City of Minden vs. SWEPCO

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UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

EL18-__-000

COMPLAINT OF THE CITY OF MINDEN, LOUISIANA

Honorable Mayor Tommy Davis City of Minden, Louisiana 520 Broadway Avenue Minden, Louisiana Phone: (318) 377-2144 Email: mayor@mindenusa.com Email: mindenpwks@gmail.com

Kirk Howard Betts Jill M. Barker Mary-Kate Rigney Betts & Holt LLP 1100 17th Street, N.W. Suite 901 Washington, D.C. 20005 Phone: 202-530-3380 Facsimile: 202-530-3389 Email: kbetts@bettsandholt.com Email: jmb@bettsandholt.com Email: mkrigney@bettsandholt.com Counsel for the City of Minden, Louisiana

Dated: February 28, 2018

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TABLE OF CONTENTS I.

COMMUNICATIONS ......................................................................................................... 2

II. PARTIES ............................................................................................................................... 3 III. BACKGROUND ................................................................................................................... 4 A.

Power Supply Agreement ................................................................................................. 4

B. Transmission Arrangements and Related FERC Proceeding Involving Minden’s Congestion Charges .................................................................................................................. 9 Related Proceedings in which SWEPCO’s or its Sister Company’s ROE is at Issue ……………………………………………………………………………………………13

C.

D. Wind Catcher Energy Connection Project and SWEPCO’s Right to Collect Stranded Costs Under the PSA .............................................................................................. 15 IV. COMPLAINT ...................................................................................................................... 18 SWEPCO’S Current ROE is Unjust and Unreasonable ............................................. 18

A.

1.

Based Upon Minden’s Prima Facie Evidence, the Commission Should Set for Hearing the Issue of Whether SWEPCO’s Existing ROE is Unjust and Unreasonable ..... ..18 2.

Minden’s ROE Analysis Demonstrates that SWEPCO’s Current ROE Produces Unjust and Unreasonable Rates and that a Just and Reasonable ROE is No Higher than 8.20%……………………………………………………………………………………….22 3.

After Issuing an Order Finding that the Existing ROE is Unjust and Unreasonable,

the Commission Should Issue an Order Summarily Reducing SWEPCO’s ROE to a Just and Reasonable Level or Set the Determination of SWEPCO’s Just and Reasonable ROE for an Evidentiary Hearing.................................................................................................... 27 4.

The Commission Should Establish the Earliest Possible Refund Date ...................... 27

B. SWEPCO Violates the PSA and Possibly the Public Interest by Failing to Effectively Hedge Minden’s Congestion Charges Through the MISO ................................................. 28 1.

FERC Should Enforce the “Agency” and “Implementation” Provisions of the PSA by Requiring SWEPCO to Effectively Hedge Minden’s Congestion Risk ............................... 29 i.

Minden Experiences Substantial Cost and Risk from SWEPCO’s Failure to Hedge MISO Congestion Charges Effectively ............................................................................. 29

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ii.

The PSA Requires SWEPCO to Effectively Hedge MISO Congestion Charges for Minden .............................................................................................................................. 32 2.

In the Alternative, if FERC Does Not Mandate SWEPCO to Conduct the Effective Congestion Hedging Strategy then the PSA Should be Terminated as Contrary to the Public Interest................................................................................................................................... 34 C. Unjust, Unreasonable, and Discriminatory Provisions of the PSA Should be Amended .................................................................................................................................. 37 1.

The Formula Rate Should be Amended to Address “Excess” Accumulated Deferred Income Tax Arising from the Changed Federal Corporate Tax Rate ................................... 37 2.

SWEPCO Should Be Required to Update its Depreciation Study and the PSA Should Be Amended to Base Depreciation Expense on a Wholesale Depreciation Study ............... 38 3.

SWEPCO Should Stop Double Collection of Depreciation Expense on Contra AFUDC and Refund Any Amounts Collected in Prior Periods ........................................... 39 4.

The PSA Should be Amended to Offset Rate Base for Unfunded Reserves .............. 40

5.

