troutman sanders llp 401 9th street, n.w., suite 1000 ... · (“cogentrix nautilus”), which is...

Troutman Sanders LLP 401 9th Street, N.W., Suite 1000 Washington, DC 20004-2134

troutman.com

Christopher R. Jones

[email protected]

December 10, 2018

Hon. Kimberly D. Bose, Secretary

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

Re: EP Rock Springs, LLC

Docket No. ER19-523-000

Transmission Rate Update

Dear Ms. Bose:

Pursuant to Section 205 of the Federal Power Act (“FPA”),1 and Part 35 of the

Commission’s regulations,2 EP Rock Springs, LLC (“EPRS”) hereby submits a revision to its

limited-scope transmission revenue requirement found in Attachment H-23 to the PJM

Interconnection, L.L.C. (“PJM”) Open Access Transmission Tariff (“OATT” or “Tariff”).3

EPRS is a transmission owning member of PJM and EPRS is filing to update its transmission

revenue requirement, which contains only certain limited operation and maintenance (“O&M”)

costs associated with transmission facilities EPRS owns in the PJM region. The EPRS revenue

requirement in Attachment H-23 to the PJM Tariff is a “stated,” or fixed, transmission rate that

was the result of a black box settlement.4 EPRS respectfully requests that the Commission

accept the enclosed revised stated transmission rate for filing without hearing or suspension,

effective February 8, 2019.

116 U.S.C. § 824d (2012).

218 C.F.R. Part 35 (2018).

3The PJM OATT may be found under PJM’s “Intra-PJM Tariffs” eTariff title, available here:

https://etariff.ferc.gov/TariffBrowser.aspx?tid=1731. Pursuant to Order No. 714, this filing is submitted by PJM on

behalf of EPRS as part of an XML filing package that conforms to the Commission’s regulations. PJM has agreed

to make all filings on behalf of the PJM Transmission Owners in order to retain administrative control over the PJM

Tariff. Thus, EPRS has requested PJM to submit this Attachment H-23 in the eTariff system as part of PJM’s

electronic Intra PJM Tariff.

4See PJM Interconnection, L.L.C. and Essential Power Rock Springs, LLC, 146 FERC ¶ 61,037 (2014)

(letter order accepting uncontested offer of settlement); see also PJM Interconnection, L.L.C. and Essential Power

Rock Springs, LLC, Docket No. ER13-488-002 (Mar. 27, 2014) (delegated letter order accepting compliance tariff

filing).

https://etariff.ferc.gov/TariffBrowser.aspx?tid=1731


I. COMMUNICATIONS

All communications and service related to this filing should be directed to the following

persons:


Miles H. Kiger

TROUTMAN SANDERS LLP

401 9th Street, N.W.

Suite 1000


(202) 662-2181

[email protected]

[email protected]

Christopher P. Sherman

Vice President, Regulatory Affairs

Cogentrix Energy Power Management, LLC

3 Mill Street

Arlington, MA

(781) 643-0607

[email protected]

II. BACKGROUND

A. About EPRS

EPRS is a wholly owned indirect subsidiary of Cogentrix Nautilus Holdings, LLC

(“Cogentrix Nautilus”), which is indirectly owned and controlled by fund vehicles managed or

advised by The Carlyle Group L.P. (“Carlyle Group”). The Carlyle Group is a publicly traded

investment management firm. On June 8, 2016, the Commission authorized the acquisition and

disposition of EPRS from Essential Power, LLC to Cogentrix Nautilus.5 Prior to that, Essential

Power, LLC purchased EPRS, as part of a portfolio of generating assets, from Consolidated

Edison Development Company (“ConEd Development”) in 2008.

EPRS wholly owns and operates four gas-fired combustion units and related facilities

totaling approximately 653.5 MW (summer rating) at a generating station (the “EPRS

Generating Station”) located in Rising Sun, Maryland. EPRS also wholly owns two parallel 500

kV lines and a substation (“EPRS Transmission Facilities”) that interconnect the EPRS

Generating Station to the transmission system owned by PECO Energy Company (“PECO”) and

operated by PJM.

EPRS formerly owned only a 50 percent interest in the EPRS Transmission Facilities and

owned two of the four generating units and a 50 percent interest in related facilities at the EPRS

Generating Station. On August 28, 2018, the Commission authorized a transaction under FPA

Section 203 where EPRS acquired the remaining 50 percent ownership interest in the EPRS

5 Essential Power, LLC, 155 FERC ¶ 62,191 (2016) (delegated letter order authorizing acquisition and

disposition of jurisdictional assets).


Transmission Facilities and the remaining two units and 50 percent interest in related facilities at

the EPRS Generating Station from Old Dominion Electric Cooperative (“ODEC”).6

B. The EPRS Transmission Facilities

The EPRS Transmission Facilities now wholly owned by EPRS include a 500 kV

substation, configured as a five circuit breaker ring bus (the “EPRS Substation” or

“Switchyard”), and two 900-foot, 500 kV transmission lines, configured as double circuits on a

single tower line. These facilities were interconnected to PECO’s transmission system by

looping the two 900-foot transmission lines from the EPRS Substation to PECO’s 500 kV Peach

Bottom-to-Keeney transmission line. Radial lines connect the EPRS Transmission Facilities to

the four EPRS Generating Station units, as well as to the three generating units of the newly-

constructed Wildcat Point generating facility owned by ODEC.7 As a result of this

configuration, the EPRS Transmission Facilities operate as an electrically integrated part of

PJM’s transmission system; all electricity flowing on PJM’s transmission system, regardless of

the source, potentially flows through the EPRS Transmission Facilities. Because of its

ownership of the EPRS Transmission Facilities, EPRS is a party to the PJM Transmission

Owners Agreement. It is also registered as a Transmission Owner for NERC compliance

matters.

C. EPRS’s Transmission Revenue Requirement

EPRS’s currently effective transmission revenue requirement is found in Attachment H-

23 to the PJM Tariff, which was the result of a rate filing made in 2012 in Docket No. ER13-

488.8 Per Attachment H-23, EPRS’s stated rate is “invoiced by PJM on a monthly basis to

customers taking Network Integration Transmission Service in the PECO zone on the basis of

each customer’s respective monthly Network Service Peak Load ratio share.” However, some

further background on the unique history of how the EPRS Transmission Facilities came to be

6 Essential Power Rock Springs, LLC, 164 FERC ¶ 62,110 (2018) (delegated letter order authorizing

acquisition and disposition of jurisdictional assets); see also Notice of Consummation of Essential Power Rock

Springs, LLC, Docket No. EC18-118-000 (Sept. 17, 2018) (letter advising the Commission that the transaction

closed on Sept. 14, 2018).

7 Wildcat Point began commercial operation in April of 2018. Wildcat Point is a combined cycle generation

facility consisting of three generating units interconnected to the EPRS Substation. Wildcat Point is currently rated

at 940 MWs under its current Interconnection Agreement with PJM. That initial interconnection required System

Feasibility, System Impact, and Facilities Studies prior to interconnection. Additionally, ODEC has filed to increase

the claimed capacity of Wildcat Point to 1,090 MWs, which, like the initial interconnection, required System

Feasibility and System Impact Studies.

8 Attachment H-23 was recently amended consistent with the Commission’s action pursuant to the Tax Cuts

and Jobs Act, as discussed below.


will help to underscore the uniqueness of EPRS’s transmission revenue requirement and EPRS’s

instant rate change proposal.9

The EPRS Transmission Facilities were developed in order to interconnect the EPRS

Generating Station to the PECO transmission system. Consistent with reliability parameters and

the results of PJM’s System Feasibility, System Impact, and Facilities Studies, to interconnect

the EPRS Generating Station, PECO’s then-existing Peach Bottom-to-Keeney 500 kV line was

severed and each of the two line segments that resulted were connected to a circuit on each of the

two, then-newly constructed 900-foot 500 kV lines.10

Thus, where formerly there was one 500

kV network line from Peach Bottom to Keeney, after the EPRS Transmission Facilities were

completed and interconnected, there was now a looped line from Peach Bottom to the EPRS

Substation and a second line from the EPRS Substation to Keeney.11

This accounts for why the

EPRS Transmission Facilities are an electrically integrated part of PECO’s transmission system

and why EPRS is a PJM Transmission Owner.

The EPRS Generating Station used to be owned by an affiliate of ConEd Development.

When ConEd Development owned the EPRS Generating Station (which was then held by an

entity called CED Rock Springs, LLC), it filed an application with the Commission in Docket

No. ER06-491-000 seeking to implement a tariff under which it would recover its share of the

construction costs associated with the EPRS Transmission Facilities.12

The Commission denied

CED Rock Springs’ pursuit of rate recovery, finding that CED Rock Springs, although a PJM

transmission owner, was responsible for the transmission system upgrades pursuant to PJM’s

generator interconnection policies, which dictate that the interconnecting generator is responsible

for upgrades that would not have been necessary “but for” the generation project and that do not

provide benefits to the transmission grid.13

EPRS is not seeking to re-litigate that case. Rather, EPRS is merely updating the rate

already on file. The generating facilities at the EPRS Generating Station are now connected to

the grid and no additional costs will be incurred to establish that interconnection. Further, on

November 30, 2012 in Docket No. ER13-488-000, as amended on December 7, 2012, PJM filed

on behalf of EPRS a proposed formula transmission rate for inclusion in the PJM OATT as

Attachment H-23.14

The purpose of that filing was to permit EPRS to recover certain limited

9 See Transmittal Letter of PECO Energy Co., Docket No. ER02-1779-000 (May 9, 2002) (stating that “the

Rock Springs Interconnection Agreement being filed herein is different from most interconnection agreements filed

with the Commission in that it does not concern the typical ‘generation interconnection’ facilities. Rather, [it’s] an

agreement between two separate transmission owners for the interconnection of their transmission facilities.”).

10 See id.

11 See id.

12 Application of CED Rock Springs, LLC, Docket No. ER06-491-000 (filed Jan. 17, 2006).

13 CED Rock Springs, LLC, 114 FERC ¶ 61,285 (2006) (citing section 37 of the PJM OATT).

14 Formula Transmission Rate Filing of EP Rock Springs, LLC, Docket No. ER13-488-000 (filed Nov. 30,

2012).


costs applicable to its then-50 percent ownership share in the EPRS Transmission Facilities

associated with compliance with transmission-related mandatory NERC CIP and TO/TOP

Reliability Standards, as well as to put in place a formula rate for any future transmission

enhancements that EPRS could be required to build by virtue of the PJM Regional Transmission

Expansion Process (an “RTEP Project”).

The Commission accepted that proposed formula rate filing and set it for hearing and

settlement procedures.15

Unlike the construction costs at issue in the CED Rock Springs filing

made in Docket No. ER06-491-000 (discussed above), the Commission stated that the costs

associated with compliance with transmission-related NERC CIP and TO/TOP Reliability

Standards were “different.”16

The Commission further stated that “Rock Springs could

potentially recover the CIP and TO/TOP costs under section 35.35(f) of the Commission’s

regulations, which allows transmission owners to recover expenses necessary to comply with

mandatory reliability standards.”17

As a result of settlement negotiations, on July 18, 2013, EPRS filed an Offer of

Settlement with the Commission.18

The Settlement provided, in relevant part, that EPRS’s

proposed formula rate would be replaced by a fixed, i.e., “stated,” annual transmission revenue

requirement of $225,000 recovered through Attachment H-23 of the PJM Tariff and would not

contain a placeholder for RTEP Projects.19

The majority of the $225,000 Settlement figure

represented NERC CIP compliance-related O&M costs.20

The Settlement was certified by the

Settlement Judge to the Commission as uncontested and the Commission approved the

Settlement by delegated letter order on January 23, 2014.21

The settlement version of

Attachment H-23 was effective as of July 1, 2013.

The only modification made to Attachment H-23 since then was a result of the

Commission’s action pursuant to the Tax Cuts and Jobs Act.22

Consistent with the

Commission’s Show Cause Order, EPRS filed a revised Attachment H-23 on May 10, 2018, in

15

PJM Interconnection, L.L.C. and EP Rock Springs, LLC, 142 FERC ¶ 61,073 (2013).

16 Id. at P 23.

17 Id.

18 Offer of Settlement of Essential Power Rock Springs, LLC, Docket No. ER13-488-000 (Jul. 17, 2013).

19 Id. at 4.

20 See Formula Transmission Rate Filing of EP Rock Springs, LLC, Attachment 2 to Exhibit EPR-4 - the

proposed formula rate, Docket No. ER13-488-000.

21 See PJM Interconnection, L.L.C. and Essential Power Rock Springs, LLC, 146 FERC ¶ 61,037 (2014)

(letter order accepting uncontested offer of settlement)

22 Alcoa Power Generating Inc.—Long Sault Division et al., 162 FERC ¶ 61,224 (2018) (the “Show Cause

Order”).


Docket No. ER18-1566-000, to reduce its stated transmission rate from $225,000 to $224,031.23

On November 15, 2018, the Commission accepted EPRS’s proposed revision to Attachment H-

23, effective June 1, 2018.24

III. DESCRIPTION OF THE RATE UPDATE

EPRS tenders here a revision to its revenue requirement found in Attachment H-23 to the

PJM tariff. Consistent with EPRS’s filing in Docket No. ER13-488, EPRS’s instant proposed

stated rate revision reflects only the costs associated with operating and maintaining the EPRS

Transmission Facilities. These costs include EPRS’s ongoing NERC CIP and TO/TOP

compliance costs, as well as limited O&M costs associated with the operation of the EPRS

Transmission Facilities. As in the Docket No. ER13-488 filing, EPRS is not requesting a return

on or of any capital-related costs associated with the construction of the EPRS Transmission

Facilities, nor requesting recovery of any other typical cost-of-service categories (e.g.,

depreciation & amortization, taxes, etc.). EPRS’s revised stated transmission rate remains of a

very limited scope and reflects only certain labor and non-labor costs related to operating and

maintaining the EPRS Transmission Facilities. The proposed transmission revenue requirement

included herein is $1,089,401 (“Proposed Revenue Requirement”).

As more fully described in the sponsoring testimonies of Mr. Ralph Jones and Mr. Steven

Garwood, the costs of operating and maintaining the EPRS Transmission Facilities are broadly

categorized as labor and non-labor costs. The labor costs consist of the labor time company staff

dedicate to EPRS Transmission Facilities duties. These duties include mandatory CIP and

TO/TOP compliance efforts, monitoring Switchyard operations and conducting regular

inspections, executing switching orders, and performing maintenance of the switchyard

facilities.25

The non-labor costs consist of out-of-pocket expenses associated with compliance,

operations and maintenance of the EPRS Transmission Facilities. These largely include

contractor services, such as for SCADA system support, cybersecurity and physical security of

the substation, maintenance work on the substation, and other information technology services.

