistent with the manner in which its previous Rider T and T 1 cases were filed with and approved by the Commission. 3 IV. RECOVERY OF PROJECTED RATE YEAR COSTS 4 Q. 5 6 A Please discuss the Company's approved formula to recover Subsection A 4 costs incurred during the Rate Year from its Virginia jurisdictional customers. Per the Commission's Final Orders in previous Rider T and T1 cases, Dominion Virginia Power has estimated the Rate Year level of Subsection A 4 costs by populating the formula with amounts derived from FERC-approved rates available at the time of filing this Application. Dominion Virginia Power has included in the formula each of the components necessary to appropriately estimate the Subsection A 4 costs for the projected Rate Year in this proceeding, subject to Commission review and approval. The inputs used to calculate the forward-looking Rate Year consist of actual tariffs and rates, billing determinants for the Rate Year, and the most current jurisdictional allocation factors for cost assignments. 15 Q. 16 A Please describe how the formula works. Formula Schedule 2 estimates the revenue requirement for costs to be incurred during the Rate Year according to the same cost categories described in Subsection A 4 - which were approved by the Commission in previous Rider T and T1 cases- and discussed earlier in my testimony. These costs include: costs for transmission service, charges for new and existing transmission facilities (transmission enhancement), administrative charges, transmission-related ancillary service charges (included in the NITS rate), and costs ofpjm-administered demand response 17

37 programs. Each cost category is supported by: (1) rates from the PJM OATT approved by the FERC and posted on the PJM website, < (2) Rate Year billing determinants based upon projections posted on the PJM website, as developed by the Company or derived from historical PJM invoices; (3) historical actual dollar amounts supported by PJM invoices; 1 and/or (4) a PERC-approved settlement agreement in the case of the Dominion Settlement Charges. The formula calculates a revenue requirement by multiplying these relevant billing determinants by the applicable tariff rates or by forecasting certain items based on historically incurred costs or a PERC-approved settlement agreement. Costs are then allocated to Virginia jurisdiction retail customers using the same allocation methods actually used by the FERC Q. Please describe the calculation of the revenue requirement in this proceeding for Subsection A 4 costs incurred during the Rate Year for each of the cost components described above. A. Formula Schedule 2 presents the formula, along with all of the necessary cost components, for calculating the revenue requirement for each component of Subsection A 4 costs. The first component of the formula starts with the costs for transmission services, otherwise known as the NITS charges NITS costs are derived from the ATRR billed by the transmission provider (PJM) based upon the current NITS tariff rate. The billing determinants applied to the NITS rate for calendar year 2014 network integrated transmission services are based upon 1 Point-to-Point Transmission Service Credits, Generation Deactivation charges, Michigan- Ontario Interface PARs charges, and Economic Load Response Program and energy-related Emergency Load Response Program costs are based on actual historical amounts derived from PJM invoices. 18

38 transmission demands at the time of the 1CP for the Dom Zone during the twelve months ending October 31, 2013 (PJM's fiscal year). Using PJM's terminology, this is referred to as the Network Service Peak Load ("NSPL"). Transmission demand for the customers serviced by DOMLSE totaled 16,344.6 MW at the time of the 2013 Dom Zone 1 CP peak. This MW level represents the PERC-approved billing determinant that is being used by PJM to bill DOMLSE for calendar year 2014, and includes the transmission demands for the Company's Virginia jurisdictional customers. 9 Q. A Please continue your discussion of the NITS rate. The annual NITS rate of $35,936. per MW is applied to the DOMLSE transmission demands described above to calculate the NITS expense. The NITS expense is reduced by the Firm and Non-Firm Point-to-Point Transmission Service revenue credits (reported on Formula Schedule 3) and increased by the annual level of the Dominion Settlement Charge. The net result equates to a DOMLSE revenue requirement of $580.0 million. The Virginia jurisdictional revenue requirement for this component, after allocation, is $478.9 million based upon the transmission demands of Virginia jurisdictional retail customers coincident with the Dom Zone peak demand. 19 Q A. 23 How has Dominion Virginia Power projected the revenue requirement necessary to recover the second component of costs- i.e., the Transmission Enhancement Charges billed by PJM? The Transmission Enhancement Charges consist of three components. The first is a charge that occurs when PJM bills Dominion Virginia Power for its allocated portion 19

39 of the revenue requirements for RTEP projects constructed by all TOs in PJM, including the Company's own projects, that benefit the Company and that the FERC has approved for recovery. The second component is a credit that consists of the revenue requirements for all RTEP projects constructed by the Company and billed by PJM per Schedule 12 of the PJM OATT, and recovered from all TOs within PJM. This credit fully offsets the project costs included in the NITS rate, so that the net charge to Virginia jurisdictional retail customers is the amount that PJM bills the Company for (1) Dominion Virginia Power's own RTEP projects allocated to Virginia jurisdictional customers, and (2) Dominion Virginia Power's allocated share of costs from the RTEP projects of every other TO within PJM allocated to Virginia jurisdictional customers. The third component is the Other category which includes the Generation Deactivation charges and the Michigan - Ontario Interface PARs charges PJM publicly posts on its website the PERC-approved formulas used by each TO within the PJM service territory to calculate the ATRR and the resulting NITS rate. Specifically, these formulas can be found in the Markets & Operations, Transmission Services, and Formula Rates section ofpjm's website. An attachment to each of these formulas contains a listing of individual RTEP projects and the associated annual revenue requirements for these projects. Also publicly posted on the PJM website, per Schedule 12 of the PJM OATT, are the allocation ratios necessary to split the revenue requirement for each such RTEP project among all TOs within PJM Dominion Virginia Power has calculated the revenue requirement associated with Transmission Enhancement Charges by incorporating the latest available RTEP 20

40 1 2 3 project revenue requirement (posted to the PJM website for each TO as of March 1, 2014), multiplied by the Dominion Virginia Power allocation ratio located in Schedule 12 of the PJM OATT PJM billings for RTEP projects, termed Transmission Enhancement Charges (developed on Formula Schedule 4) on the PJM invoices, consist of the sum of the revenue requirements associated with all TO projects attributable to the Dom Zone, including the Company's own projects. As shown on Formula Schedule 2, using the latest available data, this translates to a Virginia jurisdictional revenue requirement of $57.6 million. The Transmission Enhancement Credits (developed on Formula Schedule 5 and allocated to the Virginia jurisdiction on Formula Schedule 2) are the sum of all of the recoveries of the revenue requirements for the Company's own RTEP projects as billed per Schedule 12 of the PJM OATT, which reduces the revenue requirement by ($3.5 million). The Other component of the Transmission Enhancement Charges includes a Generation Deactivation charge of $0.5 million and a Michigan- Ontario Interface PARs charge of $0.2 million on a Virginia jurisdictional basis. As previously stated, these two costs are forecasted based on the actual amount included on the PJM invoices for the twelve months ended January This produces a net Virginia jurisdictional Transmission Enhancement Credit of ($45.1 million). 21

41 Q. A. A correction has been made in the determination of the Transmission Enhancement Credits on Formula Schedule 5 in this Application. Please explain this correction and why it was made. In the 2013 Rider T1 Case and previous Rider T/T1 cases, Formula Schedule 5listed the annual revenue requirements for transmission enhancement projects owned by the Company from Schedule 12 of the PJM OATT ("Schedule 12 Projects"). The total of the annual revenue requirements for these projects was taken to Formula Schedule 2 and allocated to the Virginia jurisdiction as the Transmission Enhancement Credits. In these previous cases, the annual revenue requirements for each of these Schedule 12 Projects that were listed on Formula Schedule 5 incorrectly included the impact of an incentive return on equity ("ROE"), to the extent any had been approved by the FER C. Because the purpose of these Transmission Enhancement Credits on Formula Schedule 2 is to offset the charges for these projects embedded in the NITS charges on Formula Schedule 2, the NITS rate used to develop the NITS charges on Formula Schedule 2 has not included the impact of incentive ROEs on Schedule 12 Projects. Hence, in the 2013 Rider T1 Case and previous Rider T/T1 cases, the Transmission Enhancement Credits incorrectly reduced the total revenue requirement by an amount that should not have been included in the revenue requirement. Previously, the issue has been corrected by the mechanics of the true-up calculation. In particular, Virginia jurisdictional customers have paid an understated projected portion of the revenue requirement for NITS charges. However, the costs that have been understated in the projections have been included in the calendar year true-ups through the inclusion of actual NITS charges and Transmission Enhancement Credits from the appropriate 22

42 PJM invoices. Hence, from a recovery perspective, this has been a timing issue. The Company proposes to correct the timing of the recovery in the projected Subsection A 4 costs in this proceeding, and prospectively, by the corrections made to Formula Schedule 5, which subtract the impact of the incentive ROEs on Schedule 12 Projects, as appropriate, by taking the projected annual revenue requirement without the incentive ROEs to Formula Schedule 2 as Transmission Enhancement Credits. This correction will provide timely recovery in the proper rate year and minimize volatility in future true-ups Q. A. Please describe how Dominion Virginia Power will recover the third component of Subsection A 4 costs sought in this case- the PJM administrative charges approved in previous Rider T and Tl cases. The PJM administrative charges requested in this proceeding consist of charges for the following administrative services: control area and dispatch, financial transmission rights ("FTRs"), regulation and frequency response, and planned costs for the Advanced Second Control Center. All of these costs that the Company has incorporated for recovery through this proceeding are consistent with those that the Commission has approved for recovery in previous Rider T and T1 cases. For projected PJM administrative charges to be recovered in this proceeding, the Company uses billing determinants and rates provided in various subsections of Schedule 9 of the PJM OATT- i.e., the same rates and billing determinants actually used by PJM to bill the Company for those respective administrative charges. The rates contained in the PJM OATT that are used to bill for PJM administrative charges are supplemented quarterly and posted publicly on the PJM website. In short, these 23

43 subsections from Schedule 9 of the PJM OATT contain the specific types of billing determinants and rates necessary to calculate the total amount of the administrative charges recoverable in a Subsection A 4 proceeding per the Commission's Final Orders in the Company's previous Rider T and T1 cases The rates supporting the PJM administrative charges component of the Subsection A 4 costs are based on the First Quarter 2014 updates to these rates currently included in Schedule 9 of the PJM OATT for calendar year i.e., those rates used for billing purposes in the first quarter of The majority of dollars included for recovery through the Subsection A 4 proceeding for PJM administrative charges is based upon the Company's projections of billing determinants for the Rate Year. When projecting billing determinants for the remaining administrative charges, Dominion Virginia Power uses billing determinants based upon actual PJM billing history for the twelve months ending 1 anuary 31, 2014 as a proxy for the Rate Year. The allocation basis used to distribute PJM administrative charges from DOMLSE to the Virginia jurisdiction is consistent with the billing determinants used by PJM to bill the Company for these same administrative charges. Dominion Virginia Power uses an energy allocation factor for costs billed by PJM based on a number of MWh or FTR bid obligations/options. I will now discuss the revenue requirement associated with each such subsection of PJM administrative charges in more detail. 20 Schedule 9-1, Control Area Administrative Service PJM charges DOMLSE and other PJM members that use Point-to-Point Transmission Service and NITS a yearly administrative fee based on the number of MWh delivered 24

44 1 by PJM on behalf of users, including DOMLSE. Dominion Virginia Power has 2 projected the level of MWh to be delivered for the Rate Year in this case. The Yearly 3 Control Area Administration Service Rate in PJM OATT Schedule 9-1, reflecting the 4 first quarter of 2014 update, is applied to these annual MWh for the Rate Year to 5 calculate the projected costs for this PJM administrative fee of $15.0 million for 6 DOMLSE. Energy allocation factors are then applied to this figure to produce a 7 Virginia jurisdictional revenue requirement of $11.9 million. 8 Schedule 9-2, Financial Transmission Rights Administration Service 9 FTR Service Rate, Component 1 PJM charges DOMLSE and other PJM members that are allocated FTRs an 11 administrative fee based on all FTRs awarded by PJM, using the amount of the 12 Company's owned MW capacity times the number of hours per year. The result is 13 the MWh billing determinant. For the Rate Year, the Company uses the MWh billing 14 determinant based upon PJM's billing history for the twelve months ending January 15 31, 2014 for this fee. The FTR Service Rate, Component 1 in PJM OATT Schedule , which reflects the first quarter of 2014 update, is applied to these annual MWh 17 and produces DOMLSE costs in the amount of $240,402 for this administrative 18 service fee. Energy allocation factors are then applied to determine a Virginia 19 jurisdictional revenue requirement of $190,

45 1 FTR Service Rate, Component 2 2 PJM charges an administrative fee to DOMLSE and other PJM members that 3 participate in PJM's annual and monthly FTR auctions. This fee is based on the 4 number of hours of FTR obligations/options purchased by the Company. For the 5 Rate Year, the Company uses the number of hours of FTR Obligations and the FTR 6 Options purchased (multiplied by five) billing determinants based upon PJM's billing 7 history for the twelve months ending January 31, 2014 in determining this fee. The 8 FTR Service Rate, Component 2 in PJM OATT Schedule 9-2, reflecting the first 9 quarter of 2014 update, is applied to the annual hours of FTR Obligations/Options to produce DOMLSE costs in the amount of $4,855 for this administrative service. 11 Formula Schedule 2, Page 1, Column 6, Lines show the elements of this total 12 amount. Energy allocation factors are then applied to determine a Virginia 13 jurisdictional revenue requirement of $3,852, as shown by adding Lines of 14 Formula Schedule 2, Page 1, Column Schedule 9-4, Regulation and Frequency Response Administration Service 16 Component 1 17 PJM charges DOMLSE and other PJM members an administrative fee yearly based 18 on the MWh required for a user's "hourly system regulation objective" (defined by 19 PJM as 1% of maximum daily load). For the Rate Year billing determinants, the 20 Company uses the MWh billed to DOMLSE based upon PJM's billing history for the 21 twelve months ending January 31, 2014 in determining this fee. The Regulation and 22 Frequency Administration Service Rate in PJM OATT Schedule 9-4, reflecting the 26

46 first quarter of 2014 update, is applied to these annual MWh to calculate DOMLSE costs for this PJM administrative fee in the amount of $127,212. Energy allocation factors are then applied to produce a Virginia jurisdictional revenue requirement of $0, Component PJM annually charges an administrative fee based on the number of MWh of the Company's scheduled hourly regulation. For the Rate Year billing determinants, the Company uses the MWh of scheduled hourly regulation based upon PJM's billing history for the twelve months ending January 31, 2014 in determining this fee. The Regulation and Frequency Administration Service Rate in PJM OATT Schedule 9-4, reflecting the first quarter of 2014 update, is applied to these annual MWh to calculate Dominion Virginia Power's costs for this PJM administrative fee in the amount of $252,925. Energy allocation factors are then applied to these costs to produce a Virginia jurisdictional revenue requirement of $200, Schedule 9-6, Formula Rate for Cost of Advanced Second Control Center PJM annually charges Dominion Virginia Power and other users of PJM services an administrative fee based on actual costs incurred for the operation of, and investment in, the Advanced Second Control Center by way of additional charges to each customer billed on PJM OATT Schedules 9-1 through 9-5. Dominion Virginia Power estimates these costs based on billing determinants for Schedules 9-1 and 9-3 because the billing determinants for these schedules are the bases for over ninety percent of the costs billed by PJM, and because the total charge is relatively small. Dominion 27

47 Virginia Power projects both the MWh delivered to DOMLSE (under Point-to-Point Transmission Service and NITS for the Rate Year) and the MWh generated by the Company (which are delivered to the transmission system for the Rate Year). These billing determinants are the same MWh used for projecting costs under Schedules 9-1 and 9-3 of the PJM OATT. The rates approved by the PERC for this fee are calculated using PJM OATT Schedule 9-6 from the PJM website. These rates are then applied to the Company's projected Rate Year MWh described above to calculate the Rate Year costs for this PJM administrative fee in the amount of $2.5 million, as shown in Formula Schedule 2, Page 1, Column 6, Lines Energy allocation factors are applied to these costs to produce a Virginia jurisdictional revenue requirement of $2.0 million, which is the sum of Formula Schedule 2, Page 1, Column 9, Lines Schedule 9-FINCON, Financial Committee Retained Outside Consultant Dominion Virginia Power is not estimating this cost due to a lack of billing activity by PJM during the most recent twelve-month period, and because any potential charges are expected to be small. The actual costs for this fee, if any, will be recovered through the true-up mechanism in a future Subsection A 4 proceeding. 18 Q A. 21 What is the overall revenue requirement impact of these PJM administrative charges sought to be recovered in this proceeding? The total sum of the PJM administrative charges described above produces a Virginia jurisdictional revenue requirement of $14.4 million for this Subsection A 4 28

48 1 2 proceeding. Again, these costs are consistent with the administrative charges approved by the Commission for recovery in the previous Rider T and T1 cases Q. A. The last component of formula costs to be recovered in this proceeding is the demand response programs, which include both the Economic and the Emergency Load Response Programs administered by PJM. Please describe the method used by the Company to develop the energy-related portion of the Economic and Emergency Load Response Program costs. Because participation in these programs can fluctuate from year to year, the resulting costs can also vary dramatically. As a result, the Company is unable to forecast the costs of these programs because of the inherent variable nature of the charges. Therefore, the Economic and Emergency Load Response Program costs included in the Company's cost of service for the energy-related costs of the programs are set at the actual level of costs for the twelve-month period February 2013 through January 2014, consistent with previous Rider T and T1 cases. The components of Subsection A 4 costs related to the Economic and Emergency Load Response Programs are energy-related costs. As such, they are apportioned using an energy allocation factor for purposes of estimating Subsection A 4 costs. Formula Schedule 2, Page 1, Column 9, Line 35 shows an increase to the Virginia jurisdictional revenue requirement of $95,026 for these programs. 29

49 Q. The Company's Application contains both charges and credits associated with its participation in the PJM Economic Load Response Program. Please describe the Company's treatment of these charges and credits in this Subsection A 4 proceeding. 5 A The Company, for its CSP account ("DOMCSP"), elected to participate in the Economic Load Response Program and receive energy payments based on the LMP of energy when demand and the associated LMP were extremely high. DOMLSE receives a charge when the Company participates, while DOMCSP receives an equal and offsetting credit. Both the charges and the credits are included in this current proceeding Q. Please summarize the calculation of the projected Rate Year level of Subsection A 4 costs that Dominion Virginia Power seeks to recover through application of its previously approved formula. 14 A Unless otherwise noted, each cost item described earlier in my testimony is separately listed as a line item in Formula Schedule 2. Each line item contains a description of the pertinent costs, a description of the billing determinant used, the type of billing determinant (e.g., energy, demand, hour, months, amounts, etc.), the DOMLSE billing determinant, the allocation factor designed to produce a Virginia jurisdictional level of costs, the rate derived from the PJM OATT and/or the PJM website service rate update, and the resulting revenue requirement. W orkpapers and supporting documents are included in Filing Schedule 46A, Statement 12, reflecting the determination of these allocation factors, the DOMLSE billing determinants, and the PJM OATT rates. 30

50 The Virginia jurisdictional projected revenue requirement for the Rate Year Subsection A 4 costs in this proceeding totals $448.2 million as shown on Column 9, Line 36 in Formula Schedule 2. In addition to these costs projected over the Rate Year, the revenue requirement also includes the true-up component of actual 2013 calendar year costs as compared to the actual revenues designed to recover those costs, and an update for the difference between known Subsection A 4 costs that will be incurred by the Company for the Update Period and those same components of the cost of service used to develop the Subsection A 4 rates currently in effect. I will next discuss the true-up component of the revenue requirement, followed by a detailed discussion of the update calculation. 11 v. TRUE-UP OF CALENDAR YEAR 2013 COSTS 12 Q A How does the Act ensure that Virginia jurisdictional retail customers are charged only the Subsection A 4 costs incurred on their behalf? The Act protects both customers and the Company from overpayment or underrecovery, respectively, by allowing for the deferral of the difference between the actual Subsection A 4 costs incurred and the current revenues designed to recover those costs. Any difference between these amounts is to be either credited to (or recovered from) Virginia jurisdictional retail customers in a future Subsection A 4 filing through the true-up mechanism. 31

51 1 Q. 2 3 A What did the Commission's order in the 2009 Rider T Case conclude in this respect? In the 2009 Rider T Case, the Commission stated that the Act provides for the deferral and future recovery or refund of the difference between incurred Subsection A 4 costs and the revenues intended to recover those costs. This approach was reconfirmed in the 2012 Rider T1 Case for use in recovery of Subsection A 4 costs through a combination of the Subsection A 4 component of base rates and Rider T 1. Formula Schedule 9 calculates the amount of the calendar year 2013 true-up adjustment. Q Please discuss the true-up mechanism designed to recover the actual amount of Subsection A 4 costs incurred during 2013, and identify the sources of the costs and revenues used for calculating this true-up A. Dominion Virginia Power's true-up formula, which is set out in Formula Schedule 9, has been populated with actual Subsection A 4 costs taken directly from the Company's monthly PJM invoices for the calendar year ended December 31, These costs have been allocated to Virginia jurisdictional customers based on either demand or energy factors. The transmission demand allocator is based on the 1CP for the twelve months ended October 31, 2012, consistent with the allocator utilized by PJM when billing the Company in calendar year The energy allocator is based on the delivery of MWh to DOMLSE for calendar year 2013, also consistent with the method utilized by PJM The actual costs shown on the 2013 PJM invoices included in Filing Schedule 46A were allocated to Virginia jurisdictional retail customers and then compared to the 32

52 revenues actually collected from those customers based upon the rates in effect and approved in the 2012 Rider T1 Case for the period January 1 through August 31, 2013, as well as the revenues generated by the rates in effect and approved in the 2013 Rider T1 Case for the period September 1 through December 31, Q. 6 7 A. 8 9 Please describe each component of the true-up calculation presented in Formula Schedule 9. For convenience and ease of reference, I will discuss each component of the Subsection A 4 costs and retail revenues included in the true-up calculation in detail in the order that they appear on Formula Schedule 9. All of the Subsection A 4 costs identified previously in my testimony are included in this true-up mechanism. 11 Transmission Service Charges The first component of Subsection A 4 costs to be trued-up is the NITS charge billed to the Company by PJM. The amounts for the NITS charge, the revenue credits for both Firm and Non-Firm Point-to-Point Transmission Services, and the Dominion Settlement Charge were taken directly from the PJM invoices billed to DOMLSE in each month of calendar year These monthly amounts were then allocated to Virginia jurisdictional customers using the appropriate 2012 DOMLSE transmission demand allocation factor to derive the NITS charges subject to recovery during the year For the twelve months ending December 31,2013, the total amount of NITS charges for transmission service, including the Dominion Settlement Charge, net of revenue credits for Point-to-Point Transmission Service billed to the Company by PJM 33

53 1 2 amounted to $379.0 million on a Virginia jurisdictional basis, as shown in Formula Schedule 9, Column 16, Line 9. 3 Transmission Enhancement Charges/Credits The second component of Subsection A 4 costs subject to true-up is the net Transmission Enhancement Charges/Credits billed to DOMLSE per the monthly invoices from PJM. Transmission Enhancement Charges/Credits consist of several components. The first is a charge that PJM bills the Company for the Company's allocated portion of the costs associated with RTEP projects (subject to Schedule 12 of the PJM OATT) constructed by all TOs within PJM, including the Company's own projects. These charges are referenced on Formula Schedule 9, Line Another component represents a credit comprising the revenue requirements for all RTEP projects subject to Schedule 12 of the PJM OATT constructed by the Company. Formula Schedule 9, Line 11 shows these credits from the PJM bill by month There are two additional PJM charges included in the 2013 Transmission Enhancement section of Formula Schedule 9. The Michigan-Ontario Interface PARs charges, as shown in Formula Schedule 9, Line 12, are taken directly from the PJM invoices. Also, the Generation Deactivation charges, as shown on Formula Schedule 9, Line 13, are also taken directly from the PJM invoices. These two charges are described more fully in the direct testimony of Company Witness Jackson. 34

54 The net monthly amount of Transmission Enhancement Charges/Credits is then allocated to Virginia jurisdictional customers using the 2012 DOMLSE transmission demand allocation factor. Note, however, that this allocation is based on a system amount representing charges to DOMLSE, whereas the factor used to allocate these same net Transmission Enhancement Charges/Credits for the estimated Rate Year is based on a system amount representing the Dom Zone. This is because net Transmission Enhancement Charges/Credits are billed to DOMLSE per the PJM invoices, while the charges derived from the outstanding PJM OATT tariff represent Dom Zone cost levels. For the twelve months ending December 31, 2013, the net amount of Transmission Enhancement Charges/Credits attributed to the Company by PJM and subject to true-up amounted to a ($17.0 million) credit on a Virginia jurisdictional basis. Formula Schedule 9, Line 15 displays the 2013 monthly breakdown of the net Transmission Enhancement Charges/Credits. 14 PJM Administrative Charges The third component of Subsection A 4 costs to be trued up is the amount of applicable PJM administrative charges billed to the Company from January 1 through December 31,2013. The PJM administrative charges billed to DOMLSE can be referenced on Lines of Formula Schedule 9. The total PJM administrative charges for the twelve months ending December 31,2013 are $16.1 million and are located in Column 16, Line 23. The total DOMLSE amounts were then allocated to Virginia jurisdictional customers using the 2013 energy allocation factor to derive the actual calendar year PJM administrative charges subject to true-up totaling $12.7 million, as shown on Formula Schedule 9, Column 16, Line

55 1 Demand Response Programs The final components of Subsection A 4 costs subject to true-up are the charges for the PJM Economic and Emergency Load Response Programs. As previously discussed, the Economic Load Response Program consists of energy payments to participants for voluntary reductions in consumption based on economic conditions, such as the price of energy in the PJM energy markets, while the Emergency Load Response Program has the potential for both energy and capacity payments for participants The energy charges for both the Economic and Emergency Load Response Programs are taken from monthly PJM invoices and included on Line 25 of Formula Schedule 9. The total amount of net energy charges received by the Company for both the Economic and Emergency Load Response Programs in 2013 was $76,854. The energy charges and credits related to the emergency events that occurred in calendar year 2013, and the charges and credits related to PJM's testing of the Emergency Load Response Program participants, are included on this line in the 2013 true-up calculation. The 2013 DOMLSE energy allocator was applied to this net system amount to derive the Virginia jurisdictional balance subject to true-up of $60,974 presented on Formula Schedule 9, Column 16, Line Q A. 22 Next, please describe the Amortization of Deferred Costs item listed on Line 28 of Formula Schedule 9. This line item includes the amortization of any prior period under- or over-recovered amounts. In order to match cost recognition with revenue recoveries, Line 28 of 36

56 Formula Schedule 9 captures the straight-line amortization of any under- or overrecovered balances recorded on the books at the beginning of a rate year for recovery from (or credit to) Virginia jurisdictional customers over the twelve months beginning September 1 of the succeeding rate year. Any actual over- or underrecovered balance as of August 31 is amortized using the straight-line method based on a daily rate over the September 1 through August 31 rate year. In this proceeding, for the months of January through August 2013 (Columns 4 through 11), Line 28 reflects the monthly amortization of the remaining under-recovered balance as of August 31, For the months of September through December 2013 (Columns 12 through 15) on Line 28 of Formula Schedule 9, the actual under-recovered balance as of August 31,2013 is amortized using the straight-line method based on a daily rate over the rate year September 1, 2013 through August 31, Q. Please describe how Line 29 of Formula Schedule 9, Calculation of the Monthly True-Up Adjustment, accommodates the Update Period adjustment. 15 A Line 29 of Formula Schedule 9, the Monthly True-Up Adjustment schedule, was established to ensure that a duplication of cost recovery or reduction between the Formula Schedule Update Period adjustment and the true-up does not occur. The Update Period adjustment allows for the more timely recovery of costs incurred during the Update Period, even though revenues will not start to be recovered for the current Update Period until September 1 of each year. Costs for the Update Period in the calendar year subject to true-up will generally be higher than the level of Update Period revenues collected for the calendar year subject to true-up. Because the recovery of these costs, as a result of the Update Period adjustment, will commence 37

57 by September 1 of each year, those same Update Period costs will be excluded from recovery for the period January 1 through August 31 during the calendar year subject to true-up. Thus, the monthly Update Period adjustment amounts on Line 29 taken from the previous year's Formula Schedule adjust this year's amount of Subsection A 4 costs subject to true-up. Line 29 is populated with the 2013 monthly Update Period adjustment amounts appearing on Formula Schedule, Columns 4-11, Line 18 from the 2013 RiderT1 Case. Because the Update Period adjustment amounts on Line 29 represent a recovery of additional costs, the monthly amounts reduce the costs subject to true-up for this proceeding, which prevents double recovery of the Update Period adjustment amount Q. A. Please describe the overall results of the 2013 true-up calculation as represented in Formula Schedule 9. The Company was billed a total of $374.8 million by PJM for Subsection A 4 costs on a Virginia jurisdictional level for calendar year 2013 as noted in Formula Schedule 9, Column 16, Line 27. The costs billed by PJM for the Update Period January 1 through August 31, 2013 are reduced by the amount of costs included in current rates through the Update Period adjustment mechanism approved by the Commission in the 2013 Rider T1 Case, and then the remaining costs for January through December 2013 are increased by the amortization of the deferred amounts discussed above. These adjusted 2013 costs, which represent the total costs subject to true-up, are then compared to the actual Virginia jurisdictional retail revenues intended to recover Subsection A 4 costs received in calendar year 2013 to determine the over- or underrecovery of Subsection A 4 costs for the year. Comparing the Virginia jurisdictional 38

58 retail revenues received in 2013 of $362.4 million (Formula Schedule 9, Column 16, Line 31) to the Company's actual Subsection A 4 costs subject to true-up for 2013 shows an under-recovery of $39.7 million (Formula Schedule 9, Column 16, Line 32) in this proceeding. 5 6 I will now discuss the proposed Update Period adjustment and its impact on the Company's revenue requirement in this proceeding. 7 VI UPDATE PERIOD COSTS 8 Q. 9 A Please discuss the recovery of known cost changes occurring during the Update Period for this Application. As initially approved by the Commission in the 20 Rider T Case, this adjustment allows for under- or over-recoveries arising from changes in FERC-approved rates and billing determinants that are known to occur during the Update Period to be built into rates for recovery or credit beginning September 1 of each rate year, instead of being delayed until much later when calendar year Subsection A 4 costs and revenues intended to recover Subsection A 4 costs are trued up The known costs that the Company is updating in this proceeding include the same types of costs that were approved for recovery by this Commission in the 2013 Rider T1 Case- i.e., they are costs for transmission services provided to the Company by PJM under the FERC-approved PJM OATT and Transmission Enhancement Charges/Credits. 39

59 The costs for the Update Period are also based on charges billed by PJM using PERCapproved rates, terms, and conditions known at the time of filing this Application and in effect during the Update Period. For example, the ATRR included in the 2013 Rider T1 filing was based upon the NITS rate approved by PERC for calendar year 2013 and was the latest known at the time of the 2013 Rider T 1 application filing. The 2014 ATRR based on the latest NITS rate approved for use by the Company for calendar year 2014 was not available at the time of that filing and, therefore, could not have been used in that application. Thus, the Company is using the same bases for determining costs for the Update Period as for the Rate Year in this proceeding. The latest PERC-approved rates known to be in effect for the Update Period applied to known billing determinants are also the same rates applied to the same billing determinants used to develop the Subsection A 4 costs for the Rate Year. 13 Q A What is the total revenue requirement for the expected under-recovery of Subsection A 4 costs for the Update Period in this proceeding? As shown in Formula Schedule, the Company has determined an under-recovery of Subsection A 4 costs for the Update Period in the amount of $50.0 million to be included in this Application. These total costs are derived from the following: (1) increases in the ATRR resulting from the NITS tariff effective January 1, 2014; and (2) decreases in amounts necessary to recover the current net credit level of Transmission Enhancement Charges/Credits for the Update Period. 40