SWEPCO Should Exclude Non-Production Related CWIP from Rate Base and Refund Any Amounts Collected in Prior Periods ................................................................. 41 6.

A Set of Protocols Should be Inserted to Guide the Parties’ Annual Review of the Formula Rate in Accordance with Current FERC Guidance ................................................ 41 7.

The Projected Excess Capacity Associated with the Planned Wind Catcher Project Renders the PSA’s Lopsided Stranded Cost Obligation Unjust and Unreasonable; the PSA Should be Amended to Ensure that Minden is Never Required to Pay a Termination Payment for Excess Capacity Installed During the PSA’s Term .......................................... 42 8.

In These Circumstances, the PSA’s Prohibition on Minden’s Right to File a Price Squeeze Case is Contrary to the Public Interest and Should Be Changed............................ 45 V.

OTHER RULE 206 INFORMATION .............................................................................. 46 A.

Good Faith Estimate of Financial Impact or Harm (Rule 206(b)(4)) ........................ 46

B.

Operational or Nonfinancial Impacts (Rule 206(b)(5)) ............................................... 47

C.

Specific Relief or Remedy Requested (Rule 206(b)(7)) ............................................... 47

D.

Documents Supporting Complaint (Rule 206(b)(8)) .................................................... 49

E.

Alternative Dispute Resolution (Rule 206(b)(9)) .......................................................... 49

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VI. SERVICE AND NOTICE .................................................................................................. 50 CONCLUSION AND REQUEST FOR RELIEF .................................................................... 50 ATTACHMENT A: FORM OF NOTICE CERTIFICATE OF SERVICE

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LIST OF EXHIBITS Exhibit No.

Description

PARCELL-1

Direct Testimony of David C. Parcell

PARCELL-2

Qualifications of David C. Parcell

PARCELL-3

Economic and Financial Indicators

PARCELL-4

Selection of Proxy Group Members

PARCELL-5

Dividend Yields

PARCELL-6

DCF Cost Rates for Proxy Group Members

PARCELL-7

Long-Term Growth Rates of Gross Domestic Product

PARCELL-8

Workpapers Supporting Direct Testimony of David C. Parcell

SLATER-1

Direct Testimony of Michele M. Slater

SLATER-2

Qualifications of Michele M. Slater

SLATER-3

Depreciation Double Collection Issue

SUHANIC-1

Direct Testimony of Kevin P. Suhanic

SUHANIC-2

Qualifications of Kevin P. Suhanic

SUHANIC-3

ACES’s Analysis of Minden Hedging Strategies

SUHANIC-4

Form of Transaction Specification Sheet for Network Integration Transmission Service Between MISO and AEP for Service to Minden, May 31, 2013

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UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Minden, Louisiana, Complainant

) ) ) ) ) ) )

v.

Southwestern Electric Power Company Respondent

Docket No.

EL18-__-000

COMPLAINT OF THE CITY OF MINDEN, LOUISIANA Pursuant to Sections 206, 306, and 309 of the Federal Power Act (“Section 206,” “Section 306,” and “Section 309”)1 and Rules 206 and 212 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission (“Commission” or “FERC”),2 the City of Minden, Louisiana (“Minden”) hereby files this complaint (“Complaint”) against Southwestern Electric Power Company (“SWEPCO”) regarding the Power Supply Agreement (“PSA”), FERC Rate Schedule No. 128, between them. Minden seeks one or more Commission orders summarily finding that: (a) pursuant to Section 206 that the current return on equity (“ROE”) of 11.1% used in calculating SWEPCO’s formula rate for power supply service to Minden is unjust and unreasonable and setting a new just and reasonable ROE no higher than 8.20%; (b) pursuant to Sections 206, 306, and 309 certain contract terms in the PSA are unjust and unreasonable or contrary to the public interest and issuing an order amending the PSA to correct these flawed provisions; and (c) pursuant to Sections 306 and 309, issuing an order enforcing the PSA’s requirement that SWEPCO implement the effective hedging strategy for congestion charges for transmission service to Minden from SWEPCO’s location in the Southwest Power Pool (“SPP”) 1 2

16 U.S.C. §§ 824e, 825e, 825h (2018).

18 C.F.R. §§ 385.206, 385.212 (2018).

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to Minden’s location in Entergy, Louisiana, LLC’s (“Entergy”) service area which is now part of the Midcontinent Independent System Operator, Inc. (“MISO”) and (d) in the alternative, pursuant to Sections 206, 306 and 309, if the PSA does not require SWEPCO to implement the effective congestion hedging strategy, that the PSA contravenes the public interest and should be terminated.