Nearly all of these labor and non-labor costs can be tied to activities related to ensuring

compliance with mandatory NERC Reliability Standards, which EPRS is subject to as a NERC

registered Transmission Owner.26

The updated rate utilizes Period I cost data based on 12-months ending October 31,

2018.27

Because EPRS is filing for a rate increase for Period I that is less than $1,000,000, EPRS

23

See Essential Power Rock Springs, LLC, Transmission Rate Compliance Filing to Implement Corporate

Tax Rate Change, Docket No. ER18-1566-000 (May 10, 2018).

24 See Alcoa Power Generating Inc.―Long Sault Division et al., 165 FERC ¶ 61,094 (2018).

25 See Exhibit EPRS-2, Testimony of Mr. Ralph Jones.

26 See id.

27 18 C.F.R. § 35.13(d)(1).


is not required to file Period II data.28

Thus, the Test Period for this rate filing is Period 1, i.e.,

12-months ending October 31, 2018,29

adjusted for one known and measurable change during the

Test Period.30

The Company’s Cost of Service (“COS”) Statements being submitted with

application reflect both Period I – Unadjusted, and Period I – Adjusted, O&M cost amounts.31

The Period I data is adjusted for a single known and measurable change. This known and

measurable change is the fact that EPRS now bears 100 percent of the expenses of the EPRS

Transmission Facilities as a result of EPRS’s recent acquisition of ODEC’s former 50 percent

ownership share of the facilities.32

The O&M costs at issue have also increased overtime since

the current rate was established, as discussed more fully in the testimony of Mr. Ralph Jones, as

compliance requirements expanded and the obligations thereunder became fully understood and

implemented by EPRS.

The proposed rate is supported by the testimony of Mr. Ralph Jones (Rock Springs

General Manager/Senior Manager CIP Compliance), Ms. Linda Okowita (Cogentrix’s Senior

Vice President for Human Resources), and Mr. Steven Garwood (rate consultant). In addition,

EPRS engaged the services of Mr. Bryan Craig, former FERC Chief Accountant, to review

EPRS’s costs and their assignment to the respective FERC O&M accounts.

IV. THE UPDATED RATE IS JUST AND REASONABLE

The Proposed Revenue Requirement is just and reasonable for several reasons.

First, EPRS has developed a conservative, narrow revenue requirement containing only

those costs clearly and directly attributable to compliance and other O&M related to the EPRS

Transmission Facilities. These costs are supported by testimony from two EPRS employees with

direct knowledge of the costs, and the supporting workpapers contain detail down to the vendor

on non-labor costs and down to the specific employee on labor costs.33

Other cost items

28

Id. § 35.13(d)(2)(ii)(A) (“A utility may elect not to file Period II data if: (A) The utility files a rate increase

that is less than one million dollars for Period I”).

29 Id. § 35.13(d)(4) (“Test period. If Period II data are not submitted . . . Period I shall be the test period.”)

30 Id. § 35.13(d)(1) (“Any utility that is required . . . to submit cost of service information . . . shall submit . . .

: (i) Unadjusted Period I data; or (ii) Period I data adjusted to reflect changes that affect revenues and costs prior to

the proposed effective date of the rate change and that are known and measurable with reasonable accuracy at the

time the rate schedule change is filed, if such utility: (A) Is not required to and does not file Period II data; (B)

Adjusts all Period I data to reflect such changes; and (C) Fully supports the adjustments in the appropriate cost of

service statements.”).

31 Id. § 35.13(h).

32 See Exhibit EPRS-2, Testimony of Mr. Ralph Jones.

33 As explained by company witness Linda Okowita, the only labor costs included here are the direct

compensation paid to the employee (annual base pay and accrued annual discretionary target bonus). The

Commission has routinely found bonuses to be recoverable in rates. See NRG Energy, Inc. v Entergy Services, Inc.,

126 FERC ¶ 61,053, at P 32 (2009); see also Williams Natural Gas. Co., 77 FERC ¶ 61,277, at 62,179 (1996).


generally recoverable in transmission rates have been excluded from this filing, including, e.g.,

labor-related overhead, corporate overhead and other administrative and general costs.

Second, the Commission has confirmed and codified in its regulations that public utilities

may recover prudently incurred costs necessary to comply with mandatory reliability standards

under section 215 of the FPA.34

The labor and non-labor costs that make up this limited scope,

O&M-only stated rate filing mostly consist of compliance activities on the EPRS Transmission

Facilities related to mandatory NERC Reliability Standards. To the extent of any O&M costs not

directly related to reliability compliance, their inclusion in the rate is consistent with the

Commission’s precedent in PJM that the ongoing O&M costs associated with “but for” network

upgrades are recoverable by the interconnected Transmission Owner through that Transmission

Owner’s transmission rates.35

As discussed above, the EPRS Transmission Facilities have a

unique history. Merchant generators are not typically also Transmission Owners, and

interconnection facilities usually are not transformed into networked facilities that are fully

integrated components of the PJM transmission system. If, for example, the EPRS

Transmission Facilities has been constructed by PECO, the initial capital costs would still have

been assigned to EPRS as “but for” facilities, but PECO would roll the ongoing O&M costs into

its transmission rates. The enclosed rate results in that same basic rate treatment.

Moreover, to the extent there was any historical doubt about the function of the EPRS

Transmission Facilities and the role they play in the Bulk Electric System, the 2018

interconnection of the ~1000 MW Wildcat Point plant to the EPRS Switchyard should resolve

any such doubt.36

As described in the testimony of Mr. Ralph Jones, the EPRS Transmission

Facilities are now responsible for the delivery of an additional 1000 MW of non-affiliated,

baseload generation owned by ODEC, making the compliance and reliability of the EPRS

Transmission Facilities all the more important.

For these reasons, the Commission should the accept for filing the Proposed Revenue

Requirement and revised stated transmission rate contained in Attachment H-23 to the PJM

Tariff.

34

See 18 C.F.R. § 35.35(f) (2018); Promoting Transmission Investment Through Pricing Reform, Order No.

679, 116 FERC ¶ 61,057 at P 343 (2006) (“Order No. 679”); on reh’g, Promoting Transmission Investment through

Pricing Reform, Order No. 679-A, 117 FERC ¶ 61,345 at P 14 (2006) (“Order No. 679-A”).

35 See Ontelaunee Power Op. Co., LLC v. Met. Ed. Co., 119 FERC ¶ 61,181, at P 47 (2007) (“The

Commission previously has determined that under the PJM tariff, O&M costs for network upgrades (as that term is

defined in the PJM tariff) are the responsibility of the transmission owner, and O&M costs for Attachment Facilities

are the responsibility of the interconnecting generator.”) (citing PJM Interconnection, L.L.C., 104 FERC ¶ 61,154, at

P 19-21 (2003), reh’g denied, 109 FERC ¶ 61,236, at P 18 (2004)).

36 https://www.odec.com/news/dedication-ceremony-marks-completion-of-odecs-wildcat-point-generation-

facility/.

https://www.odec.com/news/dedication-ceremony-marks-completion-of-odecs-wildcat-point-generation-facility/

https://www.odec.com/news/dedication-ceremony-marks-completion-of-odecs-wildcat-point-generation-facility/


V. PART 35 FILING REQUIREMENTS AND WAIVER REQUEST

To the extent this filing may require waivers of Part 35 of the Commission’s regulations,

EPRS respectfully requests all such waivers, including waiver of the full Period I-Period II data

requirements37

and associated cost statements.38

The detailed cost support and supporting

workpapers with testimony accompanying this filing provide ample support for the

reasonableness of the proposed transmission rate. Moreover, insofar as only the above-described

mandatory CIP and TO/TOP costs and limited O&M costs associated with the operation and

maintenance of the EPRS Transmission Facilities are included in the stated rate, such cost of

service information beyond that provided would not be relevant to the filing.

In addition to the cost of service statements, the following information is required for

filings of changes in rate schedules or tariffs, pursuant to Section 35.13 of the Commission’s

regulations:

18 C.F.R. § 35.13(b)(1): See Section VIII for a list of documents included with this filing.

18 C.F.R. § 35.13(b)(2): See Section VII for the proposed effective date for the rate

changes proposed herein.

18 C.F.R. § 35.13(b)(3): See Section VI for the process used to serve this filing on

customers.

18 C.F.R. § 35.13(b)(4): See Section III and the testimony of Mr. Steven Garwood for a

description of the rate changes proposed herein.

18 C.F.R. § 35.13(b)(5): See Section III, the testimony of Mr. Steven Garwood, and the

testimony of Mr. Ralph Jones for a statement of the reasons for the rate changes proposed

herein.

18 C.F.R. § 35.13(b)(6): No agreement from any other entities, including any agreement

required by contract, must be obtained in order for EPRS to file or implement the rate

changes proposed herein.

18 C.F.R. § 35.13(b)(7): No costs or expenses included herein have been alleged or

judged in any administrative or judicial proceeding to be illegal, duplicative, or

unnecessary costs that are demonstrably the product of discriminatory employment

practices.

18 C.F.R. § 35.13(c): The testimony of Mr. Steven Garwood describes EPRS’s existing

transmission rate and how the associated revenues are recovered, as well as a comparison

with EPRS’s proposed rate.

37

18 C.F.R. § 35.13(d).

38 Id. § 35.13(h).


18 C.F.R. § 35.13(e): See Section VIII for a list of testimony and exhibits included with

this filing.

VI. SERVICE

PJM has served a copy of this filing on all PJM Members and on all state utility

regulatory commissions in the PJM Region by posting this filing electronically. In accordance

with the Commission’s regulations,39

PJM will post a copy of this filing to the FERC filings

section of its internet site, located at the following link: http://www.pjm.com/documents/ferc-

manuals/ferc-filings.aspx with a specific link to the newly-filed document, and will send an

email on the same date as this filing to all PJM Members and all state utility regulatory

commissions in the PJM Region40

alerting them that this filing has been made by PJM and is

available by following such link. If the document is not immediately available by using the

referenced link, the document will be available through the referenced link within 24 hours of the

filing. Also, a copy of this filing will be available on the Commission’s eLibrary website located

at the following link: http://www.ferc.gov/docs-filing/elibrary.asp in accordance with the

Commission’s regulations and Order No. 714.

VII. EFFECTIVE DATE

EPRS respectfully requests that the Commission accept the enclosed rate for filing

without hearing or suspension, effective February 8, 2019, sixty days after filing.

VIII. FILING COMPONENTS

Exhibit EPRS-1: Direct Testimony and Exhibits of Mr. Steven Garwood

Exhibit EPRS-2: Direct Testimony and Exhibits of Mr. Ralph Jones

Exhibit EPRS-3: Direct Testimony and Exhibits of Ms. Linda Okowita

Exhibit EPRS-4: Direct Testimony and Exhibits of Mr. Bryan Craig

Exhibit EPRS-5: Clean Tariff Sheet for Attachment H-23

Exhibit EPRS-6: Marked Tariff Sheet for Attachment H-23

39

See 18 C.F.R §§ 35.2(e) and 385.2010(f)(3).

40 PJM already maintains, updates and regularly uses e-mail lists for all PJM members and affected state

commissions.

http://www.pjm.com/documents/ferc-manuals/ferc-filings.aspx

http://www.pjm.com/documents/ferc-manuals/ferc-filings.aspx

http://www.ferc.gov/docs-filing/elibrary.asp


IX. CONCLUSION

For the reasons discussed herein, EPRS respectfully requests that the Commission accept

this revised stated rate for filing effective February 8, 2019 without hearing or suspension.

Respectfully submitted,

/s/ Christopher R. Jones


TROUTMAN SANDERS LLP

401 9th Street, N.W.

Suite 1000


(202) 662-2181

[email protected]

Exhibit No. EPRS-1 Prepared Direct Testimony of Mr. Steven S. Garwood

Exhibit No. EPRS-1 Page 1 of 14

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

EP Rock Springs, LLC ) Docket No. ER19-___-000

PREPARED DIRECT TESTIMONY AND EXHIBITS OF

STEVEN S. GARWOOD

I. INTRODUCTION

Q. Please state your name and business address.

A. My name is Steven S. Garwood. My business address is 8 York Lane, Winthrop,

ME 04364.

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

A. I am the owner of PowerGrid Strategies, LLC, an energy and transmission

consulting firm, which I founded in January 2004. I provide business consulting

services to clients principally engaged in the electric energy and transmission

industry, including strategic management consulting, economic and financial

analysis, analysis of issues pertaining to the development and interconnection of

generation and transmission projects, and cost of service and rate design analysis.

Q. Please outline your formal education.

A. I have a Bachelor of Science degree in Professional Studies majoring in Marketing

Management from Thomas College and an Associate Degree in Applied Science


majoring in Electric Power Technology received from Eastern Maine Technical

College.

Q. Please briefly describe your professional experience.

A. I have worked in the electric utility industry in excess of 33 years having worked

as an employee of multiple electric utilities for approximately 16-years from 1985

– 2001 including Central Maine Power Company (“CMP”), Maine Electric Power

Company (“MEPCO”) and Energy East, and as a consultant to the electric utility

industry for approximately 17 years from 2001 to the present. During my career as

a utility employee, I held positions in a variety of capacities including staff

positions, mid-management positions and executive management positions.

During my career with these utilities, I worked in the areas of engineering, rates

and cost of service, transmission operations and divestiture, merger and acquisition

support. The management positions I held included Manager, Pricing Operations,

Manager, Transmission Services, Manager System Operations and Transmission

Services, Managing Director, Transmission Operations and I served as Vice

President and Board Director for MEPCO. I later held the position of Managing

Director, Transmission for Energy East after it acquired both CMP and MEPCO. I

began my consulting career in 2001 first working as Vice President for R. J. Rudden

Associates, and later founding my own consulting practice, PowerGrid Strategies,

LLC. As a consultant, I have assisted and advised numerous clients, including

electric utilities, independent generation and transmission developers, energy

marketing firms, regulatory agencies and others on a variety of matters including

energy policy, regulatory issues, financial and economic analyses, transmission


tariff development, cost of service and stated and formula transmission rates. For

further information regarding my relevant work and educational experience and

background, please refer to my curriculum vitae provided as Exhibit No. EPRS-

SSG-1.

Q. Have you testified before this Commission before?

A. Yes. In addition to this proceeding I have testified, or otherwise participated in a

number of proceedings before this Commission and certain state proceedings on a

variety of FERC and state jurisdictional matters. A summary of my regulatory

work is provided as an attachment to my curriculum vitae indicating those

proceedings in which I provided testimony or an affidavit.

Q. What is the purpose of your testimony?

A. The purpose of my testimony is to support the development of Essential Power

Rock Springs, LLC’s (“EPRS” or the “Company”) transmission revenue

requirement associated with its ownership, operations and maintenance activities

of certain transmission facilities, including a 500 kV substation referred to in my

testimony as the EPRS Substation and two 900-foot, 500 kV transmission lines

referred to, collectively, as the EPRS Transmission Facilities. For a more detailed

description of the EPRS Transmission Facilities, please refer to the testimony of

EPRS witness Mr. Ralph Jones.