60 1 2 Q. Why did the Company select these two components of Subsection A 4 costs to update instead of updating all Subsection A 4 costs? 3 A As previously approved by this Commission, the Company has limited the update of Subsection A 4 costs to known cost changes as of the date of this Application filing derived from rates and billing determinants that will be in effect during the Update Period, compared to the respective amounts currently being recovered through the existing Subsection A 4 component of base rates and Rider Tl. The Subsection A 4 costs included for updating represent current levels of costs being billed by PJM for NITS charges and net Transmission Enhancement Charges/Credits. Again, the Update Period adjustment is not an effmt to update all Subsection A 4 costs, but rather to identify known material cost or rate changes that are incurred during the Update Period to allow for the more timely and current recovery of these costs as required by Subsection A In each of these components of the cost of service, the applicable, currently effective PERC-approved rates reflect rate changes that have occurred since the Company's application filing in the 2013 Rider T1 Case and that will be in effect during the Update Period. Accordingly, they have been included for updating, which produces an increase to the revenue requirement in the amount of $66.6 million for NITS and a net decrease of ($16.6) million for Transmission Enhancement Charges/Credits. Thus, the total portion of the revenue requirement resulting from updating these cost components is an increase of $50.0 million. 41

61 1 Q. 2 3 A Are there any Subsection A 4 costs that have not been included in the Update Period? Yes. Consistent with the methodology approved in prior Rider T and T1 cases, there are several components of Subsection A 4 costs that did not warrant updating prior to being addressed in the true-up process in a subsequent Subsection A 4 proceeding. Point-to-Point Transmission Service revenue credits, as noted previously, can vary significantly from period to period and are, therefore, difficult to project. The Dominion Settlement Charge is a fixed amount each month. Therefore, it is not necessary to update the Dominion Settlement Charge. The Generation Deactivation, Michigan- Ontario Interface PARs, and PJM administrative charges are subject to periodic cost changes. Therefore, specific amounts are not currently known for the Update Period. Finally, amounts for energy-related demand response program charges tend to be very small and can fluctuate depending on each period's operating conditions. 15 Q. 16 A How is the Update Period adjustment incorporated into the formula schedules? As first approved by the Commission in the 20 Rider T Case, the Update Period adjustment is presented in Formula Schedule and develops an increment or decrement between updated levels of the appropriate Subsection A 4 costs compared to those same costs used to develop the cost of service supporting the Subsection A 4 rates currently in effect. Formula Schedule updates the previously described Subsection A 4 costs to current levels in the Update Period. The update is performed in Formula Schedule by comparing levels of Subsection A 4 costs known at the time of filing this Application, and billed by PJM for the Update Period, to the 42

62 amounts included in the cost of service supporting the Subsection A 4 rates currently in effect. For the two Subsection A 4 cost components -NITS and Transmission Enhancement Charges/Credits - considered in the Update Period adjustment, the annual updated level of costs in Formula Schedule, Column 2, Lines 6-8 is equivalent to the costs included on Formula Schedule 2, Page 1 of 2, Column 9, Lines 1, 16, and 18, respectively, for the Rate Year. 7 VII. CONCLUSION 8 Q. Please discuss in more detail the primary drivers of the increase in the total 9 revenue requirement over that requested in the 2013 Rider Tl Case. A. The total Subsection A 4 revenue requirement consists of three primary components: the projected Subsection A 4 costs, the true-up adjustment, and the Update Period adjustment. The increase in the total revenue requirement in this Application over that requested in the 2013 Rider T1 Case to be recovered from Virginia jurisdictional customers is due to significant cost increases associated with each of these components. There are three primary drivers influencing the increase of $133.6 million in revenue requirement for the 2014 projected rate year over the 2013 projected rate year The increased costs associated with the projected Subsection A 4 costs are due almost exclusively to an increase in the NITS charges reduced by net Transmission Enhancement Credits for the Rate Year. As described previously in this testimony, the Update Period adjustment updates the NITS charges and net Transmission Enhancement Credits for changes known to be effective for the January- August 43

63 Update Period. For analytical purposes, the projected Subsection A 4 costs and the Update Period adjustment are combined because they primarily include the same types of underlying cost projections, being the NITS charges offset by the net Transmission Enhancement Credits. An analysis of the combined projected Subsection A 4 costs and the Update Period adjustment shows that the increase in the total revenue requirement proposed in this Application is due to increased net investment in plant contained in the NITS charges which, after reduction by the net Transmission Enhancement Credits, reflects Dom Zone's share of the Company's own transmission projects, as well as transmission projects of other TOs. The charges developed exclusively from the NITS rate increased by $65.7 million on a Virginia jurisdictional basis from the 2013 to 2014 rate years. This figure is prior to considering the net Transmission Enhancement Credits reflected in the Subsection A 4 RAC. There was also a year-over-year increase in the net Transmission Enhancement Credit of $24.9 million on a Virginia jurisdictional basis that partially offset the increase in charges resulting from the incremental investment in plant contained within the NITS charges. The Update Period adjustment, which also includes NITS charges reduced by net Transmission Enhancement Credits, increased the revenue requirement for net investment in plant by an additional $21.7 million. The net impact of these three related changes is approximately 46.8% of the increase in the total revenue requirement requested in this Application Another primary driver of the increase in the total revenue requirement included in the projected Subsection A 4 costs category in this Application is the 2012 true-up within the PJM NITS rate, which is a component of the 2014 NITS rate allocated to 44

64 the Virginia jurisdictional customers. This true-up increased by $21 million yearover-year on a Virginia jurisdictional basis. The NITS rate true-up accounts for approximately 15.8% of the total increase in the revenue requirement in this Application A final primary driver of the increase in the total revenue requirement in this Application is the Subsection A 4 RAC true-up and the non-net plant investment component of the Update Period adjustment. The RAC true-up included in this Application increased by $17 million over the amount included in the 2013 Rider T 1 Case. The increase in the non-net plant investment component of the Update Period adjustment (which allows the Company to accelerate the recovery of rate increases for the NITS rate effective January 2014) added an additional $18.3 million to the incremental revenue requirement requested by the Company for The increase in the Subsection A 4 RAC true-up and the non-net plant investment component of the Update Period adjustment accounts for approximately 26.4% of the increase in the total revenue requirement requested in this Application. 16 Q. 17 A. Does this complete your pre-filed direct testimony? Yes, it does. 45

65 APPENDIX A BACKGROUND AND QUALIFICATIONS OF DAVID M. WILKINSON David M. Wilkinson received a Bachelor of Science degree in Business Administration and Accounting from Washington & Lee University in 1985 and a Masters of Business Administration degree from the University of Richmond in He is also a certified public accountant. Prior to joining the Company in January 1998, he had over ten years of experience in public accounting and industry. During his career with the Company, he has held numerous staff and managerial positions in finance and regulatory accounting. Currently, his position is Manager- Regulation in the Regulatory Accounting Department with responsibility for analyzing and calculating revenue requirements for Dominion Virginia Power rate proceedings. Mr. Wilkinson has previously submitted testimony before the State Corporation Commission of Virginia.

66 Virginia Electric and Power Company Subsection A 4 Costs Calculation of Cost of Service~ Summary For the Rate Year Beginning September 1, 2014 Virginia Jurisdiction Company Exhibit No. _ Witness: DMW Schedule I Page I of 14 Formula Schedule I Page I of I Line ~ Component Amount Item Location 1 Network Integrated Transmission Service $ 478,939,484 Formula Schedule 2; pg 1 of 2; Col. 9; Line 5 2 Transmission Enhancement Charges/Credits ( 45,145,97 3) Formula Schedule 2; pg 1 of 2; Col. 9; Line 22 3 PJM Administrative Cl'larges Current 14,359,943 i'ormula Schedule 2; pg 1 of 2; Col. 9; line 32 4 Demand Response P rograrns Approved by FERC 95,026 Formula Schedule 2; pg 1 of 2; Col. 9; Line 35 5 Subtotal- Subsection A 4 Cost of Service (sum of Lines 1 through 4) $ 448,248,481 6 True.. up Adjustment 39,742,348 Formula Schedule 9; pg 1 of 1: C'-ol. 16; Line 32 7 Update January 2014 to August ,028,42.7 Formula Schedule 1 D; pg 1 of 1; Col. 12; Line 15 8 Subsection A 4 Cost of Service (Line 5 +Line 6 + Line 7) L 538,019,256

67 Virginia Electric and Power Company Subsection A 4 Costs Calculation of Cost of Service Based on PJM Charges For the Rate Year Beginning September 1, 2014 Virginia Jurisdiction ~- 1 Line DescripUon ~ "'.Q_~t~cri~]tfon Billing Determinant ~D.! 1 1 Type Billing B!H!n,g Q Determinant Rate (a) {a) Network lntegrc:.te-d Transmission Service {NITS) 2 Rrm Point-to-Point Transmission Sentice 3 Non-Finn Po!nHo-Point Transmission Service 4 Dominion Sett1emer.l Transmission Demand MW 16, ,936. Fixed Amounts- Do!lars- Historical $ (6,821,3 0) Fixed Amounts- Dollars- Historical $ (778,863) Fixed Amounts- Dollars- PJM OATI $ 2.49,996 5 Net Network lnt~grated Transmission Service {NITS} 6 Transmission Enhancement Charges (Schedule 12.. PJM OATI) Atlantic Elcctsk Baltimore Gas and Electric Co. Delmarva PPL Electric Utilities Corporation PEP CO Pubiic Service Electric and Gas Co. AHeghcny Power AEP 15 VIrginia E!ectrt1): and PO\ver Co. 16 Total Transmission Enhancement Charges {b) Axed Amounts - Dollars- Annual $ 423,609 Various Fixed Amounts- Dollars- Annual $ 1,418,785 Various Fixed Amounts- Dollars -Annual s 1,303,454 VariOliS Fixed Amounts- Dollars- Annual $ 4,891,324 Various Fixed Amounts - Dollars - Annua.l $ 2, Various Fixed Amounts - Dollars -Annual 12,245,369 Various Fix.ed Amounts- Do!lars- Annual 26,725,374 Various Fixed Amounts- Dollars- Annual s 588,609 Various Fixed Amounts - DoHars ~ Annual $ 30,093,402 Varlous 79,920, Transmission Enhancement Credits (Schedule 12- PJM DATI) 18 Domln!on (b) FtXed Amounts -Dollars- Annualized $ (143,612,05"{) Various 19 Other 20 Generatlon Deactivation Charge 21 Mch!gan.. Ontario interface Phase Angle Regulators Charge FIXed fl.cnounts- Dollars- Hlstoncal s 649,679 FIXed Amounts- Dollars- Historical $ 258, rota\ Tt<.lrlSmis~ ion Enhancement 23 PJt.l Administrative Charges- Current Control Area Financial Transmlssfon Rights 9-2 financial Transmission Rlghts 9~2. Financial Transmission Rlghl'ii 9-4 Regulation and Frequency Response 9-4 Regulation and Frequency Response 9-6 Advanced Second Control Center- 9-1 Control Center *6Advanced Second Control Center- 9-3 Maf."<etSupport Rate Year Projected Transmission Use MWh 88,4, Quantity of Ml'/h of All FTR MWh 96,160, FTR Bid Options X 5 Hours ftr Bid Obligations Hours 2,sss,sn Regulation Obligation + Regu!a~on Scheduled MWh 560, Regulation Obligation +Regulation Scheduled MWh 1,113, Rate Year Projected Transmission Use MNh 88,4, Rate Year Projected Generation Provided MVVh 74,686, Total Admlnlsirotivc Charges Demand Response Programs Approved by FERC 34 Economlc/Eme'l)enoy load Response Programs Historical/Assigned $ 119,ns 35 To1al Demand Resoonse Programs Approved by FERC 36 Total Revenue Requirement Notas: (a) See Formula Schedule 2, page 2 for Source Location. (b) Billed at Dominion Zono level.. Transmission Ex2cnses (col4"col5) $ 567,361,180 (6,621,360) (778,863) 249, ,0, ,609 ~ 1,418,785 $ 1,303,454 4,S91l324 2,230,551 12,245,369 26,725, ,609 30,093,402 79,920,478 (143,612,057) 649, ,898 (62,783,002) s 14,959, ,402 4, , ,925 2,132, ,735 18,099, , ,447,651 z. ~ VIrginia Juris. Virginia Juris. Allocator Transmission Allocator Descrletlon Exoenses (a) (coi. 6 col. 7) % Demand- DOMLSE ~ 484,993, % Demand- DOMLSE (5,632,509) % Demand- DOMLSE (643,120) % Demand- DOMLSE- MODIFIED 221,299 s 478,939, !;01% Demand- Dom Zone 7Z.0601% Demand- Dom Zone % Demand- Dom Zone % Demand - Dom Zone % Demand- Dom Zone % Demand- Dom Zone % Demand - Dom Zone % Demand - Dom Zone % Demand- Dom Zone $ o05,253 1, ,270 3,524,651 1,607,337 8,824,022 19,258, ,152 21,685,328 57,590, % Demand- Darn Zor.e (3,486,957) % Demand- DOMLSE % Demand- DOMLSE 536, ,Tt7 s (45,14s,9n) Q% Energy- OOMLSE % Energy- DOMLS E % Energy- DOMLSE % Energy" DOI~LS E 7S.3370% Energy- DO~:LSE % Energy- DOMLSE % Energy- DOMLSE % Energy- DOMLSE ~ 11,868, ,728 3,852 0, ,663 1,692, ,651 $ 14,359, % Energy- DOMLSE 95,026 95,026 - ::::: 0 ;;;...,(/J "' P' >-rj 0 ~ a N Q ::::: 0 448,248,481 "'0(/J P' () (JQ ~ () () N"-,_,., 0 E. ~ :;EO - :::t ::j 2 ~~ <n.. '-< :::> Om 3:::~ <g: z 0

68 Virginia Electric and Power Company Subsection A 4 Costs Cost of Service- Source Location Unc ~ Descrlption Billing Delenninant aem location Rate ttem Locat:on VirglnJa Juris. Allocator ltc'm LccaUon Network Integrated Transmission Scrvfcc (NITS} Finn Po!nt-ta-Polnt Transmfsslcn Service Non-FJnn Poinl-to-Point Transmission Scrvlce Dominion Seltl~ment 16,3_44.6 {6,821,360) {778,863) 249,996 PJM Webslte ~Oasis Section 35,936. PJM Website I Market Operations; Transmission Ser.rlce- Fomu!!a Rates Formula Schedu~e 3; llne 1 Jnfcrmauan obtained per historical!nvo!ces (PJM) Forrnuia Schedule 3; llnc 2 fr.formation obtained per hislcric.<3! irwoices (PJM) Fonm.1!a Schedule 3; l!ne 3 fnfonnation obtained per PJM OAIT- Mtachment f-1,-}l\a...a. 8:?:.5716'% Fonnu!a Schedule B; pg. 1; iine % Formula Schedule 8; pg. 1; line % Formula Schedule B; pg. 1; nne % Formula Schedule 8; pg.1; 1\ne 12 Net Network Tntegrt~ted Transmission Service {NITS) 6 Transmission Enhancement Charges {Schedule 12- PJM OATT) 7 Atlantic Electric: 8 Baltimore Gas and Electric Co. 9 Delmarva PPL Electric U!Hities Corporation 11 PEPCO 12 Public Service Electr1c and Gas Co. 13 Allegheny Power 14 AEP 15 Virginia Electr1c and Power Co. 16 Total Transmls~ion Enhanc;cmcnt Charges 423,609 1,418,785 1,303,454 4,891,324 2,230,551 12,245,369 26,725, ,609 30,093,402 79,920,478 Formula Schedule 4;!lne 2 (a) Formula Schedule 4; fine. 2 Formula So'1edule 4; rlne 4 {a} Formula Schedule 4i llne 4 Formula Schedule 4; Hne 8 (a) Formula Schedule 4; line 6 Formula Schedufe 4; line 18 (a) Formula Schedule 4; line 18 Formula Schedule 4; line 25 (;;~) FormulaSchedu!e4; llne25 Formula Schedule 4; line 33 {a) Formula Schedule 4; line 33 Fonnula Schedule 4; fine 50 {a) Fonnu!a Schedule 4; llne 50 Fonnu!a Schedule 4; line 65 (a) Forrnu!a Schedule 4; line 65 Pormu!a Schf!du!e 4;!inc 3 (a) Fonnu!a Schedule 4; l!ne 3 fcrmufa Schedule 4; line 4 (a) Formula Schedule 4; line % Formula Schedule 8; pg. 1; Hne % Formufa Schedu!e 8; pg. 1; line % Formula Schedule 8; pg. 1; line G01% Formu!a Schedule 8; pg. 1: line ')\ Formula Schedule 8; pg. 1; l!ne % Fonnula Se:'ledu!e 8; pg. 1; llne 'l', Formula Sc.~eduie 8; pg. 1; line S01% FormuiaSdhodule 8; pg. 1; line % Formula Schedule 8; pg. 1; Hoe G % Formula Sch!!dule S; pg, 1; line 6 17 Transmission Enhancement Credits (Schedule 12 PJM OATT} 18 Dominion (143,ti12,057) Fonnufa SGhedule. 5; line 37 (a) Formula Sdhedule 5; line % Formuia Schedu!e 8; pg. 1; l!ne 6 19 Other 20 Generation p~;cti'ja.tion Ch~rge 21 Michigan- On!arlo interface Phase Angle Regulators Charge 649, ,898 Formu!a Schedule 4a; line 1 Information cbtalned per h!storical invoices {PJM) Formu!a Scheduie 4a; Hnc 2 Information obtained per historical in.voices (PJM) % Fomw[a Schedule 8; pg. 1; line 3 1:!2.5716'% Fomw!a Schedule 6; pg. 1; llne 3 22 Totat TransmiSS!.2n Enhancement 23 PJM Administrative Charges- Current COntrol A"'a Financial Transmission Rlghts 26 S-2 Financial Transmlssicn Rlghts Financial Tmnsmisslcn Rights 28 g..4 Regulation and Frequency Resp-onse Regulation and Frequency Response Advanced Second Control Centerw g..1 Control Center Advanced Scrond Control Center Market Support 88,4~432 96,160,773 2,855, ,160 1,113,717 58,4, ,686,784 Fo;mula Sc.1edule B; line (b) PJM \:Vebslte; "OATT- Schedule 9"; plus any posted quarterly adjustments Formula Schedule 6;!ine (b) PJM WebsiTe; uoatf ~ Scf~ed\Jle 9''; plus any posted quarterly adjustments Formula Schedule 6; line (b) PJM Website; "OATT- Sr.herlule 9"; plus any posted quarterly adjustments formula SC~"'ledule 6; line (b) PJM Website; "OATT- Schedule 9": plus any posted quarlerly adjuslrnents Formula Schedule O: tine {b) PJM Website; ~oati- Schedule g :: pius any posted quarterly adjustments Formula Schedule 6; fines (b) PJM Website; ".Q6IT- Sche~.h.U~.. :; plus any posted qvarterly adjustments Formula Schedule 6; Une (b) PJM Website; ~OATI- Schedule 9": plus any posted quarterly adjustments Fo:mula Sc.1edule 6i!lne (b) PJM Website; "'OATT -Schedule 9" plus any posted quarterly adjustments % Fom1ula Schedule 8; pg. 1 ;'line % Formula Schedule 8; pg. 1; line % Formula Schedule 8; pg. 1; Hnc % formula Schedule 8; pg. 1; line % Formula Schedule a; pg. 1; line % formula Sche-dule 8: pg. 1; line % Formula Schedule a; pg. 1; l!ne % Formula. Schedule 8; pg. 1; l!ne 9 32 Total Admfnfstratlve Charoes 33 Demand Response Programs Approved by FERC 34 EconomidEmergency Load Response. Programs 119,775 Formula Schedule 7: Une 1!nforma1ion obtained per historical invoices {PJM) % Formula Schedule 8; pg. 1; lfne s 35 Total Demand Response Programs Approved by FERC Notes: {a} The billing de.tennjnant Js the product of the revenue requirement listed for each enhancement project owned by member transmission ownors muftiphed by the <!ppropliate demand ratio applicable to those responsible transmission owners' charged. The revenue requirement assigned to each project ls listed Jn the appropriate formula rate for each transmission owner and can be located per. PJM.com I Mafi<.et & Operations I Transmission Service I Formula Rates. Enhancement projects for each tr.jnsmission owner and the applicable demand allocation ratios fot those transmlsslon owners charged are listed on PJM OATT-Schcdule 12 and can be located per: PJM.com I Documents J Agreements I PJM Agreements 1 PJM DATI. (b} The rates listed arc per the PJM website effur::tive for the first quarter of 2.014; posted 1/17/2014. '"() 'Tj (Jq "' 0... " N C 3 0 PJ ~~ if 0.. c (D N Jii " C/)::;20 g. ;=. 2 '"() n ::::5 ::: 8-_(P':-'!~..,. Om 3;::x ::;;:::!. g c Ul "' z ~ wo..n"''

69 line.t:!q, 1 Firm Point-to-Point Transmission Service (a) $ 2 Non-Firm Point-to-Point Transmission Service (a) $ 3 Dominion Settlement (b) $ Notes: (a) Information obtained per llis\orical PJM invoices. (b) Information obtained per PJM OATT- Attachment H-16AA Virginia Electric and Power Company Subsection A 4 Costs Derivation of Point-to-Point Transmission Service Revenue Credits and Dominion Settlement Charges Jan-14 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 (814,162) $ (566,714) $ (528,715) $ (535,796) $ (553,656) s (535,807) $ (568,697) $ (561,074) $ (509,695) $ (211,250) $ (39,286) s (52,849) $ (39,156) $ (50,652) $ (50,794) $ (64,706) $ (49,655) $ (39,050) s RATE YEAR Sep-14 Oct-14 ~ Dec-14 Jan-1!i Feb-15 Mar-15 Apr-15 Mav-15 20,833 $ 20,833 $ 20,833 ~ 20,833 $ 20,833 $ 20,833 $ :20,833 $ 20,833 $ 20,833 $ Oct-13 Nov-13 ~~ Total (546,804) $ (505,567) (594,673) $ (0,821,360) (44,890) $ (68,861) $ (67,714) $ (778,863) Jun-1s Jul-15 Aug-15 J:ptaf 20,833 $ 20,833 $ 20,833 s 249,996, 0 (JQ ~ g.;=. 2 a '"0 'Tj ";:)(/)<() - c +:;;.0..0'"0 c "', 0..., ;;- 8._(i':':~ C/) (') --Om ~ :s: :-<' (1> (i) CD :::::; :j?f 0. <~ w z c g: 0 y

70 Virginia Electric and Power Company Subsection A 4 Costs Company Exhibit No._ Calculation of Cost of Service for Transmission Enhancement Charges Witness: DMW 2014 Schedule I Page 5 of 14 Project Formula Schedule 4 Line Revenue Dam Zan~ DomZone DomZone ~ PJM Transmission.Q.wner (;!l. ~~"-guirem~ Ratio (a) Charge Total Atlantic Ci~ Electric Co. 2 PJM Upgrade - b02.a 3,636, % $ 423, ,609 :; Baltimore Gas and Electric _Co. 4 PJM Upgrade ID b0298 $ 12,294, % $ 1,418,785 1,416,785 Page I of2 5 Delmarva Power & Ll~ht Co. 6 PJM Upgrade - b0512 $,360, % $ 1,206,944 7 PJM Upgrade ID- b $ :;4,1~J % $ 3,984 8 PJM Upgrade ID b0751 $ 794, % 9Z,S2G $ 1,303,454 Jersey Central Power & Light Co. Motropollt.an Edison Co.* 11 Old Dominion Electric Cooperative' 12 Ponnsylvanla. Electric Co, 13 Phila. Ele~tj_c and Gas PECD Enc_ 91 Co.' PPL Electric Utilities Corporation 15 PJM Upgrade ID b $ 15, % $ 1, PJM Upgrade ID- b s 11, % s 1, PJM Upgrade ID- b $ 22, % $ 2, PJM Upgrade ID- b0487 $ 41,935, % $ 4,885,495 4,891, Potomac Ele<:trlc Power Company 20 PJM Upgrade ID - b0512 $ 15,297, % $ 1,782, PJM Upgrade ID- b $ 403, % $ 46, PJM Upgrade ID- b $ 4{)3, % $ 46, PJM Upgrade ID- b $ 403, % $ 46, PJM Upgrade ID- b $ 406, % $ 47, PJM Upgrade ID - b0496 $ 2,384,651.91% $ 260,165 $ 2,230,551 26!!_~I Utilities, Inc. 27 Public Service EI~~_Gas_.2.:...,._. 28 PJM. Upgrade 1D b041l9 $ 94,568, % $ 11,017, PJM Upgrade 1D b0498 $ 3,802, % $ 442, PJM Upgrade ID b $ 4, % $ PJM Upgrade ID - b041l9.5- b $ 1,327, % $ 154, PJM Upgrade - b $ 269, % $ 31, PJM Upgrade - b0290 $ 5,138, % $ 598,577 $ 12,245, Rockland Electric Company* 35 Allcghen~ Power 36 {Monont~nha!t~.; Potomnc Edl! ;on; West Punn.} 37 Allegheny Power- Trailco 38 PJM Upgrade ID- b0216 $ 6,547, % $ 762, PJM Upgrade ID b0218 $ 3,206, % $ 434, PJM Upgrade ID- b0230 $ 1,077, % $ 126, PJM Upgrade ID- b0328.1;b0328.2; b0347 {.1;.2;.3;.4) $ 165,386, % $ 19,267, PJM Upgrade ID b0559 $ 865, % s 0, PJM Upgrade - b0229 $ 1,031, % $ 149, PJM Upgrado ID b0495 $ 5,267, % $ 613, PJM Upgrade ID- b0344 $ 702, % $ 202, PJM Upgrade ID- b0345 $ 77:8, % $ 224, PJM Upgrade ID- b0343 s 7, % $ 205, Allcshcny Power- PATH 49 P.JM Upgrade ID- b0491/b0490- See AEP -PATH below s 20,554, % $ 2,394, PJM Upgrade b0492; bosso $ 19,252, % $ 2,242,904 $ 26,725,374

71 Virginia Electric and Power Company Subsection A 4 Costs Company Exhibit No. _ Calculation of Cost of Service for Transmission Enhancement Charges Witness: DMW 2014 Schedule 1 Page 6 of 14 Project Formula Schedule 4 Line Revenue DomZone Dam Zona DomZone Page 2 of2 ~ PJM Transmission Owner (a} Regulrement!h) Ratio!a) Char~ a Total 51 Allegheny Power- Other* 52 Commonwealth Edison Company' 53 Dayton Power and Light Co.* 54 AEP East Operatin~ Companies 55 (Appalachi~Sn Power; Co!urnbU$ Southern Power; 56 fndlann Michigan Power; Kentucky Power; 57 Klng!port Power; Ohio PowtJrj Wheollng Power) 58 AEP -PATH 11.65% 59 PJM Upgrade ID- b0490/b0491 -See Allegheny- PATH above GO AEP -othor 61 PJM Upgrade ID - b0504 1,051, ()/d 122, PJM Upgrade ID- b ,671, % $ 194, P JM Upgrado ID b14g , % $ 08, PJM Upgrade ID- b ,301, % $ 151, PJM Upgrade ID - b171z.2 41, % s 31, , Duquesne Light Company* 67 Viminia Electric and Power Comeanl 68 PJM Upgrade ID b0217 $ 276, % $ 32, PJM Upgrade ID b0222 $ 236, % $ 27, PJM Upgrade ID - b0226 $ 1,184, % $ 1,015, PJM Upgrade b0227 $ 3,191, % $ 2,147, PJM Upgrade ID b0231 $ 3,269, % $ 380, PJM Upgrade ID- b0403 s 1,396, % $ 1,172, PJM Upgrade ID b0455 $ 529, % $ 268, PJM Upgrade ID b0456 $ 727, % $ 291,493 '16 PJM Upgrade ID- b $ 35,531, % $ 4,139, PJM Up!Jrade ID b $ 2,382, % $ 277, PJM Upgrado ID b s 6, % $ 71, PJM Upgrade ID- b $ 234, % $ 217, PJM Upgrade ID- b $ 2,731, % s 2,533, PJM Upgrade ID b $ 533, % $ 494, PJM Upgrade ID- b0837 $ 116, % $ 13, PJM Upgrade ID - b0327 $ 960, % s 731, PJM Upgrade ID b0329.2b $ 34,750, % $ 4,048, PJM Upgrade ID b $ 895, % 86 PJM Upgrade ID- b1507 $ 37,264, % s 4,341, PJM Upgrade ID - b0457 $ 24, % $ 2, PJM Upgrada ID - b0784 $ 7, % $ PJM Upgrade ID b1224 $ 2,177, % $ 1,703, PJM Upgrade ID- b $ 287, % $ 180, PJM Upgrade ID b1647 $ % $ PJM Upgrade ID- b1648 $ % $ PJM Upgrade ID - b1649 $ 134, % 15, PJM Upgrade ID b1650 $ 134, % s 15, PJM Upgrade ID- b $ 2,476, % $ 1,871, PJM Upgrade ID b1188 $ 1,0, % $ 128, PJM Upgrade ID- b $ 6, % $ 12, PJM Upgrade ID - b1321 $ 2,623, % $ 2,570, PJM Upgrade ID b $ 528, % $ 61,619 0 PJM Upgrade ID b1797 $ 2,049, % $ 238,7 1 PJM Upgrade ID- b1799 s 1,069, % s 124,641 2 PJM Upgrade ID b1798 $ 5,659, % $ 659,308 3 PJM Upgrade ID b1805 $ 2,597, % $ 302,598 30,093,402 4 Total Dominion Transmission Enhancement Charl!es 79,920,478 N!>J L (') No Projects allocated to Dominion. (a) PJM website; OATT; Schedule 12 Appendix (Section 270 D). (b) PJM website; transmission service; formula rate (per most recent posted formula rate posted by transmission owner).