Alternatively, Minden requests that the Commission set the Complaint for investigation and evidentiary hearing; establish the Complaint’s filing date as the refund effective date for relief to be afforded in response to this Complaint; and order refunds, with interest at Commissionapproved rates, for the difference in rates calculated using the current ROE and the ROE resulting from this Complaint, and for the difference in rates calculated using the PSA and the Mindenrecommended PSA amendments.

The Complaint is supported by the Direct Testimony and Exhibits of David C. Parcell (“Parcell Direct Testimony”), Exhibit PARCELL-1 through PARCELL-8; the testimony of Michele M. Slater (“Slater Direct Testimony”), Exhibit SLATER-1 through SLATER-3; and the testimony of Kevin P. Suhanic (“Suhanic Direct Testimony”), Exhibit SUHANIC-1 through SUHANIC-4, all of which are appended to this Complaint.

COMPLAINT I.

COMMUNICATIONS All pleadings, correspondence and communications with Minden in this docket should be

addressed to the following individuals, whose names should be entered on the official service list for this proceeding.

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Honorable Mayor Tommy Davis City of Minden, Louisiana 520 Broadway Avenue Minden, Louisiana Phone: (318) 377-2144 Email: mayor@mindenusa.com Email: mindenpwks@gmail.com

Kirk Howard Betts Jill M. Barker Mary-Kate Rigney Betts & Holt LLP 1100 17th Street, N.W. Suite 901 Washington, D.C. 20005 Phone: 202-530-3380 Facsimile: 202-530-3389 Email: kbetts@bettsandholt.com Email: jmb@bettsandholt.com Email: mkrigney@bettsandholt.com

Minden respectfully requests a waiver of Rule 203(b)(3) of the Federal Energy Regulatory Commission’s Rules of Practice and Procedure, 18 C.F.R. § 385.203(b)(3) (2017), to permit inclusion of the additional persons on the Commission’s service list.

II.

PARTIES 1.

The City of Minden is a municipality located in Webster Parish, Louisiana. It

operates a municipal utility system for the benefit of its citizens under the laws of the state of Louisiana.3 Minden’s utility system recently retired its 25,000 kW of steam generation and continues to operate a distribution system that serves approximately 5,500 residential and commercial customers in the city. Minden’s current average annual peak for billing purposes is approximately 30,192 MW. Minden is interconnected with Entergy, a wholly owned subsidiary of Entergy Corporation. Minden entered into the PSA with SWEPCO with an effective date of January 1, 2009, and is a requirements customer thereunder.

2.

SWEPCO, a wholly owned subsidiary of American Electric Power Company, Inc.

(“AEP”), has its principle place of business at 428 Travis Street, Shreveport, Louisiana. SWEPCO owns and operates facilities for the generation, transmission, and distribution of electric power and

3

LA. Rev. Stat. Ann. § 45:121 (2017).

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energy in the States of Arkansas, Louisiana, and the SPP portion of Texas. SWEPCO is a member of SPP but is not a member of MISO. SWEPCO is Minden’s agent in arranging transmission service from SWEPCO in SPP through MISO to Minden.

III.

BACKGROUND A.

Power Supply Agreement

3.