Q. Are you sponsoring any Exhibits?

A. Yes. In support of EPRS’s rate filing, I have prepared and I am sponsoring certain

Cost of Service (“COS”) Statements, as defined in Section 35.13 of the


Commission’s regulations. Specifically, the COS Statements I have prepared and

am sponsoring are listed in Table 1 below.

Table 1 Cost of Service Statements

Submitted in Support of EPRS’s Proposed Revenue Requirement

These COS Statements are included as Exhibit No. EPRS-SSG-2, Pages 1-8, to my

testimony.

Q. Why have you limited the preparation and submission of COS Statements to

those listed in Table 1?

A. Because EPRS is seeking only to recover limited O&M costs associated with

operation and maintenance of the EPRS Transmission Facilities, only those COS

Statements needed to support the requested revenue requirement have been

prepared and submitted. In addition, for those COS Statements which are being

submitted, much of the data typically included in those COS Statements is not

applicable and, thus, that data has been labeled as “NA.”

Q. What costs form the basis for the Proposed Revenue Requirement?

Cost of Service

Statement Description

AH Operations and Maintenance Expenses

AI Wages and Salaries

BA Wholesale Customer Rate Groups

BG Revenue Data to reflect Changed Rates

BH Revenue Data to reflect Present Rates

BJ Summary Data Tables

BK Electric Utility Cost of Service


A. The Proposed Revenue Requirement is based on EPRS’s estimated labor costs and

actual non-labor costs incurred during the Test Period, i.e., 12-months ending

October 31, 2018, related solely and specifically in support of the EPRS

Transmission Facilities, adjusted for a significant known and measurable change.

Q. You indicate that the labor costs used in the development of the Proposed

Revenue Requirement are estimated. Please explain.

A. As discussed more fully in the testimonies of EPRS witnesses Mr. Ralph Jones and

Ms. Linda Okowita, EPRS performed a detailed labor analysis of the specific

Company personnel that worked in support of the EPRS Transmission Facilities

and their related labor time and costs during the Test Period. There were two

primary components to the labor analysis. First, the company conducted a survey

of employees with some level of operations and maintenance responsibility for the

EPRS Transmission Facilities in order to determine how much time each employee

spent on that function. See the testimony of Company witness Mr. Ralph Jones for

a discussion of the labor time estimation survey. The second step was to determine

an annual labor cost for the Test Period by applying the wage and salary data of

individual employees to their labor hours spent on the EPRS Transmission

Facilities. Please see the testimony of Company witness Ms. Linda Okowita for a

discussion of the annual labor cost estimation. I used the results of this granular

labor analysis to develop a workpaper showing the labor costs (as well as non-labor

and total costs) provided as Exhibit No. EPRS-SSG-4 and to populate COS

Statements AI, BJ, and BK with the annual labor portion of the O&M costs of

operating the EPRS Transmission Facilities.


Q. Can you describe the non-labor O&M costs?

A. The Company bears non-labor O&M costs associated with its mandatory reliability

obligations and other general operations and maintenance of the EPRS

Transmission Facilities. These non-labor costs include out-of-pocket expenses and

mostly consist of payments to third party contractors who render reliability

compliance and other services to the EPRS Transmission Facilities.

Q. And how were these non-labor O&M costs ascertained to form part of the

Proposed Revenue Requirement?

A. As discussed more fully in the testimony of Mr. Ralph Jones, Mr. Jones assembled

the non-labor cost information for the Test Period by combining a financial

accounting report from the Company’s general ledger with an operations report

from the Company’s maintenance management system. Mr. Jones then categorized

each transaction-level non-labor cost consistent with his understanding of the

definitions of the FERC Uniform System of Accounts as set forth in Part 101 of the

Commission’s regulations, which I supplied to him.

Q. Did you and Mr. Jones discuss how to interpret the account descriptions and

apply them?

A. Yes, we did.

Q. Did you review Mr. Jones’s application of the FERC accounts to the labor and

non-labor cost data and develop a workpaper for inclusion as an exhibit to

your testimony?

A. Yes. I reviewed Mr. Jones’s application of the FERC accounts. I also developed a

workpaper Exhibit No. EPRS-SSG-3 that summarizes the non-labor cost


information. Exhibit No. EPRS-SSG-3 provides a monthly breakdown by contract

service provider and FERC account, detailing the amount of non-labor cost that

includes a description of the type of function or service the contractor performs for

EPRS in the notes section.

Q. Please explain the “known and measurable change” to the Test Period you

referred to and which supports the Proposed Revenue Requirement.

A. Until as recently as late September 2018, the EPRS Transmission Facilities were

jointly owned by EP Rock Springs and Old Dominion Electric Cooperative

(“ODEC”), each owning a 50 percent share of the EPRS Transmission Facilities.

As such, they jointly shared in the cost of operating and maintaining the EPRS

Transmission Facilities, each bearing a cost responsibility for the EPRS

Transmission Facilities in proportion to their 50 percent ownership share. In late

September 2018, EPRS acquired all of ODEC’s 50 percent share in the EPRS

Transmission Facilities, thus causing EPRS to be solely responsible for 100 percent

of the cost of owning, operating and maintaining the EPRS Transmission Facilities

going forward. As such, the actual non-labor costs incurred during the Test Period

prior to the acquisition of ODEC’s share by EP Rock Springs had to be adjusted to

account for this known and measurable change.

Q. Please describe the adjustment you made.

A. Because EPRS became the sole owner of the EPRS Transmission Facilities in late

September 2018, i.e., one month before the end of the Test Period, I had to

annualize the Test Period for this known and measurable change. Because EPRS

paid 50 percent of the non-labor cost of operating the EPRS Transmission Facilities


during 11 months of the Test Period (ODEC paid the other 50 percent), I doubled

EPRS’s actual non-labor costs for those 11 months of the Test Period (i.e.,

November 2017 – September 2018) and added EPRS’s October 2018 actual non-

labor cost to derive an annual amount of non-labor O&M cost for the Test Period.

Q. Where is this adjustment represented in the Company’s COS Statements and

workpapers?

A. This adjustment is titled Company Adjustment 1 ADJ-SGG-1 and is shown in the

non-labor workpaper Exhibit No. EPRS-SSG-3 referenced above, as an increase to

Test Period non-labor costs. As can be seen Exhibit EPRS-SSG-3, the unadjusted

Test Period non-labor costs totaled $237,601. After making the adjustment

described, the total non-labor costs are $379,983.

Q. Why was it not necessary to make a similar adjustment to the labor costs used

in the derivation of the proposed Revenue Requirement?

A. The labor portion of the Test Period O&M costs did not require a similar adjustment

as the non-labor portion of O&M costs because EPRS has exclusively performed

the operations and maintenance activities on the EPRS Transmission Facilities.

During the time that ODEC was 50 percent owner of the EPRS Transmission

Facilities, ODEC was responsible for its 50 percent share of all O&M costs

associated with the operation of the EPRS Transmission Facilities, including both

the labor and non-labor O&M for which EPRS seeks recovery of in this filing.

Thus, on a going forward basis, EPRS will continue to exclusively perform all of

the labor-related O&M on the EPRS Transmission Facilities but ODEC will not be

responsible for any portion of these costs. In other words, the labor-related cost of


service of the EPRS Transmission Facilities is not changing as a result of the

transfer of ODEC’s 50 percent ownership share of the EPRS Transmission

Facilities to EPRS and, therefore, no adjustment to the labor portion of the Test

Period O&M costs was needed.

Q. Do the labor costs contain any associated labor-related adders such as benefit

costs or other overheads, like payroll taxes?

A. No. My understanding is that the labor rates used by Company witness Ms. Linda

Okowita excluded all such labor-related adders.

Q. Please summarize the proposed Revenue Requirement.

A. The proposed Revenue Requirement is computed to be $1,089,401. This represents

an increase of $865,370 from EPRS’s current stated annual transmission revenue

requirement set forth in Attachment H-23 of the PJM Tariff.

Q. Regarding the COS Statements you have prepared and are sponsoring, as

listed in Table 1 of your testimony, please explain the information presented

in each COS Statement beginning with COS Statement AH?

A. Certainly. But first I will reiterate that, consistent with the Company’s request of

waiver from the requirement to provide all of the COS Statements and related

information set forth in Section 35.13 of the Commission’s regulations, the COS

Statements I have prepared and I am sponsoring, and the data contained therein,

relate solely to the specific costs at issue; that is to say, labor and non-labor cost

information directly relevant to supporting EPRS’s total O&M costs associated

with operating and maintaining the EPRS Transmission Facilities. Where the COS

Statements I have provided would typically present cost information pertaining to


a utility’s non-Transmission functions such as Production, Distribution, Customer

Service, Customer Accounts and Information, etc., these data fields have been

labeled “NA” for “Not Applicable.”

Q. Please proceed with describing the information contained in COS Statement

AH.

A. Exhibit No. EPRS-SSG-2 at pages 1 and 2 contains COS Statement AH. COS

Statement AH presents the Company’s Operations and Maintenance Expenses.

Page 1 of COS Statement AH summarizes the costs at issue, namely EPRS’s labor

and non-labor O&M costs related to operating and maintaining the EPRS

Transmission Facilities. These O&M costs consist of Transmission Operations and

Maintenance Expenses. The information presented shows the costs for Period I –

Unadjusted in column (a), and also Period I – Adjusted in column (b), to account

for EPRS’s acquisition of ODEC’s 50 percent ownership share in the EPRS

Transmission Facilities, as previously described in my testimony. This summary

page shows the O&M costs at issue totaling $947,019 and $1,089,401, for Period I

- Unadjusted and for Period I – Adjusted, respectively. Page 2, of COS Statement

AH presents EPRS’s Transmission-related Operations and Maintenance Expense

broken down by FERC Account. Total Transmission-related Operations Expense

for Period I - Unadjusted is shown totaling $706,186 and for Period I - Adjusted is

shown totaling $844,194. Likewise, Transmission-related Maintenance Expenses

are presented by FERC Account and total $240,833 for Period I – Unadjusted and

$245,207 for Period I – Adjusted.

Q. Please describe COS Statement AI.


A. COS Statement AI is provided at page 3 of Exhibit No. EPRS SSG-2 and shows

direct Transmission Wages & Salaries for the Test Year totaling $709,418. As

discussed previously in my testimony, these Transmission-related Wages &

Salaries stem from the labor study sponsored by Company witnesses Mr. Ralph

Jones and Ms. Linda Okowita.

Q. Please describe COS Statement BA.

A. COS Statement BA is provided in Exhibit No. EPRS-SSG-2 at page 4 and describes

the Wholesale Customer Groups that are intended to be subject to the proposed rate

or charge. In the case of EPRS, the Wholesale Customer Group that is subject to

paying the charges designed to recover EPRS’s Proposed Revenue Requirement is

the group comprised of those Network Integration Transmission Service (“NITS”)

customers within the PECO Zone taking NITS from PJM. EP Rock Springs does

not have the names of the individual NITS customers comprising this Wholesale

Customer Group.

Q. You appear to have combined COS Statements BG and BH. What

information is presented in COS Statements BG and BH?

A. COS Statements BG and BH are contained on page 5 of Exhibit No. EPRS-SSG-2.

These have been combined for ease of reference. COS Statement BG shows the

current revenues collected from the affected Wholesale Customer Group. The first

row of revenues contained on page 5 of Exhibit No. EPRS-SSG-2 contains this

information by month for Period I based on EPRS’s existing authorized revenue

requirement of $224,031 set forth in Attachment H-23 of the PJM Tariff. A review

of PJM Settlement Statements issued to EPRS shows that PJM distributes EPRS’s


annual revenue requirement in twelve equal monthly amounts of $18,750 per

month. This monthly amount correlates to EPRS Attachment H-23 revenue

requirement totaling $225,000 prior to that revenue requirement being adjusted

recently in conjunction with the Tax Cuts and Jobs Act. As noted at the bottom of

COS Statement BG and BH, effective June 1, 2018, EPRS’s authorized revenue

requirement was recently reduced as a result of the Commission’s action pursuant

to the Tax Cuts and Jobs Act. As such, the monthly revenue from current rates has

been adjusted accordingly to $18,669 for the months of June through October 2018.

COS Statement BH requires a showing of the monthly revenues to be collected

from the affected Wholesale Customer Group under the proposed rates/revenue

requirement. This information is contained in the second row of data in this same

Exhibit. The proposed revenues to be collected from the affected Wholesale

Customer Group totals $1,089,401 (the total Proposed Revenue Requirement based

on the Test Period) in equal monthly amounts of $90,783. Finally, the last row of

data contained in this Exhibit shows the change in revenues to be paid by the

affected Wholesale Customer Group per month and for the 12-month Test Period

in total. This shows the annual increase in Test Period total revenues to be collected

by EPRS based on the Proposed Revenue Requirement of $864,806.

Q. Please describe what information is presented in COS Statement BJ.

A. COS Statement BJ is provided at page 6 of Exhibit No. EPRS-SSG-2. COS

Statement BJ requires the presentation of summary data tables summarizing the

detailed information contained in various other COS Statements. For efficiency, I

will only discuss the information pertinent to the costs at issue in this proceeding


and will not describe the other information deemed not relevant, all of which has

been labeled “NA” for the reasons discussed previously in my testimony.

Q. Please continue.

A. The only summary data information relevant to the cost at issue is that contained in

COS Statements AH and COS Statement AI. Statement BJ shows summary

information of the costs shown on COS Statement AH, which is EPRS’

Transmission Operations and Maintenance Expenses for both Period I –

Unadjusted, and for Period I – Adjusted. Transmission Operations and

Maintenance Expenses are shown totaling $947,019 and $1,089,401 for Period I –

Unadjusted and for Period I – Adjusted, respectively. Additionally, COS Statement

BJ provides summary data for COS Statement AI, showing direct Transmission-

related Wages & Salaries total $709,418.

Q. Table 1 in your testimony shows COS Statement BK as your final COS

Statement. Please describe the information contained in COS Statement BK.

A. COS Statement BK is contained at pages 7 and 8 of Exhibit EPRS – SSG-2 to my

testimony. COS Statement BK sets forth the cost of service study used to derive

the proposed revenue requirement. COS Statement BK would typically present a

comprehensive cost of service model setting forth the derivation of a company’s

total revenue requirement and how that total revenue requirement has been

allocated among the various functions performed by the company, e.g. Production,

Transmission, Distribution and Other. However, in the case of EPRS, whose

Proposed Revenue Requirement is limited solely to certain labor and non-labor


O&M pertinent to operating the EPRS Transmission Facilities, an abbreviated COS

Statement BK has been prepared.

Q. Please continue.

A. Schedule 1, page 1 of COS Statement BK summarizes the results of the

transmission O&M cost of service. As shown, the cost of service includes only

Transmission-related Operations and Maintenance Expense and totals $1,089,401

based on the Test Period. This information is pulled from Schedule 2, page 1 of

COS Statement BK. Schedule 2, page 1 of COS Statement BK provides the

relevant O&M costs included in the cost of service, pulling from total costs shown

in COS Statement AH. As shown, the cost of service includes only Transmission-

related Operations and Maintenance Expense totaling $1,089,401 based on the Test

Period, all of which are directly related to EPRS’s cost of operating and maintaining

the EPRS Transmission Facilities.

