AIR EMISSION PERMIT NO. 16300087- 004 IS ISSUED TO Cogentrix
Troutman Sanders LLP 401 9th Street, N.W., Suite 1000 ... · (“Cogentrix Nautilus”), which is...
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Troutman Sanders LLP 401 9th Street, N.W., Suite 1000 Washington, DC 20004-2134
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Christopher R. Jones
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).
Federal Energy Regulatory Commission
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I. COMMUNICATIONS
All communications and service related to this filing should be directed to the following
persons:
Christopher R. Jones
Miles H. Kiger
TROUTMAN SANDERS LLP
401 9th Street, N.W.
Suite 1000
Washington, DC 20004
(202) 662-2181
Christopher P. Sherman
Vice President, Regulatory Affairs
Cogentrix Energy Power Management, LLC
3 Mill Street
Arlington, MA
(781) 643-0607
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).
Federal Energy Regulatory Commission
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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.
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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).
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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”).
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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).
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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).
Federal Energy Regulatory Commission
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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/.
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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).
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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.
Federal Energy Regulatory Commission
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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
Christopher R. Jones
TROUTMAN SANDERS LLP
401 9th Street, N.W.
Suite 1000
Washington, DC 20004
(202) 662-2181
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
Exhibit No. EPRS-1 Page 2 of 14
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
Exhibit No. EPRS-1 Page 3 of 14
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
Exhibit No. EPRS-1 Page 4 of 14
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
Exhibit No. EPRS-1 Page 5 of 14
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.
Exhibit No. EPRS-1 Page 6 of 14
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
Exhibit No. EPRS-1 Page 7 of 14
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
Exhibit No. EPRS-1 Page 8 of 14
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
Exhibit No. EPRS-1 Page 9 of 14
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
Exhibit No. EPRS-1 Page 10 of 14
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.
Exhibit No. EPRS-1 Page 11 of 14
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
Exhibit No. EPRS-1 Page 12 of 14
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
Exhibit No. EPRS-1 Page 13 of 14
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
Exhibit No. EPRS-1 Page 14 of 14
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
Exhibit EPRS-SSG-1Page 2 of 13
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)
Exhibit EPRS-SSG-1Page 3 of 13
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
Exhibit EPRS-SSG-1Page 4 of 13
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
Hampshire Transmission, LLC
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
Hampshire Transmission, LLC
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
Exhibit EPRS-SSG-1Page 5 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 6
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
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
Exhibit EPRS-SSG-1Page 6 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 7
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
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
Exhibit EPRS-SSG-1Page 7 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 8
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
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
Exhibit EPRS-SSG-1Page 8 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 9
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
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
Exhibit EPRS-SSG-1Page 9 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 10
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
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
Exhibit EPRS-SSG-1Page 10 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 11
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
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
Central Maine Power Company
May 2000 Casco Bay / MIS Interconnection Agreement
No - Participated in Settlement
Proceedings
Exhibit EPRS-SSG-1Page 11 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 12
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
FERC ER00-2006 Central Maine Power Company
S.D. Warren Mar. 2000 S.D. WarrenInterconnectionAgreement
No - Participated in Settlement
Proceedings
FERC ER00-982 Central Maine Power Company
Central Maine Power Company
Dec. 1999 Transmission Rate Proceeding
Yes
FERC ER00-604 Central Maine Power Company
Central Maine Power Company
Nov. 1999 Gorbell/Thermal Interconnection Agreement
No
FERC ER99-878 Central Maine Power Company
Central Maine Power Company
Dec. 1998 Androscoggin Energy Center, LLC Interconnection Agreement
No - Participated in Settlement Proceeding
ME MPUC98-058 Central Maine Power Company
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
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
Exhibit EPRS-SSG-1Page 12 of 13
Summary of Regulatory, Industry Restructuring & Strategic Management
Experience for Steven S. Garwood
Page | 13
JURISDICTION CASE OR
DOCKET NO. UTILITY/ORGANIZATION INITIATING PROCEEDING CLIENT
APPROXIMATE DATE SUBJECT MATTER
PRESENTED TESTIMONY OREXPERT REPORT
ME MPUC 92-315 Central Maine Power Company
Central Maine Power Company
1992-1994 Backup and Standby Service for Generators Yes
ME MPUC 92-315 Maine Public Utilities Commission
Central Maine Power Company
1992 -1994 Resource Planning, Rate Restructuring, Avoided Cost Investigation, Marginal Cost Study
Yes
ME MPUC 92-345 Maine Public Utilities Commission
Central Maine Power Company
1992-1994 Retail Rate Proceeding Yes
Exhibit EPRS-SSG-1Page 13 of 13
Exhibit No. EPRS-SSG-2
Exhibit No. EPRS-SSG-2
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.
Exhibit No. EPRS-SSG-2
Page 2 of 8
Essential Power Rock Springs, LLC PERIOD I
Operation and Maintenance Expenses STATEMENT AH
Twelve Months Ended October 31, 2018 Page 2 of 2
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$
Exhibit No. EPRS-SSG-2
Page 3 of 8
Essential Power Rock Springs, LLC Period I
Wages & Salaries Statement AI
Twelve Months Ended October 31, 2018 Page 1 of 1
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
Exhibit No. EPRS-SSG-2
Page 4 of 8
Essential Power Rock Springs, LLC PERIOD I
Customer Rate Groups - FERC Jurisdictional STATEMENT BA
Twelve Months Ended October 31, 2018 Page 1 of 1
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.