72 Line No. 1 Generation Deactivation Charges (a) $ 2 Michigan-Ontario Interface Phase Anglo Regulators Charge (a) s Notes~ (a)!nfcrmatlcn obtahed per historical PJM invoices. Virginia Electric and Power Comp~ Subsection A 4 Costs Derivation of Generation Deactivation Charges and Phase Angle R"gulators Charges ~ Feb-13 Mar~13 Apr-13 May-13 ~ Jul-13 Aug-13 59,861 $ 58~876 s 62,857 s 55,248 s 63,750 $ 60,732 s 58,671 $ 3,244 21,088 s 21,772 s 21,758 s 21,903 s 21,311 s 21,617 $ 22,126 s 22,023 Ser-13 ~ ~ s 56,4 $ 46,692 s 63,291 $ 21,580 $ 21,542 s 20,955 $ Dec-13 60,046 21,224 '1:! 'Tj (JQ "' :::; 0 "' ::; ~ c 0 ;;..., en "' ~ 0. c co -l>- "' 'U (JQ "' "' --..} 0..., -l>- Total 649, ,898 CZl;E(') ~ ~: 2 n :::5 :;j o.ou s ~ "'.. '-< Om :S::x :E~ z ~

73 Company Exhibit No._ Virginia Electric and Power ComEan;:: Witness: DMW Subsection A 4 Costs Transmission Enhancement Credits Schedule I 2014 Page 8 of I4 Transmission Enhancement Prolocts Owned b~ Dominion Formula Schedule 5 Annual Annual Page I of I Line PJM Revenue Requirement Revenue Requirement No, UQgrade ID (al including Incentive (b) Incentive (b) without Incentive (b) b , ,985 b , ,339 b0226 1,184,174 1,184,174 bd227 3,191,119 3,191,119 b0231 3,269,266 3,269,266 b0403 1,396,397 1,396,397 b , ,140 b , ,277 b ,531,473 1,375,503 34,155,970 b ,382, ,067 2,218, b ,191 41, , b ,127 13, , b ,731, ,137 2,576,4 1 1 b ,6 30, , b , , b , , b0329.2b 34,750,239 2,354,449 32,395, b ,799 52, , b ,264,051 37,264, b ,45 24,45 21 b0784 7J456 7, b1224 2,177,637 2,177, b , , b b b , , b , , b1188.g 2,476,349 2,476, b1188 1,0,38 1,0, b ,498 6, b1321 2,623,809 2,623, b , , b1797 2,049,011 2,049, b1799 1,069,883 1,069, b1798 5,659,293 5,659, b ,597,405 2,597, Total 147,799,495 4,187, ,612, Notes "(a)pj'm' website, OATT, Schodule12 Appendix (Section 7.70 D). {b) PJM website; transmission servjce; formula rate (per most recent formula rate posted by transmission owner).

74 Line ~ DOMINION VIRGINIA POWER (LSE) PJM Administrative Charges- Current 9-1 Control Area 9-2 Financial Transmis~;io!l Rights 9-2 Financial Transmis~:ion Rights- ftr Sid Options x Fimmcial Transmission Rights- FTR Bid Obligations Regulation and Frefluency Response Advanced Second Gontro! Center- 9 1 Control Cc.r:ter DOMINION VIRGINIA POWER a PJM Administrative Charges- Current 9-4 Regulation and Frec;uency Response 9-6 Advanced Second Control Center- 9-3 t~'iarket Support-Generation Provlded Notes: (a) Projections supplied per Integrated Resource Planning- (Rate Year) 9/14-8/15. (b) Projections supplied per Generation System Planning- {Rate Year} 9/14-8!15. {c) Information obtained per historical PJM invoic~;<s. Virginia Electric and Power ComQany Subsection A 4 Costs Derivation of Billing Determinants for PJM Administrative Costs-Current Birling Determinant Basis Jan-14 Fcb-13 Mar~13 Apr-13 May-13 Jun 13 (n) MWh B.!!sed on ptojectud lr?lnsrnis$n usage- f.or rate year (c) MWh 7.260,404 7,520,584 8,556,064 6,174,920 8,425,224-7,907,808 (c) Kours {c) Hours 281, , , , , ,641 {c} MWh 44,389 48,537 49,366 40, ,060 52,283 (a} MWh Oas('cd on project~dtr.ansmissiorl usaga for rate yco:tr Bi!Iing Oetermin<'lnt Bilsis Jan-14 Feb-13 Mar-13 ~r~13 Ma~-13 Jun-13 (c) MWh 1,867 84,958 77,5 81,257 80,693 2,603- (b) MWh S01scd on projected genetatlon provided for rate year Annt~al Jul-13 ~ Sep-13 Oct~13 Nov-13 Dec-13 Amount 88,4,482 8,218,434 8,311,320 8,005,008 8,Z61,791 7,&51, ,1!15 96,160, , , , , , ,162 2,855,692 59,577 54,021 t3,7~i5 39,222 42,055 42, , ,4,432 Jul-13 Aus-13 ~13 Annu:tl Oct-13 Nov-13 Dco-13 Amount 129,545 9,379 83,628 69,433 88, ,113,717 74, 'l:! >-rj 'UCI):;EO 0 (IQ "' (D 8 c Cl:l ~ 0 ~ ~ s 3 - c \OO..<Du ~0~~ "',_.., C/) (") --Om :::>" (D 0.. """ ;;:: X :<2": c g: (D 0\ z ::>

75 Line No. FERC Approved Demand Response Program Costs Econc mic/emergency Load Response Notes: {a) Information obtained per t1istorical PJM invoices. Jan-14 (a) 61,373 Virginia Electric and Power Company Subsec1ion A 4 Costs Derivation of Demand Response Program Costs ~ Mar 13 Apr-13 May-13 Jun-13 Jul-13 Aua~13 Sep-13 Oct-13 Nov-13 Q_ec-13 41,419 $ 29,306 41,755 36,302 $ 45,761 $ 81,688 s 49,129 s (435,816) $ 194,838 $ {155,660) $ 128,982 Total 119,775 0 ;:?~:<Q (JQ ::::;- ;::::; c 0~~-g 0...,., ::;;- 0 ~ :'": ~ (/) ~ - 3:::>< "C) 'Tj "' (JQ C1> (tl (tl '=' =::l...,_vm () 0..,.. :<:::!. c ;:;- [. ---l z ;:>

76 Virginia Electric and Power Company Subsection A 4 Costs Calculation of Virginia Jurisdictional Allocate~ Company Exhibit No. Witness: DMW Schedule I Page II of 14 Formula Schedule 8 Page I of2 Line No Demand~ DOMLSE MW DOMLSE Network Service Peak Load 16, Virginia Jurisdictional Coincident Peak Demand 13, Virginia Jurisdictional Allocator (Line 2 I Line 1) Allocation Factor % Demand ~ DOMZONE MW Network Service Peak Load 18, Virginia Jurisdictional Coincident Peak Demand 13, Virginia Jurisdictional Allocator (Line 5/ Line 4) % Energy~ DOMLSE ~ DOMLSE Network MWh 84,795,342 Virginia Jurisdictional Coincident Peak MWh 67,274,4 Virginia Jurisdictional Allocator (Line 8 I Line 7) % Demand ~ DOMLSE Modified for Settlement (excludes VMEA} MW DOMLSE Coincident Peak Demand 15, Virginia Jurisdictional Coil)cident Peak Demand 13, Virginia Jurisdictional Allocator (line 11 I line ) %

77 Virginia Electric and Power Company: Subsection A 4 Costs Calculation of Virginia Jurisdictional Allocators 2012 Company Exhibit No. _ Witness: DMW Schedule I Page 12 of 14 Formula Schedule 8 Page 2 of2 Line No. 2 3 Demand - DOMLSE MW DOMLSE Network Service Peak Load 16, Virginia Jurisdictional Coincident Peak Demand 14, Virginia Jurisdictional Allocator (line 2 I line 1) Allocation Factor % Demand - DOMZONE MW Network Service Peak Load 19, Virginia Jurisdictional Coincident Peak Demand 14, Virginia Jurisdictional Allocator (line 5 I line 4) % Energy- DOMLSE MWh DOMLSE Network MWh 82,502,4 Virginia Jurisdictional Coincident Peak MWh 65,159,130 Virginia Jurisdictional Allocator (line 8 I line 7) % Demand - DOMLSE Modified for Settlement {excludes VMEA} MW DOMLSE Coincident Peak Demand 15, Virginia Jurisdictional Coincident Peak Demand 14, Virginia Jurisdictional Allocator (line 11 /line ) %

78 Col. No. 1 g ]! Uno!!!!.: Onscriotion Ridfjr T Costs Por PJM Network Integrated Transmission Servica (NITS) Firm Point to Point Tran~mlsslon Scrvicu Non-Firrn Pelot to Point Transmiss1on So1vice Subtot.,l- System {line$ ) Subtotal- VA Jurisdictlonal Amount (fino 4"" 83.61n%- DOMLSE Demand Allocator) Dominion Settlement VA Jurisdictional Amount (lin& 6 * %- DOMLSE Darnand Alloc"toH>~odlfhuJ) Total NITS VA Jutisdi~:tional Amount (linos 5 + 7) % Sdw ~ PJMit1V?JMJr;v PJM\l\Y..':l!:\ p..2?jminv % Sd1ed.8, p.z Transmission Enhanc$rn&nt Charges 1'1 Credits 12 Michigan-Onlario interface Phase Angle Regulators Charge 13 Generation Deactivation Charge 14 Tola! Transmission Enhancement (sum Jines..13) 15 VA Jurisdictionool Amount (tino 14,. 83.S1n% ~ DOMlSE D~m-"nd Allocator} f}jm1nll PJMl:w PJMlnv PJMlrw % Scl.ed.a.,p.2 Administrative Chargos- Cummt \6 S..1 Control Area Fin.-mcia! Transmission Rights Financial Transmission Rights -FTR Bid Options x Financial Transmission PJghls- FTR Bid Obligations Regulation and Froquency Rospon.t&OOMLSE Re-gulation and frequency Respon,re..DVP AdVatJcod Second Conhol Center 23 Total Adminis!:r::.tlve Chr.rgos-Currerrt (sum lines 16>22) 2.4 VA Jurisdictional Amount (linlil 23 * % ~ DOMLSE Enorgy Allocator) PJMlll" PJM!rw PJM!:w PJr.t!nv f'jminv PJMinv f>.jm"in'<' % Scr-:oo.a, p.1 25 Economic and Ernocgoncy Load Responsu Programs (En orgy Only) 2S VA JucisdicUona! Amount {Uno '70%- DOMLSE Energy Allocator} PJMlrw % SvhM..8.p.1 27 Subtotal Costs Subjoctto Doforral (linas ) 28 Amortization of Actoa1 Undor/Ovor Rocovornd Costs t>.'c::ta 29 Subsection A 4 Costs Monthly Up data Amount (from prior year filing} Nv\,.iJ. 30 TOTAL COSTS SUBJECT TO DEFERI<AL (lines ) Subsection A 4 REVENUES 31 Subsection A 4 Rotail Rovonuos- VA Jurisdictional NotoC 32 Monthfy {Undor)fOvcr Rncovsry (Hnes } Note t".:-. Pf;!f ;""inuncial recon'c at bn;-~1nning cf :ate year, provided by Virginia PO',...'O: Corpcrate Aceountino group. Note 6: Subsoction A 4 Cost of Sen ice Compliance Filir.n, PUE , Fcrrnula Schedule. Not-e C: Revenue provideq by V~rgini:a Pow-er Corporn.!o Accounting group. Al.:tuaJ monthly r<jco\'eric::>. Virginia Electric and Power Company Subsection A 4 Costs Calculation of Monthly True-Up Adjustment For the Period January through December ~!l z.!l!t 1Q 11 1Z :!.: Q J.rt.n-13 Fob-13 Mar-13 ~.n.r-13 May.. 13 J.!!.n-13 :JJ!l:fl 8.\!.!!.:ll Sop~13 ~ Nov-13 ~ ~ s (3s,oso,824i s (35, ) s (39,096,524) s {37.S35,o.l6J > {39, ) s (37,835,636) s (39,096,824) s (39,096,824) s (37,635,636) s (39,oss.sz4) s (37,835,636) s (3s,os8,824J s (460, ) 654, , , , ,B07 568, , , , , ,673 6,671,69$ --"'so,,2"'5<>"'-- "39, , , , :2. 2_ ,861 67, $ (38,346,069) s (34,707,260) (38,515,260) s (37,260,684) $ {38,4ii2,516) $ (37,249,035) s (38,463,421) s (38,488,095) s (37,286,891) s (38,505, 130) (37,261,208) $ (38,434,437) $ (453,008,007) $ (32,0fi4,1) ~ (29,021,413) s (32,205,575) $ (31,156,527) 5 (32,186,557) s (31,146,786) $ (32,162,228) $ (32,181,187) s (31,178,441) $ (32,197,4) s (31,156,965) $ (32,137,992) $ (378,794,676) (20,833) (20,833) (20,833) (20,833) {20,833) I18,G:l1} il8,631) (18,631) {18,fi31) {18,631) (20,833) {18,631) (20,833) (20,833) (20,833) (20,833) (20,833) (20,833) (250,000) (18.631) (18,631) (18,631) (18,831) (18,631) (18,631) (223,576) s (32,082,732) s (29,040,044) s (32,224,206) $ (31,175,158) $ (32,205,188) $ (31,165,418) s (32,180,859) 5 (32,199,819) s (31,197,072) $ (32,215,735) $ (31,175,597) $ (32,156,624) 5 (379,018,452) s (5,314,875) 5 (5,814,875) s (5, ) $ (5,814,875) s (5,814,875) s {5,652,33!) s {5,700,143) $ (5,700,143) s (5,700, 143) $ (5,700, 143) s (5,700,143) $ (5,700,143) s (68, ) 7,514, ,9-34 7,514,934 7,514,934 7,514,934 7,514,934 7,514,934 7,514,934 7,514,934 7,514,934 7,514,934 7,514,934 90,179,207 (19,588) (21,772) (21,758) {21,fl03) (21,3 11) (21,617) {22,126) (?2,023) (21,580) (21,542) (20.955) (21,224) (257,399) {62.223) {58,876) (62.857)!55.248} (G3.750) j!jq.z:g) (58.671) (3,244) {56,4) {46,6!>2) {63.291) (60,046) (652,040) $ 1,618,247 $ 1,619,4 $ 1,615,444 s 1,622,908 s 1,614,998 $ 1,780,253 $ 1,733,993 $ 1.789,524 $ 1, $ 1,746,556 $ 1,730,545 $ 1,733,521 20, $ 1,353,141 s 1,354,113 s 1,350,797 $ 1,357,03S $ 1,350,424 $ 1A88,607 s 1,'.49,925 $ 1,496,359 $ 1,452,273 $ 1,460A30 $ 1,447,042 $ 1,449,530 s 17,009,679 s (1,271,348) s \1 '160,753} $ (1,202,789) s (971,832) s (1,C>44,133) s (1,189,071) s (1,363,864) $ (1,224,872) s {1,064,928) s (860,274) s ( } $ (892,380) s (12,939,818) (2i,085j (18,8) (21.390) (20,437) (21,063) (19,770) (20.546) (20,'178) (20,012) (19,002) (15,019) (i5,849) (233,760) (255) (230] (273) (255) (286) (4ii7) (455) (456) (441) (390) (359) (369) (4,238) (19,407) (19,294) (17,604) (17,803) (17,680) (2.2,480) (28,137) (23,756) (18,239) (12,324) (11,221) {15,507} {2.23,453} (12,012) (11.023) (11,213) (8,769) (9,555) (11,455) {12,791) (11,729) (9,512) (6,962) (5,145) (6,395) (116,664) {238,8..~5) ( ) ( ) (204,0/1\ (226!049) (187,495) ( ) (205,7"4) 1204,37-,) (195,092) f221.7e6) (197,297) (21530, 157) (1,552,941) (1,431,186) (1,473,976) (1,223,527) (1,318,866) (1,430,728) (1,638,029) (1,487,336) {1,317,50-1) (1,094,043) (947,255) (1,127,799) s (16,054,091) s (1,239,991) $ (1,135,460) $ (1, 169,409) s (970,943) s (1,046,349) $ (1,135,097) $ (1,300,039) s (1,180,007) s (1,045,268) $ (867,981) $ (751,524) $ (894,762) $ (12,73,834) ~ (18,452) $ (41,419) $ (29,806) s (41,755) s (36,302) s (45,76i) $ (81,883) s (49,129) $ 435,816 $ (19 1,838) $ 155,560 s (126,982) s (76.654) $ (14,639) $ {32,880) $ (23,647) $ (33,127) $ (26,801) $ (36.305}.$ (64,967) s (38,977) s 345,763 $ (154,578) $ $ {.1!,330) $ (60,974) s (31,984,221) $ (28,654,251) $ (32,066,465) $ (30,822,195) $ (31,929,913) $ (30,8413,213) $ (32,095,941) $ (31,922,445) s (30,444,304) $ (31,777,865) s {30,356,582) $ (31,704,186) s (374,606,581) s (2,603,290) $ (2,355,875) $ (2t 08t.i!90) s {2,524, 151) s (2,608,290) $ (2,524,151) s (2,608,290) $ (2,608,290) $ (4, 159,808) $ (4,298,469) $ (4,159,808) $ (4,298,469) s (37,362, 179) s 1, s 1,158,932 $ 1,283,159 L_1.241,767 $ 1,283,159 s 1,241,767 $ 1,283,159 $ 1,283,159 s $ _s! -_ $,058,311 $ (33,309,351) s (30,051,143) s (33,391,595) s (32,4,580) $ {33,255,044) $ (32,130,595) $ (33,421,071) $ (33,247,575) s (34,604,112) s (36,076,334) $ (34,516,391) $ (36,002,655) s (402,1,449) s 33,488,882 $ 30,671,088 $ 30,451,445 ~ 25,579,880 s 25,859,496 $ 30, $ 35,576,648 $ 31, s 1.7,611,175 s 26,743,727 s 29,507,796 $ 35,139,707 $ 362,368,1 179, ,945 $ (2,940,150) $ (6,524,700) $ (7,395,548) s {1,679,304) $ 2,155,576 s (1,960,613) s (6,992,937) $ (9,332,606) $ {5,oos,sgs) s (862,948) s ('39,742,348) 'Tj "t!cij:;e(j 0 (Jq "' -. ~ Q (1) 3 o n s a 0.(1)'0 - c:: (/) ~ - c 0 ;:;.;- >-+; ~CD~~ C/)...,_t:Jtn (') :::;- (1) - 3::::>< 0- ~ <~ c 0 \0 z ::>

79 Col. No. 1 Una No. DescripUon ~ Network Integrated Transmission System (NITS) A Transmlss[on Enhancement 2 Charges 3 Credits 4 Total Transmission Enhancement (lines 2 + 3) A A 5 Total Transmission Costs Per Compliance Filing {lines 1 + 4) 6 Network Integrated Transmission System (NITS) B Transmission Enhancement Charges Credits Total Transmission Enhancement {lines 7 + 8) B B Total Transmission Costs Per Current Filing (lines 6 + 9) Subsection A 4 Costs -Monthly Update Amount 11 Network Integrated Transmission System (NITS) (line 6 - line 1) Transmissron Enhancement 12 Charges (uno 7- 'ina 2) 13 Crodil< (line 8- line 3) 14 Total Transmission Enhancement (lines ) 15 Total Subsection A 4 Costs- Monthly Update Amount {lines ) Note A:. Subsection A 4 Cost ofservfce Compliance Filfng, PUE , Formura Schedule 2 Note B: formula Schedule 2- Current Fillng. Virginia Electric and Power Company Subsection A 4 Costs Subsection A 4 Costs Update Calculation For the Period January 1 through August 31, 2014.;; Annual Amount ;2 Daily Amouot ;1 Q z.q January-14 February-14 March-14 April-14 May-14 g.1q 11 June-14 July-14 Auqust-14 Subsection A 4 Costs Per Filing, PUE $384,920,492 $ 1,054,577 $32,691,877 s 29,528,147 $32,691,877 $31,637,301 $ 32,691,87! $ 31,63'1,301 $ 32,691,8?7 $32,691,877 $ 50,455,751 $ 138,235 $ 4,285,283 $ 3,870,578 $ 4,285,283 $ 4,147,048 $ 4,285,283 $ 4,147,048 $ 4,285,283 $ 4,285,283 {71,424,208) (195,683) (6,066, 166} (5,479,11:0 (6,066, 166) (5,870,483) (6,066, 166) _15,870,483) (6.066, 166) (6, ) $ (1 '780,883) $ (1,608,539) $ (1,780,883) $ (1,723,435) $ (1,780,883) $ (1,723.~5) $ (1,780,883) $ (1,780,683) $ 30,9,995 $ 27,919,608 $ 30,9,995 $ 29,913,866 $ 30,9,995 s 29,913,866 s 30,9,995 $ 30,9,995 Subsection A 4 Costs Per Current Filing $ 484,993,815 $ 1,328,750 $ 41,191,256 $ 37,205,005 $ 41,191,256 $ 39,862,505 $ 41 '191,255 $ 39,862,505 s 41,191,256 $ 41,191,256 $ 57,590,757 $ (1 03,486,957) 157,783 $ 4,891,270 $ (283,52il) (8.789,1 ) $ (3,898,033) $ 4,417,921 $ 4,891,270 $ 4,733,487 $ 4,891,270 $ 4,733,487 $ 4,891,270 $ 4,891,270 (7,938,725) _(,789,303) {8,505,777) (8,789,303) (8.505,777) (8,789,303) (8,789,303) (3,520,804) $ (3,898,033) $ (3.772,290) $ (3,898,033) $ (3,772,290) $ (3,898,033) $ (3,898,033) $ 37,293,222 $ 33,684,201 $ 37,293,222 $ 36,090,215 $ 37,293,222 s 36,090,215 $ 37,293,222 $ 37,293,222 s 8,499,378 $ 7,676,858 $ 8,499,378 $ 8,225,205 $ 8,499,378 $ 8,225,205 $ 8.499,378 $ 8,499,378 $ 605,987 $ 547,3~ $ 605,987 $ 586,439 $ 605,987 $ 586,439 s 605,987 $ 605,987 (2. 723,138) (2,4.."9,608) (2,723,138) (2,635,294) (2.723, 138) (2.635,294) {2. 723, 138) (2,723,138) $ (2,117,151) s (1,912,265) $ (2,117,151) $ (2,048,856) s (2,117,151) $ (2,048,856) s (2,117,151) $ {2,117,151) s 6,382,227 $ 5, 764,592 $ 6,382,227 $ 6,176,349 $ 6,382,227 $ 6.176,349 $ 6,382,227 $ 6,382,227 "0 'Tj 0 ()q "' <> 3..., [/) - c 0 :;;- (') ;:J" (1) c. -0 c 0 _g Total $256,262,136 $ 33,591,089 (47.550,911i $ {13,959,822) $242,302,314 $ 322,885,293 $ 38,341,244 {68,896,795) $ (30,5$5,552) $292,330,741 $ 66,524,157 s 4,750,155 (21,34.5,885) $ (16,595,730) s 50,028,427 "'C/l:E() ~ & ~ 0 <> <> ;:J 3 ~s~~ 0 ~ ~...,-om - S:x -!'- :E2: [. z!='

80 Company Exhibit No. Witness: DMW Schedule 2 Page 1 of 1 Virginia Electric and Power Company Rider T1 Rate Adjustment Clause Comparison of Current Rider T Rates in Effect Projected Over Rate Year With Subsection A 4 Costs Virginia Jurisdiction Formula Schedule 11 Page 1 of 1 Component Current Subsection A 4 Rates Included In Base rates In Effect Projected Over 2014/2015 Rate Year Subsection A 4 Costs Rider T1 Increment!( Decrement) RAC Subsection A 4 Revenue Requirement $ 488,266,973 1 $ 538,019,256 $ 49,752,283 1 Per CompanyWrt.ness Haynes's Testimony~ Transmission Revenues projected over Rate Year ended August 31, 2015, based on rates currently in effect as approved in Case No. PUE

81

82 DIRECT TESTIMONY OF JAMES D. JACKSON, JR. ON BEHALF OF VIRGINIA ELECTRIC AND POWER COMPANY BEFORE THE STATE CORPORATION COMMISSION OF VIRGINIA CASE NO. PUE Q. 2 3 A Please state your name, business address, and position with Virginia Electric and Power Company ("Dominion Virginia Power" or the "Company"). My name is James D. Jackson, Jr., and my business address is 701 East Cary Street, Richmond, Virginia I am a Regulatory Consultant in the Electric Transmission Policy Group for Dominion Virginia Power. A statement of my background and qualifications is attached as Appendix A. 7 Q. 8 A Please describe your areas of responsibility with the Company. I am actively involved in regulatory policy issues related to electric transmission on behalf of Dominion Virginia Power including: (1) updating part of the Company's Federal Energy Regulatory Commission ("PERC") formula rate regarding transmission project costs; (2) advising on customer information requests; (3) advising on transmission rate and cost allocation proposals, as well as other PERC matters that could affect the Company's transmission costs; and (4) providing regulatory support in the Company's rate adjustment clause ("RAC") filings for cost recovery under A 4 ("A 4" or "Subsection A 4") of the Code of Virginia ("Va. Code") before the State Corporation Commission of Virginia (the "Commission").

83 1 Q. 2 A Will you be introducing any exhibits with your testimony? Yes, I have prepared Company Exhibit No._, JDJ, consisting of Schedules 1 and 2, which is accurate and complete to the best of my knowledge and belief. References to bank account information for PJM Interconnection, L.L.C. ("PJM") in Schedule 1 have been redacted for relevance by counsel consistent with such treatment in last year's Rider T1 proceeding, Case No. PUE (the "2013 Rider T1 Case"). I am also sponsoring Filing Schedule 46B, which is included in the Company's Application pursuant to the Commission's Rules Governing Utility Rate Applications and Annual Informational Filings, 20 VAC , et seq. Q A Is Filing Schedule 46B organized in the same manner as it was in the Company's previous Subsection A 4 RAC proceedings? Yes, it is. Consistent with the Commission's grant of an ongoing limited waiver in Case No. PUE (the "2012 Rider T1 Case"), Filing Schedule 46B contains only those relevant FERC orders that were issued since the 2013 Rider T1 Case. In other words, the Filing Schedule 46B that I am sponsoring in this proceeding contains only the interim relevant FERC orders that were not previously included in Filing Schedule 46B in earlier Rider T and T 1 cases Consistent with the approach used in the 2012 and 2013 Rider T1 Cases, to ensure that the Commission continues to receive complete information about older FERC dockets that are relevant to Subsection A 4 cost recovery, but not included in Filing Schedule 46B because no new relevant orders affecting Subsection A 4 cost recovery were issued therein, I am continuing to list- as I have in the Company's past Rider T and T 1 2

84 1 2 cases - all of the dockets pertaining to the FERC-approved tariffs forming the basis for cost recovery under Subsection A 4. 3 Q. 4 A Please describe the purpose of your testimony in this proceeding. The purpose of my testimony is to provide detailed information supporting the revenue requirement that the Company is seeking to recover in this proceeding through a combination of the Subsection A 4 component of base rates (the Company's former Rider T) and a Subsection A 4 RAC, labeled Rider T1, from Virginia jurisdictional retail customers for the twelve-month rate year beginning September 1, 2014 (the "Rate Year"). More specifically, as in previous Rider T and Rider T1 cases, I will: (1) give an overview of PJM, the regional transmission entity of which the Company is a member; (2) describe the Subsection A 4 services and programs provided and administered by PJM; and (3) discuss for purposes of the statute and cost recovery how these Subsection A 4 services and programs are charged to the Company by PJM under rates, terms, and conditions approved by the FERC for the purpose of serving Virginia jurisdictional retail customers As discussed by Company Witness David M. Wilkinson, the Rider T1 presented in this case is designed to recover the new increment/decrement between the revenues produced from the current Subsection A 4 component of base rates resulting from the 2011 Rider T approved by the Commission in Case No. PUE (the "2011 Rider T Case"), and the new revenue requirement developed from the Company's Subsection A 4 costs for the Rate Year presented in this Application. 3

85 1 2 3 Subsection A 4 states that the following costs "shall be deemed reasonable and prudent" and recovered "on a timely and current basis" from customers under Subsection A 4: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission, and (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member. Consistent with the Commission's Final Order dated June 29, 2009 in Case No. PUE (the "2009 Rider T Case"), as explained herein, the Company is again not seeking recovery of certain PJM-related administrative charges in this case. 14 Q A Please describe the function of PJM and the general nature of the services that it provides. PJM is a FERC-approved regional transmission entity (to use the statutory language in Subsection A 4) or regional transmission organization ("RTO") that coordinates the movement of wholesale electricity in all or parts of thirteen states and the District of Columbia. It acts independently in managing the regional transmission system and wholesale electricity market. Accordingly, PJM ensures the reliability of one of the largest centrally dispatched electrical grids in North America. It has more than 800 members - including power generators, transmission owners, electric distributors, power marketers, and large consumers. PJM's operations include balancing electricity supply and demand, conducting dispatch operations, and monitoring the status of a grid comprising of approximately 63,000 miles of transmission lines. Thus, PJM has a broad view of regional conditions and reliability issues, including those in neighboring 4

86 systems. PJM's organized electricity market coordinates the continuous buying, selling, and delivery of wholesale electricity through competitive spot markets, and PJM further monitors market behavior. It also provides on-line tools that enable members/customers to submit bids and offers that facilitate trade, and supplies continuous real-time data to such entities Additionally, PJM manages a comprehensive planning process for generation and transmission expansion to ensure the continued reliability of the electric system. It is responsible for managing changes to the grid to accommodate new generating plants, substations, and transmission lines. PJM analyzes and forecasts the future electricity needs of the region, and its planning process ensures the growth of the system, so that reliability is maintained Finally, PJM has developed both emergency and economic load response programs. The PJM Emergency Load Response Program enables load management resources (i.e., resources with demonstrated capabilities to provide reductions in demands or to otherwise control loads) to receive payments for reducing load during emergency conditions. The PJM Economic Load Response Program, in turn, enables load management resources to receive payments for reducing consumption in response to PJM market prices for electricity. 19 Q. 20 A Please describe how the Company interfaces with PJM. Like several other PJM members, the Company provides its retail customers with generation and distribution services, and fulfills many of its retail customer obligations - including the provision of transmission and ancillary services -through its 5

87 participation in the RTO. Upon its May 2005 integration into PJM, the Company ceased to be a control area operator and transferred its control area and balancing authority obligations to PJM, which is now responsible for those obligations. Thus, the Company's former control area became what is now known as the Dominion control zone (the "Dominion Zone" or "Dom Zone") Once the Company joined PJM, PJM started providing services to the Company under the PJM Open Access Transmission Tariff ("PJM OATT"), thereby eliminating services that the Company had previously provided for itself pursuant to its own Open Access Transmission Tariff in effect before integration. The PJM OATT is a PERC-approved tariff that governs the rates, terms, and conditions of the markets and services administered and provided by the RT As a member of PJM, the Company is viewed as having four different primary accounts: Load Serving Entity ("DOMLSE"), Generation Owner ("DOMGEN"), Electric Distribution Company ("DOMEDC"), and Curtailment Service Provider ("DOMCSP") Relevant to Rider T1, each of these accounts is billed charges by (or receives credits from) PJM for services and programs as described below. The Company is an electric distribution company ("EDC") within the Dominion Zone, and one of six load serving entities ("LSEs") currently providing electric service to retail customers within the Dominion Zone. The Company's LSE function, DOMLSE, obtains transmission, 1 See < for a copy of the PJM OATT. 6

88 1 2 capacity, energy, and ancillary services from PJM and the markets that PJM administers, and the DOMLSE account is charged by PJM for these services As a Generation Owner, the Company provides electric generation, capacity, and energy, as well as generation-related ancillary services, to the markets administered by PJM, and the DOMGEN account receives credits from PJM for these services As a Transmission Owner, the Company has turned over operational control of its transmission system to PJM, and the DOMEDC account receives credits from PJM for use of the Company's transmission facilities. Both PJM as a Transmission Provider, and the Company as a Transmission Owner, are subject to the PERC-approved mandatory reliability standards established and enforced by the North American Electric Reliability Corporation ("NERC") Finally, the Company established the DOMCSP account so that it could enter demand-side resources, a term used here interchangeably with load management resources, into PJM's capacity markets Q. Please generally describe how PJM assesses charges and credits to the Company. A. The costs of providing services to PJM market participants are charged according to the PERC-approved PJM OATT. 2 PJM applies these tariff rates to the various generation and load billing determinants as specified in the PJM OATT. As part of the PJM 2 In Electronic Tar(ff Filings, Order No. 714, 124 FERC Cj{ 61,270 (2008), the FERC adopted regulations requiring that tariffs and tariff-related filings be made electronically. As part of its transition to electronic tariff filings, the FERC required that regulated entities make "baseline" tariff filings, which were to reflect existing accepted tariffs with no proposed substantive changes or revisions. In compliance with this directive, PJM submitted its baseline filing on September 17,20 and has since amended it on several occasions. This baseline filing contained every sheet in the PJM OATT that had been accepted up to that date, and provided a starting point for electronic maintenance of the PJM OATT in FERC' s etariff database. The FERC accepted PJM' s baseline filing by order issued December 20, 20 in Docket No. ER-27. 7