Q. Does this conclude your testimony at this time?

A. Yes, it does.

[Next page is signature page.]

Exhibit No. EPRS-SSG-1

POWERGRID STRATEGIES, LLC PO Box 37 Phone / Fax : (207) 377-2781 (207) 377-2783 8 York Lane Cell (207) 446-3057 Winthrop, ME 04364 Email: [email protected]

CURRICULUM VITAE OF STEVEN S. GARWOOD

SUMMARY Mr. Garwood has extensive experience working in the electric utility industry spanning a period in excess of 33 years. Over a period of approximately 16-years he worked for multiple electric utilities in a variety of capacities including staff and executive management positions in various disciplines including engineering, rates and transmission operations, as well as divestiture and merger / acquisition support.

He has worked as an energy consultant for 17-years assisting numerous clients including electric utilities, independent generation and transmission developers, energy marketing firms, regulatory agencies and others engaged in the energy industry, advising them on a variety of matters including energy policy and regulatory issues, financial and economic analyses, project development, transmission tariff and market design matters, and development and implementation of successful business strategies tailored for the complex and ever-changing business and regulatory climate affecting the energy industry.

He has extensive experience in cost of service, stated and formula transmission rates, as well as pricing for Reliability-Must-Run contracts for merchant generation; experience with the interconnection of merchant generation projects including wind generation projects, having managed the interconnection process for both transmission utilities and merchant wind developers; experience in transmission development including terrestrial AC and submarine HVDC transmission projects; experience with NERC Reliability Standards Compliance; experience in FERC’s regulatory policies for restructuring the electric utility industry, including its policies on open access transmission service, regional transmission organizations (RTO), standard market design (SMD), standard interconnection procedures and its recently enacted Order 1000 that opened up the regulated transmission business to competition by both incumbent and non-incumbent transmission developers.

Throughout his career he has demonstrated strong leadership, technical and effective communication skills. His wide ranging breadth of experience and knowledge of the issues and challenges facing utilities and other energy industry companies makes him uniquely qualified to helping energy and transmission companies with developing, implementing and achieving successful business strategies.

Exhibit EPRS-SSG-1Page 1 of 13

Page | 2

PROFESSIONAL EMPLOYMENT

1/ 04 – Present PowerGrid Strategies, LLC President and Founder

8/01 – 12/03 R.J. Rudden Associates, Inc. Vice President

1/01 – 8/01 Energy East Management Corporation, Portland, Maine Managing Director, Transmission

11/99– 8/01 Maine Electric Power Company, Augusta, Maine Vice President & Director

5/99 – 12/00 Central Maine Power Company, Augusta, Maine Managing Director, Transmission Operations

2/98– 4/99 Central Maine Power Company, Augusta, Maine Manager, System Operations and Transmission Services

7/96 – 1/98 Central Maine Power Company, Augusta, Maine Manager, Transmission Services

6/93- 6/96 Central Maine Power Company, Augusta, Maine Manager, Pricing Operation

8/92- 5/93 Central Maine Power Company, Augusta, Maine Supervisor, Cost Studies

3/89 – 7/92 Central Maine Power Company, Augusta, Maine Staff Engineer, Rate Department

11/87- 3/89 Central Maine Power Company, Augusta, Maine Electrical Engineering Assistant II, Licensing

6/85 – 11/87 Central Maine Power Company, Augusta, Maine Electrical Engineering Assistant I, Electrical Design

PROFESSIONAL EXPERIENCE

Assisted client with project development efforts and bid package in response to 2016 NewEngland Tri-State RFP for Clean Energy Resource Procurement

Supported development of HVDC Submarine Cable Project (SeaLink) as a reliability projectserving Boston in ISO-NE


Page | 3

Developed Order 1000 Compliance Filing for stakeholders as alternate to ISO/TO filing whichprevailed at the FERC, setting stage for competition in the regulated transmission business

Supported NERC Reliability Standards Compliance Reporting for an electric utility in NPCC

Performed Performance Audit of a FERC-approved Independent System Administrator

Participated in Northeast Energy Alliance Audit Team to perform INPO Readiness Audits

Assisted major developer of wind generation projects in the development and interconnection of aportfolio of wind generation projects including approximately 50 separate wind farms in 11different states.

Managed transmission assets at a Nuclear Power Station.

Developed and implemented strategy to allow regulated cost recovery of transmission assetsowned by merchant generator at a nuclear power station

Testified as Expert Witness on behalf of Canadian Provincial Regulatory Commission Staffregarding utility rate design proceeding.

Filed Expert Witness testimony on Cost of Service supporting Generator’s Application to FERCfor RMR Contract

Assisted client with obtaining Capacity Transfer Rights in NEPOOL LICAP Markets

Developed and implemented strategy for transfer of transmission assets between affiliatedcompanies to permit cost recovery under regional transmission tariff.

Strategic & Financial Impact Assessment of Standard Market Design for major gas & electricutility

Merger / Acquisition Due Diligence Support for acquisition of RG&E by Energy East

Federal Regulatory Approvals Team for the Energy East / CMP Group Merger

Expert on Litigation Team Regarding CMP Generation Asset Sale to FPL

Directed RTO Strategy Team for Energy East Corporation

Expert Witness Representing NEPOOL regarding first Regional OATT in FERC Hearings

Managed implementation of FERC Open Access Transmission Policy for CMP and MEPCo

Directed Cost-of-Service studies supporting transmission rates used in assessing impact of FERCOrder 888 Open Access Transmission Policy

Project Manager for development of Central Maine Power's State mandated Energy AuctionProgram

Consultancy Service, CMP International, Cost of Service/Rate Design Seminar to Bulgarianutility

COMMITTEE MEMBERSHIPS AND OTHER AFFILIATIONS

Energy Bar Association – non-attorney member – 2004-Present

NEPOOL and ISO-NE Committees – 1998 - Present on behalf of Client(s)


Page | 4

NEPOOL Executive / Participant’s Committee; 1998 to 2001

New England Regional Transmission Operations Committee; Chair, Jan. ‘98 - Jan. ‘00; Vice Chair, Mar. ‘97 - Dec. ‘97

New England Regional Transmission Group Negotiating Committee; July ‘96 - Mar. ‘97

Represented New England Transmission Providers on the How Working Group in the development of the OASIS Phase IA and Phase II Standards & Communications Protocol document

EEI Transmission Policy Task Force; 1997 to 2001

NERA Marginal Cost Work Group; 1994 to 1997

PUBLICATIONS / SPEAKING ENGAGEMENTS Gen Interconnection: Lessons from New England; Public Utilities Fortnightly, September 15, 2002

Grid Business - Mid-West Region; St. Louis, MO, Mar 2002; sponsored by Platts

Generation and Grid Business 101 - West Coast Power Conference, San Francisco, CA, Oct 2002; organized by Tradefair Group

FERC SMD - The Good, the Bad & the Ugly;

EEI Strategic Issues Conference, Chicago, IL, Oct. 2002

Grid Business 101 & SMD: Electric Power 2003 Conference, Houston, TX, Mar 2003; organized by Tradefair Group

Generator Interconnection Cost Allocation and Applicability of Transmission Service to Generators; Northeast Power Conference, Boston, MA, June 2003; organized by Tradefair Group

EDUCATION Thomas College; Waterville, Maine; Bachelor of Science Degree in Professional Studies; majoring in Marketing Management; Sept. '87 - Dec. '90

Eastern Maine Vocational Technical Institute; Bangor, Maine; Associate Degree in Applied Science, majoring in Electrical Power Technology; Aug. '83 - May '85

Florida Keys Community College; Key West, Florida; Completed 1 year of a 2 year Environmental Marine Science Program; Aug. '79 - May '80

HONORS Graduated Magna Cum Laude, G.P.A. of 3.73, Thomas College, Dean's List

Graduated with G.P.A. of 3.36, E.M.V.T.I., Dean's List, Delivered commencement address at graduation ceremony, E.M.V.T.I


Summary of Regulatory, Industry Restructuring & Strategic Management

Experience for Steven S. Garwood

Page | 5

JURISDICTION CASE OR

DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT

APPROXIMATE DATE SUBJECT MATTER

PRESENTED TESTIMONY OREXPERT REPORT

FERC EL16-19 FERC New NextEra Energy Transmission – New

Hampshire Transmission, LLC

Dec 2015 – Current/On-

Going

FERC 206 Proceeding – Justness / Reasonableness of ISO-NE Regional Transmission Rates

No – Case still pending in Settlement Phase

FERC ER09-1731 EMERA Maine – Bangor Hydro District

Penobscot Energy Recovery Company

May 2017 – Feb 2018

New Interconnection Agreement following expiration of QF Contract – Cost of InterconnectionService going forward

No

MPUC 2014-00048 2012-00589

Maine Public Utilities Commission

NextEra Energy Transmission – New


Jan 2014 – Jul 2014

Transmission Solutions in response to investigation into reliability of electric service in northern Maine; CPCN Proceeding for EMERA Maine - MPD

Yes

FERC ER13-193-000 ER13-196-000

ISO-New England NextEra Energy Transmission – New


February 2012

Implementing FERC Order 1000 in ISO-NE; drafting tariff language, negotiating with stakeholders; crafting legal strategy / assisting with drafting intervention and protest

Yes

FERC ER09-1731 Midwest ISO Edison Mission Energy July 2010 Cost Allocation of Network Upgrades

No




Page | 6





FERC NHPUC ISO-NE

EC10-58-000 NextEra Energy Resources FPL / US Transmission Holdings

2010 Support for obtaining regulatory approvals for transfer of transmission assets to a new transmission holding company structure

No

FERC ER09-1581 Community Wind North, LLC Edison Mission Energy Sept. 2009 Cost Allocation of Network Upgrades assigned to wind generating facility

Yes

FERC ER-09-1431 Midwest ISO Edison Mission Energy August 2009 Cost Allocation of Network Upgrades assigned to interconnecting generators

Yes

NERC / NPCC FPL-New England Division (FPL-NED)

FPL-NED June 2007-June 2010

Responsible for routine and on-going NERC Standards Compliance Reporting

No

NERC / NPCC FPL-New England Division (FPL-NED)

FPL-NED 1st Quarter 2007

Performed Gap Analysis to determine compliance with NERC Standards

No




Page | 7





FERC EL07-78 330 Fund, LP 330 Fund, LP Jun. 2007 Advised client with respect to developing complaint against an ISO associated with its mismanaging of a TCC Auction and processing of generator interconnection request.

Yes

Multi-State / FERC

Edison Mission Energy Wind Development Affiliates

Edison Mission Energy Oct. 2006 - Present

Managed Interconnection Process for the Interconnection of approx. 50 separate wind projects in 13 different states.

No

ME LURC ZP-702 Maine Mountain Power, LLC MMP & Edison Mission Aug. 2006 Transmission-related matters in support of obtaining State permits to construct 90MW Redington Wind Farm

Yes

FERC ER06-491 CED Rock Springs, LLC CED Rock Springs, LLC Jan. 2006 ROE – Transmission Yes

New Brunswick, CA

Board of Public Utility

Commissioners

2005-02 New Brunswick Electric Distribution Company

Public Utility Board 2005 Advised Regulatory Commission on matters pertaining to a retail rate design case filed by NB-Disco.

Yes




Page | 8





FERC TBD ISO-NE and National Grid enXco Corp. / Hoosac Wind Project

2004 - 2005 Assisted client with matters pertaining to interconnection of 20 wind turbines to NEPOOL Transmission System including negotiating interconnection agreement and cost responsibility for upgrades; Assisted client with development of Power Sales Agreement; Advised client on ISO & NEPOOL Rules & Procedures pertaining to wind generation

No

FERC ER05-611 Bridgeport Energy, LLC Bridgeport Energy, LLC Feb. 2005 Expert Witness on Cost of Service supporting RMR Contract Rates

Yes

FERC ER03-563-030 ISO-New England Duke Energy, North America, LLC

2004-2005 Assisted Client with obtaining allocation of Capacity Transfer Rights associated with Generator-funded transmission upgrades in the context of the design of the New England Locational Installed Capacity Market

Yes




Page | 9





FERC and

NHPUC

EC03-69 EG03-50 ER04-714 DE03-186

FPL and FPL Energy, LLC FPLE Seabrook and FPLE New England Transmission Company

2002-2004 Assisted with development of business strategy to transfer transmission facilities acquired as part of merchant generator acquisition to a new ITC / FPL and obtain recovery of transmission revenue requirements

Yes

NA NA NA Duke Energy North America

2002-2004 Advised DENA on a number of market, transmission & interconnection matters pertaining to its operations in the northeast

No

FERC NY Market Participants / FERC

NYISO 2004 Assisted client with development of unbundled ISO Admin. Services Charges

No

NA NA NA NYISO 2004 Provided strategic assessment and options for enhancing market settlement function

Yes

FERC ER03-601 San Diego Gas & Electric Co. San Diego Gas & Electric Company

2003 Transmission Rate Filing to implement a Formula Rate

Yes




Page | 10





IRS IRS IRS 2002-2003 Market Analysis of affiliate transactions of a company undergoing an IRS Audit

Yes

Arbitration National Gird, USA National Grid, USA 2002-2003 Served as an Expert Witness representing NGRID in a dispute over power contract

Yes

New Brunswick, CN

Board of Commissioners

New Brunswick Power Corp. New Brunswick Power Corp.