Minden has received requirements service from SWEPCO since 1995. On October

14, 2008, Minden and SWEPCO entered a long-term formula rate power supply agreement (“Original Agreement”).4 FERC set the contract for hearing and settlement procedures5 to address certain elements of the formula rate, including fixing the ROE of 11.1% in the PSA, and the Parties reached a settlement that FERC approved.6 The PSA was further amended in 2014 to address changes compelled by the formation of SPP and MISO South.7 The PSA was last amended in June

4

Power Supply Agreement by and Between Southwestern Electric Power Company and City of City of Minden, Louisiana, FERC Docket No. ER09-86-000 (Oct. 16, 2008). This Original Agreement used a formula for determining the ROE “annually as the average of the December yields of the Moody’s Seasoned Baa Corporate Bond, as reported by the Federal Reserve in the H.15 statistical release plus 6.00%.” Id. 5 Southwestern Electric Power Company, 125 FERC ¶ 61,389 (2008).

6 Settlement Agreement, FERC Docket No. ER09-86-000 (Oct. 25, 2010). The Settlement Agreement had an effective date of January 1, 2009. FERC accepted the Settlement Agreement on April 29, 2011. Letter Order, Stipulation of Agreement, FERC Docket Nos. ER09-86-000, ER09-86-001 (Apr. 29, 2011). On July 5, 2011, FERC accepted the eTariff submission of the PSA with an effective date of January 1, 2009. Letter Order, Revised and Restated Power Supply Agreement, FERC Docket No. ER11-3562-000 (July 5, 2011).

7 Southwestern Electric Power Company, 49 FERC ¶ 61,118 (2014). In February 2014, SWEPCO filed the following changes to the PSA: the addition of § 3.10, pertaining to the “integrated market” charges of the Southwest Power Pool being passed along to Minden; the addition of § 5.04 covering NERC requirements; and, a revision to Exhibit C, reflecting retirement of Minden’s diesel generating units. Southwestern Electric Power Company Revised and Restated Power Supply Agreement, FERC Docket No. ER14-1307 (Feb. 11, 2014) (“PSA”).

In August 2014 the parties entered into a settlement agreement that was accepted by FERC on November 12, 2014. Letter Order, Approval of Settlement Agreement, FERC Docket No. ER141307-000 (Nov. 12, 2014).

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2017 in settlement of, among other things, MISO congestion charges dating from the time of the MISO wheel, December 19, 2013, through May 31, 2017.8 Pursuant to the PSA, SWEPCO supplies Minden with all of Minden’s capacity and energy requirements in excess of the allocated hydroelectric capacity and energy supplied by the Southwest Power Administration.9 4.

The PSA terminates in 2028 unless SWEPCO terminates early on three years’

notice.10 Minden enjoys no reciprocal early termination right. If either party alleges an Event of Default against the other, an Early Termination Date may be declared.11 An Event of Default occurs upon items such as failure to perform a material covenant, bankruptcy, or a merger with a financially unsound enterprise.12

The Non-Defaulting Party may suspend performance and

exercise any remedy, including the right to seek and recover direct damages in court, and SWEPCO has the right to seek recovery from Minden of “Stranded Costs in accordance with Section 35.26 of the FERC’s Regulations.”13 5.

SWEPCO is obligated to plan to serve Minden’s Retail Load. To facilitate this

planning, Minden must provide eight calendar years of forecasted load to SWEPCO on June 1 each year during the PSA term.14 Minden’s load has been declining.

6.

Under the PSA, the monthly demand charges are determined by multiplying the

monthly capacity rate by Minden’s billing demand.15 The capacity charges are calculated pursuant

8

FERC accepted the amendments by Letter Order in Docket No. ER17-1895-000 dated August 3, 2017. The parties’ settlement is further described in Section III. B., infra.

9 PSA § 3.01.

10 PSA §§ 2.02, 3.06.

11 PSA §§ 7.01, 7.02.

12 PSA § 7.01.

13 PSA § 7.03.

14 PSA § 2.03.

15 PSA Art. 4, Exhibit B-1.

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to a formula rate that the parties intended to be derived from SWEPCO’s actual system average annual cost of plant capacity investment and operating expenses, excluding energy-related variable costs, and costs of fuel used in SWEPCO’s generating plants.16 The source for the data used in the formula rate is SWEPCO’s FERC Form No. 1 (“FERC Form 1”). During each service year, SWEPCO bills Minden based upon an estimated Monthly Capacity Rate.17

An annual

reconciliation of estimated charges to actual charges occurs prior to May 31 of each Contract Year, and payments owed to or from Minden are billed or credited to Minden, with interest, in three equal installments during the months of July, August, and September.18 On October 1 of each Contract Year, SWEPCO re-determines Minden’s load share responsibility based upon SWEPCO’s system-wide peak demands for each summer month (June, July, August, and September) during such Contract Year and Minden’s contributions to such peak demands.19 7.