89 1 settlement process, PJM charges and credits DOMLSE, DOMGEN, and DOMCSP for 2 services provided to and by the Company on behalf of its wholesale and retail 3 customers within the Dominion Zone. The monthly charges incurred by the Company 4 include all applicable tariff rates under the P JM 0 A TT, applied to the various billing 5 determinants for the DOMLSE, DOMGEN, and DOMCSP functions. Portions of 6 these billing determinants are directly related to the load requirements of the Virginia 7 jurisdictional retail customers served by the Company. Likewise, the Company 8 receives monthly credits for services that the Company provides in return under the 9 PJM OATT and the PJM Operating Agreement (the provisions of Schedule 1 of this agreement are included in Attachment K of the PJM OATT) through the DOMLSE, 11 DOMGEN, DOMEDC, and DOMCSP accounts. 12 For reference, a copy of PJM's monthly billing statement to the Company for January is attached as Schedule 1. This statement shows the various PJM charges and 14 credits broken out by each of the Company's functions and accounts. I will discuss 15 later in more detail, using Schedule 1, the particular charges and credits billed by PJM 16 that are appropriate for recovery through Subsection A As explained by Company Witness Wilkinson, the costs described in Subsection A 4 18 that the Company is seeking to recover in this proceeding are derived from the 19 FERC-approved tariff rates contained in the PJM OATT. These Subsection A 4 costs 20 are identified from PJM's monthly billing statements (included in Filing Schedule 21 46A, which he sponsors). Mr. Wilkinson further explains how these costs are allocated 22 or assigned to Virginia jurisdictional customers. 8

90 1 2 3 I will now discuss these PJM charges and credits below on a functional basis (i.e., on the basis of DOMLSE and DOMGEN), and not according to those portions that are allocated or assigned to Virginia retail jurisdictional customers. 4 Q. 5 6 A As a preliminary matter, does Subsection A 4 specify the FERC-approved, RTO-related costs subject to recovery through an A 4 RAC? Yes. The PERC-approved, RTO-administered costs identified for recovery under Subsection A 4 include "without limitation, costs for transmission service, charges for new and existing transmission facilities, administrative charges, and ancillary service charges designed to recover transmission costs," as well as "costs charged to the utility that are associated with demand response programs..." Q. Please provide a detailed definition of, and PJM OATT reference for, each of these Subsection A 4 categories of costs. 13 A The following definitions and references apply to the Subsection A 4 categories of costs expressly identified in the statute: 1. "costs for transmission service" -These costs comprise the PERC-approved Annual Transmission Revenue Requirement ("ATRR") associated with the transmission facilities in a specific PJM zone. For the Dominion Zone, the ATRR includes costs for the existing transmission system and costs for new transmission facilities that will be placed into service during the rate year. These costs are currently recovered from customers pursuant to Section 34, "Rates and Charges", of the PJM OATT using the Network Integration Transmission Service ("NITS") rate for the Company. The Company's NITS rate is determined in accordance with Attachment H-16A of the PJM OATT, and the applicable formula rate implementation protocols in Attachment H-16B of the PJM OATT. 9

91 In FERC Docket No. EL-49, the inclusion of the costs for certain transmission facilities in the calculation of the Company's NITS rate is being challenged on the basis that these facilities do not benefit certain network customers in the Dominion Zone. If the proceedings in Docket No. EL-49 result in the PERC's exclusion of any facilities from the Company's ATRR, the Company will directly assign the costs of those facilities to the customers who benefit from them and will seek to recover the cost of such facilities through direct assignment charges, effective as of the date on which they are excluded from the ATRR, pursuant to a filing under Section 205 of the Federal Power Act, such that the ultimate effect would be a reallocation (not an increase or decrease) of recoverable costs among customers. Any such direct assignment charges billed by PJM to the Company would also be costs for transmission service included for recovery under Subsection A 4. On May 18, 2012, the FERC approved an uncontested settlement in Docket No. EL-49, resolving the cost allocation of all of the transmission facilities set for hearing in that case except for the costs of undergrounding the Garrisonville, Pleasant View-to-Hamilton, and DuPont Fabros projects (the "UG Projects"). As part of this settlement, the Company incurs an additional charge for transmission service, included in Attachment H-16AA of the PJM OATT Regarding the incremental undergrounding cost of the UG Projects, the FERC issued its Order on Reserved Issue on March 20, 2014 that could have an impact on future Subsection A 4 costs. Rather than allocating the costs to only DOMLSE as the complainants in that docket proposed, or to all NITS customers with loads in the Dominion Zone as is currently being done, the FERC found that it is not just and reasonable to allocate the costs of undergrounding to wholesale transmission customers beyond those NITS customers with Virginia loads in the Dominion Zone, and ordered hearing and settlement procedures to reallocate these costs effective March 17, 20. Specifically, these procedures are to determine the appropriate amount of undergrounding costs to be allocated to each NITS customer for its Virginia load in the Dominion Zone. These procedures are in the early stages; accordingly, the FERC has not yet approved a specific amount of costs to be

92 reallocated to DOMLSE and other NITS customers for their Virginia loads in the Dominion Zone. 2. "charges for new and existing transmission facilities" - These costs are associated with the FERC-approved annual revenue requirements of required transmission enhancements (or baseline transmission projects) developed in accordance with PJM's Regional Transmission Expansion Plan ("RTEP"). The RTEP is developed annually pursuant to Schedule 6 of the PJM Operating Agreement. The subject transmission project costs are allocated by PJM to the various transmission zones within PJM in accordance with allocation methods approved by the FERC. The allocation factors used are set forth in Schedule 12- Appendix and Schedule 12- Appendix A of the PJM OATT. The annual revenue requirement for any transmission project to be charged in accordance with Schedule 12 (with crediting to assure no duplication of costs recovered in the NITS rate) is included in either a formula rate annual update or a separate rate filing approved by the FERC, as described in detail below. In the case of a transmission enhancement needed to alleviate the reliability impact of a deactivating generating unit, NITS customers that are allocated a share of the costs of such reliability upgrade are, in accordance with Part V of the PJM OATT, allocated a share of any additional transmission charge to compensate such a deactivating generator owner for its costs incurred while delaying deactivation beyond its desired deactivation date. In addition to being charged for certain transmission enhancements as discussed above, NITS customers are now incurring a charge under Schedule of the PJM OATT for the costs allocated to PJM for a portion of the revenue requirement associated with the International Transmission Company's ("ITC's") Phase Angle Regulators ("PARs"). Mr. Wilkinson also refers to these costs in his pre-filed direct testimony as the Michigan-Ontario PARs Charges. 3. "administrative charges"- These charges are intended to recover the costs associated with operating PJM, and for funding various organizations through 11

93 schedules included in the PJM OATT. These charges are included in Schedule 9 of the PJM OATT and its subsidiary schedules. A more detailed description of administrative charges for which the Company is seeking recovery through Subsection A 4 is provided later in my testimony "ancillary service charges designed to recover transmission costs"- PJM charges these costs for the Transmission Owner Scheduling, System Control, and Dispatch Service ancillary services provided in accordance with Schedule 1A of the PJM OATT. The Company currently recovers these costs through its NITS rate, which is discussed above, and therefore does not have a separate rate included in this Schedule 1A Q. A. 5. "costs charged to the utility that are associated with demand response programs approved by the [FERC]"- These are the costs related to PJM's demand response programs. Currently, PJM administers two such programs- the Economic Load Response Program and the Emergency Load Response Program. The rates associated with these demand response programs are determined in accordance with Section 3.3A of Attachment K-Appendix of the PJM OATT, the very last section of that same attachment (labeled "PJM Emergency Load Response Program"), and Attachments DD and DD-1 of the PJM OATT. I will provide a more detailed description of these programs later in my testimony. Please describe the PJM billing process for transmission service costs. DOMLSE purchases transmission service for customers served by the Company based upon their contribution to the metered demand coincident with the Dominion Zone peak hour for the annual period ending October 31 of the prior calendar year. This is shown as NITS charges on the PJM monthly billing statements to the Company, which PJM bills in accordance with Section 34 of the PJM OATT. Section 34, approved in FERC Docket Nos. EL02-121, et al.; EL05-127, et al.; EL06-55, et al.; ER-27; and ER describes the "Rates and Charges" pertaining to NITS provided 12

94 pursuant to the PJM OATT. The Company's NITS rate, approved by the FERC in Docket No. ER08-92, as revised in Docket Nos. ER-557, ER-27, ER , and ER , includes the formula for determining the cost of service, or ATRR, associated with the existing transmission system and with new transmission projects being constructed by the Company that are planned to be in service during the calendar year that the rate is charged. For example, during the 2014 calendar year, the ATRR would include new transmission facilities placed in service during that year. As approved by the FERC in Docket Nos. ER and ER , some of these planned transmission projects include "Incentive Return on Equity ("ROE") Adders" in accordance with FERC guidelines as defined in Section 219 of the Federal Power Act 3 and FERC Order Nos. 679, et al. 4 The costs of the Incentive ROE Adders for PJM non-rtep baseline projects are recovered from customers through the Company's NITS rate As I previously noted, the Company's NITS rate is determined in accordance with Attachment H-16A of the PJM OATT and applicable formula rate implementation protocols in Attachment H-16B. The specific NITS rate and ATRR are updated each year and posted publicly on PJM's website. 5 All LSEs in the Dominion Zone, including DOMLSE, receive a share of the revenues that PJM receives for providing both firm and non-firm point-to-point transmission services. These revenues are included as credits on the monthly PJM invoices and have the effect of reducing the cost of such transmission services U.S.C. 825s. 4 Promoting Transmission Investment through Pricing Reform, Order No. 679, 116 PERC'][ 61,057, order on reh'g, Order No. 679-A, 117 PERC~[ 61,345 (2006), order on reh'g, 119 PERC~[ 61,062 (2007). 5 See < 13

95 For example, Schedule 1, page 2 of 17, line 10 shows that the NITS charge to DOMLSE for January 2014 was $49,885,470. Comparably, Schedule 1, page 5, line 2130 shows the January 2014 credit for Firm Point-to-Point Transmission Service of $814,162 and, on line 2140, the January 2014 credit for Non-Firm Point-to-Point Transmission Service of $207,590. On line 2140A on that same page, there is an additional adjustment to the credits to DOMLSE of $3,660 for Non-Firm Point-to-Point Transmission Service. The NITS charges and credits for point-to-point transmission service are netted together to determine the costs recoverable under Subsection A 4. For reference, in Table 1 of Schedule 2, page 1, I show how the NITS charge to DOMLSE is calculated for the month of January Accordingly, the $49,885,470 amount shown on line 6 oftable 1 is the same amount shown on line 10 of the January 2014 bill to the DOMLSE account. 13 Q. 14 A Please now describe the PJM billing process for RTEP transmission facilities. The PJM RTEP process is a joint transmission planning process developed to meet the transmission needs in the PJM Region on a reliable, economical, and environmentally acceptable basis. It identifies system upgrades and enhancements required to preserve the reliability of the electrical grid for a region encompassing multiple transmission owner systems. Transmission projects identified in the RTEP process are charged and credited in accordance with Schedule 12 of the PJM OATT, and included on the monthly PJM invoices as Transmission Enhancement Charges ("TEC") The TEC consist of two components. The first is a charge that occurs when DOMLSE is billed by PJM for the DOMLSE-allocated portion of the revenue requirements for RTEP projects constructed by all transmission owners in PJM, including the 14

96 1 Company's own projects approved for rate recovery by the FERC. The second 2 component is a credit to compensate DOMLSE for its allocated share of the revenues, 3 excluding any Incentive ROE Adders revenues, for RTEP baseline projects constructed 4 by the Company, whether such revenues are paid by LSEs that serve loads in the 5 Dominion Zone or by LSEs that serve loads in other PJM zones. The distribution of 6 these RTEP project charges and credits is described in Schedule 12, including Schedule Appendix and Schedule 12- Appendix A, of the PJM OATT. These charges and 8 credits, in turn, were approved by the FERC in the following dockets: ER04-156, 9 ER05-513, EL05-121, EL , EL , ER05-6, EL04-135, EL02-111, EL03-212, ER06-880, ER06-456, ER06-954, ER , ER07-424, EL07-57, 11 ER09-204, ER09-484, ER09-497, ER09-913, ER-268, ER-529, ERI0-549, 12 ERI0-893, ER-907, ER-27, ER , ER , ER , ER , 13 ER , ER12-445, ER12-745, ER12-773, ERll-36, ERll-4367, ER , 14 ER , et al., ER , ER , ER , ER , ER , 15 ER13-673, ER13-703, ER13-90, ER , ER14-274, and ER The annual revenue requirements that support the TECto DOMLSE were calculated in 17 accordance with formulas set forth in subparts of Attachment H of the PJM OATT and 18 approved by the FERC. The specific Attachment H subparts of the PJM OATT, the 19 transmission owner companies, and docket numbers of the cases approving the annual 20 revenue requirements used to calculate the TEC to DOMLSE are identified as follows: 21 Attachment H-1 (Atlantic City Electric Co.), FERC Docket Nos. ER05-515, 22 ER07-913, ER , and ER-27; Attachment H-2 (Baltimore Gas and Electric 23 Co.), FERC Docket Nos. ER05-515, ER07-576, ER-27, and ER12-306; 15

97 1 Attachment H-3 (Delmarva Power & Light Co.), FERC Docket Nos. ER05-515, 2 ER07-914, ER , ER-27, ER13-607, and ER , -001 and -002; 3 Attachment H-8 (PPL Group), FERC Docket Nos. ER , ER-152, 4 ER-1209, ER-27, ER , and ER13-26; Attachment H-9 (Potomac 5 Electric Power Co. orpepco), FERC Docket Nos. ER05-515, ER07-912, ER , 6 ER-27, ER13-607, and ER , -001 and -002; Attachment H- (Public 7 Service Electric and Gas Co.), FERC Docket Nos. ER , ER-159, ER-27, 8 ER , ER , ER12-296, ER , ER , ER and -001, ER and -003, and ER14-621; Attachment H-14 (AEP-East Operating Companies), FERC Docket Nos. ER , ER-27, ER , 11 ER , and ER13-41; Attachment H-16 (Virginia Electric and Power 12 Company), FERC Docket Nos. ER08-92, ER-557, and ER-27; Attachment 13 H-18 (Trans-Allegheny Interstate Line Co. or "TrAILCo"), FERC Docket Nos. 14 ER07-562, ER08-958, ER09-600, ER , ER-1243, ER-27, ER , 15 ERll , and ER ; and Attachment H-19 (Potomac-Appalachian 16 Transmission Highline, L.L.C. or "PATH"), FERC Docket Nos. ER08-386, 17 ER , ER-1363, ER-27, ER , ER , ER12-79, 18 EL12-85, ER , ER , and ER In addition to the order in 19 Docket No. ER-27 approving PJM's baseline filing that contained these 20 attachments (see supra text accompanying footnote 2), the FERC also approved 21 corrections to PJM's baseline filing in Docket Nos. ER and ER In Table 2 of Schedule 2, page 1, I show how the TEC to DOMLSE were calculated for 23 the month of January This charge is based on the TEC (PJM OATT Schedule 16

98 1 12) settlement worksheet that PJM publicly posted on its website in late February I have included this worksheet as Schedule 2, Pages On Schedule 2, Page 11, I 3 have modified this PJM worksheet slightly by including an additional line at the very 4 bottom reading "Total TECto Dominion Zone," with a total amount of $7,277,5. 5 As a Network Customer (i.e., a customer taking NITS) serving load in the Dominion 6 Zone, DOMLSE is allocated a load ratio share of this total. As shown on Schedule 2, 7 Page 1, Table 2, the application of the allocation factor to the Total TEC to the 8 Dominion Zone based on DOMLSE's megawatt ("MW") contribution to the Dominion 9 Zone Network Service Peak Load results in total TEC of $6,339,497 to DOMLSE. That charge to the DOMLSE account, in turn, is shown in line 18 on Page 2 of 11 Schedule 1. On Schedule 1, page 3, line 18A, there is also an ($82,692) adjustment 12 to the Transmission Enhancement Charge. This adjustment was for refunds paid 13 pursuant to a PERC audit of FirstEnergy Corp. involving their PATH and TRAIL 14 transmission projects. 15 As described in Schedule 12 Parte, "Crediting of Revenue from Transmission 16 Enhancement Charges", of the PJM OATT, network customers in a Transmission 17 Owner's Zone are allocated a share of the revenue from the Transmission Owner's 18 TEC, provided that such amounts are reduced by any applicable incentives included in 19 such TEC. As shown at the bottom of the Monthly Revenue Requirement column in 20 Schedule 2, Page 8 for the Dominion Virginia Power RTEP projects, the total revenue 21 requirement from the Company's total TEC is $12,907,335. Carrying this amount to 22 Column A of Table 3 of Schedule 2, Page 1, and then subtracting from it the monthly 23 amount of $477,753 of Transmission Enhancement incentive credit to DOMEDC 17

99 (shown on line 28, Page 14 of Schedule 1), results in $12,429,583 of revenue to be allocated to the Network Customers in the Dominion Zone. Applying the DOMLSE load ratio share allocation factor to this amount results in $,827,509 being allocated to DOMLSE, which is the credit amount shown on line 28, Page 5 of Schedule 1. 5 Q A What are the costs of new facilities that the Company has projected to be added to transmission plant in service for 2014 that were used to calculate the 2014 NITS rate? The Company has projected approximately $838 million of additions to transmission plant in service that was used to calculate its 2014 NITS rate. This amount was offset by retirements and other adjustments, resulting in $805 million of projected net additions to transmission plant in service for Of the $838 million amount, approximately $620 million is for RTEP baseline reliability projects that are required by PJM, and the remaining $218 million is for transmission delivery facilities, equipment needed to meet Company reliability requirements, and to support FERC reliability and equipment protection requirements Notably, approximately $364 million of the $620 million of baseline reliability project costs are associated with projects that have a portion of their annual revenue requirement allocated by PJM to at least one PJM Zone that is not the Dominion Zone. 19 Q A. 22 Please describe the additional transmission charge to compensate Generator Owners pursuant to Part V of the PJM OATT. Briefly, Part V of the PJM OATT (approved in Docket No. ER-27) sets forth procedures that allow Generator Owners to be compensated for delaying deactivation 18

100 of generating units beyond the desired deactivation date. A Generator Owner provides notice to PJM that it is going to deactivate a unit on a desired date, and then PJM studies the impact on the transmission system to determine if any needed transmission can be built as a result of the deactivation prior to such desired date. If needed transmission cannot be built before the desired deactivation date, and if PJM determines that it is good utility practice to pay the deactivating generator owner to defer its deactivation date and have its generation unit become subject to PJM' s dispatch, PJM will then compensate the Generator Owner according to a formula in Part V of the PJM OATT. To provide the funds for this compensation, in accordance with Section 130 of Part V of the PJM OATT, an additional transmission charge is allocated to the load in the Zone(s) of the Transmission Owner(s) that will be assigned financial responsibility for the reliability upgrades necessary to alleviate the reliability impact that would result from the deactivation of the generating unit. This new charge is then collected monthly from such loads in addition to all other charges for transmission service to such loads For example, as shown on line 1930 A, Page 4 of Schedule 1, the DOMLSE account was charged $59,861 in January 2014 as a result of the Company's financial responsibility for reliability upgrades necessary to alleviate the reliability impact resulting from the deactivation of units owned by FirstEnergy Generation Corporation. It should be noted that if PJM had not determined that the Dominion Zone should be allocated any costs for these reliability transmission upgrades, then the Company would not have incurred a share of the additional transmission charge to recover the 19

101 1 2 FirstEnergy Generation Corporation Generator Deactivation costs that were accepted for filing by the FERC in Docket No. ER Q. A. Did the FERC recently accept two PJM-related compliance filings resulting from its Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities Order No. 00, and does acceptance of those filings change the costs subject to recovery under Subsection A 4 in this case? Yes, the FERC conditionally accepted PJM' s compliance filing in Docket No. ER and the PJM Transmission Owners' compliance filing in Docket No. ER13-90, which added a new Schedule 12- Appendix A. This schedule is similar to the existing Schedule 12- Appendix, except that it will include the RTEP projects that are to be cost allocated in accordance with the Order No. 00 principles for intraregional cost allocation approved by the FERC. While the FERC has conditionally accepted the cost allocation proposal filed by the PJM transmission owners that will be implemented by PJM, it is effective for the allocation of RTEP baseline transmission projects approved by the PJM Board on and after the February 1, 2013 effective date. In Docket No. ER14-274, the FERC conditionally accepted PJM's cost allocations for RTEP projects included in Schedule 12- Appendix A. Some of these project costs were allocated to the Dominion Zone, but none of the costs of these projects are currently being included in the transmission expansion charge to DOMLSE and, accordingly, are not part of the A 4 costs in this case. 20

102 1 Q A In addition to the Order No. 00 compliance filings discussed above, did the FERC recently accept any PJM-related compliance filings involving Order No. 00 interregional cost allocation, and does acceptance of those filings change the costs subject to recovery under Subsection A 4 in this case? Yes. In Docket No. ER , the FERC conditionally accepted the PJM Transmission Owners' proposed cost allocation method included in a new Schedule 12-B of the PJM OATT relating to the allocation of costs of interregional transmission system expansions and enhancements approved by PJM and participants in the Southeastern Regional Transmission Planning (SERTP) region. On January 1, 2014, Schedule 12-B became effective subject to refund and to future orders in PJM's and SERTP's related Order No. 00 interregional compliance proceedings. However, no costs relating to such interregional projects have been allocated to the Dominion Zone; therefore, this order does not impact the cost allocations of transmission facilities subject to Section A 4 cost recovery in this case. 15 Q A Please describe the additional charge to the Company for transmission service arising from the uncontested settlement in FERC Docket No. EL-49. As a part of this settlement, Attachment H-16AA of the PJM OATT was established in FERC Docket No. ER It contains an additional charge for transmission service, referred to by Company Witness Wilkinson as the Dominion Settlement Charge, of $20, per month that is to be charged for 120 consecutive calendar months. Beginning on July 1, 2012, this amount was charged to the DOMLSE account (as shown on line 1956 A, Page 4 of Schedule 1) on behalf of the Company's retail customers in Virginia. The funds from this charge are paid to the wholesale customer 21

103 settling parties in Docket No. EL-49 pursuant to Attachment H-16AA. For example, as shown on line 19S6 A, Page 4 of Schedule 1, DOMLSE was charged $20,833 for the January 2014 billing period and this same amount for the December 2013 billing period. s S Q. A. Please describe the charge to transmission customers under the PJM Schedule -Michigan-Ontario Interface OATT sheet. In Docket Nos. ER and ER , the FERC approved a new Schedule - Michigan-Ontario Interface PJM OATT sheet that became effective on AprilS, 2012, subject to refund, that allows PJM to recover the costs of PAR transformers owned by ITC from customers using NITS and Point-to-Point transmission service under the PJM OATT. The FERC approved the allocation of a portion of the ITC PARs costs to load in the PJM region, subject to refund, pending settlement and hearing procedures in Docket No. ER The FERC authorized the Midwest ISO ("MISO") to begin charging PJM for a portion of the ITC PARs costs on AprilS, 2012, the date on which the ITC PARs became operational. This Schedule provides for a $/megawatt-hour ("MWh") ITC PARs Rate which is charged monthly to all transmission users in PJM, including the Company. Accordingly, the DOMLSE account is charged monthly based on the MWh of transmission energy delivered to the Company's network load during the month. For example, as shown on line 1911 A, Page 4 of Schedule 1, DOMLSE was charged an adjustment for December 2013 ITC PARs costs, which is referred to as Michigan-Ontario Interface Phase Angle Regulators on the monthly PJM invoice, in the amount of $21,088 for the January 2014 billing period. 22

104 Q. A. Please describe the PJM administrative charge and the related billing process for that charge. The PJM administrative charge is recovered through various rates for the multiple services provided to the RTO's market participants, including the Company. The detailed administrative charges are shown in the monthly PJM invoice for January 2014 provided as Schedule 1. The charges and credits to the DOMLSE account are shown in lines 1301 through 1316 and lines 1440 through 1446 on pages 2-3 of Schedule 1. Likewise, the charges to the DOMGEN account are shown in lines 1301 through 1314 on page 8 of Schedule 1. Notably, there are adjustments to some of these charges, as indicated on the PJM invoice by the letter A after a particular line number. The administrative costs of operating PJM are recovered in PJM OATT Schedules 9-1 through 9-6, which were modified by a settlement agreement in FERC Docket No. ER , and otherwise accepted in FERC Docket Nos. ER04-548, EL06-55, EL05-148, ER05-14, ER-478, ER-893, ERl0-27, ER , ER , and ER Additionally, other administrative charges are included in the PJM OATT that have been approved by the FERC, and that provide funding for the Market Monitoring Unit (Schedule 9-MMU), the FERC itself (Schedule 9-FERC), Organization of PJM States, Inc. (Schedule 9-0PSI), Finance Committee Retained Consultant (Schedule 9-FINCON), and NERC (Schedule -NERC) The rates charged to PJM market participants, including the Company, are based on billing determinants reflecting the individual services provided. The rates for Schedules 9-1 through 9-5 are stated in these schedules. The revenues collected under the rates stated in these schedules that are in excess of PJM's expenses, plus a six 23

105 percent reserve, is refunded. In accordance with the first amendment to the settlement agreement in Docket No. ER , which the FERC permitted to become effective on April 1, 2008 in Docket No. ER08-528, such refunds are now determined and refunded quarterly rather than annually. The rates at issue are reviewed by both the PJM Finance Committee and the PJM Members Committee and are described in more detail below. To the extent that administrative fees are billed based on previous scheduled usage, such usage is reconciled to actual usage based on metered data, and a credit or charge reflecting this reconciliation is shown on the monthly PJM billing statements. Beginning October 1, 2011, the stated rates for Schedules 9-1 through 9-5 decreased by approximately 3.3% as a result of a filing that PJM made in Docket No. ER to change rates to reflect the integration of American Transmission Systems, Inc. ("ATSI") and ATSI utilities- namely The Cleveland Electric Illuminating Company, Ohio Edison Company, The Toledo Edison Company, and Pennsylvania Power Company, as well as ATSI's generation affiliate, FirstEnergy Solutions- into PJM effective June 1, Consistent with the Commission's Final Order in the 2009 Rider T Case, the Company is seeking recovery of only certain PJM-related administrative charges in this proceeding. I will now describe in more detail the current administrative charges in Schedules 9-1, 9-2,9-4, 9-6, and 9-FINCON for which the Company is seeking recovery under Subsection A 4, and Company Witness Wilkinson will discuss the calculations of these charges in the revenue requirement that he presents. 24

106 Schedule 9-1, Control Area Administration Service The Monthly Control Area Administrative Service Rate recovers the costs of all PJM activities associated with preserving the reliability of the PJM Region, and with administering Point-to-Point Transmission Service and NITS. The rates set forth in this schedule and charged to transmission customers are based on their usage of the PJM transmission system. Monthly transmission use in MWh includes network customers' real-time load and point-to-point customers' real-time energy use. Restated rates for this schedule were approved in FERC Docket No. ER-478, and PJM's baseline filing that included this schedule was approved in FERC Docket No. ERl0-27. As discussed above and approved in FERC Docket No. ER , this schedule now includes a lower rate effective October 1, Schedule 9-2, Financial Transmission Rights ("FTR") Administration Service The FTR Service Rate recovers the costs of all PJM activities associated with administering the FTRs provided for under Attachment K to the PJM OATT. These activities include, but are not limited to, coordination of FTR bilateral trading; administration offtr auctions; support ofpjm's Internet-based eftr tool; and analyses to determine what total combination of FTRs can be outstanding and accommodated by the PJM system at any given time. Simply put, PJM provides this service to entities, like the Company, that hold FTRs, or that submit offers to sell or bids to buy FTRs On a monthly basis, two FTR Service Rate components are charged to users of this service. The FTR Service Rate, Component 1 is charged to FTR holders based on FTR MW and the hours that each FTR is in effect. The FTR Service Rate, Component 2 is 25

107 1 charged to FTR auction participants based on the total number of hours submitted in 2 bids to buy FTR obligations. This Component 2 is charged to FTR auction participants 3 based on a factor of five times the number of hours in all bids to buy FTR options. 4 Restated rates for this schedule were approved in PERC Docket No. ER-478, and 5 PJM' s baseline filing including this schedule was approved in PERC Docket No. 6 ER-27. As discussed above and approved in PERC Docket No. ER , this 7 schedule now includes a lower rate effective October 1, Schedule 9-4, Regulation and Frequency Response Administration Service 9 The Regulation and Frequency Response Administration Service Rate recovers the costs of all PJM activities associated with administering the provision of this service 11 under Schedule 3 of the PJM OATT. On a monthly basis, this rate is charged to those 12 LSEs and generators that provide regulation service in accordance with Schedule 3. It 13 is applied to the MWh of the hourly regulation objective for LSEs, plus the MWh of the 14 hourly regulation scheduled from generating units, summed for each hour of the 15 month. Restated rates for this schedule were approved in PERC Docket No. 16 ER-478, and PJM's baseline filing including this schedule was approved in PERC 17 Docket No. ER-27. As discussed above and approved in PERC Docket No. 18 ER , this schedule now includes a lower rate effective October 1, Schedule 9-6, Formula Rate for Costs of Advanced Second Control Center 20 This Formula Rate recovers the actual costs of owning, leasing, and operating PJM' s 21 Advanced Second Control Center and all of its related assets, as set forth in Schedule Starting June 1, 2008, separate monthly charges have been assessed to all users of 23 services under PJM OATT Schedules 9-1 through 9-5. These charges are based on the 26

108 1 applicable billing determinants set forth in those schedules that are used to determine 2 the charges for those services. This schedule will remain in effect for seven years from 3 November 2011, which is the in-service date of the Advanced Second Control Center 4 energy management system. See FERC Docket No. ER PJM's baseline filing 5 including this schedule was approved in FERC Docket No. ER-27, and modified 6 in FERC Docket No. ER to correct references to certain defined terms that had 7 been previously undefined. 8 Schedule 9-FINCON, Finance Committee Retained Outside Consultant 9 The Finance Committee Retained Outside Consultant Rate ("FIN CON Rate") recovers the costs of paying for any consultants retained by the PJM Finance Committee. On a 11 monthly basis, the FIN CON Rate for each user as a transmission customer under the 12 PJM OATT for Point-to-Point Transmission Service or NITS equals the FINCON 13 Revenues Amount (to be established by the Finance Committee up to $0,000) 14 multiplied by the Customer Allocation. This Customer Allocation is the total monthly 15 quantity of transmission usage by a transmission customer divided by the total quantity 16 of MWh of energy delivered under Point-to-Point Transmission Service and NITS 17 during the month subsequent to the month in which the PJM Members Committee 18 approved the PJM Finance Committee's proposed consultant engagement. See FERC 19 Docket No. ER PJM's baseline filing including this schedule was approved in 20 FERC Docket No. ERl