2002 NBP Restructuring; Open Access Transmission Tariff; Transmission COS & Rate Design; Standardized Generator Interconnection Agreements

Yes

FERC Order 2000

SMD FERC SEMPRA 2002 Executive Management-

level strategic analysis of impact to SEMPRA Companies from adoption of SMD

No

NA NA Energy East Corporation Energy East Corporation 2002 Executive Management-level strategic analysis and recommendations associated with transmission business segment

Yes




Page | 11





NA NA NA EMERA 2002 Provided due diligence services related to potential acquisition of a US Utility

No

NA NA NA BRASCAN 2002 Advised client on Generator Interconnection System Impact Study matters

No

FERC FERC Mid-Continent Area Power Pool

2002 Assisted client with refund obligation / compliance filing

Yes

FERC Order 2000 RTO/SMD

FERC Electricities 2002 Executive Management-level strategic analysis of the impact to the SEMPRA Companies from adoption of SMD

Yes

NA NA NA Bay Corp. Holdings 2001 Provided strategic management services designed to enhance sale price of generating asset

No

FERC FERC Central Maine Power Company

Central Maine Power Company

July 2000 Bucksport Energy, LLC Interconnection Agreement

No – Participated in Settlement Proceeding

FERC FERC Central Maine Power Company


May 2000 Casco Bay / MIS Interconnection Agreement

No - Participated in Settlement

Proceedings




Page | 12





FERC ER00-2006 Central Maine Power Company

S.D. Warren Mar. 2000 S.D. WarrenInterconnectionAgreement

No - Participated in Settlement

Proceedings



Dec. 1999 Transmission Rate Proceeding

Yes



Nov. 1999 Gorbell/Thermal Interconnection Agreement

No



Dec. 1998 Androscoggin Energy Center, LLC Interconnection Agreement

No - Participated in Settlement Proceeding

ME MPUC98-058 Central Maine Power Company


1998 Approval of Generation Asset Divestiture

Yes

FERC OA97-237 / ER97-1079

New England Power Pool New England Power Pool 1997 - 1999 NEPOOL Restructuring; Approval of Regional Open Access Tariff; Transmission Cost of Service & Rate Design

Yes

FERC OA96-43 Central Maine Power Company


1996 Order 888/889 Compliance Open Access Tariff; Transmission Cost of Service & Rate Design

No

FERC OA96-189 Maine Electric Power Company

Maine Electric Power Company

1996 Order 888/889 Compliance Open Access Tariff; Transmission Cost of Service & Rate Design

No




Page | 13





ME MPUC 92-315 Central Maine Power Company


1992-1994 Backup and Standby Service for Generators Yes

ME MPUC 92-315 Maine Public Utilities Commission


1992 -1994 Resource Planning, Rate Restructuring, Avoided Cost Investigation, Marginal Cost Study

Yes

ME MPUC 92-345 Maine Public Utilities Commission


1992-1994 Retail Rate Proceeding Yes



Page 1 of 8

Essential Power Rock Springs, LLC PERIOD I

Operation and Maintenance Expenses STATEMENT AH

Twelve Months Ended October 31, 2018 Page 1 of 2

(a) (b)

Period I Costs Period I Costs

Operation and Maintenance Expenses at Issue Unadjusted Adjusted1

Production NA NA

Transmission 947,019$ 1,089,401$

Distribution NA NA

Customer Accounts NA NA

Customer Service NA NA

Sales Expenses NA NA

General and Administrative Expenses NA NA

Total Expenses at Issue2947,019$ 1,089,401$

Note: (1)

(2) The source for these totals are from page 2 of Statement AH.

(3) The totals for each of these categories on the Statement AH go forward to the following worksheets:

Statement BJ

Statement BK

Period I Costs Adjusted in column (b) reflecting adjustment of EPRS's cost share in the EPRS Switchyard for the period Nov. 1, 2017 - Sep. 30, 2018 from 50% to 100% due

to EPRS's acquisition of ODEC's 50% ownership share in the EPRS Switchyard effective Oct. 1, 2018. See Company Adjustment 1 - ADJ-SSG-1 worksheet included as Exhibit

No. EPRS-SSG-3.


Page 2 of 8


Operation and Maintenance Expenses STATEMENT AH


Unadjusted Adjusted

Demand Energy Total Total

Transmission Expenses

Operation

560 Operation Supervision and Engineering - -

561.1 Load Dispatch- Reliability 172,763$ 172,763$

561.2 Load Dispatch - Monitor and Operate Transmission System 235,602 373,610

561.3 Load Dispatch - Transmission Service and Scheduling - -

561.4 Scheduling, System Control and Dispatch Services - -

561.5 Reliability Planning and Standards Development 269,498 269,498

561.6 Transmission Service Studies 28,322 28,322

561.7 Generation Interconnection Studies - -

561.8 Reliability Planning and Standards Development Services - -

562 Station Expenses - -

562.1 Operation of Energy Storage Equipment - -

563 Overhead Line Expenses - -

564 Underground Line Expenses - -

565 Transmission of Electricity by Others - -

566 Miscellaneous Transmission Expenses - -

567 Rents - -

Total Operation 706,186$ 844,194$

Maintenance

568 Maintenance Supervision and Engineering 77,620 77,620

569 Maintenance of Structures 1,900 1,900

569.1 Maintenance of Computer Hardware 20,323 20,323

569.2 Maintenance of Computer Software 55,840 55,840

569.3 Maintenance of Communication Equipment 13,682 13,682

569.4 Maintenance of Misc. Regional Transmission Plant 4,374 8,748

570 Maintenance of Station Equipment 55,392 55,392

570.1 Maintenance of Energy Storage Equipment -

571 Maintenance of Overhead Lines -

572 Maintenance of Underground Lines -

573 Maintenance of Miscellaneous Transmission Plant 11,701 11,701

574 Maintenance of Transmission Plant (Nonmajor only) -

Total Maintenance 240,833$ 245,207$

Total Transmission Expenses 947,019$ 1,089,401$


Page 3 of 8

Essential Power Rock Springs, LLC Period I

Wages & Salaries Statement AI


Function/

Statement Description Sub-function Amount

AI Wages & Salaries Production NA

Transmission1709,418$

Distribution NA

Customer Accounts NA

Customer Service NA

Sales Expenses NA

Admin & General NA

Total 709,418$

Note: (1) Transmission Wages and Salaries are estimated based on EPRS's Labor Study. Refer to the testimony of Company

Witnesses Mr. Ralph Jones and Ms. Linda Okowita


Page 4 of 8


Customer Rate Groups - FERC Jurisdictional STATEMENT BA


Wholesale Customer Rate Groups

Per Attachment H-23, EPRS’s stated rate is “invoiced by PJM on a monthly basis to customers taking Network Integration

Transmission Service in the PECO zone on the basis of each customer’s respective monthly Network Service Peak Load ratio

share. EPRS requested from PJM a recent list of these NITS customers in the PECO zone in order to report them here, but

EPRS did not reecieve a response.


Page 5 of 8


Present and Proposed Revenues STATEMENT BG & BH


Wholesale Customer Rate Group Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Total

Network Integration Transmission Service Customers - PECO Zone

Current Revenues paid by Customers1

18,750$ 18,750$ 18,750$ 18,750$ 18,750$ 18,750$ 18,750$ 18,669$ 18,669$ 18,669$ 18,669$ 18,669$ 224,595$

Proposed Revenues to be paid by Customers 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 90,783$ 1,089,401$

Change from current to proposed revenues 72,033$ 72,033$ 72,033$ 72,033$ 72,033$ 72,033$ 72,033$ 72,114$ 72,114$ 72,114$ 72,114$ 72,114$ 864,806$

Note (1) As a result of the Commission’s action pursuant to the Tax Cuts and Jobs Act (see Alcoa Power Generating Inc.—Long Sault Division et al. , 162 FERC ¶ 61,224 (2018) (the “Show Cause Order”)), and consistent with the Commission’s Show Cause

Order, EPRS filed a revised Attachment H-23 on May 10, 2018, in Docket No. ER18-1566-000, to reduce its stated transmission rate from $225,000 to $224,031 (see Essential Power Rock Springs, LLC , Transmission Rate Compliance Filing to

Implement Corporate Tax Rate Change, Docket No. ER18-1566-000 (May 10, 2018)). On November 15, 2018, the Commission accepted EPRS’s proposed revision to Attachment H-23, effective June 1, 2018 (see Alcoa Power Generating

Inc.―Long Sault Division et al. , 165 FERC ¶ 61,094 (2018)).


Page 6 of 8

Essential Power Rock Springs, LLC Period I

Summary Data Tables Statement BJ


Function/ Unadjusted1

Adjusted1

Statement Description Sub-function Amount Amount

AH Operating & Maintenance Expenses Production NA NA

Transmission 947,019$ 1,089,401$

Distribution NA NA

Customer Accounts NA NA

Customer Service NA NA

Sales Expenses NA NA

Admin & General2

NA NA

Total 947,019$ 1,089,401$

AI Wages & Salaries Production NA

Transmission2 709,418$

Distribution NA

Customer Accounts NA

Customer Service NA

Sales Expenses NA

Admin & General NA

Total 709,418$

Notes: (1)

(2)

Unadjusted amounts are Period I actuals. Adjusted amounts reflect the gross up of Period I actual non-labor costs of operating and

maintaining the EPRS Switchyard to reflect EPRS's now 100% ownership in the EPRS Switchyard after acquiring ODEC's 50%

ownership share, effective October 1, 2018.

Transmission Wages and Salaries are estimated based on EPRS's Labor Study. Please see the tetimonies of Company Witnesses Mr.

Ralph Jones and Ms. Linda Okowita


Page 7 of 8

Essential Power Rock Springs, LLC Period I - Adjusted

Cost of Service Study Statement BK

Twelve Months Ended October 31, 2018 Schedule 1

Page 1 of 1

TRANSMISSION REVENUE REQUIREMENTS

Summary of Results

(a) (b) (c) (d) (e) (f) (g)

Total

Line Description Source Electric Production Transmission Distribution All Other

1 Gross Plant In Service NA NA NA NA NA

2 Depreciation Reserve NA NA NA NA NA

3 Net Utility Plant NA NA NA NA NA

4 Accumulated Deferred Taxes NA NA NA NA NA

5 Other Subtractive Adjustments NA NA NA NA NA

6 Materials & Supplies NA NA NA NA NA

7 Fuel Inventory NA NA NA NA NA

8 Prepaid and Other NA NA NA NA NA

9 Cash Working Capital NA NA NA NA NA

10 Acct. 190 and Other Additive Adj. NA NA NA NA NA

11 Total Rate Base NA NA NA NA NA

Operating Expenses

12 Total O&M Expenses Sch. 2; Page 1 NA NA 1,089,401$ NA NA

13 Total Depreciation Expense NA NA NA NA NA

14 Total Other Taxes NA NA NA NA NA

15 Subtotal - O&M & Other

16 Net Federal Income Taxes NA NA NA NA NA

17 Net State Income Taxes NA NA NA NA NA

18 Total Operating Expenses 1,089,401$

19 Return on Rate Base NA NA 0 NA NA

20 Total Cost of Service NA NA 1,089,401$ NA NA

22 Revenue Credits -$

23 Net Cost of Service 1,089,401$

Rate Base


Page 8 of 8

Essential Power Rock Springs, LLC Period I - Adjusted

Cost of Service Study Statement BK

Twelve Months Ended October 31, 2018 Schedule 2

Page 1 of 1

TRANSMISSION REVENUE REQUIREMENTS

O&M Expenses

(a) (b) (c) (d) (e) (f) (g)

Total

Line Allocator Electric Production Transmission Distribution All Other

Production O&M

Energy Related Production O&M

1 Fuel NA NA NA NA NA

2 Purchased Power NA NA NA NA NA

3 Other NA NA NA NA NA

4 Total Energy Related NA NA NA NA NA

Demand Related Production O&M

5 Purchased Power

6 Fixed Fuel NA NA NA NA NA

7 Other NA NA NA NA NA

8 Total Demand Related NA NA NA NA NA

9 Total Production Related O&M NA NA NA NA NA

Transmission O&M

10 Total NA NA 1,089,401 NA NA

11 Total Transmission O&M NA NA 1,089,401 NA NA

Distribution O&M

12 Distribution O&M NA NA NA NA NA

13 Customer Accounting NA NA NA NA NA

14 Customer Service & Information NA NA NA NA NA

15 Sales NA NA NA NA NA

Adminstrative & General

16 A&G Salaries NA NA NA NA NA

17 Property Insurance NA NA NA NA NA

18 Regulatory Commission Expense NA NA NA NA NA

19 Outside Services NA NA NA NA NA

20 Total Administrative & General NA NA NA NA NA

21 Total O&M Expenses NA NA 1,089,401 NA NA

Description


Page 1 of 1

Non-Labor Workpaper

Essential Power Rock Springs, LLC

Cost of Service Study Company Adjustment 1

Twelve Months Ended October 31, 2018 ADJ-SSG-1

Total

Service Provider FERC Account Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Period I Costs

Gridforce Energy Management, LLC 561.2 6,547$ 13,094$ 6,711$ 6,711$ 6,711$ 6,711$ 6,711$ 6,711$ 6,711$ 6,711$ 13,421$ 86,749$

Foxguard Solutions Corp 561.2 68,243 68,243

Network & Security Technologies 561.2 11,000 29,970 40,970

Tangible Group, Inc 561.2 12,220 12,455 24,675

QEI, LLC 561.2 9,318 9,318

Whittenbach Business Systems LLC 561.2 300 250 175 1,100 1,825

SHI International Corp 561.2 131 866 997

Dell Marketing LP 561.2 451 451

Scott Testing Inc. 569.4 2,416 1,802 4,218

Conaire, Inc. / PO161 Conaire Inc. 569.4 156 156

9,394$ 24,344$ 30,126$ 6,711$ 6,711$ 6,711$ 6,711$ 17,830$ 6,711$ 19,796$ 7,337$ 95,219$ 237,601$

Notes:

Service Providers Primary Function for EPRS Rock Springs Switchyard

1. Gridforce Energy Management, LLC NERC Reliability Standards Compliance and PJM Ops Interface Non-Labor Costs

2. Foxguard Solutions Cyber Security Technology Services for CIP Compliance A. Sum of Nov. -Sep. Non-Labor Costs 142,382$

3. Network & Security Technologies NERC CIP Compliance and Vulnerability Assessments B. Adjustment reflecting EPRS acquisition of ODEC 50% share (2 X A) 284,763

4. Tangible Group Inc. Assist with PJM initiated studies and NERC Reliability Standards Compliance - Facilities Ratings C. Plus Oct. Non-Labor Costs 95,219

5. QEI, LLC SCADA Systems Support and Maintenance D. Total Period I Adjusted Non-Labor Costs (B+C) 379,983$

6. Whittenbach Business Systems, LLC Switchyard Physical Security Barriers

7. SHI International Corp. Software Security Services

8. Dell Marketing, LP Computer Systems for CIP Compliance

9. Scott Testing, Inc. Switchyard Maintenance

10. Conaire, Inc. Control Room HVAC maintenance and repairs

Adjustment to Period I Costs


Essential Power Rock Springs, LLC Page 1 of 1

Cost of Service Study

Twelve Months Ended October 31, 2018Switchyard Labor Hours Labor Cost Non-Labor Costs 11/1/2017 - 10/31/2018 Total Costs

561.1 Load Dispatch - Reliabiltiy 2192 172,763$ 172,763$ 561.2 Load Dispatch-Monitor and Operate Transmission System 50 2,376$ 233,227$ 235,602$ 561.5 Reliability Planning and Standards Development 3,498 269,498$ 269,498$ 561.6 Transmission Service Studies 300 28,322$ 28,322$ 568 Maintenance Supervision and Engineering 840 77,620$ 77,620$ 569 Maintenance Structures 40 1,900$ 1,900$

569.1 Maintenance Computer Hardware 380 20,323$ 20,323$ 569.2 Maintenance Computer Software 904 55,840$ 55,840$ 569.3 Maintenance Communitication Equipment 279 13,682$ 13,682$ 569.4 Maintnenance Misc. Regional Transmission Plant - -$ 4,374$ 4,374$ 570 Maintenance of Station Equipment 835 55,392$ 55,392$ 573 Maintenance of Mscellaneous Transmission Plant 180 11,701$ 11,701$

Total Labor and Non-Labor Expenses Unadjusted 9,498 709,418$ 237,600.97$ 947,019$ Expense Post-ODEC Acquisition Oct. 1-31, 2018 95,219.00Expense Pre-ODEC Acquisition Jan 1-Sep 30, 2018 142,381.97Total Expense Jan 1 - Sep. 30 2018 adjusted to 100% 284,763.94Total Expenses Jan 1-Oct 31 2018 709,418$ 379,982.94$ 1,089,401$

Exhibit No. EPRS-2 Prepared Direct Testimony of Mr. Ralph Jones






RALPH JONES

I. INTRODUCTION


A. My name is Ralph Jones. My business address is 1423 Rock Spring Road, Rising

Sun, MD 21911.