Calculating the demand charges (Annual Production Fixed Cost) requires

multiplying SWEPCO’s generation capacity rate base by the weighted cost of capital, which reflects its fixed 11.1% ROE.20 8.

The standard of review for party-initiated proceedings regarding ROE is the “just

and reasonable” standard.21 Although the PSA includes a binding arbitration provision, the parties are “entitled, at any time and from time to time, to apply for or to take other action to request a

16

PSA, Art. 4, Exhibit B. PSA § 4.04.

18 PSA § 4.13.

19 PSA § 4.13.

20 PSA Exhibit B pp 4, 5, 11.

21 PSA §§ 4.05, 4.13, Exhibit B p 11, Note F (“the Parties expressly agree that either Party shall have the right unilaterally to submit to FERC a rate filing that proposes that the 11.1% ROE be revised, and any such filing(s) shall be reviewed by FERC under the ‘just and reasonable’ standard of Sections 205 and/or 206 of the FPA.”).

17

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change to provisions of this Agreement under FPA Sections 205 or 206.”22 Certain items in the PSA, as pertinent to this Complaint, such as the Term and expiration date, and price squeeze may be successfully changed only by application of the “public interest standard” of review.23 9.

Minden expert Mr. Parcell performed a standard discounted cash flow (“DCF”)

analysis and concluded that under the Commission’s methodology the proper ROE for SWEPCO should be 8.20%.24 Minden expert Ms. Slater calculated that the impact to Minden of this adjustment is an annual rate reduction of $405,082 per year.25 10.

Minden expert Ms. Slater reviewed the PSA and recent annual true–up calculations

and identified the following problems and errors in the PSA for which Minden seeks amendment, if necessary, and/or enforcement of the PSA. a.

The recently enacted Tax Cuts and Jobs Act of 2017 (“Tax Act”) 26 creates “excess” accumulated deferred income taxes by reducing the federal corporate income tax rate to 21% from 35%, giving rise to a need for amendments to the PSA to flow these funds back to Minden.27

b.

SWEPCO has not updated its FERC depreciation study since 1983, and the depreciation rates are significantly higher than more recent depreciation studies approved for SWEPCO by state commissions, giving rise to a need for amendments to the PSA to require SWEPCO to update the depreciation

22

PSA §§ 15.02, 15.03.

PSA § 15.03 (a), (g).

24 Ex. PARCELL-1 at 12:1-5 (Parcell Affidavit).

25 Ex. SLATER-1 at 14:5-7 (Slater Affidavit).

26 Pub. L. No. 115-97 (2017).

27 Ex. SLATER-1 at 4:20-5:2 (Slater Affidavit).

23

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study; and for amendments to base the depreciation expense in the PSA upon only the FERC-jurisdictional depreciation study.28 c.

SWEPCO miscalculated depreciation expense on the allowance for funds used during construction (“AFUDC”) resulting in a double collection of depreciation expense by SWEPCO, giving rise to a need for enforcement of the PSA from its inception requiring SWEPCO to stop this erroneous practice.29

d.

SWEPCO incorrectly includes certain non-production related construction work in progress (“CWIP”), giving rise to a need for enforcement of the PSA from its inception requiring SWEPCO to exclude non-production related items from CWIP.30

e.

The PSA omits a rate base offset for “unfunded reserves” and thus the PSA fails to recognize customer-contributed capital, giving rise to a need for amendments to the PSA to provide the proper recognition.31

Ms. Slater calculates that the estimated impact to Minden of correcting these issues and problems in the PSA is an estimated $645,169, of which $405,082 relates to the ROE reduction recommended by Mr. Parcell.32 11.