109 1 Q. Please describe the PJM demand response programs and the related billing 2 process for the costs of these programs, beginning with the Economic Load 3 Response Program and Emergency Load Response Program. 4 A. The Economic and Emergency Load Response Programs charges are costs for demand response programs approved by PERC and administered by PJM. These programs function as a means for participants to receive payments for reducing load. The Economic Load Response Program allows qualifying entities to participate in the PJM markets by submitting bids to reduce demand and to receive payments for their voluntary load reductions. Generally, these payments are based on the Locational Marginal Prices ("LMPs") in PJM' s Day-Ahead Energy Market and Real-Time Energy Market More specifically, effective April1, 2012, in accordance with PERC's orders accepting a series ofpjm compliance filings in Docket Nos. ER11-46, ER , ER , ER , ER , and ER , when payment of LMP is cost-effective as determined by a net benefits test prescribed by FERC Orders 745 and 745-A, 6 payments to the participant are based on LMP, and the cost of such payments is distributed to those loads that benefit from the demand reduction. The net benefits test establishes a threshold price so that, when LMPs are equal to or higher than the threshold price, payments based on LMPs are determined to be cost-effective; and, when LMP is less than the threshold price, payments are zero. The cost of the payments for the demand reductions is charged to those loads and exports in each zone 6 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 134 FERC'J[6l,U:P, reh 'g denied, Order No. 745-A, 137 FERC ~[ 61,215 (2011 ), reh 'g denied, Order No. 745-B, 138 FERC fj[ 61,148 (2012). 28

110 for which the load-weighted average LMP for the hour during which such load reduction occurred is greater than the threshold (net benefits test) price. Thus, when the Company is determined to be a beneficiary through application of the net benefits test, it is charged by PJM for demand reductions under the Economic Load Response Program. For example, these charges to the DOMLSE account for January 2014 are shown in lines 1242 and 1243 on Page 2 of Schedule The Emergency Load Response Program is designed to provide a method by which end-use customers may be compensated by PJM for reducing load during an emergency event and is comprised of two Load Management Program options - the Full Program Option and the Capacity Only Option. Both options allow participants to receive capacity payments for their Load Management Resources. Under both of these programs, curtailments are mandatory during emergencies and tests, and participants are subject to penalties for noncompliance. In addition to the capacity payment, under the Full Program Option, participants also receive an energy payment during emergencies. The energy payment under this option is the LMP, but the total payments during an emergency are subject to a minimum amount, including a minimum dispatch price, which can result in compensation much higher than the LMP. This compensation is paid to the provider and allocated among PJM market participants in proportion to the net increased purchases or decreased sales in the Real-Time Energy Market during the emergency event, as compared to their positions in the Day-Ahead Energy Market Effective February 1, 2012, and in accordance with FERC's orders in Docket Nos. ER and ER , real-time dispatch reduction MWh were subtracted 29

111 1 from the purchases to determine the net increased purchases for the purpose of 2 allocating the cost of the energy payment. This change removed a disincentive that a 3 net purchaser might have to follow PJM' s dispatch instructions to reduce MWh in 4 real-time supplied from its resource during a PJM emergency event. In other words, 5 without this change, a market purchaser with a resource who followed PJM' s dispatch 6 instruction to reduce the number of MW supplied in real-time during an emergency 7 would have faced an allocation of emergency-related costs if, by following PJM's 8 dispatch instruction, it increased the market purchaser's net purchases in the Real-Time 9 Energy Market as compared to the Day-Ahead Energy Market. In addition to the two Load Management options discussed above, there is an Energy 11 Only option, which is also part of the Emergency Load Response Program but is not 12 commonly used. It is similar to the Economic Load Response Program in that 13 curtailment is voluntary and no capacity payment is involved. However, unlike the 14 Economic Load Response Option, the energy compensation is the same as that 15 discussed above for the Full Program Option and is available only during emergencies. 16 The PERC approved the Economic Load Response Program in Docket No. 17 ER , as modified in Docket Nos. ER06-406, ER08-841, ER08-824, ER08-780, 18 ER09-701, ER , ER-893, ER-27, ER , ER , 19 ER , ER , ER , ER , ER , 20 ER , and ER ; and approved the Emergency Load Response Program in 21 PERC Docket No. ER , as modified in Docket Nos. ER06-406, ER05-14, 22 EL05-148, ER09-701, ER09-797, ER09-63, ER , ER-27, ERll-2527, 23 ERll-2898, ERll-3322, ER , ER12-525, ER , ER , 30

112 ER , ER , and ER While these programs were initially set up to be temporary, subsequent PERC orders in Docket No. ER removed their termination dates. The costs to the Company of these programs are the PJM Load Response Charges referenced in PJM Manual 29: Billing, Section 2: Monthly Billing Statement, and are described in detail in PJM Manual28: Operating Agreement Accounting, Section 11: PJM Load Response Programs Accounting. 7 7 Q. 8 A. Does this conclude your pre-filed direct testimony? Yes, it does. 7 See < 31

113 APPENDIX A BACKGROUND AND QUALIFICATIONS OF JAMES D. JACKSON, JR. James D. Jackson, Jr. received a Bachelor of Science degree in Agriculture from the University of Florida in 1978, and a Master of Economics degree from North Carolina State University in In 1980, he worked as a research assistant for North Carolina State University. He joined Duke Energy in 1981, and held positions as Rate Analyst, Senior Rate Designer, Project Manager of Cost Studies, Manager of Regulatory Affairs, and Manager of Rate Design. In 1998, Mr. Jackson joined Virginia Electric and Power Company as a Regulatory and Pricing Advisor, and was promoted to the position of Regulatory Consultant in Mr. Jackson has previously submitted testimony before the State Corporation Commission of Virginia and the Federal Energy Regulatory Commission.

114 Settlement~ Company Exhibit No._ Witness: JDJ Schedule I Page I ofl7 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA INVOICE NUMBER: CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: Dominion Virginia Power (LSE) DOMLSE (964) FINAL BILLING STATEMENT ISSUED: 02/07/ :22:09 BILLING PERIOD: 01/01/2014 to 01/31/2014 Monthly Billing Total: $54,160, Previous Weekly Billing Total: ($17,000,505.41) '. Monthly Billing Statement Summa,.Y..... ~ Total ~ ~ " " " ~ ~ ; '-'~ - "' ~ "' " ~", 0 "' { r ~ "':> ' ~ Total Net Charge. Please Pay This Amount. $71 '160, WIRE TRANSFER FUNDS TO: TERMS: PAYABLE IN FULL BY 12:00 PM EPT ON 02/14/2014 Redacted for Relevance R~!daetcd for Rdc\anc~ ACCOUNT NUMBER- ' FOR INQUIRIES CONTACT: PJM MEMBER RELATIONS (Banking I Payment): [email protected] (866) PJM MARKET SETTLEMENTS (Billing Line Items): [email protected] (866) ADDITIONAL BILLING STATEMENT INFORMATION: ***This cover page includes PJM Settlement, Inc. banking information that is NOT to be publicly shared. In order to reduce the risk of potential fraud, please redact any PJM Settlement banking information prior to including these billing statements in any public documents.*** David Budney Manager, PJM Market Settlement Operations Page 1 of6

115 Settlement~ Company Exhibit No._ Witness: JDJ Schedule I Page 2 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (LSE) DOMLSE (964) 02/07/ :22:09 01/01/2014 to 01/31/2014. CHARGES ADJ :..' 7.BILLING ll.ine ITEM NAME.., 4 SOURCE BILLING. ~. AMOUNT.. '.:. ;J. v ~.., :. _.:. _. 'PERIOD START-.. :. - :. "'~ =, '*"}~, ~,,t: ~,.,.." ~'~"$ ~ ~ '- = ""'"""'"~, >~' ~ J "\,:;,',r " : "'~ "'*' ~ d /&'~," ~ " "''~ r 10 Network Integration Transmission Service.. 11 o8 Jrar1smls!>i<:lry E.=rihf!Q~ernenC Other Supporting Facilities jj3o. - Firrl1Poif1f:te>'-PoirifTr~nsrl1i~siof1 $ei\tlce Non-Firm Point-to-Point Transmission Service :14Qb, pay.:a~ead p6tf0?i"ket ~nergy 1205 Balancing Spot Market Energy 12}o < > --- D~y':a.head Tr~r~srl1is?i 119pf1gestle>n': 1215 Balancing Transmission Congestion... _:.)22o. pay7?he?~ Tra.n~i-nisslon~.osses, Balancing Transmission Losses 'inadvertent H1tercha.ri9e' 1242 Day-Ahead Load Response Charge Allocation :12if3 _, RE)ai-Jim.e.~oad R:~spoh!>W harg~ja.itoc.ation Meter Error Correction \j~6o..... ~rljergencyj~nergy_ 1301 PJM Scheduling, System Control and Dispatch Service - Control Area Administration. PJM.scheduJing, system control arid Dispatch( S8_f'i,ice,:: FT,R Administration PJM Scheduling, System Control and Dispatch Service - Market Support. PJJYl Stheduiing, System Control and Dispatch.:. _ _ 1320 < SerVice - Regul?tion Market Administration _ PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. P JM Scheduling, System Control and Dispatch Seryice - Advanced Secor1d. Controi Genter PJM Scheduling, System Control and Dispatch Service - Market Support Offset._PJMScheduling, System t6ntrol.allcidispatch<.... Ser:vic~ Refund ~control Area Admini~tn3tion PJM Scheduling, System Control and Dispatch Service Refund - FTR Administration. PJM Scheduling, SystemControland Dispatch, SerVice Refund - Market Support PJM Scheduling, System Control arid Dispatch... Service Refund - Regulation Market Administration.PJM Scheduling, System Control and Dispat9h Service Refund -Capacity Resource/Obligation.. Mgnit.... PJM Settlement, Inc. Market Monitoring Unit{MMU)Funding. FERC Annual Recovery. Organization of PJM States, Inc. (OP,$1) Funding Transmission Owner Scheduling, System Control and Dispatch Service Page 2 of6 $49,885, $6,339,497,2.8. $31, $0.6o. ~0,00. $0,00 : $14,862, " $0.00. $7,230, )0~00 $293, $(1.01 ;327:93)_.: $8, '.$52,720.~3... $438.4: $(2Q,364.J34} $1,467, $1.8, $323, $,080~75 $50, $183, $(45,968.02)... $(219,432:25) $(1,512.35) $(49,445.07) $(1,877.65) $(6,691.97). $45, $38; $608, $6,071 ~24 $0.00

116 Settlement ~ Company Exhibit No._ Witness: JDJ Schedule I Page 3 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: Dominion Virginia Power (LSE) CUSTOMER IDENTIFIERS: DOMLSE (964) FINAL BILLING STATEMENT ISSUED: 02/07/ :22:09 BILLING PERIOD: 01/01/2014 to 01/31/ , '.Reactive Supply ahd.voltage Control from Generation and Other Sources Service Regulation and Frequency Response Service. SynchroniiE~d Reserve Day-aheacl scheduling Reserve oay~ahead bperati69reseiye Balancing Operating Reserve.. Baiancing operating R.eseiveforLoad Response. Synchronous Condensing Rea dive services Black Start Service. foad R.econciliatioilfor spot Mark~t Energy Load Reconciliation for Transmission Congestion Loaci Reconciliation for transmission Losses Load Reconciliation for Inadvertent Interchange Load Reconciliation for PJM Scheduiing,System gontrol and Dispatch Service. Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund Load Reconciliation for Scheduie 9~6 -Advanced Second Control Center Load Reconciliation for Market Monitoring Unit (MMU) Funding Load Reconciliation for FERC Annual Recovery Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding Load Reconciliatioofor Regulation and Frequency Response Service Load Reconciliation for Day-ahead Scheduling Reserve Load Reconciliation for BalanCing Operating Reserve Load Reconciliation for Reactive Services Financial Transmission Rights Auction Locational Reliability A TransmisslonEnhaocement A Other Supporting Facilities A Planning Period Congestion Uplift A Inadvertent Interchange A PJM Scheduling, System Control and Dispatch Service- Regulation Market Administration. A PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration A PJM Scheduling, System Control arid Dispatch Service - Advanced Second Control Center A PJM Scheduling, SystemControl and Dispatch Service - Advanced Second Control Center A PJM Scheduling, System Control and Dispatch Se!Vice- Advanced Second Control Cehter 12fo1/2o13 12/01/ /01/ /01/ /01/ /01/ /01/ /01/ /01/2013. $2; 144, $165, $o.oo. $4,182, $3;~30,41(): 67 ;. $70,403, $371.11: $6, $26,2(){{39. $72, $(83,824;69) $(3,6t)!.13). $(1,09~,01). $54.66 $(430.98) $ $(59.) $(7.97) $(124,18) $(1.44) $(388.74) $(0.44) $(47.02) $(811.24) $7,022, $16,553,812,45 $(82,692.32)... $22, $(172,339.64) $ $1.55 $(0.48) $(0.01) $0.11 $0.01. Page 3 of 6

117 Settlement~ Company Exhibit No. _ Witness: JDJ Schedule I Page 4 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (LSE) DOMLSE (964) 02/07/ :22:09 01/01/2014 to 01/31/ A PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration 1311 P.JM Schecluling; system control and Dispatch. >'. S~rvice Refuncl '- F{egulati()fl M~rkl?t Adrni11istca!i9n A Regulation and Frequency Response Service _ 1~46>. :--_.':fl.~ _--~~gyj~~io 11 a11~f=requen6)1j~esp~ 11 ~~$~ryi6e, A Day-ahead Operating Reserve ; A3.i~:.-.A,.Bala0~1h9()P.~ratln9Rese~e.~.. _ 1375 A Balancing Operating Reserve. _1375{ A ~ _8~1a11df1g pp~r~tif1g_13esejyy ) 1375 A Balancing Operating Reserve A BC)I9[1dng Qp~r~tJng R~s~ry~.. J 37 > 1375 A Balancing Operating Reserve -, )375: A. - sala.f19if19 op~fatin9 Rese!Ye 1375 A Balancing Operating Reserve / A _B~I~!J~ing ()pe,rating Res~f\1~ Balancing Operating Reserve J3.ze ". A : s~lah~ing ()p~rating Res~fV~ for L.o9~ R~~ponse 1378 A Reactive Services j3:za; _ :p_; R~adive se!vices 378 A Reactive Services 911 : A rjjidilgan -: bjjtario lrite?rfac~ Phasi:i Angle. Regulators A Generation Deactivation 195~,,,i A Do!l1If1iof1setuer:nerit_ 1956 A Dominion Settlement Total Charges 08/01/ /01/2013. : j2j01/?013 12/01/ /91! /01/2009. : ji'o1/2oo9 04/01/ Q5tb1)2bt3'. 07/01/ /Q1/2613 /01/ /01/2013 < 12;Q1J.2o13< 07/01/2013 0~/011401~ /01/ /201'3.. 12/01/2013 1Zto1/2o13._ 01/01/2014 $(0.07) $ $(29,:48) $(1 05,290.28). $(2(),}7~.1)9).. $(14,506.24).. $(:?1 '( ).. - $3, $33,~0 $(1,629.43).. $?..9t36_.82' $ '$866,64' $ $4, $(8,293.58) $(2~9., 7~4.}6)... $, $2.1; $59, _$26,83:3.3:1- $20, $184,930, Page 4 of6

118 Settlement k1 Company Exhibit No._ Witness: JDJ Schedule 1 Page 5 of17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: Dominion Virginia Power (LSE) DOMLSE (964) FINAL BILLING STATEMENT ISSUED: 02/07/ :22:09 BILLING PERIOD: 01/01/2014 to 01/31/ } Network Integration Transmission Service Transmission Enhancement t=irrri. Point-to~Point frailsmlssioi1 service. ;. ~ ' Non-Firm Point-to-Point Transmission Service Transmission Congestion Transmission Losses. Emerg~~C:y Enel'9Y Transmission Owner Scheduling, System Control and Dispatch Service Reactive. supply and Voltage. control from.. Generation and Other Sources Service Regulation and Frequency Response Service Synchronized Reserve.. Day-ahead Scheduling Reserve Day-ahead operating Reserve. Balancing Operating Reserve Black Start service Load Reconciliation for Transmission Losses Financia l Transmission Rights Auction Auction Revenue Rights lncrememtal CapacityTransferRfghts Demand Resource and ILR Compliance Penalty capacity Resource Deficiency. Load Management Test Failure cr Lost OpportunitY cost Allocation A Non-Firm Point-to-Point Transmission Service A transmission Congestion A Transmission Congestion A Transmission Congestion A Transmission Congestion A Transmission Congestion A Transmission Cong7stion A Transmission. Congestion. A Transmission Congestion A T!Cjnsmission Congestion A Transmission Congestion A Transmission Conf)estion A Transmission Congestion A. Transmission Congestion A Planning Period Congestion Uplift A. Transmission Losses A Transmission Losses A Transmission Losses A Transmission Losses A A A Transmission Losses Demand Resource and ILR Compliance Penalty Demand Resource and ILR Compliance Penalty 12/01/ /01/ /01/ /01/2009 /01/ /01/ /01/ /01/ /01/ /01/ /01/ /01/ /01/ /01/ /01/2012 /01/ /01/2009. '.12/01/ /01/ /01/2013 /01/ /01/2013 $0.00 $,827, $814, $207, $95,Q87,128J9. $15,771, $3, $0.00 $0.00 $0.00 $0.00. $0,00 $0.00. $0.00 $a:oo ~(786.92) $226, $7,125, $171, $2, $191, $4, $1, $3, $(0.02) $0.01. $0.01. $18, $16,316,15 $12, $12, $8, $23, $15, $5, $4.04.$ $(113,288.00) $(0.15) $(0.19) $(0.01) $30.66 $(40.06) $(114,089.04) $(22,370.40) Page 5 of6

119 Settlement~ Company Exhibit No._ Witness: JDJ Schedule I Page 6 of17 PJM Settlement, me. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (LSE) DOMLSE (964) 02/07/ :22:09 01/01/2014 to 01/31/ A Demand Resource and ILR Compliance Penalty Total Credits 12/01/2013 $259, $130,770, Page 6 of6

120 Settlement~ Company Exhibit No._ Witness: JDJ Schedule 1 Page 7 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA INVOICE NUMBER: CUSTOMER ACCOUNT: Dominion Virginia Power CUSTOMER IDENTIFIERS: DOMGEN (71) FINAL BILLING STATEMENT ISSUED: 02/07/ :22:09 BILLING PERIOD: 01/01/2014 to 01/31/2014 Monthly Billing Total: Previous Weekly Billing Total: $119,607, $184,703, Monthly Billing Statement Summary... Total ~ ~ - " > f ~ : :;: Total Net Credit to You. Please Do Not Pay $65,096, TERMS: PAYABLE IN FULL BY 12:00 PM EPT ON 02/14/2014 WIRE TRANSFER FUNDS TO: Redacted for Relevance Rcdaclcd for Rclc\anc ACCOUNT NUMBER -'f"'f'f'm''f FOR INQUIRIES CONTACT: PJM MEMBER RELATIONS (Banking I Payment): [email protected] (866) PJM MARKET SETTLEMENTS (Billing Line Items): [email protected] (866) ADDITIONAL BILLING STATEMENT INFORMATION: ***This cover page includes PJM Settlement, Inc. banking information that is NOT to be publicly shared. In order to reduce the risk of potential fraud, please redact any PJM Settlement banking information prior to including these billing statements in any public documents.*** David Budney Manager, PJM Market Settlement Operations Page 1 of 4

121 /Settlement~ ' Company Exhibit No._ Witness: JDJ Schedule I Page 8 ofl7 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power DOMGEN (71) 02/07/ :22:09 01/01/2014 to 01/31/2014. CHARGES ADJ BILLING LINE ITEM NAME SOURCE BILLING, AMOUNT. : : ". PERIOD START.. ;::: ;?*,t " "' ' ~ "' -'>,_ j ~ "' ' 10 Network Integration Transmission Service.112.oc;.-._ - - othersupporl:ih9facilities ----._.-. _ 113o Firm- Point-to~Poirit Transmission service. JJ4.0. N6n~Firm Polnt-:f9-Polnttransmlssion service Day-ahead Spot Market Energy -1266: : Ba,lallcing ~p()t!y1~~k.et f:nergy 12 Dc:lY-ahead Transmission Congestion - -1i1~): '/)3al~ncln9Ji-an:S rl11s~io~ ~cori9esti~>6. - ; 1220 Day-ahead Transmission Losses 1225;,._._-.... ~~a.lal1s:i.n~itrarsl1"1i~~i()ri ~o~~el> Meter Error Correction 1?Eio' - _Ernerg~n2y E 11 ergy> ' 1301 PJM Scheduling, System Control and Dispatch _13Q4' 1305 :J306I ' _ Service - Control Area Administration :' PJflll~cheduiing:sY.stem corihoi'and.bi~pat9 h _.-_ Service, FJJ3 Adm~nistratlon. PJM Scheduling, System Control and Dispatch Service - Market Support P Jflll schedl.j iir19; System controland bfspatch SerViCe-:: R~gulatiof1 MarketAdhlinistratiorj - PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt..PJM Scheduling, System Control anddispatch - Service _ 7 Advanced Second Control Center. -.. PJM Scheduling, System Control and Dispatch Service - Market Support Offset - PJM Scheduling, System Control and DispatCh Service Refund~ Market Support PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration PJfvl Scheduling, System Control and Dispatch. Service Refund - capacityresource/qbligation MgiTJt PJM Settlement, Inc. Market Monitoring Unit (MMU) Funding _ Trarisrnissiori owner Scheduling, system coritrol and Dispatch Service Reactive Supply and Voltage Control from.. Generation and Other Sources Service - Regulation and Frequency Response Service Synchronized Reserve Day-ahead Scheduling Reserve Day-ahead Operating Reserve Balancing Operating Reserve Balancing Operating Reserve for Load Response Black Start Service RPM Auctiofl Page 2 of4 $0.00. xr. $~2,588,.1:3 $0.00 $O.,oo:_ $85,832,292.65,$(8;Q2r;l,46~.[13) :.,19~]Q.? l;?j7_ --- -' $(35~,374.14); $32,998, ; $?~0)~6,91 $(215,078.31)... $1?2;19$.44 $0.00 $312, $23; $51, $34,~ $(44,208.40) $(47,664.30). $(4,308.97) $(6,886;34). $44, $37;38} :39.. $0.00 $0.00 $6,508, $682,668; 16 $0.00 '$0,00 $5,353, $ $0.00 $7,506.45

122 Settlement k1 Company Exhibit No._ Witness: JDJ Schedule 1 Page 9 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: Dominion Virginia Power CUSTOMER IDENTIFIERS: DOMGEN (71) FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: 02/07/201411:22:09 01/01/2014 to 01/31/ () Auction Specific MW Transaction. D~rnarid Resource and ILR CompHance Penalty A Non-Firm Point-to-Point Transmission Service A... PJfV1s6t1eduling,systemcontrOi al1d bispatch Service ~ Advanced Second Control Center A PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center 'A: PJMsct1eduHn9, systeitl controi'~rid[)ispatch : ~~r'v'ice -Advanced Second Control 9ent~r... A Regulation and Frequency Response Service A ; Regulation and FrequencYResponseSer\tic~ A Balancing Operating Reserve.A Bafaridrigoperating Reserve A Balancing Operating Reserve A ~. 8alaridrig operating Reser\ie A Balancing Operating Reserve A sal~llcing operating R.es~r\re A Balancing Operating Reserve A Balallcing Operating Reserve A Balancing Operating Reserve A Balancing Operating Reserve A Balancing Operating Reserve for Load Response A. Dernand Resource and ILR Compliance Penalty 12/01/2013 : o~io112o13 11/01/ /01/ /01/ Jb1/2.o13.. /01/ /01/ /01/ /01/ /01/ /01/ /01/2013 /01/ /01/2013 ~2/01/ /01/ /01/2013 $561, $2, $9, $(0;46). $(0.01) $0.22.$(1,40) $(0.04). $(66, ).$(51,313~l8) $(58,189.08). $7, E0,67 $(2,737.) $11, $ $1, $ $5, $6, Total Charges $224,506, Page 3 of 4

123 Settlement~ Company Exhibit No._ Witness: JDJ Schedule 1 Page of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power DOMGEN (71) 02/07/ :22:09 01/01/2014 to 01/31/2014 CREDITS ADJ BILLING LINE ITEM NAME SOURCE BILLING AMOUNT., PERIOD START,.. ::. "' ~~ - ~ ~t A>,~" r 0 ~ ~ "'' "" ~~ _ ~ g21{) Network Integration Transmission Service --~- f=ir)n PpiriFto~Poirii.Iral"l~inisslon s~ivic;~ _... Non-Firm Point-to-Point Transmission Service ' Transmission c6rigestioh Transmission Losses. -.~'!l~rge.f"lcy Er1ergy Transmission Owner Scheduling, System Control and Dispatch Service 233o <t -:.)~eadi~e sllp'pl:/andv6ifa9e!'contr6j from -~}i'2:> :.. Generatfon andqther S()urces Se!Vice <~36b Regulation and Frequency Response Service "~ynci1tciriized F{es.erve Non-Synchronized Reserve... '2.3$?. - pay~aheaci sctiedulin9 ResefVe 2370 Day-ahead Operating Reserve 4:?7!5... 8?Jandng bp~rating R.eseryt! Black Start Service :~9b6. R.PrJIAuction CT Lost Opportunity Cost Allocation >237'5 A. BalanCing operating Reserve 2375 A Balancing Operating Reserve A Reactive services A Reactive Services 08/01/ /01/ /01/ /01/2013. $ $ $0.00.<; - - _ $o.oo. $0.00 $7, > $ "" ~. $15,505, $j6,t)o~.364:so. $1,220, $3;'92.6;5,96;64: $2,032, $4.~;~5,5Q8~91 ; $89, ')i6,e)o~,'q19,49 : $2,123,19 $.1,054:03... $(475.41) $(8,003A7} $(32,831.44) Total Credits $4,899, Page 4 of4

124 Company Exhibit No._ Witness: JDJ Schedule I Page II ofl7 \Settlement"" PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA INVOICE NUMBER: CUSTOMER ACCOUNT: Dominion Virginia Power (EDC) CUSTOMER IDENTIFIERS: DOMEDC (963) FINAL BILLING STATEMENT ISSUED: 02/07/ :22:09 BILLING PERIOD: 01/01/2014 to 01/31/2014 Monthly Billing Total: Previous Weekly Billing Total: ($57,937,406.95) ($53,572, 8.81) Monthly Billing Statement Summary. / Total Total Net Credit to You. Please Do Not Pay $4,365, TERMS: PAYABLE IN FULL BY 12:00 PM EPT ON 02/14/2014 WIRE TRANSFER FUNDS TO: Redacted for Relevance Redacted for Rclcvanc~: ACCOUNT NUMBER - FOR INQUIRIES CONTACT: PJM MEMBER RELATIONS (Banking I Payment): [email protected] (866) PJM MARKET SETTLEMENTS (Billing Line Items): [email protected] (866) ADDITIONAL BILLING STATEMENT INFORMATION: ***This cover page includes PJM Settlement, Inc. banking information that is NOT to be publicly shared. In order to reduce the risk of potential fraud, please redact any PJM Settlement banking information prior to including these billing statements in any public documents.*** David Budney Manager, PJM Market Settlement Operations Page 1 of4

125 Settlement k1 Company Exhibit No._ Witness: JDJ Schedule I Page 12 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (EDC) DOME DC (1 0963) 02/07/ :22:09 01/01/2014 to 01/31/2014 CHARGES ADJ BILLING LINE ITEM NAME SOURCE BILLING AMOUNT.. PERIOD START... ~. ' " /.. 10 Network Integration Transmission Service I13q.... Firm Polnt~io~Point transmission seivlce 1140 Non-Firm Point-to-Point Transmission Service ~ /; ' o1?oo.... [)?x~cih~ad Spot rv1arl<e!. Energy.. < 1205 Balancing Spot Market Energy 1.2. : Pi=IY~C!head Trcip~ry,IssipnC~ngesH()ii B~lanc;Jn.g.T.r in~missisji} Q9nge~t]c:>r1 /),2_2()... pay:-ahead Trall\)rhis~i()n,Lcisses 1225 Balancing Transmission Losses '' ;125o Met~r E:rror correctiori 1260 Emergency Energy 1so1; PJM Scheduling, Systel)l C()ntrol and Dispatch Service.., C()ritrol Area AdrY)inistration. _ PJM Scheduling, System Control and Dispatch Service - FTR Administration.... '.. pjfv1 Scbedu ling, System. Control and D ispa:fcti : Serv!c:e.-::M?rketSupport PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration... PJM _Scheduling, System co~froi anddispatch.. Service...: Capacity Resource/Obligation Mgmt PJM Scheduling, System Control andbispatch Service -Advanced Second Control Center 1320'. Transmission Owner Scheduling; System Control arid Dispatch Service Reactive Supply and Voltage Control from Generation and Other Sources Service 1_ Regulation and Frequency Response Service Synchronized Reserve bay~aheadscheduling Reserve Day-ahead Operating Reserve. Bala11cing Operating Reserve. Black Start Service Load f{econciliation for Spot Market Energy. Load Reconciliation for Transmission Congestion Load Rec;onciliation for Transmission Losses... Load Reconciliation for Inadvertent Interchange Load Reconciliation for PJM Scheduling, System. Control and Dispatch _Service Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund.._1442 Load Reconciliation for Schedule 9-6.: Advanced Second Control Center...,, : Load Reconciliation for FERC Annual Recovery 1460 Load Reconciliation for Regulation and Frequency Response Service $0.00 $0.()Cl.. $0.00. $Q.OO $(39.65).. $ $(1!?J 9).. $0.()0... $(0.35) $138,580,63 $0.02 $0.00 $0.00 $0.00. $0.00 $(0.01) $0.00 $0.00 $(0.02). $0.00 $0.04 $0.00 $4.59 $0.00. $8.30. $0.39 $0.20 $(0.01) $0.06 $(0.01) $0.01 $0.02 $0.05 Page 2 of 4

126 Settlement~ Company Exhibit No._ Witness: JDJ Schedule 1 Page 13 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: Dominion Virginia Power (EDC) DOME DC (1 0963) FINAL BILLING STATEMENT ISSUED: 02/07/ :22:09 BILLING PERIOD: 01/01/2014 to 01/31/ o : Load Reconciliation for Balancing Operating Reserve Load Rec611cfllatlonforRea~tive services A Balancing Operating Reserve.. A Balal1dn9 9i>eratir19 Reseive.. A Balancing Operating Reserve A i3alal1cirig bperatlrig Reserve A Balancing Operating Reserve A Balancing ()peratillg Reserve. A Balancing Operating Reserve A.. BalanCing Operating Reserve t'or Load Response A Reactive Services /01/ !61/ /01/ /01/ /01/ /01/ /01/ / /01/2013 $ $0. $(0.13) $(0.07). $(Q,Q8) $ $(0:91) $0~00. $0.01 $0.02 $0.02 Total Charges $138,538.97, Page 3 of 4