A. I am employed by Essential Power Operating Services, LLC (“EP OpCo”) as

General Manager of Essential Power Rock Springs (“EPRS” or the “Company”),

which includes both the EPRS Transmission Facilities and the EPRS Generating

Station. I also serve as Senior Manager for NERC Critical Infrastructure Protection

(“CIP”) compliance.


A. I have a Bachelor of Science degree in Management from the University of

Phoenix. I also have completed Advanced Boiler Technician training with the

United States Navy.

Q. What are your duties and responsibilities at EPRS?


A. I am responsible for the safe and efficient operation, maintenance, and business

management of the EPRS Generating Station (a 680 MW natural gas fired simple

cycle power plant) and the EPRS Transmission Facilities (a 500 kV substation,

configured as a five circuit breaker ring bus, designated as NERC CIP Medium

Impact (the “EPRS Substation” or “Switchyard”), and two 900-foot, 500 kV

transmission lines, configured as double circuits on a single tower line).


A. I possess over 30 years of progressive experience in the power generation field

starting in the U.S. Navy in 1985. I have held the following positions: First Class

Boiler Technician/work center supervisor (U.S. Navy), Senior Plant Technician,

Production Manager, Plant Engineer, Operations and Maintenance Manager,

Assistant General Supervisor of Operations and Maintenance, and Plant/General

Manager at various power generating facilities.


A. I will provide factual support for this rate filing and Proposed Revenue

Requirement by describing the EPRS Transmission Facilities owned by EPRS and

the resources, both labor and non-labor, required to operate and maintain them.

Specifically, I will provide information about the operations and maintenance

(“O&M”) costs related to the EPRS Transmission Facilities owned by EPRS that

form the basis of the rate filing.

Q. How is your testimony organized?

A. Section II Background, provides background on the EPRS Transmission Facilities,

how they are operated and maintained, and what has changed since the Company’s


last rate filing, as well as the extent of EPRS’s NERC compliance obligations and

how the Company satisfies them. Section III Operations and Maintenance Cost

Information, describes the labor and non-labor O&M costs attendant to operating

the EPRS Transmission Facilities that the Company is seeking rate recovery of in

this stated rate filing.

II. BACKGROUND

Q. Please describe EPRS Transmission Facilities and the EPRS Generating

Station.

A. EPRS, LLC owns two primary energy assets – the EPRS Generating Station and

the EPRS Transmission Facilities. EPRS’s operation of the EPRS Transmission

Facilities forms the basis of this rate filing. The EPRS Generating Station is located

in Rising Sun, Maryland. There are four gas fired electric generating units located

at the EPRS Generating Station. The four generating units are interconnected to a

500 kV substation (the “EPRS Substation”) and two 900-foot, 500 kV transmission

lines (referred to collectively with the EPRS Substation as the “EPRS Transmission

Facilities”). The EPRS Transmission Facilities were developed in order to

interconnect the EPRS Generating Station to the PECO transmission system.

Interconnection of the four generating units to PECO’s transmission system was

accomplished by, in effect, looping the two 900-foot lines from the EPRS

Substation to an existing 500 kV transmission line on PECO’s system. Radial lines

then connect the EPRS Substation to the four EPRS Generating Station units, as

well as to the three generating units of the newly-constructed and interconnected


Wildcat Point generating facility owned by Old Dominion Electric Cooperative

(“ODEC”). As a result of this configuration, the EPRS Transmission Facilities

operate as an electrically integrated part of the PJM transmission system. All

electricity flowing on the PJM transmission system, regardless of the source,

potentially flows through the EPRS Transmission Facilities.

Q. Have there been any additional interconnections to the EPRS Transmission

Facilities?

A. Yes. Wildcat Point began commercial operation in April of 2018. Wildcat Point

is a combined cycle generation facility consisting of three generating units

interconnected to the EPRS Substation. Wildcat Point is currently rated at 940

MWs under its current Interconnection Agreement with PJM. That initial

interconnection required System Feasibility, System Impact, and Facilities Studies

prior to interconnection. Additionally, ODEC has filed to increase the claimed

capacity of Wildcat Point to 1,090 MWs, which, like the initial interconnection,

required System Feasibility and System Impact Studies (see PJM-QUEUE AD2-

167).

Q. Do those system studies require EPRS resources to complete?

A. Yes. They require operations resources to coordinate the process and complete the

studies, in addition to hiring outside contractors to assist in the completion of the

studies and communicating the results to PJM.

Q. Is Wildcat Point a shared facility?

A. No. ODEC wholly owns the Wildcat Point facility.


Q. Did EPRS bear any of the capital or O&M costs of establishing the

interconnection of the Wildcat Point facility to the EPRS Transmission

Facilities?

A. No. EPRS did not contribute to any capital or O&M costs related to establishing

the Wildcat Point interconnection.

Q. Did the interconnection of Wildcat Point introduce additional operations

responsibilities on EPRS for the EPRS Transmission Facilities?

A. EPRS, as the TO, would have been fully responsible for the operations of the EPRS

Transmission Facilities regardless of the interconnection of Wildcat Point.

However, in practice, because the interconnection of Wildcat Point means the

EPRS Transmission Facilities have two customers now instead of one, and because

Wildcat Point is a baseload facility that operates more frequently than the EPRS

Generating Station (which is a peaking facility), EPRS must coordinate with

Wildcat Point staff periodically on the operation of the EPRS Transmission

Facilities, recognizing that the importance of reliably operating and maintaining the

EPRS Transmission Facilities is heightened.

Q. Are the EPRS Transmission Facilities just generator interconnection

facilities?

A. No, they are not. The EPRS Transmission Facilities’ configuration as looped

facilities makes them integrated components of the PJM system, which is why

EPRS is a PJM Transmission Owner, not just a generator.


Q. Has anything changed regarding the operations and maintenance

responsibilities and costs of the EPRS Transmission Facilities since the

company filed its current transmission rate in 2012?

A. A number of things have changed. In addition to the Wildcat Point interconnection

described above, EPRS now owns 100 percent of the EPRS Transmission Facilities,

instead of the 50 percent it owned at the time of the 2012 rate filing. Further, the

entire NERC CIP program changed from Version 3 to Version 5 in the summer of

2016, adding a significant number of cyber assets to the CIP program and thus,

requiring significantly more support to maintain an effective program.

Q. Did the EPRS Generating Station previously have two owners?

A. Yes. Until recently, ODEC owned a 50 percent share of the EPRS Generating

Station and an associated 50 percent share of the EPRS Transmission Facilities.

Now, EPRS wholly owns both the EPRS Generating Station and the EPRS

Transmission Facilities.

Q. What is the impact of that change in ownership on EPRS’s cost responsibility

for the EPRS Transmission Facilities?

A. EPRS was previously only responsible for half of the costs of operating and

maintaining the EPRS Transmission Facilities. Now, EPRS is responsible for 100

percent of those costs.

Q. What specifically has changed with respect to CIP Compliance?

A. CIP compliance demands an increasing amount of resources. As mentioned above,

the entire NERC CIP program changed from Version 3 to Version 5 in the summer

of 2016. This change to Version 5 increased the number of cyber assets within the


EPRS Substation that are part of the NERC CIP program from roughly 16 to 63,

which put additional demands on Company resources and required additional

contracting services for compliance. In fact, as a result we now have a fully-

dedicated CIP subject matter expert to handle these additional requirements and I

also contribute roughly half of my labor time to CIP compliance activities as the

Senior Manager for NERC CIP compliance. Moreover, the overall program

requirements drastically increased the time and resources required to manage the

program. EPRS has to remain current with and comply with all NERC Operations

and Planning standards and their associated requirements as they pertain to the

switchyard, including those outlined in the PJM Transmission Owner/Transmission

Operator (“TO/TOP”) matrix. And for good reason – I understand the Commission,

NERC and the regional reliability entities have placed a great deal of emphasis on

ensuring the grid is protected from a cyber attack and remains reliable for

transmitting bulk power from facilities like the EPRS Generating Station and

Wildcat Point. As I previously explained, the EPRS Transmission Facilities are

integrated components of the PJM transmission grid that must be protected from

cyber or physical attack. This requires us to devote significant labor and non-labor

resources to CIP compliance.

Q. Have the EPRS Transmission Facilities expanded over time?

A. Yes, we recently upgraded the wave traps on the 500 kV Kenney line as a PJM

project AB2-021. A third party funded the studies and all material and labor for

the project. However, the operations, maintenance and compliance activities

associated with the project equipment remains EPRS’s responsibility. Further, the


Wildcat Point baseload plant was recently interconnected as well, as discussed

earlier in my testimony.

Q. Is EPRS a PJM Transmission Owner?

A. Yes. Because the EPRS Transmission Facilities function as looped components of

the PJM transmission system, EPRS is a signatory to the PJM Transmission Owners

Agreement.

Q. Please describe the operational responsibilities that come with owning the

EPRS Transmission Facilities?

A. There are a number of responsibilities. First and foremost, as owners of the EPRS

Transmission Facilities, EPRS must comply with various NERC Reliability

Standards associated with transmission ownership and operations. In particular,

ownership of the EPRS Transmission facilities requires compliance with the CIP

and TO/TOP standards. Note that, although EPRS is not designated as a

Transmission Operator, EPRS is required to support various TOP requirements in

support of PJM as part of its Tariff agreements. In addition, we routinely assist

PJM in transmission-related studies, including System Feasibility, Impact, and

Facilities Studies associated with requests for interconnection service or

transmission service, or other PJM-directed transmission planning studies.

Q. What are Critical Infrastructure Protection or CIP costs?

A. CIP costs are those costs incurred to comply with mandatory CIP Standards. The

Company, as a result of its ownership in the EPRS Transmission Facilities, is a

NERC registered Transmission Owner. Under applicable Reliability Standards,

portions of the EPRS Transmission Facilities are classified as BES Cyber Systems


or as cyber assets associated with these BES Cyber Systems, which also require

compliance with the NERC CIP Standards. The Company is, therefore, subject to

the CIP Standards CIP-002 through CIP-011, including CIP-014. Compliance with

these standards requires investment in personnel, hardware and third-party

contractors to ensure that the CAs and CCAs are protected, thus, ensuring the

reliability of the Bulk Power System.

Q. Is compliance with CIP standards required under NERC rules and also

described in the PJM tariff?

A. Yes, EPRS is designated as an owner, operator, and/or user of the Bulk Power

System and is appropriately registered as such on the NERC Compliance Registry.

As a result, EPRS must adhere to the NERC Standards, including CIP standards,

that apply to the facility as a TO. In addition, the PJM standard Interconnection

Service Agreement includes the following requirement, which applies to

Transmission Owners:

“All interconnection parties agree to comply with all infrastructure security requirements of the North American Electric Reliability Corporation.”1

Q. Please describe the types of CIP compliance activities that are mandated for

the EPRS Transmission Facilities.

A. The NERC CIP Version 5 standards include nearly 170 separate requirements or

sub-parts of requirements to which EPRS must comply. These include:

performance of a BES Cyber Asset categorization; development of a documented

1 See Section 23.0 of Attachment O to the PJM Tariff.


set of CIP policies and procedures; implementation of a CIP quarterly awareness

program; development and implementation of annual CIP training; programs for

performing personnel risk assessments for individuals requesting access to NERC

CIP assets at EPRS; user authorization, provisioning, and revocation programs;

securing BES Cyber Systems through configuration of and management of an

electronic security perimeter; documentation of all access rules and privileges into

and from the CIP networks; implementation and management of remote access

using two-factor authentication; implementation of a site physical security plan

with managed access to secured locations containing BES Cyber Systems;

individual BES Cyber System management such as limiting open ports and services

to only those necessary; monthly security patch identification, evaluation for

applicability, and implementation; maintenance of active anti-malware tools;

logging and alerting of security related events and activities; user account

management and password controls; cyber security incident response planning and

associated exercises; development of cyber asset backup and recovery processes;

monitoring and maintaining up-to-date baseline configurations for BES Cyber

Systems; managing the implementation of a configuration change management

process; coordinating and supporting an annual vulnerability assessment;

implementation of a program for securing removable media and managing the use

of transient cyber assets for site staff and third-party service providers; and,

protecting BES Cyber System Information through implementation of a site

information protection program. These activities require significant labor time of

Company personnel, the installation of required hardware and software, and the


development of procedures to ensure compliance. These activities also include the

implementation of a Compliance Management Software solution and the

preparation for, and execution of, CIP audits conducted by the responsible Regional

Entity, ReliabilityFirst Corporation.

Q. How does the company pay for the CIP Compliance activities?

A. The Company is party to the Second Amended and Restated Scheduling, Dispatch,

Operating Procedures and Operation and Maintenance Agreement dated as of

September 14, 2018 (the “O&M Agreement”) with an affiliate of the Company, EP

OpCo under which EP OpCo provides all required operation and maintenance

services at EPRS Generating Station, as well as the EPRS Transmission Facilities.

Under the O&M Agreement, EP OpCo performs all O&M services, including

Reliability Standards compliance activities for the EPRS Generating Station and

the EPRS Transmission Facilities. This contract structure is a vestige of the former

joint ownership structure with ODEC, under which EP OpCo provided operations

and maintenance services for the entire project on behalf of both owners. Costs

incurred under the O&M Agreement used to be assigned and/or allocated between

the Company and ODEC in accordance with their respective ownership shares, but

are now borne 100 percent by EPRS as the sole owner of the EPRS Generating

Station and the EPRS Transmission Facilities.

Q. Would EPRS still be responsible for CIP compliance if it did not own the


A. Yes, but not nearly to the same extent. The EPRS Generation Station is

categorized by NERC as a Low Impact facility, which is much less complex to


manage than the Medium Impact program required for Transmission Owners of

Transmission Facilities at or above 500 kV, like the EPRS Transmission

Facilities.

Q. What are the other categories of compliance that EPRS is responsible for as

the TO for the EPRS Transmission Facilities?

A. EPRS is a registered Transmission Owner within the PJM footprint and must satisfy

the NERC TO standard requirements. In addition, PJM serves as the official

Transmission Operator for the EPRS facilities. As part of its arrangement with

PJM, PJM conveys certain of its TOP responsibilities to its resident TOs through

the use of a TO/TOP matrix of Responsibilities.