Exhibit No. EPRS-SSG-2
Page 5 of 8
Essential Power Rock Springs, LLC PERIOD I
Present and Proposed Revenues STATEMENT BG & BH
Twelve Months Ended October 31, 2018 Page 1 of 1
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 $224,031 (see Essential Power Rock Springs, LLC , Transmission Rate Compliance Filing to
Implement Corporate Tax Rate Change, Docket No. ER18-1566-000 (May 10, 2018)). On November 15, 2018, the Commission accepted EPRS’s proposed revision to Attachment H-23, effective June 1, 2018 (see Alcoa Power Generating
Inc.―Long Sault Division et al. , 165 FERC ¶ 61,094 (2018)).
Exhibit No. EPRS-SSG-2
Page 6 of 8
Essential Power Rock Springs, LLC Period I
Summary Data Tables Statement BJ
Twelve Months Ended October 31, 2018 Page 1 of 1
Function/ Unadjusted1
Adjusted1
Statement Description Sub-function Amount Amount
AH Operating & Maintenance Expenses Production NA NA
Transmission 947,019$ 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
Exhibit No. EPRS-SSG-2
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
Exhibit No. EPRS-SSG-2
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
Exhibit No. EPRS-SSG-3
Exhibit No. EPRS-SSG-3
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
Exhibit No. EPRS-SSG-4
Exhibit No. EPRS-SSG-4
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
Exhibit No. EPRS-2 Page 1 of 23
UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
EP Rock Springs, LLC ) Docket No. ER19-___-000
PREPARED DIRECT TESTIMONY AND EXHIBITS OF
RALPH JONES
I. INTRODUCTION
Q. Please state your name and business address.
A. My name is Ralph Jones. My business address is 1423 Rock Spring Road, Rising
Sun, MD 21911.
Q. By whom are you employed and in what capacity?
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.
Q. Please outline your formal education.
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?
Exhibit No. EPRS-2 Page 2 of 23
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).
Q. Please briefly describe your professional experience.
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.
Q. What is the purpose of your testimony?
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
Exhibit No. EPRS-2 Page 3 of 23
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
Exhibit No. EPRS-2 Page 4 of 23
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.
Exhibit No. EPRS-2 Page 5 of 23
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.
Exhibit No. EPRS-2 Page 6 of 23
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
Exhibit No. EPRS-2 Page 7 of 23
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
Exhibit No. EPRS-2 Page 8 of 23
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
Exhibit No. EPRS-2 Page 9 of 23
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.
Exhibit No. EPRS-2 Page 10 of 23
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
Exhibit No. EPRS-2 Page 11 of 23
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
EPRS Transmission Facilities?
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
Exhibit No. EPRS-2 Page 12 of 23
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.
Exhibit No. EPRS-2 Page 13 of 23
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.
Exhibit No. EPRS-2 Page 14 of 23
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
EPRS Transmission Facilities?
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
Exhibit No. EPRS-2 Page 15 of 23
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
Exhibit No. EPRS-2 Page 16 of 23
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
Exhibit No. EPRS-2 Page 17 of 23
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.
Exhibit No. EPRS-2 Page 18 of 23
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
Exhibit No. EPRS-2 Page 19 of 23
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,
Exhibit No. EPRS-2 Page 20 of 23
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.
Exhibit No. EPRS-2 Page 21 of 23
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
Exhibit No. EPRS-2 Page 22 of 23
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.
Exhibit No. EPRS-2 Page 23 of 23
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
EPRS Transmission Facilities?
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.
Q. Does this conclude your testimony at this time?
A. Yes, it does.
[Next page is signature page.]
Exhibit No. EPRS-3 Prepared Direct Testimony of Ms. Linda Okowita
Exhibit No. EPRS-3 Page 1 of 5
UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
EP Rock Springs, LLC ) Docket No. ER19-___-000
PREPARED DIRECT TESTIMONY AND EXHIBITS OF
LINDA OKOWITA
I. INTRODUCTION
Q. Please state your name and business address.
A. My name is Linda Okowita. My business address is 13860 Ballantyne Corporate
Place, Suite 300, Charlotte, NC 28277.
Q. By whom are you employed and in what capacity?
A. I am employed by Cogentrix Energy Power Management, LLC as the Senior Vice
President, Human Resources.
Q. Please outline your formal education.
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”).
Q. Please briefly describe your professional experience.
A. I possess over 30 years of experience in various human resource functions.
Exhibit No. EPRS-3 Page 2 of 5
Q. What is the purpose of your testimony?
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
Exhibit No. EPRS-3 Page 3 of 5
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.
Exhibit No. EPRS-3 Page 4 of 5
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).
Exhibit No. EPRS-3 Page 5 of 5
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.
Q. Does this conclude your testimony at this time?
A. Yes, it does.
[Next page is signature page.]
Exhibit No. EPRS-4 Prepared Direct Testimony of Mr. Bryan Craig
Exhibit No. EPRS-4 Page 1 of 8
UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
EP Rock Springs, LLC ) Docket No. ER19-___-000
PREPARED DIRECT TESTIMONY AND EXHIBITS OF
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
Exhibit No. EPRS-4 Page 2 of 8
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.
Q. What is the purpose of your testimony?
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
Exhibit No. EPRS-4 Page 3 of 8
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.
Exhibit No. EPRS-4 Page 4 of 8
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.
Exhibit No. EPRS-4 Page 5 of 8
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?
Exhibit No. EPRS-4 Page 6 of 8
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?
Exhibit No. EPRS-4 Page 7 of 8
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
Exhibit No. EPRS-4 Page 8 of 8
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.
[Next page is signature page.]
Exhibit EPRS-5 Clean Tariff Sheet for Attachment H-23
Page 1
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
Page 1
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.