127 Settlement~ Company Exhibit No._ Witness: JDJ Schedule I Pag,e 14 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (EDC) DOME DC (1 0963) 02/07/ :22:09 01/01/2014 to 01/31/2014 CREDITS ADJ. BILLING LINE ITEM NAME SOURCE BILLING. :: AMOUNT.. 2JOQ 28 21~ ? sa oo- 212o _.. ~ _PERIOD ~T~RT'_.....!.:~-~ ::,: :-...:-. ~-. Network Integration Transmission Servic~ Tral1smissicin El1hal1cemel1t... _.c_:6thersupp6rtingfadlities : Firm PoinHo-Point'transm(ssion. seivice Non-FirmPoint~to-PointTransmisslonseiVite,,.. _, ' "... : :......,..... Transmission Congestion TransmissionLoS'ses Transmission Owner Scheduling, System Control and Dispatch Service.. Reactive supplfand\!oitage controlt~orri.generation and Other Sources_ Service < Regulation and Frequency Response Service Sy~~l1:rol1ized J3eser\fe Day-ahead Scheduling Reserve pay-afie;3d dp_er ting. R,esef'l~ Balancing Operating Reserve Black 8_tari: service Load Reconciliation for Transmission Losses... A - i--ieiwork lntegrati011trai1s'rnisslol1 service.. A Ott1-erSupportil1gFacHfties A Dominion settlement A Dominion Settlement. 01)01/2()14' 12/01/ io1t2o13 01/01/ $!57,26(3,613!326 $477, $4.79;J30,13~ $0.00,. ~a:po $0.00 ::$(0~48)... $0.00 $ jg:oo $Q,OQ $().()() ; $ _$b.qo' $0.05 $<1i8.JJ15.~4) $26, $2;199:79 $2, Total Credits $58,075, Page 4 of4

128 Company Exhibit No._ Witness: JDJ Schedule I Page 15 of 17 Settlement~ PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA INVOICE NUMBER: CUSTOMER ACCOUNT: Dominion Virginia Power (CSP) CUSTOMER IDENTIFIERS: DOMCSP (12444) FINAL BILLING STATEMENT ISSUED: 02/07/201411:22:09 BILLING PERIOD: 01/01/2014 to 01/31/2014 Monthly Billing Total: Previous Weekly Billing Total: ($6,968.40) $0.00 Monthly Billing Statement Summary ~ ~, Total.. ~ ~ ~ ~ ~~ " ' Total Net Credit to You. Please Do Not Pay $6, WIRE TRANSFER FUNDS TO: TERMS: PAYABLE IN FULL BY 12:00 PM EPT ON 02/14/2014 Redacted for Relevance Redacted for Rclc\an ACCOUNTNUMBER FOR INQUIRIES CONTACT: PJM MEMBER RELATIONS (Banking I Payment): [email protected] (866) PJM MARKET SETTLEMENTS (Billing Line Items): [email protected] (866) ADDITIONAL BILLING STATEMENT INFORMATION: ***This cover page includes PJM Settlement, Inc. banking information that is NOT to be publicly shared. In order to reduce the risk of potential fraud, please redact any PJM Settlement banking information prior to including these billing statements in any public documents.*** David Budney Manager, PJM Market Settlement Operations Page 1 of 3

129 Settlement~ Company Exhibit No._ Witness: JDJ Schedule I Page 16 of 17 PJM Settlement, Inc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (CSP) DOMCSP (12444) 02/07/ :22:09 01/01/2014 to 01/31/2014 CHARGES ADJ BILliNG LINE ITEM NAME ~ SOURCE BtLLING ~. AMOUNT.,;~... PERIOD START.... o ' 10.jj39: Jb 1215 i122t) ; } ~ "' ~ > ; ~ y ". """"' ~: 4 Network Integration Transmission Service. Firrn F>oint~to-F>OidtJran~r.rilsslod ervicf..... Non-Firm Point-to-Point Transmission Service. > b~y~ahead ~po(r.aar~~t~nergy Balancing Spot Market Energy Day~?ti~ad'frarisrnlssi6n.c0.!19esf1on Balancing Transmission Congestion ~ bay-ahe9 dtrari~rl1jssioq ~6st;es Balancing Transmission Losses.?Jl\11 Schedulin'g,System.Contr{)l.and bispatd1 Service.::.Corit[9l Area Administration. PJM Scheduling, System Control and Dispatch Service - FTR Administration A PJM sci1eduling,systein control e1hd blspatct1. i ~rvic~ ~ tl/1arket Sl1PPOTL PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration PJ!v'l Scheduling, sysfern.tontrol and blspatcb.... s~ryic~ ~. caec;3city Resdl1rce/Qblig?tion MgrnL.... Transmission Owner Scheduling, System Control and Dispatch Service.. Reactive supply and Voltage 6nt[ol frorn. '. Generation and Other Sources Seniice.... < - '. -,. -" ~ Regulation and Frequency Response Service Synchronized Reserve. Day-ahead Scheduling Reserve... Day~ahead Operating Reserve.. Balancing Operating Reserve BlackStart Service...., Balancing Operating Reserve for Load Respons~. '.,_. 12/01/2013 ~"" "" ft 0 0 " "' ~ "' " $0.00 $9.ao $0.00. $0:66 ~O.QO. $O:o.o... $0.00 $0:00. $0.00 ; $0,00 $0.00 $0.00 $0.00 $0.00 $0.00. $0.00 $0.00 $b.ob $0.00 $0.00 $(6,968.40) Total Charges ($6,968.40) Page 2 of 3

130 Settlement~ Company Exhibit No._ Witness: JDJ Schedule 1 Page 17 of17 PJM Settlement, mc. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA CUSTOMER ACCOUNT: CUSTOMER IDENTIFIERS: FINAL BILLING STATEMENT ISSUED: BILLING PERIOD: Dominion Virginia Power (CSP) DOMCSP (12444) 02/07/ :22:09 01/01/2014 to 01/31/2014 CREDITS ADJ, BILLING LINE ITEM NAME,, 'SOURCE BILLING ~.. AMOUNT... ~.. PERIOD.START ".....,u,. "' ~ " ":~"" ~~, "':'"'""':/~~~,;,~,~:,: 4 &;,_:'"" ~"<'""~'v::cy;,'!;~""""~"~:s, 4 : ~~(" '"7!- 20, ' '2380 Network Integration Transmission Service. Firm Point-to-Point Transmission Service Non-Firm F>Oint-to-F>Oint Transmission serl/ice. c. c' - ' ' Transmission Congestion Transmission Losses.. Transmission Owner Scheduling, System Control and Dispatch Service 'R'eactive'supply an8v61h:lge control from Generation and Other Sources Service Regulation and Frequency Response Service synchronized Reserve.. Day~ahead Scheduling Reserve Day-ahead Operating Reserve Balancing Operating Reserve Black Start Service. $0.00 $0.00 $().6() $0.00 $0.00 $0.00 $0,00 $0.00 $0.00 $0.00 $0.00 $0.00 Total Credits $0.00 Page 3 of3

131 Company Exhibit No. Witness: JDJ Schedule 2 Page 1 of 11 Derivation of NITS Charge and TEC Charges and Credits to DOMLSE for January 2014 )Table 1 -Network Integration Transmission Service Charge to DOMLSE Line# Description 1 Rate for Network Integration Transmission Service ($/MW/yr) 2 Daily Rate $/MW/day 3 DOMLSE MW Contribution to Dominion Zone Network Service Peak Load ("NSPL") 4 Number of Days per Month (days) 5 Billing determinant (MW days/month) 6 NITS Charge (Sfmonth) Reference Amount (a) 35,936. L.1/(365 days/yr) (b) 16, #of days in January. 31 L.3'L.4 506, L.2'L.5 49,885,470 )Table 2- Transmission Enhancement Charges ("TEC") to DOMLSE Line# Description Reference Total $/month Col. A Allocation Factor MW days/year Col. S DOMLSE S/month Col. C =A'S 1 TotatTEC (c) and (d) 7,277, ,339,497 )Table 3- Transmission Enhancement Credit to DOMLSE Line# Description Reference Total $/month Cot. A Allocation Factor MW days/year Col. B DOMLSE $/month Col. C =A'S 1 Total TEC from Dominion Electric Transmission {e) 2 Less Incentives (f) 3 Dominion Transmission Enhancement Charges excluding Incentives amount L.1~L.3, (d) 12,907, , ,429, s,827,509 Notes: (a) This is taken from the Company's 1~15-14 Informational Filing of2014 Formula Rate Annual Update, Attachment B, Fonnula Rate Appendix A, Page 4, Line 171 in FERC Docket No. EROS-545. See < (b) The DOMLSE MW Contribution to the Dominion Zone Network Service Peak Load (HNSPLH) is the amount used by PJM for billing DOMLSE for NITS. (c) The amount in Col. A, Line 1 is the total of the Monthly Revenue Requirements for all of the projects and it is shown as the Total TEC under the Dominion column on Schedule 2, Page 11. (d) The allocation factor is derived from the DOMLSE MW Contribution to the Dominion Zone NSPL. See < DOMLSE Dominion Zone MW Contribution to Dominion Zone NSPL Col. A 16, , January #of Days Col. S Calculated MW-days Col.C=A*B 506, , (e) The amount in CoL A, Line 1 is the lola I monthly revenue requirement amount for the Dominion Projecls on Schedule 2, Page 8. (f) The amount in Col. A. Line 2 is the total monthly incentives amount for the Dominion Projects shown on Schedule 2, Page 8.

132 PJM Upgrade b0216 b021ll b b b b b b b0323 b0230 b0559 b0229 b0495 b0704 b1243 b0563 b0574-b23.3 b23.3 b\023.2 b1770 b1990 b1965 b1998 b055g b0674-b23.1 b23.1 TOTAL PJM Upgrade b049<l b0492 b0560 TOTAL AMu~l Monthly Revenue Requireme111 Requirement Jan-Mav2014 6,547,507,531$ ,206, $ 267, ,386, $ , $ 2UOU tls ,898,311$ ,031,646,591$ ,267, $ 438.9H1,33 7, $ 59, , $ ,04!$ 64,$ ,133,146,751$ , $ 17,238,52 92,504,99!$ 7.708,75 7S.905,51IS 6, ,994.25IS , $ \IS , $ 37, ,699.7SIS 2, , $ ,19 40,20S.t3IS ?.89 t2.2.80is , $ I s , $ , $ 15, A!1!'1Ual Monthly Reve:nue Requirement $ Revenue Requirement Jan.Oec2014 1, $ , $39.806, , Tr~nsmission Enh~ncement Ch~rgu {PJM OATI Schedule 12) set11ement worksheet Required Tr~nsmission Enh~ncements owned by: Tr~ns AUegheny lnterst~te UM Company {TrAILCo) Respo!'lsihle Customers'/Zones' ~Uocatio!'l shnes of monthly charges AE BGE CornEd ConEd Dayton Ouke Energy OHIKY Duquesne 1.70% 14,18% 5,39% 11.16% 2.12% 3.19% UU% s 77, $ s ,05 $ s 75, s 3.055,50 s 11, s 17, s 9, s 11.62% 1.79% 31,049,86 s 4,783,07 $ 1.70% 14.18% 5.39% 8.16% 4.24% 13,82% 0.56% 2.12% 3.19% 1,83' s t.9s4.313.oa s s s s s s 292, s s s 0,00% --1.!.:.! $ 79.16% 3.61% 0,86% 71.9,13 s s s s $ s $ s % 14.18% 5.39% 8.16% 4.24% 13.82% 0.56% 2.12% 3.19% 1.83% 2.49% 1, s $ 3.5e9.33 s $ s s $ 1, s 2,301,85 s s 1,700, % 14.18% 7, $ s 1.85% s 1, % 1,088,82 $ 1.85% $ 50.95% 13,42% 43, s 11, $ 1, % 5.39% 8.16% 4.24% 13.82% 0,56% 3,19% 1,83%,929, s s 18,6,14 $ :,51 $ 2.457,94 s 9, s s 8, s 21.49% 3.91% ,728.(;6 $ 21.50% 3,91% , $ 21.49% 3.90% 2,530,66 13, $ 74.36% 2,73' s s 0.00% 17, $ 97.68% 0, , $ s 0,00% $ 0.00% 37,S00.16 $ 0,00% $ 0.00% $ 8.58% ~ 3.72% $ 1.69% --lzd2. $ 6.23% s 97,68% 8, $ 0.00% s 16.75% 1, $ 0.39% s 0.32% 35. $ 0,96% s 287, s 2.4, s 1.160, $ 1.2, , $ 2,050,733,47 87,923.5& 314, $ 473, s % ,169,47 Required Transmission Enhancements owned by: Potomac App:olach!an Transmission HighHne, LLC. {PATH) RuponJible Customers'/Zones' ahoc~tlon shares of monthly ch:orgu AE AEP ATSJ BGE Com Ed ConEd Dayton Duke E!'letgy OH/KY Duquesne Oelm:uva 1.70% 29, s 1.70% s 56, s 14.18% s 14.18% 227, % ,77 s 5.39" $ 176, s 8.16% 4.24% 13.82% O.SS"h 2.12% 3.19' ,31 $ 72, $ $ s $ s 8.16% 4.24% 13.82% 0.56% 2.12'!(. 3.19% $ ,13 $ s $ 34, s , s 140,650,57 s 458, s 18, $ 70, s % s 1.83% ,705, % 42,650, % "0 ~ N C/) 0 ::r c,_..,0 0 - N :EO - 0 s 3 0""0....., (/).., (/) - '-<'< otn '-<X ::rc:r ;:::;: z 0

133 Upgt>lde b029/.l b0244 b0477 TOTAL PJM Upgrade b0217 b0222 b0403 b b b b0768 b0337 b0311 b0231 b0456 b0455 b b b b0837 b0327 b0329.2a b0329.2b b b1507 b0457 b0784 b1508,3 b1650 b b11u b169tl.1 b1321 Required Transmission Enhancements owned by: Baltimore Gu and Electrk; Company's Network Customers Monthly Rn!X!_I\_~i~le C1ntomers~(.Z'onu' ;~!location shares of monthly charges R11venue I Revenue Requirement Requirement AE AEP APS ATSI BGE ComEd ConEd Dayton Duquesne J<~n2013-M~~014 1t.994.soo.oo 1 s 999, % $ $ 8, I s 743,099, % s s I s 485, <l.5B% $ 439, s $ 1,833,706, , $ 2,228, Required Transmiulon Enhan<::emenls owned by; Dominion Virginia Power's Network Customers Annual Monthly Responsible Cudomers'/Zonu' allocation sh...res of monthly charges Revenue Re~nue Requirement Requirement AE AEP APS ATSI BGE Dayton D<1ke Energy OHIKY Duquesne Delmarva Jan..Oec ,985, !.70" % 5,39% 8,16% 4,24% 13.82% 0.56% 2.12% 3.19% \,83% 2.49% ! 1S ,184,174,00 986$1.17 1,396, I , G ,862, , I ,098,751, , $ s 1.244,12 s 1, s $ 3,189,94 s $ $ $ $ % 14.18% 5,39% 8.16% 4.24% 13.82% 0,56% 2.12% 3,19% 1.83% 2.49% $ $ $ 1.607,11 $ 835,06 s $ 1.29 $ 417,53 s s $ % 3, s 3,35% $ 3,54% ~ 4.22% $ 1.70% 14.18% 5.39% 8,16% 4,24% 13.82% 0.56% 2.12% 3,19%- 1.83% 2.49% $ s 159, $ 24t $ s ,13 $ 16, s s 94, s s % 14.16% 5.39% 5.16% 4.24% 13,62% 0.56% 2.12% 3.19% 1.83% 2,49% s s $ 16,203.4U $ $ ,63 $ s s 6, $ s 4, % 14.16% 5.39% 8,16% 4.24% 13,82% 0.56% 2.12% 3,19% 1.53% 2.49% s s 2,740,77 $ 4, s 2.15'3.01 $ $ s 1, $ 1.622,09 s $ 1,26,15 1,% ,009,263, I , , ,191, ,58 529, , , I , sso.84a.oo I aoo7o ,976, % 14.18% 5,39% 8,16':4 4.24% 13.82% 0.56% 2.12% 3,19% 1.63% 2,49% 0,71% 4, $ 38, s 14, $ s 11, $ 37, $ $ $ 8, $ $ 6, <'18.03 $ 33.69% 12.16% , s $ 3.35%,92% s ,18 $ $ 32.70% s 0.31% ~48$ 0.31% 0.31% $ $ 1,70% 14.18% 5.39% 8.16% 7.01% s 3.01% $ 6.850,86 $ $ s 1; s s s 4.46 s $ 19.79%- 15, $ 0,% 265,93 s 1.66% 1.80" % 0.04% 2.12% 3.19% 1.83% 2.49% 4,414, ~ 0,04" s $ s $ ,750, ! , ,456, ss.oo I , I LJOI:S.UI:S I , ,0,3!!6,00 S I % 14.18% 5.39% 8.16% 4.24% 13.82% 0.5'3% 2.12% 3.19% 1.63% 2.49% $ $ 156.()86.49 s $ $ s 16, $ 61, s 92, s $ % 19.66% 22.09% 0.18% 3.69% s 14,676,17 s 16, $ s % 14.18% 5.39% 8.16% 4.24% 13.82% O.S6% 2.12% 3,19% 1.83% 2.49% $ $ 167, s 253,395,55 $ 131, s 429, s 17,369,89 s $ 99, $ s % 14.18% 5.39% 8.16% 4.24% 13.82% 0.56% 2.12% 3.19% 1.83% 2.49% s $ s $ $ s $ s $ $ % 14.18% 5,39%.56 $ s $ 37,05% 1,70% 14,18% 5.39% 8,8?7.86 $ 0.44 s 3.64 $ 1.36 $ 1.70% 5.39% 0.44 s 3.64 $ 1.38 $ 6.16% s ~34 s 7.55% $ % 4.24% --.2:QL! 1.09 $ 8.16% 2.09 $ 1.09 $ 1J.a2% 13.82% s 3.55 $ 3.55 $ 0.56% 2.12% 3,19% % 2.49% 3.45 s s $ s % 2.12% 3.19% 1.83% ~ 0.47 s 0.56% 2.12% 0.14 s 054 s 0.62 $ 0.47 $ 1,70% 14.18% 8.16% 13.82% 0,56% 2.12% 3,19% 1.53% ~ s s s $ $ ~ ~.47$ 1.70% 8.16% 13.82% 0.56% 2.12% 3.19% 1.8.3' , s 1,590,8.5 s s s 475.':;:9 s 1.550,4i s 0.22% 7.SO A. 0.59% 1, s s 2.49% 1.70% 14.1!!% 5.39% 8.16% 4.24% 13.82% 0.56% 2.12%- 3.19% 1.53% $ s s s $ s $ 1, $ 2, s s % 14,18% 5.39% 8.16% 4.24% 13.82% 0.56% 2.12% 3.19% 1.83.(, 2.49% s $ 478,35 $ $ $ 1, s s $ $ $ % 1, $ 'i:!vj ~ 0 [Jq ::r (l> (!> wo.. c: 0 >-+,(!> - tv ~() :;:) :::::1 (l>u ~ "' - ;_:...:< urn <-<>< ::r- CJ ;:::;: z 0

134 b0756,1 b1797 b1799 b1798 b\805 TOTAL PJM Upgrade b0498 b0170 b0489 b b b\017 b0489.s-9 b b0290 b0472 b '""' bt226 bt b82 b\155 b1399 TOTAL 526, % 14.16% 5.39% 6.16% 4.24% 13,82% 0.56% 2.12% 3,19% 1.63% , ,60 S S S S S S S S S S SO 14.16% 5.39% 8.16% 4.24% 13,82% 0.56% 2.12% 3.19% 1.83% 2.49% 2, ! 1707S $ $ s s 7.239,84 s 23, s s 3, s s $ 1.70% 14.18% 5.39% tug% 4.24% 13.82% 0.56% 2.12% 3.19% ,069, , , s s s s s s s $ s s 2.2: % 14.18% 5.39% 6.16% 4.24% % 0.56' 2.12:% 3.19% 1.83% 2.49% 5, ! , : 8, s ,98 s ,66 s 38, $ 19, s s s $ s s 3.19% 1.83% , % 14.18% 5.39% 8.16% 4.24% 13.82% 0.56% 2.12% , , , , $.75 6, ,%1,04 s s s s s s s s S S 184, s 1.5,769,70 $ $ 869,385. $ 556, $ 1, , ,8-59,66 s 339, $ 194,972, , s 12,907, ,154,994,00 12,429, \'dqutincentives 5.733, , Required Transmission Enhancements owned by: PSE&G's Network Customers Annual Monthly Rupon$ible Customers'/Zonu' a.lk>ca.tion $h3ru ol mqn!hly chargu Revenue Revenue Requiremtnl Requiremtnt AE AEP ATSI BGE Com Ed ConEd Dayton Duke Energy OHIKY Duquesne Delmarva Jan~tc ,848,353 $ 1.36% 0,26% $ 400,48 $ $ 7, $ 665, ,871!$ ,25 316, % s 3.802, % 1.70% 5.39% 8.16% 4.24% 13.82% 0,56% 2.12% 3,19% 1.83% 2.49% 7,689,90 5, $ S ,05 S S 43, S S 6,717,SO S.7.94 $ 5.798,6-0 s $ 2.971,7ools ,6791$ 54,639, % 1.06% s 2.625,01 s 2, $ ,8S5IS ,00 tt,005.2sois , ls $ \S 236, $ 1.605, $ $ $ $ % 2.49% ,38 1,75% ,31 s 0,56% 1.70% 14.18% 5.39% 1!.16% 4.24% 13,82% 2.12% 3,19% 1,a3% 133, s 1,\17, s s s 1.0S9,117.S9 s 44, s 167, s 251, $ 144, s 5,07% 0.29% 0.48% 0.03% $ $ s s s 2.659,61 s s s s s 16, % 14.18% 5.39% 8.16% 4.24% \3,62% 0,56% 3.19% 1,83% ,38 30, s 5 s s $ $ s 8.02 s s 6.92: s % s % s % s s 0.56% 1.70% 14.18% 5.39% 8.16% 4.14% 13.82% 2.12% 3.19% 1.83% s s s $ s s s s s s 2.754, % 14.18% 5.39% 8.16% 4.14% 13.82% 0.56% 2.12% 3.19% 1.83% s 3.183,93 $ $ s s 3.3. s 125,74 s $ s 4.00 s 1.70% 14.18% 5.39% IUS% 4.24% 13.82% 0.56% 2.12% 3.19% 1.83% 7, $ 60, s s $ 59, , s s ,53 s s % $ ,834,17) t90 I s 3, s 4, ,59S.357IS !$ 4, lSG.S63IS 1,904, % 0.85% 2.11% s $ 40, s 97, $ s , ,9591$ 373, $ 306, $ 27,405, $ 291, s 1,242, , s 714, , ,311, s 697, s 191, , , , 'I:! 1=0 (Jq (1)..f::>. C/) 0 :::r (1) 0.. c...,(]) 0 - N :EO,..., ::l ~ (l)u rn 1=0 rn - :.:..-< urn <-<X ::ro-: ;:::;: z I. 0

135 PJM Upgrade b0487 b hll172.1 b b "'" TOTAL PJM Upgrade b0504 hll316 b1231 b0570 b b bl034.1 b34,6 b bt b2048 b34,8 b1870 TOTAL PJM Upgrade b0265 b0276 b0211 b02.a b02.b TOTAL Required Tr;msmiuiun Enhancements ownl!d by: PPL Electric Uhlitiu Corp. dbo:~; PPL Ut!lilles Annual Monthly Respon$ibleCustomers'/Zone$'alloco:~;tionsharesofmonthlycharges Requirement Requirement AEP ATSI Com Ed ConEd Dilyton Duke Energy OHIKY Duquesne 42,707,755.42/S 17,165.78/$ /S /S Jo:~;n-May ,430,48 1, , $ % 3.19% 2.49% ~$ % 2,49% ,49% % 6.16% 4.24% 13.82% 0.56"-' 2.12% 1.83% , s s ,74 s s s 29<l, s 19, s 75, s 113, $ 1.70% 14.18% 5.39% 8,16% % 0.55% 2.12% 1.63% $ s 77. s s 60,65 s s 8,01 s s 45,63 $ s 14.18% 8.16% 13.82% 2.12% 1.63% 1.70% 5,39% 0.56% 3.19% , s s s s $ $ s 1.70% 14.18% 5,39% 8.16% 4.24% 13.82% 0,56% 2.12% 3,19% 2.49% s $ ,26 s $ $ $ s &6,17 $ $ ,033.70/S , /S 475, ,336,839,32 $ 4,194, , $ 505, $ s 290, , , s 19, $ 75, $ 113,675.9$ 65, , Required Transmiuion Enhancements owned by: AEP Eut Operating Companies and AEP Transmission Companies Annual Monthly Responsibf.eCustomen'/Zones'allocationsharesofmonthlycharges Revenue Requirement 1 Requirement Jitn.Jun2014) t o.oo 1 s I s ,187, I s 98, , I s ! 1,859, ,67 1, $ 135, , !5 119, t.79t.OOIS AE AEP ATSI BGE Com Ed ConEd Dayton Duke Energy OHIKY Delmarva 1,70% 5,39% 8.16% 4.24% 0,56% 2.12% 3.19% 2,49% 2,5.17 1, $ 11, $ ( $ 6, s 3, $ 11, $ s $ 2.6%,99 $ 1,547,17 $ 99.00% 161, $ 99.73% 0.27% s $ 96.69% 3.31% s s 41.99% 5S.ot% , s s 13.82% 1.70% 14.18% 5.39% 8.16% 4,24% 0.~% 2.12% 3.19% 1.83% $ , s $ 5, $ ,48 $ $ s 4, s s 3, ,70% 14.18% 5.39%!1.16% 4,24% 13,62% 0.56% 2.12% 3.19% 1.83% $ ,17 S S 9, S 5,0S3.27 $ 16,568,57 $ S S $ S 95.01% 0.62% 0.19% 0.44% 0.13% :) ,38 s s $ s s s $ s 5.28 $ 96.01% 0.62% 0.19% 0,44% 0,13% s s s s s s s s s 155.an s s s s 1, s s s s 4,597.0S s s s $ $ s $ s s s s s s s s $ s 1, s 8,421.58!.70% 14.18% 5.39% 6.16% 4.24% 13.82% 0~% 2.12% 3.19% 1.83% 2.49% 301, s , s % 622% 3.52% 1.04"h s $ s 4,676,30 s s s s s s $ 591,65 s s % 8.22% 3.52% 1.04% s s s s $ s $ s $ 92.49% s % s $ $ s s s s s s s s s % 0.62% 0,19% 0.44% , s s s s s s s s s I s % 25.27% 3.85% $ 12JS0.24 $ s 764, s 30, s 51, s 19, , $ 2, $ , s /$ 1.323, , ,15!U6 Required Transmission Enhancements owmd by: Atlilntic Electric's Network Cuslomers Annui!l Monthly ResponsibleCustomer$'/Zunes' allocation sharu of monthly_ charges Revenue Revenue Requirement Requiremcmt AE ATSI BGE Com Ed Dayton Duke EnergyOHIKY Dt.aquune Oe/marvil Jan-May / s 57, % 1.04% $ $ 1,051,795.71\S 88, % 80, $ 1, /$ 151, % o.s5 ;. 97, $ $ 3,536,1261$ 303, % 14.18% 5.39% 6.16% 4.24% 13,82% 0.56% 2.12% 3.19' % 2.49'.4 5, s !1 s s s 12, s 41, s 1,6! $ s 9.6S6.03 $ 5, s !16 2, , ,65% 140, $ 1, $ 9,798,638.%1$ 616, $ s 42,% , ,725,65 s 12, s 41, , s 6, s 9, $ 5,545,09 7,544.9$ '"OC/J., ("l (JQ :::;- CD CD v.o.. c,_,.,cd 0 - tv :EO - 0,... - ::s ::;j CD'U rn., rn - ;..:.,-:< Cjt:Tl <--<>< :::::;- & ;:::;: z,. 0

136 PJM Upgrade b0512 b b b0751 b0733 TOTAL PJM Upgrade b0512 b0357,1 2 b0512,7 b b b b0478 b0526 b TOTAL PJM Upgrade b b22.2 TOTAL Annual Revenue Requirement,360,0341$ 2,212,4t7IS 34,t97.73IS $ 1,245, $ 14, $ Monthly Rev.tnue Requirement Jan-May14 663, , , , , Required Tnmsmission Enhan.;ements owned by: Delmarva's Network Customers ResponsibleC:tlslomen'/Zones' allo<::ation shares of monthly charges AE 3.19% AEP ATSI BGE CornEd ConEd Dayton DukeEnergyOJ..YKY Duquesne Delmarva 5.39% 8.16% 4.24% 13.82% 0.56% 2.12% 2.49% 21, , s s l$ s s s 18, s s $ s $ 64.50% 160, % 1.70% 14.18% 5.39% 8,16% 4.24% 13.82% 0,56% 2,12% 3.19% 1,83% $ 404. $ $ $ s s s s $ $ % 14.18% 5,39% 6.16% 4.24% 13.82% 0.56% 2.12% 3.19% 1,83% 2;119% 1, , , too.23 9, , $ $ s s s s $ $ $ $ 97.00% , ,30 $ 132,2.!7 50, $ 76, s 39, s 128, s s 29, , s.,,.1 I ~evenue Monthly Requirement Requirement Jan-May2014! 15, s ,240,4241$ , s 33, ,140,45 s , s , $ , s ,402,294 s Required Transmission Enhancements owned by; PEPCO's Network Customers RuponsibleCustomers'/Zones'aUo.;ationsharesofmonthlycharges AE AEP APS ATSI BGE Com Ed ConEd Dotyton Duke Energy OHIKY Duquesnl! Dclmarva 1.70% 14.18% 5.39% 8.16% 4,24% 13.82% 0.~% 2.12% 3,19% 1.63% 2.49% 21,670.8a $ $ 66, s 4, $ $ s 7.138, ,77 23, s s s $ 1.78% 26.52% 3.25% $ $ s 1.70% 14.18% 5,39% 8.16% 4.24% 13.82% 0.56% 2.12% 3.19% 1.83% 2,49% , JS , $ s s s s s s s s s s 1.70% 14.16% 5,39% 8.16% 4.24% 13.82% 0.~% 2.12% 3.19% 1.83% $ s s s 1, s 4, s , s s s s 1,83% 1.70% 14.18% 5.39% 8.16% 4,24% 13,82' s s s s $ s s $ 4, s 1813,13 $ 1.70% 14,18% 5.39% 8.16% 4,24% 13.82% 0.55% 2.12% 1,83% $!.&26.63 s 2.765,36 s 1, s s s $ s s 1,68% 1.83% s s 3,54% 7,31% s 1,076, s 0,77% 7, s $ $ s 16.76% s s 30.57% 1.22% $ s 29,68% 2, $ 5,67% I s s 58, s 1, s s $ s 3, s 37, , s 115, , , , ,9(;().88 s s Annual Monthly Requ ~rl!d Transmiuion Enhan.;ements owned by: Duquesne LiqhtCompany's Network Customers Ruponsible Customl!rs'/Zone~<' ;!!location shmu of monthly.;harges Requlrl!ment I Requirement AE AEP ATSI BGE CornEd ConEd Dayton Duke Energy OHJKY Duquesne Delmarva Jun201l-Mav so.t84.oo 1 s 1.746, ,74% 93.26% s $ s Is 96.98% 3.02% s s 1,630, s 175,938,85 '"0 P' ao ('!) 0\..., 0 [/} (") ::::; ('!) 0.. c (D N :ECJ - 0 ;::I... - ;:j ('l)v CIJ P' CIJ - ;..:..~ vm c... X ::::;- & ;:::;: z 0 I.