Q. Please describe the TO/TOP standards.

A. The TO/TOP set of Reliability Standards apply to either Transmission Owners or

Transmission Operators or both in the NERC functional model. According to

NERC, TOPs have a primary responsibility for maintaining the real-time reliability

of their local transmission system. PJM is the TOP for its footprint, but delegates

certain responsibilities to its member Transmission Owners through something

called the TO/TOP matrix.2 As described by NERC:

PJM coordinates and directs the operation of the transmission grid and plans transmission expansion improvements to maintain grid reliability in this region. PJM assures there are no gaps in reliability as reflected in their manuals, compliance bulletins, and summarized in the TO/TOP matrix. There is a clear understanding of responsibilities and authorities as included in PJM agreements, the TO/TOP matrix, training and the TO audit program.

2 http://www.pjm.com/markets-and-operations/~/media/markets-ops/compliance/pjm-to-top-matrix-version-4-pdf.ashx.


The TO/TOP matrix is intended to clarify the assignment of tasks based on the unique relationship between PJM and its member TOs as defined in the agreements and described in detail in various PJM manuals. The TO/TOP matrix does not create any new obligations for PJM or its members, but is simply a cross-reference to indicate where the assignment of various reliability tasks is documented.3

Transmission Owners incur costs to comply with their responsibilities under the

TO/TOP matrix.

Q. How does EPRS satisfy its responsibilities under the TO/TOP matrix?

A. Like the CIP standards, EP OpCo, under the O&M Agreement, performs O&M

services including TO and TOP compliance activities at the EPRS Transmission

Facilities. The Company also has agreements with contractors, like GridForce

Energy Management (“GridForce”), which performs TO/TOP compliance services

on behalf of EPRS.

Q. How does EPRS satisfy its responsibilities under the CIP standards?

EPRS takes CIP compliance very seriously and is required to maintain

compliance and meet the expectations of FERC, NERC, and ReliabilityFirst.

There are a number of responsibilities we have in order to ensure compliance. In

addition to the compliance activities undertaken by onsite personnel and third-

party contractors, we rely on the Cogentrix Compliance department and the

Cogentrix IT department to meet the requirements set forth in all the applicable

NERC CIP Standards.

3 http://www.nerc.com/files/BA,%20RC,%20and%20TOP%20Certification%20of%20PJM%20Inte-rconnection,%20LLC.pdf.


III. OPERATIONS AND MAINTENANCE COST INFORMATION

Q. Were you responsible for gathering the raw cost data that forms the basis of

this limited O&M stated rate filing?

A. Yes.

Q. Please generally explain the categories of costs associated with complying

with these NERC standards and otherwise operating and maintaining the


A. There are two primary cost drivers associated with the EPRS Transmission

Facilities that make up the requested stated rate – labor and non-labor.

Q. Please explain the labor costs.

A. The labor costs associated with operating the EPRS Transmission Facilities is

comprised of both compliance and operations personnel who are physically

located onsite at Rock Springs, as well as by remote compliance and IT support

personnel.

Q. Please describe the onsite compliance and operations staff.

A. As the Senior Manager for NERC CIP compliance, I am responsible for the

overall NERC CIP program. I review and approve/deny all procedures, work

processes, change management activities, lead incident activities, assist in third

party contract development and the ongoing management of those contractors.

We also have an onsite CIP subject matter expert (“SME”) devotes all his time

(including overtime) to that function. His sole responsibility is the NERC CIP

program and he helps to maintain compliance with all the applicable standards

associated with the EPRS Switchyard. The SME coordinates and leads the


system patch management program, conducting patch availability reviews,

tracking security related updates, evaluating for applicability, creating necessary

mitigation plans and configuration change management activities. The SME also

ensures that all onsite personnel follow the processes and procedures required in

all areas of CIP compliance, IT and physical security. Additionally, the SME

works on the associated instrumentation and controls in the Switchyard, the IT

equipment in the electronic security perimeter, procedure development, and all

administrative duties associated with front line management of the program. The

EPRS Generating Station is also staffed by eight technicians. Six of those

technicians are operators that carry out switching duties and perform maintenance

for the EPRS Transmission Facilities. There are two instrument & control

technicians: one is the CIP SME for the EPRS Transmission Facilities, described

above; the other performs operations and maintenance duties on the EPRS

Transmission Facilities. The other technicians are tasked with routine operations

and maintenance responsibilities for the EPRS Substation, as well as the EPRS

Generating Station. I note that the 500 kV lines that make up the remaining

portion of the EPRS Transmission Facilities do not require regular maintenance.

Q. What type of duties to these personnel perform on the EPRS Transmission

Facilities?

A. The technicians monitor Switchyard operations and conduct inspections twice per

shift. These technicians communicate with GridForce and execute switching

orders, per the TOP standards. The technicians also perform preventative

maintenance on the battery backup system, the emergency diesel generator, and


assist in managing third party contractors performing maintenance in the

switchyard.

Q. Please describe the remote compliance and IT support staff.

A. We have compliance professionals that provide direct NERC CIP and other IT

support to the EPRS Transmission Facilities, including:

Providing overall program administration

Administering and processing configuration change management

requests

Coordinating annual cyber security training program development

Organizing cyber security incident response plan development and

testing

Coordinating annual vulnerability assessments

Maintaining up-to-date program documentation such as procedure

templates, BES asset spreadsheets, BES Cyber Asset spreadsheets,

NERC user access application, and asset specific configurations, backup

files, ports and services, and recovery plans.

Reviewing and ensuring overall quality of CIP program documentation

and evidence

Administration of CIP Sharepoint portal and associated CIP process

workflows

Coordinating NERC Compliance audit and monitoring activities with

ReliabilityFirst, EPRS’s NERC-designated Regional Entity, including

violation processing and mitigation plan development and management

Coordinating and performing CIP procedure and policy review; and,

Coordinating new or modified standard implementation.

Performing monthly patch identification, evaluation, and

implementation for networking and non-plant operating systems

Provisioning user access on assets

Performing annual change of passwords


Participating as subject matter experts in the cyber security incident

response plan and associated exercises

Supporting execution of the annual vulnerability assessment

Implementing anti-malware protections on NERC CIP program assets

Processing configuration change requests

Updating asset-level documentation, including baseline configurations,

backup files, ports and services, and recovery plans

Maintaining firewall security through effective rule administration

Configuring and maintaining network connectivity;

Implementing and maintaining interactive remote access through use of

two-factor authentication, and,

Response to emergent issues with the CIP environment.

Q. How were labor costs calculated?

A. Aside from the CIP SME for the EPRS Transmission Facilities, EPRS does not

employ technicians with sole responsibility for EPRS Substation maintenance.

Moreover, EPRS does not employ a labor time system that enables employees to

code their time to different functional areas of operations, like to transmission or

generation. Therefore, we had to perform a post-facto analysis to determine how

to assign the costs of the personnel with operations and maintenance

responsibilities to the EPRS Transmission Facilities. I personally worked with

Cogentrix’s human resources department to survey each member of the EPRS

team to determine the amount of time in the Test Period that was dedicated to the

EPRS Transmission Facilities.

Q. Please describe the initial process you undertook to gather the relevant labor

cost information.


A. The process for developing the labor cost analysis was directed by Linda Okowita,

the Vice President of Human Resources, who is also sponsoring testimony in this

proceeding. There were two primary components to the labor analysis. First, the

Company conducted a survey of employees with some level of operations and

maintenance responsibility for the EPRS Transmission Facilities in order to

determine how much time each employee spent on that function. The second step

was to determine an annual labor cost for the Test Period applicable to the EPRS

Transmission Facilities by applying the wage and salary data of individual

personnel to their labor hours spent on the EPRS Transmission Facilities. I assisted

in executing the first part of the labor analysis, i.e., the labor time estimation survey.

Ms. Okowita handled the second part of the analysis, i.e., the annual labor cost

estimation.

Q. Please describe the labor time estimation survey.

A. First, an email was sent to all personnel of Cogentrix by the Director of Asset

Management who were believed to have contributed some labor time to the EPRS

Transmission Facilities, asking that they estimate how many hours per week they

spent in the prior year managing and operating the EPRS Transmission Facilities,

including CIP compliance activities. The results of that survey were then compiled

into a labor file by the Director of Asset Management. I then received a request to

review the file for accuracy.

Q. How did you verify the accuracy of the labor file?

A. Based on my knowledge of the activities related to the EPRS Transmission

Facilities, I sought clarifications from some employees and also made a minor


adjustment to add an employee who was inadvertently omitted from the initial

survey, who then provided their estimate of time of time worked on the EPRS

Transmission Facilities.

Q. Does the labor time estimation include both Company personnel who

physically work at Rock Springs, as well as those that provide NERC CIP

support and other IT to the EPRS Transmission Facilities?

A. Yes. As mentioned above, we have compliance professionals that provide NERC

CIP and other IT support to the EPRS Transmission Facilities. For instance, the

results of the labor time estimation survey showed that NERC CIP compliance and

IT support accounted for more than 40 percent of the total labor hours spent in

support of the EPRS Transmission Facilities.

Q. Please describe the non-labor costs included in the filing.

A. The Company bears non-labor costs associated with its mandatory reliability

obligations and other general operations and maintenance of the EPRS

Transmission Facilities. These non-labor costs include out-of-pocket expenses

and mostly consist of payments to third-party contractors who render reliability

compliance and other services to the EPRS Transmission Facilities, as well as

payments made to third parties for parts and equipment.

Q. How did you categorize the labor and non-labor costs.

A. EPRS has a waiver from the Commission of the requirement to follow the FERC

Uniform System of Accounts. But, to properly organize the labor and non-labor

costs as both reliability-, and non-reliability-, related and to ensure consistency

with the cost categories the Commission would normally see for O&M expenses,


I allocated each of the labor and non-labor cost components into a cost category

by FERC account.

Q. Please provide examples of the types of non-labor costs for which EPRS seeks

recovery.

A. We use a number of contractors to support the EPRS Transmission Facilities, both

for reliability compliance and general maintenance. For example, we use a

company called GridForce to provide PJM TO/TOP compliance services and

operational services (e.g., certified interfacing with PJM, executing switching

orders). We use a company called QEI for the SCADA systems monitoring that

supports the EPRS Substation. We use a company called Scott Testing for

maintenance issues related to the EPRS Substation. A firm called Wittenbach

Business Systems has installed and maintained physical security systems around

the EPRS Substation. A firm called Network and Security Technology provides

assistance with CIP compliance, and they also conduct the required annual

vulnerability assessment. Finally, a firm called Foxguard Solutions provides

additional cybersecurity-related information technology services – again, to assist

in CIP compliance. These contractors, and other smaller expenditures on similar

outside services, make up the bulk of the non-labor costs included in Mr.

Garwood’s rate calculation.

Q. Were you also responsible for initially gathering the non-labor portion of the

O&M costs?

A. Yes, I was.

Q. Please describe how you assembled the non-labor cost information.


A. First, I requested from our Hyperion System Administrator a report from our

general ledger of all the actual non-labor costs for the Test Period, i.e., 12 months

ending October 31, 2018. This report identified actual non-labor cost information

categorized by functional department (e.g., operations, maintenance, NERC CIP

compliance, other regulatory compliance, etc.) and provided the annual cost

amount for the Test Period. Next, in order to get additional detail on a specific

annual expenditure identified in the Hyperion report, I queried the computerized

maintenance management system (i.e., Peoplesoft). This report shows the

transaction level detail of all actual non-labor costs categorized by functional

department and also shows the date the expense was incurred, the specific vendors

paid for the service rendered or the vendors paid for equipment purchased. By

comparing these two reports, I’m able to verify both the amount of a non-labor cost

and the nature of the cost.

Q. Does the Cogentrix operating and cost accounting information databases

utilize or map to the FERC Uniform System of Accounts?

A. No.

Q. Did you apply the FERC Uniform System of Accounts to the non-labor cost

information that you queried and developed based on Cogentrix’s operating

and cost accounting information?

A. Yes.

Q. Please describe the process you undertook to assign the non-labor cost

information associated with operating and maintaining the EPRS


Transmission Facilities to the FERC Uniform System of Accounts for purposes

of this rate filing.

A. First, I received a list of the FERC Uniform System of Accounts from rate

consultant Mr. Steve Garwood, who is also providing testimony in this proceeding,

that included the list of accounts and a description of the costs to be included in

each account that was taken from Part 101 of the Commission’s regulations.

Q. Did you and Mr. Garwood discuss how to interpret the account descriptions

and apply them?

A. Yes, we did.

Q. How did you identify which FERC account a particular non-labor cost

transaction would apply to?

A. I went line by line through the transaction level non-labor file I created and used

my best judgment of which FERC account the cost would apply.

Q. Can you provide an example?

A. Sure. As mentioned elsewhere in my testimony, EPRS uses the contractor

GridForce for a variety of TO/TOP compliance services. Based on the non-labor

file I created, I could identify that GridForce is paid a monthly operations fee for

the operations monitoring it does on the EPRS Transmission Facilities. A review

of the FERC Uniform System account descriptions indicates that account 561.2 –

Load Dispatch-Monitor and Operate Transmission System accurately captures the

type of service GridForce performs in this instance, thus I tagged the GridForce

monthly operations fee as belonging to account 561.2. I performed this same task

for every relevant transaction-level non-labor O&M cost in the Test Period.


Q. Did Mr. Garwood review your application of the FERC accounts to the non-

labor cost data?

A. Yes. Please see the testimony of Mr. Garwood for additional explanation of his

review.

Q. Did Company witness Mr. Bryan Craig also review the final non-labor cost

file to ensure the consistency with the FERC Uniform System of Accounts?

A. Yes. Please see the testimony of Mr. Craig for additional explanation of his review.

Q. Does the rate addressed in this filing include any capital investment in the


A. No. I understand that the FERC previously determined that EPRS’s predecessor

owner (ConEd Development) was not able to recover its capital investment in the

EPRS Transmission Facilities.


A. Yes, it does.


Exhibit No. EPRS-3 Prepared Direct Testimony of Ms. Linda Okowita






LINDA OKOWITA

I. INTRODUCTION


A. My name is Linda Okowita. My business address is 13860 Ballantyne Corporate

Place, Suite 300, Charlotte, NC 28277.


A. I am employed by Cogentrix Energy Power Management, LLC as the Senior Vice

President, Human Resources.


A. I have a Bachelor of Arts Degree in Labor Studies from McMaster University in

Hamilton, Ontario, Canada.

Q. What are your duties and responsibilities at Cogentrix?

A. I am responsible for the human resources and payroll functions for the Cogentrix

companies, including EP Rock Springs, LLC (“EPRS”).


A. I possess over 30 years of experience in various human resource functions.



A. I will provide factual support for this rate filing and Proposed Revenue

Requirement by describing the analysis of labor costs that EPRS undertook to

support its filing. Specifically, my Payroll Manager (who reports directly to me)

and I helped to calculate the labor costs associated with the 500 kV transmission

facilities owned by EPRS (the “EPRS Transmission Facilities”).