In addition, although the PSA denotes a certain process regarding annual formula

rate updates,33 the PSA does not include any formal “protocols,” which has become common

28

Ex. SLATER-1 at 5:6-10 (Slater Affidavit).

Ex. SLATER-1 at 5:11-13 (Slater Affidavit).

30 Ex. SLATER-1 at 5:16-17 (Slater Affidavit).

31 Ex. SLATER-1 at 5:14-15 (Slater Affidavit).

32 Ex. SLATER-1 at 30: Table 2 (Slater Affidavit).

33 PSA§§ 4.13, 4.14.

29

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practice in Commission formula rates, giving rise to the need for PSA amendments to delineate further protocols. Specifically, the PSA does not include certain items that are recommended in FERC’s Staff guidance and other orders mandating minimum protocol standards, including: notice of changes in accounting standards; assurances of the reasonableness of projected costs; and workpapers that are transparently linked to FERC Form 1.34 B.

Transmission Arrangements and Related FERC Proceeding Involving Minden’s Congestion Charges

12.

The PSA provides that SWEPCO will act as Minden’s “agent” for transmission

service: [SWEPCO] shall arrange for Network Integration Transmission Service (NITS) for Customer’s Retail Load and shall be responsible during the Delivery Period for the provision of all such service. Customer shall be responsible for paying all NITS, related SPP and Entergy charges, and any other charges for the use of third-party transmission systems for the delivery of Requirements Service.

PSA § 3.02. The parties further agreed to certain provisions regarding “implementation” of transmission services, as follows: Company shall be the Market Participant that registers the [Minden] load and resources related to the Requirements Service with SPP; . . . . Company shall be responsible for all scheduling and settlement activities related to such load and resources. . . . Customer hereby gives permission to Company to access information Company reasonably requests to facilitate such settlement activities with SPP and the administration of this Agreement.

PSA § 5.01.

34

See FERC Staff Guidance on Formula Rate Updates (July 17, 2014); see also Empire Dist.

Elec. Co., 148 FERC ¶ 61,030 (2014) (Commission Order mandating minimum protocol standards); Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ¶ 61,127 (2012), order on investigation, 143 FERC ¶ 61,149 (2013) (“MISO Investigation Order”), order on reh’g, 146 FERC ¶ 61,209 (2014), order on compliance, 146 FERC ¶ 61,212 (2014) (“MISO Compliance Order”).

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13.

Minden is located geographically in the Entergy service area, and before Entergy

joined MISO, Minden reimbursed SWEPCO for both SPP transmission service and transmission service through Entergy pursuant to the PSA.35 When Entergy joined MISO, however, Minden’s wheel through Entergy became subject to the MISO rules and regulations. Around the time of the Entergy transfer to MISO-South, on May 31, 2013, American Electric Power Service Corporation (“AEPM”) entered into a Network Integration Transmission Service (“NITS”) agreement with MISO with a start date of December 19, 2013, to wheel capacity and energy from SPP through MISO to Minden. AEPM explained that the “nature” of the transmission service was a pseudotie.36 14.

Commencing with service on December 19, 2013, Minden’s invoices from

SWEPCO exhibited a marked increase in MISO transmission charges compared with the amounts previously invoiced for service through the Entergy geographic area, but the most dramatic increases occurred during the summer of 2016. Although congestion payments for this period of dramatic volatility were settled, Minden’s exposure to volatile congestion charges persists as of June 1, 2017, to today. Minden’s consultant, Mr. Suhanic, informed Minden in late 2016, and Minden informed SWEPCO, that a best practice hedging strategy for Minden would require: a) the nomination of Auction Revenue Rights (“ARRs”) for Minden; b) the conversion of the ARRs to Fixed Transmission Revenues (“FTRs”); and c) two daily virtual transactions for the amount of FTRs owned.37 Failure to perform this three-part hedge exposes Minden to extreme volatility,

35

PSA §§ 3.02, 5.01.

Ex. SUHANIC-4 at p 1, items 02, 05 (Form of Transaction Specification Sheet for NITS dated May 31, 2013) (“Providing Service to Minden, LA via pseudo-to [sic] to the CSWS balancing authority in the Southwest Power Pool . . . capacity and energy will be provided by AEPM via a pseudo-tie.”).