137 PJM Upgrade ID b0216 b0216 b b b0347,1 b b b b0323 b0230 b<l559 b0229 b0495 b0343 b0344 b0345 b{)704 b1243 b2148 b<l553 b<js$4 b0574-b23,3 b23.3 b23.2 bt770 b1990 b1%5 bt839 b1998 b{)556 b1153 b0574-b23.1 b23.1 TOTAL PJM Upgrade 00 b0490 bq491 b0492 b0560 TOTAL Annu11l Monthly Requirement I Requirement J"n-Mav , a , ,077,955,51 l 5 89, , , , , , ,2: , , $ ,75 1,133, ,6$2.19 I 5 17, , I , I ,88 34,994,25\5 2, ,353, , I s , I $ , , , $ 2.0%.& o.eo I ti , t is 8, ~-*"~ired Transmission Enhancemeots owned by; Traos-Aife~:~henylnteutate Line Comp"ny {TrA!LCoj Responsible Customen'/Zones' allocation shues of monthly ch11rges... c... Dominion EKPC HTP JCPL MetEd Neptu~~e I PECO Penelec PEPCO PPL PSEG Rodd11nd Power % 1.57% 0.01% 3.%% 1.67% 0.42% 5,35% 1.92% 4.05% 4.59% 6.46% 0.27% 0.20% , $ s 29.19(], s s 1, % 15.28% 38.70% 36, s 40, s $ 1,57% 0.01% 3.95% 1.87% 0.42% 5.35% 1.92% 4,05% 4,59% 6.46% $ s s 545, s s s , s 558, $ s % 0,67% 3.95% s s s 11.65% Ul7% 4.05% 1.57% 0.01% 3.%% 0.42% 5.35% 1.92% 4.59% 8, s 1, s s 1,349.3$ s 3{'13.06 s , , % 1.43% 17.64% 12, s s s $ $ $ $ $ luis% 1,87% 4.05% 1.57% 0.01% 3.00% 5,35% 17, , $ $ $ $ , $ $ $20.146,35 $ 35.19% % 2,97% 5.73% 28.82% 2.97% 16, s 1,7JS.59 $ 28,83% 2.98% 18, $ $ $ 0.00% 5 7, $ 16.16% 1.55% 1.77% s $ $ 12.52% 6.87% 1.70% s 753,47 s s 3, ,74% 35.20% $ 5.75% 35.20% 3,731. $ $ $ 22.91% $ $ 21.78% $ 11.49% 1, ,00% 6, % % $ 2.308,32 $ 0.00% s 0.00% 2.0%.89 s 1.09% % s 0.55% 15.35% $ s o.27% o.2oo;. 1 s 37, I 6.46% o.27% o.2o% :14.32 s s 6.46% % %.33 $ o.21,. o.2o% I o.o1% ~I 3, l 26.13% 0.97% 0.73% s 9.87 s % o.71% 2.ss% s o.2s% o.ot% o.o1% $ 0.88 $ 0,97 -I I I I , s 30, ,252, ,771, $ 1,840,65$.36 $232, , , , , Required Tun~missioo EnhMeements Owt'led by: Potomac Appalachllln Transmission Highlme, LLC, {PATH) Annual Monthly Revenue Revenue Requirrment Requirement J01n.Oec , ,00 1, $19, ,604, $39, ,317, Responsible Customers'/Zonu' ;dloeatioo shares of monthly charges Pene/ec 1.92% 0.20% EutCo<1sl Power Dominion EKPC JCPL MetEd Nrptune PECO PEPCO PSEG Rockf11nd 4.05% 0.27% 11.65% 1.57% O.ot% 1117% 0.42% 5.35% 4.59" s 26,692.Qa s $ ,03{'1.70 s s 91,638!$2 s % 0,01% 3.9$% 1.67% 0.42% 5.35":4 1.92% 185, s s $ ,65 s $ ,45~.18 $ 52, $ , $62, s 13, s 177, s 63, s s $ $ $ 4,05% 4.59% 6.46% 0.27% s $ 134,34!:1.12 $ , $ '"0 p.:> (fq CD --.) (/J () ::r (D 0... c --t,cd 0 - N :;EO ~ = CDu "' p.:> "' ~~ - vrn <...;;>-( ::rv ;:;: z 0 I. l l l I I I l I I I I I I

138 Upgrade b0295 b0244 b0477 TOTAL PJM Upgr;;~~de b0222 b0226 b0403 b b b b0337 b0311 b0231 b0456 b0227 b0455 b b b0837 b0327 b0329.2a b0329.2b b b1507 b0457 b0784 bl224 b b1648 b1650 b bttm b\698.1 Required Tran~miuion Enhancemenb owned by; Baltimore Gas and Electric Company's Network Cu$tomers Annuo.l PECO PPL 4.73% 0.92% 3.00% Monthly ResponsibleCustomers'JZones'alklcation$haresofmonthlycharges Revenue Requirement Requirement Dominion EKPC HTP JCPL MetEd NepttJne PEPCO Jun2G13-M.ty2G I s % 7.88% $ $ $ $ 8,917,197,001$ 743, % 13.61% $ s.s 5,827, $ % 4.01% $ $ s $ $ 199,3?2.28 $ ,738, $ 2.228, $ $ $ 60, , Required Transmlnion Enhancements owned by: Dominion Virginia Power's Nl!twork Customl'ts Annu-.1 Monthly Responsibll'CUstomers'JZonu'-.Uocationsharesofmonthlycharges Revenue Revenue Requirement Requirement Dominion EKPC HTP JCPL MetEd Neptune Penelec PEPCO ~ , I 1% ,184, , , , I 29S095$ , I , , I , '"'.> ,191, , I ,731, o.oo $ , ! 1227>: , ! I llll~.oo $2.42 1, I % 1.57% 0.01% 3.96% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% $ 3$2.39 s 2.31 $ s s s $ $ $ $ 11.65% 1.57% 0.01% 3.%% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% $ $ 1.97 $ s s $ $ $ s $04.00.s 85.73% 7.04% $ $ 83.94% 7.39% s s 11.65% 1.57% 0.01% 3.96% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% $ s 295. $ $ $ 12, s 153, s s $ $ 11.65% 1.57% 0.01% 3.96% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% s s s s $ s s s s $ 11.65% 1.57% 0.01% 3.9S% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59' s $ 5.08 $ s s s 2, $ $ s 2, s 0.00% $ 0.00% s 0.00% s 11.65% 1.57% 0.01% 3.9'3% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% s s $ $ $ s 14, s $ s $ 40.08% 14.05% 24, $ $ 67.31% 0.89% 2.33% 12.19% 0.54% s s V66.75 s 6.19(1.09 s s s 50.82% 7.67% $ $ 92.75" % 3.86% 18.0%.07 $ 5.85 s ~ 92.75% 0.03% 3.86% 211,2.17 s s $ 92.75% 0.03% 3.86% s $ $ 11.65% 1.57% O.o1% 3.9S% 1,67% 0.42% 5.35% 1.92% 4.05% 4.59% s s 0.97 s s s s s $ $ $ 76.18% 4.03% 60, $ $ s 11.65% 1.57% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% 337, $ $ $ $ s 12, $ ~ $ $ s 0.71% 2.48% 0.06% 5.53% 41.78% 2.07% s s s s $ s 11.65% 0.01% 1.87% 0.42% 5.35% 1.92:% 4.05% 4.59% 361, s 48, s 3.53 $ $ $ s 1& s s $ $ 11.65% 1.57% 0.01% 1.!7% 0.42% 5.35% 1.92% 4.0S% 4.59% $ s 0.20 s s $ 8.56 s 9.03 $ $ $ s 1.57% 0.01% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% $ 9.75 $ 0.00 s s s 2.61 s s $ s $ 78.21% 0.77% 1.39% 11.04% s $ s s s $ 11.65% 1.57% 0,01% 1.87' % 5.35% 2.99 $ 0.40 $ 0.00 s 1.02 $ 0.48 s 0.11 s 1.37 $ 0.49 $ 1.04 $ 1.18 s 11.65% 1.57% 0.01% 3.9S% 1.87% 0.42% 5.35% 4.05% 4.59% 2.99 s 0.40 s ~ 1.02 $ 0.48 s 0.11 s 1.37.s ~ 1.04 s 1.18 $ 11.65% 1.57% 0.01% 3.943% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% 1.307,01 s s ~ s s $ $ ~ $ $ 11.65% 0.01% 1.67% 0.42'; % 1.92% 4.05% 4.59% s $ 1.12 s s s s $00.22 s $ $ $ 75.56% 0.22% 0.73% 14.76% 155.9il8.71 s $ $ $ 1.57% 0.01% 3.%% 1.87% 0.42% 5.35% 1.92% 4.05% 4.S:9% s $ 9.17 $ :27 $ $ s $ s 3, s 4, s 11.65% 1.57% 0.01% 3.%% 1.87% 0.42% 4.05% s s 0.89 $ s s s 474.eo s s $ $ 97.95% 1.19', s s '"'" "' I PSEG Rockland Power I 1 I E:utCout PSEG Rockland Po\Wr 6.46% 0.27'JI $ $ % 0.27% 0.20% l s $ I 6.46% o.27% o.2o% $ s 6.46% 0.27% 0.20% l $ s 6.46% o.27% o.2o% s $ I 6.46% o.27% o.2o% 1 17, s s I I I 6.46% o.27% o.2o% s s I I 6.46% o.27% o.2o% $ $ 6.46% o.27% o.2o% I !U $ $ 6,2.66 o.21% o.zo% $ 5.50 s s.4s% o.27% o.2o% s 1.66 $ 1.24 o.27% o.2o% $ s 6.46% o.27% o.2o% s s o.2m o.2o% s s 6.46% o.27% o.2o% s s 6.46% o.27% o.2o% $ s o.27% o.2o% s 23.% $ "1:j ~ (t> , [fj 0 ::r (t> 0.. ::::: (i) N :EO ::l ::i (t>u "' ~ P> :;:j <...,'< t)ttl <...,;>< ::r o-: ;:::;: z 0 I. l I I I I I I l

139 b b1797 b1799 b17911 b\805 TOTAL PJM Upgrilde b0130 b0134 b0145 b0411 b0498 b0161 b0170 b0274 b b b0813 b17 blots b0469.s..9 b141().1415 b0290 1>0472 b0664-s65 b<l 68 b0614 b1156 b11s4 b1228 b b1155 TOTAL 52:8, ,049, ,069, ,659,293,00 2,597,405,00 154,6tl8, ,154, ,733, s Hi U s ,65% 1.57% 0.01% 3,96% 1.87',1, 0.42% 5, s $ 4.41 $ 1, s s $ 1.57% 0.01% 3.SS% 1.87% 0.42% 19, s s s 6, s 3, $ $ % 3,9$% 1,87~,1, 0.42% $ 1, s $ $ 1, $ s 11.65% 1.57% 0.01% 3.9$% 1.87' % s 7, $ 47,16 $ 18, $ s 1, s 11.65% 1.57% 0,01% 3.96% 1.87% 0.42% s 3, $ $ s 4,047,62 s s 3,098,494,31 $167, $ 1, $ ,49 $ 205, s 44, s 5.35% 1.92% 4,05% 4.59% $ e46.27 $ 1, $ $ 5.35' ".4 4,05% 4,59% 9, $ : $ s 7, s 5.35% 1.92% 4.05% 4.59% 4, :s 1, $ s 4, s 1.92% 4.05% 4.59% $ 9, $ 19.0,11 s s 5,35% 1.92% 4.05% 4,59% 11,5.50. s $ 8, $ 9, s 584, s 204, $ 590, $492,0.38 $ Required TrilMmiuion Enhilncements owned by: PSE&G's Network Customers Annultl Monthly Responsib~ Customers'/Zones' allocation shares of monthly ehilrges Revenue Revenue Requirement Requirement Dominion EKPC HTP JCPL MetEd Neptune PECO Penlrlee PEPCO J;m-Oec ,353 :s 47.63% 752,534jS 62, ,0261$ 665, ,6711$ , IS 316.1! ls ,92 ~ 23.35% 51.11% 32, $ 73.45% s ,76 $ 7.04% 0.28% s $ 39, s 3,%% 1.87% 0.42% 5.35% 11.65% 1.57% 0,01% 1.92% 4.05% 4.59% 16, $ 6,083,78 s 12, s s $ 4, $ s 12,547,79 s 5,925,34 s 1, $ 2.971,706!$ 247, ,6791$ 54, %.51% s s 26, s 42,95% 17.9<.1% s 9, $ 2.344,7131$ , IS 7, , I s IS ,5a9\$ 1, ,0S0.516 Is 174, !$ $ I s , ,044,08 11,65% 1.57% 0.01% 3.9$% 1.87% 0.42% 918,5.98 $ s s 312, $ 147, s s 32.57% 6.29% $ s s 57, s 11,65% 1.57% 3.%% 1.87% 5, , $ s 0,04 $ $ s 1.59 $ 9.92% 0.87%, $ 879,55 s 14.69% 1.39% $ s s 14.77% 1.39% ,46 s s s 11.65% 1.57% 0.01% 3,943% 1.87% 0.42:% $ $ 11.0S s 4, s s s 11.65% 1.57% 0.01% 3.95% 1.87% 0.42% $ s 2.25 $ s $ s 11.65% 1.57% 0.01% 3.95% 1.87% 0.42% 49,881A6 $ S $ $ 8.01)5,72 $ 1, S 5.35% 1.92% 4,05% 421, s 151,3.17 $ 319, $361, s 9,99% 0,56% SS $ S 5.35% 1,92% 4.05% $ 7.26 s $ 17,35 s 1.11% s 5.35% 1.92% 4.05% 4.59% 5, $ $ $ $ 5.35% 1.92% 4.05% 4,59% 1, s s $ 1.030,62 s 5.35% 1.92% 4.05% 4.59% 22,905,93 s 5, s 17, s s $ ( )15 ( ' 35,35% $ 39.41% s 23.49% $ (20,632.25) s 18.80% 1, s 20.38% $ 1.61% ( ) $ 5.37% ' ) $ I s 3, {$ 4.477,147A $ , % , t.70g.91jis 142, ~IS 373, ,6411$ % 1.05% s $ 49, :s 0.790% % $ s s 4.61% s 0.05% s 1.150% s $ 2.70% $ s % s s 23, s 0.95% s 0,570%, s s 1,020, $137, $ s 1,714, $ s 1,572, $ 317, s $402, $ 6.45% o.27% o.2o% $ s 6.46% o.27% o.2o% 1 11, s $ 6.46% o.27% o.2o% s $ % o.27% o.2o% s s 6.46% o.27% o.2o% , $ s 656, $26, $21, PSEG Rockland e...c..., I Power % s 45.9 % 2.93% 1 28, , s s 21.78% 4.77% I 144,982,67 $31,752,40 s 22.31% l s 6.46% o.27% o.2o..., 1 20, $ $ % 0.20% I 201, s s 2.11" % 146, s % 0,79% I $ s 88,56% 2.95% 1 173, $ 5, % 0.20% l $ $15, ~ 1.s1% o.95% 1 $13, s 8, % o.27% o.2o% $ 1.02 $ ,73% 3.12% I s 3, s 32.64% 1.2a% o.44% : s $ 1.28% o.44% I s 1, ,31 $ 6.46% o.27% o.2o% s s % o.27% o.2o% $ $ 5.46% o.27% o.2o% 1 656, s s 2.03% s s 43.24% 1.61% I s s 38.76% 1.45% I s $ 67,03% 2.50% { ) s { ) s 3.82% a5.28 $ s %.18"h 3,82% I $ s 95.83% 231, % 2.%1, ,460% % , % ~ 14,058, % o.22':4 1 s 9, $ 2.53% % 1 $ s % o.85o% 1 $ s ,19% I ~ 3.64% $~ 3.82% s 11, s $560, $146, I '"'0 I" (JQ (I) \0 0 _.., [/} 0 :::; (1) 0.. = (D N ~0-0 s s (1)'"0 (/] I" - (/] :..:.,-< t:jtn '--<X :::;- &= ;::+ z 0 I. l l I

140 PJM Upgrade b0487 b b b b b0791 b0468 TOTAL Upgrade b0504 b0839 bt231 b0570 b b b!034.1 b34.6 b\465.3 b b b b34.6 b1870 TOTAL PJM Upgrade b0265 bc276 b0211 b02.a b02to.b TOTAL Required Transmluion Enhancements owned by: PPL Eleetrlc Utilities Corp. dba PPL Utilities Annu11l Monthly Responsible Customers'/Zones' alk>eation shares of monthly charges Revenue I Revenue Requirement Requirement Jan.May ,707, , t7, is 1, Is , $ 2, ,073, $ 89, Is &6, ! s %1 50,33G,S39.32 $ 4,194, ''"c"'" I Dominion EKPC HTP JCPL MetEd Neptune PECO Penelec PEPCO PPL PSEG Rockland Power 11.65% 1.57% 0.01% 3.96% 1.87% 0.42% 5.35% 1.92% ,59% 6.46% o.2o% S 55, S 355.S<l S 140, S 6, S 14, $ 190, s 68, s 144, $ s s 9, $ % 1.57% 0.01% 3.00% 1.117% 0.42% 5.35% 1.92% 4,05% 4.59% 6.46% o.27% o.2o% , s s s s $ $ s s $ $ S $ 11.65% 1.57% 0.01% 3,96% 1.87% 0.42% 5.35% 1.92% 4.05% 4,59% 6.46% o.21.,. o.2o% , $ s $ $ s s s s s $ s s 11.65% 1.57% 0,01% 3,96% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% 6.46% o.27% o.2o% $ $ 0.21 s $ s 8.71 $ 1.97 s s 84,01 s s s 5.60 $ % 77.59% 5.13% o.t9% o.t9% 1 $ $ ~ 4,589,13 $ s % 90.45% $ s s 4.55% 0.37% 1.79% 0,33% 86.63% 5.93% 0.22% 0.1S% I 21,613.27!, $ 8, s 1, $ $ 28J68.5! s 1, , ,148,94 $ 55, $ s 162, $ 65, s 16, $ 199, $ 91, , $704, $ 262, $, Required Transmission Enhancements owned by: AEP East Operating Companies and AEP Tunsmission Companies Annual Monthly Ruponsible Cust.omers'/Zones' atkjcation sh3tu of monthly charges Revenue I Revenue Requirement Requirement Jan.Jun2014 Dominion EKPC HTP JCPL MetEd Neptune PECO Penel~:>c PEPCO PPL EastContl PSEG Rockland Power -- t.ot4.54o.oo 1 s 84.54s.oo 11.65% 1.57% 0,01% 3.%% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% 6.46% o.27% o.2o% 1 9, , , , , , , $ s $ $ s s $ $ s $ s s 1,952, Is 162, % I $ 1,187, I s 98, I IS 139.1%,92 I 1,859, I s 154, I 1, Is % 1.57% 0,01% 3,96% 1.87% 0.42% 5,35% 1.92% 4.05%.:1.59% 6.46% o.27% o.2o% s s $ 5, $ s 568.1! s 7, s $ 5, s 6, s 8, $ s , I s 119, % 1.57% 0,01% 3,%% 1.87% 0.42% 5.35% 1.92% 4,05% 4,59% 6.46% o.2m o.2o% 1 13, s s 11$ s s 2, s s s $ 4, s s s s ,791.00/S % 2, $ 424,9Hi.OO S 35, $ s s $ $ $ $ s $ s $ s s $ $ $ $ s s $ $ $ $ $ s 12, , % 24.70% 301, $ , $ $ $ $ s s $ $ s 6, $ $ s s I, s s $ s s s $ s $ s s s s $ $ s s s $ s s $ $ s s s 1,301, s % 1.57% 0.01% 3.95% 1,87% 0.42% 5,35% 1.92% 4.05% 4.59% 6.46% 0.27% 0.20% $ 56, , $ 14, ,284,00 s % s I s ,860,240.00/$ 1,323, , , s 17, , s!,882. s 23, s , s 20, S U Required Transmiuion Enhancemenb owned by: Atlantic Electric's Network Customers Revenue I Revenue Annual Responsible Customers'/Zones' :~lk>eation shue5 of monthly charges Requirement Dominion EKPC HTP JCPL Neptune Pentlec Jan-M_a_l2_! ,4151$ 9,38% 0.64% $ $ 1,061, I s 1.613, $ 25.70% 2.53% 3, $ $ 3,636,126!$ 11.65% 1,57% 3.96% 1.67% 0.42% 5.35% 1.92% s tt.s99.21 S 5.6SS.30 S s $ $ 16, $ 2,592,691/$ 25.70% 2.53% s s 9,798,638.9UIS s $ 4, s s 111, $ 5,6S5,30 s s 16, $ s 4.05% PPL 4.59% $ s $ 13, $ PSEG EastCouf I Rockl:~nd Power J e.29% o.23% o.2o% s s 6.31".4 I s o.27% o.2o% , s $ s $ $ I "0 ::>:> (Jq (I) 0 0 >-to [/) () :=> (I) a. c (p N :;EO ::l ::l (1)'"0 (I) ::>:> ~ ~ '--<'< t::jtrj <-<X :::> o ;::;: z 0 I. I

141 Upgrade b0512 b0241,3 b b0751 b0733 TOTAL PJM Upgr~de b0512 b b bos12.8 b b b0478 b0499 b0526 b04&6 TOTAL PJM Upgrade b b22.2 TOTAL Required Transmission Enh:;~;ncements owned by: Oelm:;~;rva's NetWI>fk Cudomers Annu.:~l Monthly Responsible Customers'/Zones' :;~;!location shares of monthly chargu Requirement I Requirement EKPC HTP JCPL MetEd Neptune PECO PPL J~n-M~v2014 t0,3s0,034is 863, ,272,4171$ 189, ,197.73!$ 2, !$ 65,\ , $ 3, % 1.57% 0.01% 3.96% 5.35% 1.92% 4,59% $ s s 34J88.11 s 16, s s $ s s 39, s 15.50% $ 5.35% 11.65% 1.57% 0.01% 3.96% 1.87% 0,42% 1.92% 4.05% 4.59% s $ 0.28 $ $ $ $ s $ $ $ 1.57% 0.01% 3,96% 1.87% 0,42% \,92% 4.05% 4.59% 11.65% 5.35% ~ \, Ul $ s s $ $ $ $ s $ s 2.94% 3, ,706, $ 1,225, s \ $14, s s $ 17, , , , $ 37, $ ,82 $.,,,., I Revenue Requirement Required Transmission Enh~ncemen!s owned by: PEPCO's Network Customers PPL Responsible Customers'JZon<l$' Monthly I altoeation shares of monthly chmges Reve-nue I Requirement JCPL MetEd Neptune PECO Penelec Dominion EKPC HTP PEP CO 15,297,091 $ 4, $ $ 403, $ J~n-1-.l<~y ~ ~ s ;::,~.59 s o.o1 1 ~.45 s ::So.4o s ~;~;~_97 s -;~3~3.98 s!: s ~:~~5.35 s 4,05% 4,59% $ $ % 1.16% 0.25% 4,79% 52.46% _ $ $ s $ s s s 33, % 1.57% 0.01% 3,95% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% 3,9\3, ,330, , ,3&1, ,01 s s $ $ s s s $ s s 33, % 1.57% 0.01% 3.95% 1.87% 0,42% 5.35% 1.92% 4,05% 4.59% ,36 1, , ,3$0.60 1, s $ $ $ $ $ $ $ $ $ 403, s % 1.57% 0.01% 3.%% 1.87% 0.42% 5.35% 1.92% 4,05% 4.59% % 1.57% 0.01% 3.95% 1.87% 0.42% 5.35% 1.92% 4.05% 4.59% 400,671.04! s I $ $ 3,39 $ s $ $ 3,440,212 $ 28S.fi % s 89.15% 6.402,294 s s 74.86% 12,056,752. $ % 0.59% 0.13% 2.% s s 1, s $ $ 69,43% 1,076, $ 62,294. s 53.74% 2,384,651 s 198, I.91% 21.6B0.45 s 6, s B.93 $ , $ 3,877, $ 185, s 22, $ , $36, s 8, , $ $ $ $ 3.36 $ s $ 14\, $ 1, s 645,02 s s $ s s $ 1, $ Required Tr<~n:smission Enhanc:<.'ment:s owned by; Duquesne Ugh! Company's Network Customen Annual Monthly Respon~ible Customen'/Zones' ~lk><:ation shatf!s of monthly charges Revenue Requirement Requiremenf I Dominion HTP JCPL Neptune PECO Pomelec PEP CO Jun2013-May ,960, $ 1,746, \S 60, ,680, $ 1,806, c=-u7f TOtiiTECtO Dolllii'IIOO-ZOne I PSEG... c... I Roekbnd Power % % 0.20% --1 s s I 6.46% 0.21._,. o.2o% $ $ 6.45% o.27%- o.2o , s $ 60, , , I EastCout PSEG Rockland Power 6.46% o.27% o.2o% I ,34 s $ % o.os% s $ % o.27% o.2o% $ s 6.46% o.27% o.2o% s s 6.46% o o.2o% $ s 6.46% o.27% o.2o% s $ I 2.% 0.08% I s s I s s c... I Roekland Power J 1 '"'0 P:> (JQ ('!) 0..., [/J (") ::::; ('!) 0.. t:: (D N :EO :::;. Q ::s ~ (!)u en P:> en - ;..:..:< um <--<X ::::;- v :::::;.: z 0,. 1 ' l I I I

142

143 DIRECT TESTIMONY OF PAUL B. HAYNES ON BEHALF OF VIRGINIA ELECTRIC AND POWER COMPANY BEFORE THE STATE CORPORATION COMMISSION OF VIRGINIA CASE NO. PUE Q A. 5 6 Please state your name, business address, and position of employment with Virginia Electric and Power Company ("Dominion Virginia Power" or the "Company"). My name is Paul B. Haynes and I am Director- Regulation for the Company. My business address is One James River Plaza, 701 East Cary Street, Richmond, Virginia A statement of my background and qualifications is attached as Appendix A. 7 Q. 8 A Mr. Haynes, what is the purpose of your testimony in this case? The purpose of my testimony is to discuss and sponsor the revised Rider T1 based on the revenue requirement presented by Company Witness David M. Wilkinson, to become effective for usage on and after September 1, In addition, I will discuss the impact that the revised Rider T1 rates will have on customer bills. 12 Q. 13 A During the course of your testimony, will you introduce an exhibit? Yes. Company Exhibit No._, PBH, consisting of Schedules 1-6, was prepared under my supervision and direction, and is accurate and complete to the best of my knowledge and belief. I am also sponsoring Filing Schedule 46C, Statement 1, which details the Company's methodology for allocating the revenue requirement among the rate classes and the design of the class rates.

144 1 2 Q. Mr. Haynes, would you please discuss the methodology used for calculating the revised Rider Tl rates? 3 A Yes. With one exception which I will discuss later in testimony, the Company has calculated the revised Rider Tl rates in accordance with the same methodology as those rates approved by the Commission with respect to the most recent revision to Rider Tl (Case No. PUE ) In order to develop revised Rider T 1 rates applicable to each of its rate schedules, the Company must first determine the forecasted kwh sales for each of the rate schedules. For the Virginia jurisdiction, the Company forecasts kwh sales and customers by "Revenue Class" (Residential, Commercial, and Industrial are the Company's revenue classes), and this Revenue Class kwh sales forecast is shown on page 1 of Schedule 1. Accordingly, the Company's forecasted kwh sales for each Revenue Class must then be allocated to the rate schedule level. This allocation was performed using historical monthly customer and kwh usage for each rate schedule to capture recent trends of kwh sales and the numbers of customers within each rate schedule. This allocation by revenue class (and within revenue class by rate schedule) is shown on page 2 of Schedule 1. During this allocation process, those rate schedules serving very small populations (e.g., Residential Rate Schedules DP-R, lev, and EV) are represented by the primary alternative tariff (e.g., Residential Rate Schedule 1). The summary on page 3 of Schedule 1 shows the allocation of the twelve-months ending August 31,2015 forecasted kwh sales for each rate schedule. Pages 4 and 5 of Schedule 1 categorize the forecasted rate schedule kwh sales into 2

145 1 2 the eight customer classes (i.e., the Residential, GS-1, GS-2, GS-3, GS-4, Section , Church, and Outdoor Lighting customer classes) The next step is to allocate the Virginia jurisdictional revenue requirement sponsored by Company Witness Wilkinson to these customer classes. The Company has done this class allocation in a manner similar to the allocation of the total Subsection A 4 costs to the Virginia jurisdiction based on customer class demands and energy. Page 6 of Schedule 1 shows the detailed allocation of the combined revenue requirement among customer classes in a manner similar to the allocation to the Virginia jurisdiction, along with the resulting average rate per kwh by customer class based on forecasted sales for twelve-months ending August 31, Next, the relevant customer class rate as determined by the Company on page 6 of Schedule 1 was applied to the twelve-months ending August 31,2015 forecasted kwh sales for each schedule within the associated customer class to determine a rate schedule-specific revenue requirement shown on page 7 of Schedule 1. The resulting "all in" transmission rates (the Subsection A 4 component of base rates plus Rider T 1) per kwh are shown on page 8 of Schedule Rate Schedules GS-2, GS-2T, GS-3, GS-4, 8, and are billed on a demand basis, rather than an energy basis. The Section Schedule is billed on a combination of demand and energy. The calculations for the development of the "all in" demand charges applicable to these rate schedules are shown on Page 9 of Schedule 1. In addition, as a result of the Commission's ruling in Case No. PUE , a small number of Rate Schedule 1 net metered accounts are subject to a minimum Subsection A 4 charge per kw (applicable only to net metered installations 3

146 above kw). Because the additional revenue associated with this minimum charge is not material at this time, the Company has simply adjusted the minimum rate per kw in proportion to the change in the Schedule 1 energy rate (the resulting rate is shown on Schedule 3) Q. A. You stated earlier that you have made a change to the methodology for calculating the revised Rider Tl. Please explain. The change to the approved Rider T1 methodology involves the Rate Schedules 5, 6, 6TS, and 7 that are populated with kwh from two or more customer classes. Rate Schedules 5, 6, and 7 are closed, which means that no new customers may take electric service under these tariffs. Rate Schedule 6TS, while still open, experiences continual declines in the number of customers served. The Company proposes that the Rider T1 rate for each of these rate schedules be equal to the rate of the customer class that contributes the majority of the kwh to that rate schedule. For example, Rate Schedule 5 has approximately 7.7% of its kwh sales from the GS-1 Customer Class, 87.2% of its kwh sales from the GS-2 Customer Class, and 5.1% of its kwh sales from the GS-3 Customer Class. Therefore, the Rider T1 rate for Rate Schedule 5 will be equal to the GS-2 Customer Class rate. The Rider T 1 rates for Rate Schedules 6, 6TS, and 7 will be set in a similar fashion. Making this change in methodology will simplify and clarify the overall rate calculation without making a material change to the resulting Rider T1 rates by rate schedule. A summary of the revised methodology showing the contributing kwh and the resulting rates as it compares to the current methodology is shown in my Schedule 2. 4

147 1 Q. 2 A. 3 4 Mr. Haynes, do you have an exhibit showing the derivation of Rider T1? Yes. Schedule 3 shows the derivation of Rider T1, which is simply the difference between the Subsection A 4 cost of service rate and the existing Subsection A 4 component of base rates. 5 Q. 6 7 A Do you have an exhibit which shows the revenue breakdown between the Subsection A 4 component of base rates and Rider T1? Schedule 4 shows the proposed Subsection A 4 revenue requirement breakdown between the Subsection A 4 component of base rates and Rider T1. The Company forecasts collection of $488,266,973 through the Subsection A 4 component of base rates and proposes a $49,752,283 revenue requirement through Rider Tl. Thus, the net Subsection A 4 revenue requirement is $538,019, Q A. 15 Do you have an exhibit showing the Company's proposed Rider T1 effective September 1, 2014? Yes. Schedule 5 shows proposed Rider T1 which, if approved as proposed, would be applicable for usage on and after September 1, Q A If approved, what is the impact of the proposed Rider T1 on a 1,000 kwh per month residential customer's bill? The implementation of the Company's proposed Rider T1 on September 1, 2014 will increase the residential customer's monthly bill by $1.91, based on usage of 1,000 kwh per month. Schedule 6 provides typical monthly bill increases for customers receiving service on Residential Schedule 1; General Service Schedules GS-1, GS-2, 5

148 1 2 GS-3, and GS-4; and Church Schedule 5C at several representative levels of consumption or demand. 3 Q. 4 A. Does this conclude your pre-filed direct testimony? Yes, it does. 6

149 APPENDIX A BACKGROUND AND QUALIFICATIONS OF PAUL B. HAYNES Paul B. Haynes received a Bachelor of Science degree in Business Administration from the University of Richmond in 1984 and a Master of Business Administration with a Concentration in Quantitative Methods from Virginia Commonwealth University in Mr. Haynes started his career with the Company as a meter reader. He went through the Company's Customer Service Representative training program for three-and-one-half years, during which time he designed distribution facilities to serve residential and non-residential customers. In 1990, Mr. Haynes joined the Rate Department to work in the Rate Design section, where he assisted with regulatory filings and the design of rates, and performed analysis related to the Company's Virginia and North Carolina service territories. He has held various staff analyst positions within the Cost Allocation and Pricing Department, formerly the Rate Department, since that time. In 2006, Mr. Haynes became Project Manager of Regulatory Research and Analysis, and then became Manager of Regulatory Analysis, Research and Support in On June 1, 2009, Mr. Haynes became Manager- Regulation with responsibility for cost allocation and cost of service studies, and on January 1, 2013, he assumed his current position as Director Regulation with responsibility for Cost of Service and Rate Design. Mr. Haynes has previously provided testimony before the Virginia State Corporation Commission and the North Carolina Utilities Commission.