Q. Are you sponsoring any exhibits?

A. Yes, I am sponsoring Exhibit No. EPRS-LO-1, which contains the results of the

labor cost study. This Exhibit has two pages: the first is the summary tab of the

total labor hours per each FERC account identified by Mr. Ralph Jones (who is also

sponsoring testimony) and the total labor costs that were calculated based on the

hours that were provided to me by Mr. Jones; the second page is the total hours

worked per employee per FERC account that were provided to me by Mr. Jones.

Q. Do each of the job titles on this Exhibit tie to specific employees?

A. Yes, merely for purposes of confidentiality, I did not include specific names, but

each identified job title on the exhibit ties to a specific employee. I also removed

the labor costs per employee from the Exhibit for purposes of confidentiality.

Because the labor costs are based on each employee’s compensation, that

information is incredibly sensitive.

Q. Please describe these labor costs.

A. I understand that EPRS owns two primary energy assets – the EPRS Generating

Station and the EPRS Transmission Facilities. Employees at Rock Springs have

responsibility for operating the EPRS Transmission Facilities and ensuring


compliance with what I understand are various mandatory reliability standards. In

addition, certain employees employed by Cogentrix have direct responsibility for

certain facets of the EPRS Transmission Facilities, including compliance. It was

these labor costs we calculated for this rate filing.

Q. What was the purpose of the labor analysis you helped undertake?

A. Because this filing seeks recovery of transmission-related expenses, the purpose of

the labor analysis was to isolate the time spent by each relevant Rock Springs

employee on the EPRS Transmission Facilities, in order to separate it from time

spent on the generation facility.

Q. Was the labor estimate based on a rough estimate of total Cogentrix labor

costs?

A. No, not at all. The company conducted a granular study of the labor costs directly

attributable to the EPRS Transmission Facility, using data on labor hours and costs

of specific personnel within our company.

Q. Please provide any overview of the labor analysis.

A. There were two primary components to the analysis. First, the company conducted

a survey of employees with some level of responsibility for the EPRS Transmission

Facilities, in order to determine how much time each employee spent on those

functions. The second step was to determine an annual labor cost for the Test

Period by applying wage and salary data to the hours to determine the total cost of

labor applicable to the EPRS Transmission Facilities. I was responsible for the

second of these two steps. Please see the testimony of Mr. Ralph Jones for a

discussion of the first step.


Q. Please describe the time estimation survey.

A. As explained to me, the company surveyed each relevant employee and asked for

an estimate of annual hours spent on the EPRS Transmission Facilities. The results

of that survey were provided to me. We identified 10 salaried employees who have

some responsibility for the EPRS Transmission Facilities, whose costs factor into

the study. In addition, there are six non-exempt (i.e., hourly) technicians whose

costs were also included.

Q. Were you responsible for the time estimation survey?

A. No. My primary role was the second step the analysis – the development of costs.

Mr. Ralph Jones has first-hand knowledge of the time and resources spent on the

EPRS Transmission Facilities and his testimony supports that aspect of the analysis.

Q. Please describe the labor cost development process.

A. The survey results I was provided contained granular data, down to the employee.

Therefore, we estimated an annual labor cost for each employee. This was based

on individual compensation data for each employee contained in Cogentrix’s

payroll system. We then multiplied the compensation rate for each employee by

the labor time they spent on the EPRS Transmission Facilities as a percentage of

total annual work hours.

Q. Did you include labor overhead costs, such as the costs of benefits?

A. No, all labor overhead costs were omitted from this analysis in order to provide a

conservative estimate for purposes of this rate filing. So, the only cost at issue is

direct compensation paid to the employee (annual base pay and accrued annual

discretionary target bonus).


Q. Do some employees contribute more to the total labor costs than others?

A. Yes. There are five individuals that contribute roughly 74 percent of the total labor

costs. They include the General Manager/Senior CIP Manager, the CIP subject

matter expert who is dedicated entirely to CIP standards compliance for the EPRS

Transmission Facilities, the Director of Compliance, the Manager of NERC

Compliance, and the O&M Manager.

Q. Were all employees treated this way in the analysis?

A. Yes, with one exception. There are six additional employees included in the labor

study. These employees are hourly, non-exempt employees, so we averaged their

hourly wage to apply a single rate across their hours.

Q. Do you believe that the results of the labor analysis are true and accurate

estimates of the labor costs associated with the EPRS Transmission Facilities?

A. Yes, I do. As I mentioned, there are other attributable labor costs (e.g., benefits)

that were excluded from the analysis, so I believe the analysis is a reliable,

conservative estimate.


A. Yes, it does.


Exhibit No. EPRS-4 Prepared Direct Testimony of Mr. Bryan Craig






BRYAN K. CRAIG

I. INTRODUCTION

Q. Please state your name and occupation.

A. My name is Bryan K. Craig and I am the President and Owner of an energy

consulting firm called Craig Energy & Financial Services (“CEFS”). CEFS

provides a variety of accounting, auditing, compliance and technical services to the

electric, gas, and oil industries on regulatory accounting, auditing, rate, and

compliance matters.

Q. Please summarize your qualifications and experience.

A. For over 30 years, I have been a licensed, Certified Public Accountant, and

an active member of the American Institute of Certified Public Accountants. Since

2012, I have been a Chartered Global Management Accountant. I received a

Bachelor’s of Business Administration in Accounting from Howard University in

1984.

I was employed by the Federal Energy Regulatory Commission (Commission or

FERC) for 31 years from 1987 until my retirement in January 2018. During this


period, I was promoted to positions of increasing responsibility from a field auditor

to the Commission’s Chief Accountant and Audit Director where I oversaw the

Commission’s accounting and audit programs for the electric utility, natural gas,

and oil pipeline industries. From 2010 to January 3, 2018, I served as the

Commission’s Chief Accountant. As the Chief Accountant, I issued thousands of

accounting orders and other actions to electric utilities, natural gas pipelines, and

oil pipeline carriers (i.e., regulated entities), thereby establishing the

Commission’s accounting policies governing areas such as: mergers and

acquisitions, corporate income taxes, infrastructure investments, purchase and sale

of major assets, regulatory assets and liabilities, operations and maintenance

expenses, and utility plant. I also served as the Commission’s Audit Director from

2002 to January 3, 2018. I have directed and led about a thousand audits of

regulated entities involving a myriad of regulatory accounting/rate matters such

as: merger internal labor costs, regulatory assets and liabilities, allowance for

funds used during construction, utility plant, asset retirement obligations, income

tax overpayments, commitment fees, storm damages, investment tax credits,

operations and maintenance expenses, administrative and general expenses,

transmission incentives, and reliability.


A. I provide testimony on behalf of EP Rock Springs, LLC (“EPRS”) related to the

labor and non-labor operations and maintenance (“O&M”) costs that EPRS

incurred to maintain and operate EPRS’s Transmission Facilities in compliance

with the North American Electric Reliability Corporation (“NERC”) mandatory


reliability standards. Although EPRS has a waiver from FERC to follow the

Uniform System of Accounts (the “Commission’s accounting regulations” or

“Uniform System of Accounts”), EPRS used the Uniform System of Accounts as

a guide to prepare its rate filing. Specifically, I will address whether EPRS

accounting and allocation methods used in its rate filing for labor and non-labor

O&M costs was consistent with the Commission’s accounting regulations. EPRS

witness Mr. Ralph Jones provides in his testimony a description of the labor and

non-labor O&M costs incurred to operate and maintain EPRS Transmission

Facilities. Both EPRS witnesses, Mr. Ralph Jones and Ms. Linda Okowita,

discuss in their testimonies the allocation methods used to distribute the labor

costs to various FERC transmission operations and maintenance expense

accounts. EPRS witness Steven Garwood discusses in his testimony the

ratemaking treatment of the labor and non-labor O&M costs.

Q. Please provide a summary of your testimony.

A. My testimony explains the Commission’s accounting regulations for labor and

non-labor O&M costs incurred to comply with NERC’s mandatory reliability

standards. I will also explain the FERC accounting requirements for allocating

employee pay and expenses to work projects. Moreover, I will evaluate whether

the O&M costs and allocation methods used in developing EPRS’s rate filing is

consistent with the Commission’s accounting regulations. Based on my

evaluation, I concluded that the labor and non-labor O&M costs and allocation

methods used by EPRS in its rate filing is consistent with the Commission’s

accounting regulations.


II. FERC ACCOUNTING REGULATIONS

Q. Where are the FERC operations and maintenance expense accounts

established in FERC accounting regulations?

A. The Commission’s accounting regulations for the labor and non-labor O&M costs

incurred to perform work on EPRS Transmission Facilities to comply with NERC’s

mandatory reliability standards are set forth in the chart of accounts for

transmission operations and maintenance expenses in FERC’s Uniform System of

Accounts Prescribed for Public Utilities and Licensees (see 18 C.F.R. Part 101).

Q. Where are the FERC methods of allocating employee’s pay discussed in the

Commission’s accounting regulations?

A. The Commission’s accounting regulations that explains how to distribute

employees pay and expenses to reliability-related maintenance and operations

projects are discussed in General Instruction 9 in the FERC’s Uniform System of

Accounts Prescribed for Public Utilities and Licensees (see 18 C.F.R. Part 101).

Q. Please describe the FERC accounting regulations that addresses the type of

O&M costs included in EPRS rate filing.

A. FERC has prescribed specific accounts and instructions for recording reliability-

related labor and non-labor O&M costs, such as those included in EPRS rate filing.

The account instructions are designed to provide EPRS with the necessary and

pertinent guidance for recording the reliability-related labor and non-labor O&M

costs in the appropriate FERC account. The reliability-related operating costs are

recordable in FERC accounts 560 through 567; and the reliability-related

maintenance costs should be accounted for in FERC accounts 568 through 574.


Q. Please describe the FERC accounting regulations that addresses the allocation

of the labor costs.

A. General Instruction 9 requires public utilities to distribute employee pay and

expenses chargeable to maintenance and operations based on the actual time spent

on such work. General Instruction No. 9 also allows a public utility to conduct a

study based on the actual time spent during a representative period, if it is

impracticable to track the actual time spent on projects.

Q. Have you reviewed EPRS’s O&M costs in the EPRS rate filing?

A. Yes. I have examined the labor and non-labor O&M costs and the allocation

methods used in preparing Statement AH of the EPRS rate filing. I also reviewed

the testimonies and exhibits of Mr. Ralph Jones, Ms. Linda Okowita, and Mr.

Steven Garwood.

Q. Do you believe EPRS accounting for the O&M costs included in its rate filing

is consistent with the Commission’s accounting regulations?

A. Yes. As mentioned earlier, EPRS used the Commission’s accounting regulation as

a guide in preparing its rate filing. EPRS rate filing showed the O&M costs incurred

to comply with mandatory reliability standards in FERC accounts 561.1, 561.2,

561.5, 561.6, 568, 569, 569.1 through 569.4, 570, and 573. I believe EPRS’s

accounting methodology used to prepare its rate filing is consistent with the

Commission’s accounting regulations, although EPRS is not required to follow

such regulations due to the accounting waiver it received from the Commission.

Q. Do you believe the method EPRS used to allocate labor costs is consistent with

the Commission’s accounting regulations?


A. Yes. It is my understanding that EPRS used in its rate filing, a two-step method to

distribute certain employees’ labor costs to the FERC transmission operations and

maintenance accounts. The first step of the allocation method entailed conducting

surveys of employees that worked on the EPRS Transmission Facilities to ascertain

the amount of time they spent working on these facilities. The second step involved

devising an annual labor time cost amount for the same employees, using wage and

salary data. The Commission prescribes two methods of allocating labor costs to

maintenance and operations projects that would be consistent with General

Instruction 9. One method is to allocate labor costs to maintenance and operations

projects based on the actual time the employee performed such work. The second

method is to determine the labor cost allocable to maintenance and operations

projects by conducting a study, based on the actual time for a representative period,

if it is impracticable to follow the first method described above. Since EPRS’s time

reporting system did not allow tracking of employee labor costs by functional

categories such as transmission, generation, and distribution, EPRS conducted a

study to support the labor costs included in its rate filing. I concluded that the study

used to develop the allocation method for the labor cost included in EPRS rate

filing, and as further described in the testimonies of Mr. Ralph Jones and Ms. Linda

Okowita, is consistent with the requirements of General Instruction 9.

Q: What is the appropriate accounting classification under the Commission’s

accounting regulations associated with the labor costs of compliance and IT

professionals (i.e., professionals) responsible for compliance with mandatory

reliability standards?


A: Transmission-related labor and expenses should be recorded in the functional

transmission operating accounts. More specifically, the transmission operating

costs incurred to comply with mandatory reliability standards should be considered

the costs needed to operate a reliable transmission system. The Commission’s

accounting regulations provide several accounts in the Account 561 category to

capture transmission operating costs to comply with mandatory reliability

standards. Based on the duties and responsibilities of these professionals, the

transmission operating cost was incurred to ensure the safe and reliable operation

of the transmission system. In my view, Accounts 561.1, 561.2 and 561.5 are the

appropriate accounts to book transmission operating costs to comply with

mandatory reliability standards. I believe compliance is contemplated in the text

of each of these accounts whether stated or implied because the Commission

mandates that public utilities to “operate” reliably through the issuance of

mandatory reliability standards.

III. CONCLUSION

Q. Please summarize your testimony.

A. The Commission’s accounting regulations contained in 18 C.F.R. Part 101

provide the instructions for the appropriate accounting for labor and non-labor

O&M costs related to maintenance and operations projects. These same

regulations also prescribe two methods of allocating the pay and expenses of

employees to maintenance and operations projects. EPRS’s accounting and


allocation methodologies used in its rate filing for labor and non-labor O&M costs

follows the Commission’s accounting regulations.

Q. Does this conclude your direct testimony?

A. Yes, it does.


Exhibit EPRS-5 Clean Tariff Sheet for Attachment H-23

ATTACHMENT H-23

Annual Transmission Rates – Essential Power Rock Springs, LLC

for Network Integration Transmission Service in the PECO Zone

1. The annual transmission revenue requirement of Essential Power Rock Springs LLC is

$1,089,401, which will be allocated and invoiced by PJM on a monthly basis to customers taking

Network Integration Transmission Service in the PECO zone on the basis of each customer’s

respective monthly Network Service Peak Load ratio share.

2. The rate in (1) shall be effective until amended by Essential Power Rock Springs LLC or

modified by the Commission.

Exhibit EPRS-6 Marked Tariff Sheet for Attachment H-23

ATTACHMENT H-23

Annual Transmission Rates – Essential Power Rock Springs, LLC

for Network Integration Transmission Service in the PECO Zone

1. The annual transmission revenue requirement of Essential Power Rock Springs LLC is

$1,089,401, $224,031, which will be allocated and invoiced by PJM on a monthly basis to

customers taking Network Integration Transmission Service in the PECO zone on the basis of

each customer’s respective monthly Network Service Peak Load ratio share.

2. The rate in (1) shall be effective until amended by Essential Power Rock Springs LLC or

modified by the Commission.

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