150 VIRGINIA ELECTRIC AND POWER C0~1PANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS FORECAST KWH SALES AND CUSTOMERS BY REVENUE CLASS 12 MONTHS ENDED AUGUST 31, 2015 Company Exhibit No._ Witness: PBH Schedule 1 Page 1 of REVENUE CLASS=A. RESIDENTIAL YR MONTH FORECAST GUST FORECAST KWH ' 129' 390 2,152,662, ' 131 '630 1,760,201, ,135,072 1,965,381, ,138,712 3,122,343, ' 142' 067 3' 446' 111 ' ' 144' 870 2,817,591, ' 146' 679 2,512,877' ,147,519 1,865,024, ' 149' 397 2,012,541, ' 152,163 2,611,231, ,155,418 3, 123,397, ,159,762 3,022,233,077 -~ TOTAL 30,411,596, REVENUE CLASS=B. COMMERCIAL YR MONTH FORECAST GUST FORECAST KWH ,406 2,503,943, ,645 2,426,861, ,824 2,342,915, ,063 2,499,772, ,046 2,630,713, ,253 2,395,648, ,569 2,291,922, ,752 2,3,918, ,095 2,487,813, ,420 2,841,243, ,722 2,960,244, ,041 2,907,680, TOTAL 30,599,676, REVENUE CLASS=C. INDUSTRIAL YR MONTH FORECAST CUST FORECAST KWH ,146, ,609, ,432, ,745, ,338, ,600, ,549, ,0, ,176, ,265, ,033, ,777, TOTAL 6,523,776,315 ============== 67,535,049,344

151 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS FORECAST KWH SALES BY REVENUE CLASS AND RATE SCHEDULE 12 MONTHS ENDED AUGUST 31, 2015 SCH SEQ NO.=A. RESIDENTIAL RATE SCHEDULE 1 1P 1S 1T 1W TOTAL 12 MOS ENDED 08/31/2015 FORECAST KWH 30,129,218,816 31,621,650 2,0,355 13' 165' 193 3,264 20,716,779 6,476,807 76,371 30,411,596,236 Company Exhibit No._ Witness: PBH Schedule 1 Page 2 of 9 SCH SEQ NO.=B. COMMERCIAL RATE SCHEDULE GS1 GS2 GS2T GS3 GS4 5 5C 5P 6 6TS TOTAL 12 MOS ENDED 08/31/2015 FORECAST KWH 3' 801 '838' 133 9,219,883,692 3,034,657,904 8,931,681,253 2,626,605,798 37,313, ,974,723 81,074,079 13,685, ,819,039 9 '687,763 2,360,995, ,584 41,486,663 24,718,466 5,776,576 30,599,676,793 SCH SEQ NO.=C. INDUSTRIAL RATE SCHEDULE GS1 GS2 GS2T GS3 GS TS TOTAL 12 fs ENDED 08/31/2015 FORECAST KWH 848,922 97,445,337 20,469, '400' 331 4,041,090, ,211, ,034 56,477,821 6,1, ' 167' , ' 251 6,523,776,315 67,535,049,344

152 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS SUMMARY OF FORECAST KWH SALES BY RATE SCHEDULE 12 MONTHS ENDED AUGUST 31, 2015 RATE SCHEDULE 1 1P 1S 1T 1W GS1 GS2 GS2T GS3 GS C 5P 6 6TS MOS ENDED 08/31/2015 FORECAST KWH 30,129,218,816 31,621,650 2,0,355 13' 165' 193 3,264 3,802,687,055 9,317,329,029 3' 055' 127' 501 9,911,081,584 6 '667 '696' 2 418,211,424 37,516, ,974,723 81,074,079 70,162, ,929,497 9,687,763 3' 263' 162' ,584 62,951,015 31,799,524 5,852,947 67,535,049,344 Company Exhibit No._ Witness: PBH Schedule 1 Page 3 of 9

153 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS SUMMARY OF FORECAST ~-H SALES RATE SCHEDULES CATEGORIZED INTO CUSTOMER CLASSES 12 MONTHS ENDED AUGUST 31, 2015 Company Exhibit No._ Witness: PBH Schedule 1 Page 4 of CUSTOMER CLASS=A. RES RATE SCHEDULE 1 1P 1S 1T 1W CLASS 12 MOS ENDED 08/31/2015 FORECAST KWH 30,129,218,816 31,621,650 2,0,355 13' 165' 193 3,264 30,384,326,278 CUSTOMER CLASS=B. GS RATE SCHEDULE GS1 7 CLASS 12 MOS ENDED 08/31/2015 FORECAST KWH 3,802,687,055 9,687,763 3,812,374,818 CUSTOMER CLASS=C. GS RATE SCHEDULE GS2 GS2T 5 CLASS 12 MOS ENDED 08/31/2015 FORECAST KWH 9,317,329,029 3' 055' 127' ,516,975 12,409,973,505 CUSTOMER CLASS=D. GS RATE SCHEDULE GS3 6 6TS CLASS 12 MOS ENDED 08/31/2015 FORECAST ~H 9,911,081,584 2,280,636,094 70' 162' ,929,497 12,492,8,091 CUSTOMER CLASS=E. GS RATE SCHEDULE GS4 CLASS 12 MOS ENDED 08/31/2015 FORECAST KWH 6' 667' 696' 2 982,526,254 7,650,222,356 CUSTOMER CLASS=F RATE SCHEDULE MOS ENDED 08/31/2015 FORECAST KWH 418,211,424 CUSTOMER CLASS=G. CHURCH RATE SCHEDULE 5C 5P 12 t S ENDED 08/31/2015 FORECAST ~H 184,974,723 81,074,079

154 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS SUMMARY OF FORECAST KWH SALES RATE SCHEDULES CATEGORIZED INTO CUSTOMER CLASSES 12 MONTHS ENDED AUGUST 31, 2015 Company Exhibit No._ Witness: PBH Schedule 1 Page 5 of 9 CUSTOMER CLASS=G. CHURCH (continued) RATE SCHEDULE CLASS 12 ~S ENDED 08/31/2015 FORECAST KWH 266,048,802 CUSTOMER CLASS=H. OD LIGHT RATE SCHEDULE CLASS 12 MOS ENDED 08/31/2015 FORECAST KWH 478,584 62,951,015 31,799,524 5,852,947 1,082,069 67,535,049,344

155 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS ALLOCATION OF TRANSMISSION REVENUE REQUIREMENT TO CUSTOMER CLASSES Line No. A. Transmission Revenue Requirement Virginia Witness: DMW Allocation Jurisdiction Fonnula Schedule 1 Basis 1 Network Integrated _Transmission Service 2 Transmission Enhancement Charges/Credits PJM Admin'1strative Charges- Current Economic/Emergency Load Response Programs 5 Interruptible Load for Reliability Program 6 Deferred Cost Adjustment 7 Update- January August 2014 NITS 8 Update- January August 2014 Transmission Enhancements Update- January August 2014 ILR S478,939,484 1, Page CP ($45, 145,973) 1, Page CP $14,359,943 1, Page kwh $95,026 1, Page kwh so 1, Page PJM 5CP $39,742,348 1, Page 1 Composite $66,624,157 1,Page CP (S16,595,730) 1, Page CP $0 1. Page PJM 5CP Total $538,019, Revenue Requirement allocated on 1 CP 12 Revenue Requirement allocated on energy 13 Revenue Requirement allocated on PJM 5CP 14 Revenue Requirement allocated on composite S483,821,938 $14,454,969 so S39,742,348 B. REVENUE REQUIREMENT BY CUSTOMER CLASS 1CP ALLOCATION 15 Class Demand at time of2013 System Peak 16 Class Allocation Factors 17 Revenue Requirement allocated to Classes VA JURIS RESIDENTIAL GS-1 GS 2 GS-3 13,526,691 7,237, ,061 2,255,979 2,155, % % % % % $483,821,938 S258,878,116 $28,437,698 S80,691,731 S77,096,230 GS-4 993, % S35,550,404 ENERGY ALLOCATION MWH 19 Factor 3 - Energy 20 Revenue Requirement allocated to Classes 67,274,4 30,393,191 3,726,308 12,175,286 12,647, % % % % % S14,454,969 S6,530,487 $800,660 $2,616,064 $2,717,519 7,561, % $1,624,654 PJM 5CP ALLOCATION 21 Class Demand dunng 2013 PJM 5CP 22 Class Allocation Factors 23 Revenue Requirement allocated to Classes 13,262,034 7,060, ,058 2,236,815 2,127, % % % % % $0 so so $0 $0 983, % so 24 Subtotal 25 Composite allocation factor $498,276,907 S265,408,602 $29,238,357 $83,307,796 $79,813, % % % % % $37,175, % 26 COMPOSITE ALLOCATION S39,742,348 $21,168,874 S2,332,039 $6,644,593 $6,365,9 $2,965, Total Revenue Requirement to Customer Classes {Line 26 +Line 28) 28 Weighted a,rerage allocation $538,019,256 $286,577,477 $31,570,396 $89,952,389 $86,179, % % % % % $40,140, % months ending August 2016 sales 67,535,049,344 30,384,326,278 3,8,612,866 12,404,477,069 12,503,545,071 7,646,915, Class revenue requirement per kwh $ $ $ $ $ II Reflects the Special Contracts class total Contract Firm Demand of 21,888 kw adjusted to Transmission level using the 2013 transmission expansion factor of CHURCH 22,222 # 66, % % $794,843 S2,372, , , % % $90,913 $52,875 22,222 # 65, % % $0 $0 $885,756 $2,425, % % S70,847 $193,480 $956,403 $2,619, % % 418,211, ,914,167 $ $ OD LIGHTS % so 1, % $21, % so S21, % $1,739 $23, % 1,046,798 $ lj(/):2:0 OlC'>;:::;.:O (Q ::T :::> 3 CDCDCD""Q O.cnru O'>c::cn::J O(i) '< ~-~.~m I~ g z ('

156 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS CALCULATION OF REVENUE REQUIREMENT BY RATE SCHEDULE Company Exhibit No._ Witness: PBH Schedule 1 Page 7 of 9 RATE SCHEDULE 12 ~los ENDED CUSTOMER REVENUE REQ CUSTOMER 08/31/2015 CLASS BY SCHEDULE CLASS FORECAST KWH NOTE RATE AND CLASS RES 30,129,218,816 $ $284' 171 '366 1P 1S 1T 1W GS1 GS2 GS2T GS3 GS C 5P 6 6TS 7 (SEC) (PRI) RES 31 '621 '650 $ $298,248 RES 2,0,355 $ $1,980,766 RES 13' 165' 193 $ $124' 171 RES 3,264 $ $2,926 GS-1 3,802,687,055 $ $31 '490' 171 GS-2 9' 317' 329' 029 $ $67,535,680 GS-2 3' 055' 127' 501 $ $22' 144 '771 GS-3 9,911,081,584 $ $68,370,017 GS-4 6' 667' 696' 2 $ $34,984, ,211,424 $ $956,403 GS-2 37,516,975 $ $271,938 CHURCH 184,974,723 $ $1,821,091 CHURCH 81,074,079 $ $798,181 GS-3 70,162,915 $ $484,008 GS-3 230,929,497 $ $1,593,030 GS-1 9,687,763 $ $80,225 GS-3 2,280,636,094 $ $15,732' 605 GS-4 982,526,254 $ $5,155,239 OD LIGHT 478,584 $ $111 OD LIGHT 62,951,015 $ $14,657 OD LIGHT 31,799,524 $ $7,404 OD LIGHT 5,852,947 $ $1,363 ============== ============== 67,535,049,344 $538,019,256

157 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS REVENUE REQUIREMENT BY RATE SCHEDULE AND CALCULATION OF RATE PER ~~H BY RATE SCHEDULE REVENUE REQ 12 MOS ENDED RATE BY RATE BY REVENUE 88/31/2815 SCHEDULE SEE SCHEDULE CLASS FORECAST KWH (ROUNDED) NOTES 1 $284,171,366 38,129,218, P $298,248 31,621, S $1,988,766 2,8, T $124,171 13,165, W $2, , GS1 $31,490,171 3,802,687, GS2 $67,535,680 9,317,329, GS2T $22,144,771 3,055,127, GS3 $68,370,017 9,911,081, GS4 $34,984,886 6,667,696, $956, ,211, C $271,938 $1,821,091 37,516, ,974, P 6 $798,181 $484,008 81,074,079 70,162, TS $1,593, ,929, (SEC) $80,225 $15,732, ,763 2,288,636, (PRI) $5, ,526, $ , $14,657 62,951, $7,404 31,799, $1,363 5,852, ============== ============== $538,019,256 67,535,049,344 Company Exhibit No._ Witness: PBH Schedule 1 Page 8 of 9 * THE RATE DESIGN FOR THESE SCHEDULES IS SHOWN ON THE NEXT PAGE OF THIS EXHIBIT AND REFLECTS DEMAND BILLING.

158 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A 4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS RATE DESIGN FOR RATE SCHEDULES GS-2, GS-2T, GS-3, GS-4, 8, & WITH DEMAND BILLING A. DESIGN FOR GS-2 A 4 RATE ADJUSTMENT CLAUSE Company Exhibit No._ Witness: PBH Schedule 1 Page 9 of9 DEMAND BILLING TOTAL GS-2 REVENUE REQUIREMENT DIVIDED BY TOTAL GS-2 KW DEMANDS = GS-2 KW RATE - DEMAND BILLING NON-DEMAND BILLING GS-2 KW RATE - DEMAND BILLING X GS-2 NON-DEMAND KW UNITS = GS-2 NON-DEMAND REVENUE REO. DIVIDED BY GS-2 NON DEMAND KWH = GS-2 KWH RATE - NON-DEM BILLING $67,535,680 27,070,484 $2.495 PER KW $2.495/KW 4,491,015 $11,205, ,512,082 $ PER KWH B. DESIGN FOR GS-2T A 4 RATE ADJUSTMENT CLAUSE TOTAL GS-2T REVENUE REQUIREMENT DIVIDED BY TOTAL GS-2T KW DEMANDS = GS-2T KW RATE $ ,247,763 $3.055 PER ON-PEAK KW C. DESIGN FOR GS-3 A 4 RATE ADJUSTMENT CLAUSE TOTAL GS-3 REVENUE REQUIREMENT DIVIDED BY TOTAL GS-3 KW DEMANDS = GS-3 KW RATE $68,370,017 20,448,1 $3.344 PER ON-PEAK KW D. DESIGN FOR GS-4 & SCH 8 A 4 RATE ADJUSTMENT CLAUSE CALCULATION TO ADJUST KW UNITS FOR RATE DESIGN PRESENT GS-4 ESS KW CHG - PRIMARY PRESENT GS-4 ESS KW CHG - TRANS. RATIO OF TRANS CHG TO PRIMARY CHG PRIMARY KW DEMAND UNITS TRANSMISSION KW DEMAND UNITS ADJ TO TRANSMISSION KW TO REFLECT TRANSMISSION DISCOUNT (X RATIO) TOTAL GS-4 KW DEMANDS (ADJUSTED) CALCULATION FOR GS-4 & SCH 8 KW PRICING TOTAL GS-4 REVENUE REQUIREMENT DIVIDED BY ADJUSTED GS-4 KW = GS-4 & SCH 8 ~~ PRICE (PRIMARY) X TRANSMISSION TO PRIMARY RATIO = GS-4 & SCH 8 KW RATE (TRANSMISSION) E. DESIGN FOR A 4 RATE ADJUSnlENT CLAUSE $ PER ON-PEAK KW $.873 PER ON-PEAK KW ,545, , ,413 11,247,401 $34,984,886 11,247,401 $3. 1 PER ON- PEAK K\~ $3.030 PER ON-PEAK KW DEMAND RELATED REVENUE REO. DIVIDED BY FIRM CONTRACT KW = FIRM CONTRACT KW PRICE ENERGY RELATED REVENUE REO. DIVIDED BY BOOKED KWH = ENERGY RELATED KWH PRICE $865, ,304 $3.250 PER FIRM CONTRACT DEMAND KW $90, ,211,424 $ PER KWH F. DESIGN FOR SCH A 4 RATE ADJUSTMENT CLAUSE CALCULATION OF SCH (SEC VOLT) RATE DESIGN TOTAL (SEC) REVENUE REQUIREMENT DIVIDED BY (SEC) CONTRACT KW = SCH (SEC) CONTRACT KW RATE CALCULATION OF SCH (PRI VOLT) RATE DESIGN TOTAL (PRI) REVENUE REQUIREMENT DIVIDED BY (PRI) CONTRACT KW = SCH (PRI) CONTRACT KW PRICE $15,732,605,073,036 $1.562 PER CONTRACT DEMAND KW $ ,740.7 $0.898 PER CONTRACT DEMAND KW

159 VIRGINIA ELECTRIC AND POWER COMPANY DETERMINATION OF A4 RATE ADJUSTMENT CLAUSE RECOVERY FACTORS CALCULATION OF WEIGHTED REVENUE REQUIREMENT BY RATE SCHEDULE WITH CUSTOMERS IN TWO OR MORE CUSTOMER CLASSES CUSTOMER RATE SCHEDULE CLASS s GS-1 5 GS-2 s GS-3 12 MOS ENDED PERCENT OF CUSTOMER REVENUE REQ 8/31/201S TOTAL KWH CLASS BY SCHEDULE CURRENT FORECAST KWH BY SCHEDULE RATE# AND CLASS RATE 2,894,S % $ $23,963 32,731, % $ $237,008 1,891, % $ $13,061 37,516, % $274,032 $ PROPOSED RATE Schedule 1 Page 8 $ CUSTOMER RATE SCHEDULE CLASS 12 MOS ENDED PERCENT OF CUSTOMER REVENUE REQ 8/31/2015 TOTAL KWH CLASS BY SCHEDULE CURRENT FORECAST KWH BY SCHEDULE RATE AND CLASS RATE PROPOSED RATE 6 GS-2 6 GS-3 5,821, % $ $42,153 64,341, % $ $444,381 70,162, % $486,535 $ $ CUSTOMER RATE SCHEDULE CLASS 12 MOS ENDED PERCENT OF CUSTOMER REVENUE REQ 8/31/2015 TOTAL KWH CLASS BY SCHEDULE CURRENT FORECAST KWH BY SCHEDULE RATE AND CLASS RATE PROPOSED RATE 6TS GS-2 6TS GS-3 11,025, % $ $79, ,904, % $ ~1,518, ,929, % $1,598,627 $ $ CUSTOMER RATE SCHEDULE CLASS 12 MOS ENDED PERCENT OF CUSTOMER REVENUE REQ 8/31/2015 TOTAL KWH CLASS BY SCHEDULE CURRENT FORECAST KWH BY SCHEDULE RATE AND CLASS RATE PROPOSED RATE 7 GS-1 7 GS-2 7 CHURCH 7,923, % $ $65, , % $ $4,227 1,180, % $ $11,570 9,687, % $81,393 $ $ #SLIGHT DIFFERENCE IN CUSTOMER CLASS RATE COMPARED TO THE RATES SHOWN ON SCHEDULE 1 PAGE 5 DUE TO THE RECLASSIFICATION OF THESE RATE SCHEDULES. DIFFERENCE $ ( ) DIFFERENCE $ ( ) DIFFERENCE $ ( ) DIFFERENCE $ ( ) ;.?W~~ co ::r S" 3 ~~m-g a~~~ ~NlJm OJx I::r g z r

160 Company Exhibit No._ Witness: PBH Schedule 3 Page 1 of 1 VIRGINIA ELECTRIC AND POWER COMPANY CALCULATION OF RIDER T1 RATES FOR THE RATE YEAR BEGINNING SEPTEMBER 1, 2014 (1) (2) (3) (4) (5) (6) (7) A4 Cost of Service Included in Base Rates RiderT1 kwh kw kwh kw kwh kw Schedule 1 $ $ ($ ) Schedule 1, Standby $1.361 $1.400 ($0.039) Schedule 1P $ $ ($ ) Schedule 1S $ $ ($ ) Schedule 1T $ $ ($ ) Schedule 1W $ $ ($ ) Schedule DP-R $ $ ($ ) Schedule 1 EV $ $ ($ ) Schedule EV $ $ ($ ) Schedule GS-1 $ $ $ Schedule DP-1 $ $ $ Schedule GS-2 (Non-Demand Billing) $ $ $ Schedule GS-2 (Demand Billing) $2.495 $1.971 $0.524 Schedule GS-2T $3.055 $2.313 $0.742 Schedule DP-2 $ $ $ Schedule GS-3 $3.344 $2.277 $1.067 Schedule GS-4 (Primary) $3.1 $2.371 $0.739 Schedule GS-4 (Transmission) $3.030 $2.3 $0.720 Schedule 8 (Primary) $3.1 $2.371 $0.739 Schedule 8 (Transmission) $3.030 $2.3 $ Contract-Demand $3.250 $2.701 $ Contract-Energy $ $ $ Schedule (Secondary) $1.562 $1.094 $0.468 Schedule (Primary) $0.898 $0.646 $0.252 Schedule 5 $ $ $ Schedule 5C $ $ $ Schedule 5P $ $ $ Schedule 6 $ $ $ Schedule 6TS $ $ $ Schedule 7 $ $ $ Schedule 25 $ $ $ Schedule 27 $ $ $ Schedule 28 $ $ $ Schedule 29 $ $ $

161 (1) (2) (3) Rate Schedule Forecast kwh Forecast kw All Residential 30,384,326,278 GS-1 3,802,687,055 GS-2, Non-Demand 575,512,082 GS-2 27,070,484 GS2T 7,247,763 GS3 20,448,1 GS-4 (PRIM),545,988 GS-4 (TRA) 701, ,211, , ,516,975 5C 184,974,723 5P 81,074, ,162,915 6TS 230,929, ,687,763 (SEC),073,036 (PRI) 5,740, , ,951, ,799, ,852,947 VIRGINIA ELECTRIC AND POWER COMPANY A 4 REVENUE BREAKDOWN, BASE RATES & RIDER T1 FOR THE RATE YEAR BEGINNING SEPTEMBER 1, 2014 (4) (5) (6) (7) Proposed Gross A Revenue Recovery 4 Revenue through Base Requirement Base kwh Rate Base kw Rate Rates (2)*(5) or (3)*(6) $286,577,477 $ $294,727,965 $31,490,171 $ $22,131,639 $11,205,082 $ $8,494,558 $56,330,598 $1.971 $53,355,924 $22,144,771 $2.313 $16,764,076 $68,370,017 $2.277 $46,560,326 $32,859,605 $2.371 $25,004,538 $2,125,281 $2.3 $1,620,264 $90,913 $ $79,460 $865,490 $2.701 $719,287 $271,938 $ $203,342 $1,821,091 $ $1,640,726 $798,181 $ $719,127 $484,008 $ $338,185 $1,593,030 $ $1,1,534 $80,225 $ $58,417 $15,732,605 $1.094 $11,019,901 $5,155,239 $0.646 $3,708,499 $111 $ $91 $14,657 $ $11,961 $7,404 $ $6,042 $1,363 $ $1,112 $538,019,256 $488,266,973 (8) Projected Revenue Recovery through NewRiderT1 (4)-(7) ($8, 150,488) $9,358,532 $2,7,524 $2,974,674 $5,380,695 $21,809,691 $7,855,067 $505,017 $11,453 $146,203 $68,596 $180,365 $79,054 $145,823 $491,496 $21,808 $4,712,704 $1,446,740 $20 $2,696 $1,362 $251 $49,752,283 (9) () (11) NOT USED FOR RATE DESIGN INFORMATIONAL ONLY Projected Revenue Present T1 kwh Present T1 kw Recovery through Rate Rate Present Rider T1 (2)*(9) or (3)*() ($ ) ($66,237,831) ($ ) ($266,188) ($ ) ($673,349) ($0.193) ($5,224,603) ($0.142) ($1,029, 182) ($0.4) ($2, 126,603) ($0.404) ($4,260,579) ($0.394) ($276,357) $ $16,728 ($0.406) ($8,119) ($ ) ($,880) ($ ) ($307,058) ($ ) ($134,583) ($ ) ($16,137) ($ ) ($53,114) ($ ) ($1,841) ($0.071) ($715,186) ($0.091) ($522,405) $ $19 $ $2,518 $ $1,272 $ $ ($81,943,243) JlW~b' ca::rs-3 <D<Dro-o ;~~~ - -'-~>-rom "U :r:~ I' [ z 0

162 Virginia Electric and Power Company RIDER T1 TRANSMISSION Company Exhibit No._ Witness: PBH Schedule 5 Page 1 of 1 The following Virginia Electric and Power Company filed Bundled Rate Schedules and special contracts approved by the State Corporation Commission pusuant to Virginia Code shall be increased by the applicable cents per kilowatt-hour and/or dollars per kilowatt charge. 1 Applied to kw of Demand only for net metering applications where generation is sized above kw. Such installations will pay the Rider T1 energy charge or the Rider T1 demand charge, whichever is less. 2 Applied to kw of Demand 3 Applied to kw of On-peak Electricity Supply Demand 4 Applied to kw of Contract Supplementary - Standby Demand 5 Applied to kw of firm Demand 6 Applied to kw of Electricity Supply Contract Demand Filed Electric- Virginia Superseding Filing Effective for Usage On and After This Filing Effective for Usage On and After

163 Company Exhibit No._ Witness: PBH Schedule 6 Page 1 of 6 DOMINION VIRGINIA POWER TYPICAL BILL CHANGE RESIDENTIAL -SCHEDULE 1 TOTAL A 4 SUMMER AND BASE MONTHS BILLED KWH PRESENT PROPOSED A4 A4 EFFECTIVE EFFECTIVE 09/01/ /01/2014 MONTHLY DIFFERENCE 500 $3.76 $4.72 $ ,000 1,500 $5.64 $7.07 $7.52 $9.43 $11.28 $14.15 $1.43 $1.91 I $2.87 2,000 $15.04 $18.86 $3.82 2,500 $18.80 $23.58 $4.78 3,000 $22.56 $28.29 $5.73 5,000 $37.60 $47.15 $9.55

164 Company Exhibit No._ Witness: PBH Schedule 6 Page 2 of6 DOMINION VIRGINIA POWER TYPICAL BILL CHANGE SMALL GENERAL SERVICE -SCHEDULE GS-1 TOTAL A 4 SUMMER AND BASE MONTHS PRESENT PROPOSED A4 A4 EFFECTIVE EFFECTIVE MONTHLY BILLED KWH 09/01/ /01/2014 DIFFERENCE 500 $2.88 $4.14 $ $5.75 $8.28 $2.53 1,500 $8.63 $12.42 $3.79 2,000 $11.50 $16.56 $5.06 2,500 $14.38 $20.70 $6.32 3,000 $17.25 $24.84 $7.59 5,000 $28.75 $41.40 $12.65,000 $57.50 $82.80 $25.30

165 Company Exhibit No._ Witness: PBH Schedule 6 Page 3 of 6 DOMINION VIRGINIA POWER TYPICAL BILL CHANGE MEDIUM GENERAL SERVICE -SCHEDULE GS-2 TOTAL A 4 SUMMER AND BASE MONTHS PRESENT A4 PROPOSED POWER SUPPLY EFFECTIVE EFFECTIVE MONTHLY KW DEMAND 09/01/ /01/2014 DIFFERENCE A4 50 $88.90 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $1, $ $ $1, $358.50

166 Company Exhibit No._ Witness: PBH Schedule 6 Page 4 of 6 DOMINION VIRGINIA POWER TYPICAL BILL CHANGE LARGE GENERAL SERVICE -SECONDARY- SCHEDULE GS-3 TOTAL A 4 ALL MONTHS PRESENT PROPOSED ON-PEAK A4 A4 POWER SUPPLY EFFECTIVE EFFECTIVE MONTHLY KW DEMAND 09/01/ /01/2014 DIFFERENCE 500 $1, $1, $ $1, $2, $ ,000 $2, $3, $1, ,500 $3, $5, $1, ,500 $5, $8, $2, ,000 $, $16, $5,855.00,000 $21, $33, $11,7.00

167 Company Exhibit No._ Witness: PBH Schedule 6 Page 5 of6 DOMINION VIRGINIA POWER TYPICAL BILL CHANGE LARGE GENERAL SERVICE - PRIMARY- SCHEDULE GS-4 TOTAL A 4 ALL MONTHS PRESENT PROPOSED ON-PEAK A4 A4 POWER SUPPLY EFFECTIVE EFFECTIVE MONTHLY KWDEMAND 09/01/ /01/2014 DIFFERENCE 500 $ $1, $ $4, $7, $2, ,000 $9, $15, $5,715.00,000 $19, $31,0.00 $11, ,000 $49, $77, $28, ,000 $98, $155, $57, ,000 $147, $233, $85,725.00

168 Company Exhibit No._ Witness: PBH Schedule 6 Page 6 of 6 DOMINION VIRGINIA POWER TYPICAL BILL CHANGE CHURCH SERVICE -SCHEDULE 5C TOTAL A 4 SUMMER AND BASE MONTHS BILLED KWH PRESENT PROPOSED A4 A4 EFFECTIVE EFFECTIVE 09/01/ /01/2014 MONTHLY DIFFERENCE 00 $7.21 $9.85 $ $.82 $14.78 $3.96 3,000 $21.63 $29.55 $7.92 5,000 7,500,000 15,000 $36.05 $49.25 $54.08 $73.88 $72. $98.50 $8.15 $ $13.20 $19.80 $26.40 $ ,000 $ $ $66.00