37 Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

36

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ranging from a cost of $372,000 per month to a benefit of $229,000 per month.38 These highs and lows constitute a “large” swing of 32% in Minden’s typical monthly bill from June 2016 to September 2016.39 15.

Minden and SWEPCO reached a settlement agreement on May 22, 2017, regarding

MISO transmission and congestion charges through May 31, 2017 (“Congestion Settlement”) incorporating steps a) and b) as recommended by Mr. Suhanic, but not step c). It provides, in part, as follows: 3.

The Customer congestion charges from the Midcontinent Independent System Operator (“MISO”) for the period from June 1, 2016 through May 31, 2017 shall be determined based on a calculation that assumes the Auction Revenue Rights (ARR”) in the MISO market were converted to Financial Transmission Rights (“FTR”) and priced according to the FTR auction for the relevant period. The resulting congestion charge will be invoiced to Customer, and Company will be responsible for any difference between the amount invoiced and the actual congestion cost imposed by MISO with respect to Customer. Any credits or charges for prior months back to June 1, 2016 will be included in the next monthly invoice.

4.

Customer agrees that the financial settlement provided for herein constitutes satisfaction and release of all claims by Customer related to the MISO market charges and the operation of the Minden Generation for the period prior to May 31, 2017.

SWEPCO-Minden PSA Amendment, FERC Docket No. ER17-1895-000, at Attachment C, p 1 (June 23, 2017).

16.

On September 15, 2017, in Docket No. EL17-89-000, AEP filed on behalf of

SWEPCO a formal complaint against MISO and SPP seeking to “put a stop to the assessment of duplicative congestion charges associated with SWEPCO loads that are pseudo-tied from MISO

38 39

Ex. SUHANIC-1 at 6:1-3 (Suhanic Affidavit).

Ex. SUHANIC-1 at 8:23-9:4 (Suhanic Affidavit).

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to SPP” and further alleging that Minden “faces unjust, unreasonable, and unduly discriminatory costs as a result of the congestion charges associated with its pseudo-tie arrangements.”40 MISO and SPP filed responsive pleadings answering the complaint and claiming that AEP and Minden “were (or should have been) aware of MISO’s pseudo-tie requirements when they chose to continue this arrangement in the MISO markets.”41 17.

Entergy also filed a protest to SWEPCO’s complaint in Docket No. EL17-89-000,

and in terms very similar to those recommended by Mr. Suhanic,42 pointed out the methods by which SWEPCO could have hedged Minden’s load to avoid unnecessarily high congestion charges. Entergy states as follows: AEP’s argument that MISO does not provide it with tools to hedge Minden’s congestion costs because AEP does not schedule for Minden in the Day-Ahead market is also without merit. When the Entergy Operating Companies integrated into MISO, AEP voluntarily elected to pseudo-tie the Minden load into SPP. AEP had (and has) other options that would have allowed Minden to hedge its congestion costs, including incorporating the load into the MISO market and scheduling imports of AEP generation resources into MISO. (This approach also might resolve AEP’s obligation under the 2014 PSA to schedule Minden’s 25 MW steam generation resource for the benefit of Minden. [fn omitted]) . . .Further, AEP does not appear to have considered using features of MISO’s markets that allow for hedging of Real-Time schedules in the Day-Ahead markets including the use of virtual schedules. [fn omitted] A virtual schedule allows a market participant to make a purchase or sale of energy in the MISO Day-Ahead market, “close out” the transaction in real time, and then pay the difference between the Day-Ahead and Real-Time settlements. If properly managed, the use of virtual schedules could have greatly reduced AEP’s exposure to Real-Time congestion charges. This, combined with the ARRs/FTRs allocated to AEP, could have further reduced all congestion charges owed to MISO for its Minden load. But AEP appears not to have availed itself of this feature of the MISO markets, or, at least, not accounted for this in its calculation of its alleged harm.

40

Formal Complaint of American Electric Power Service Corporation on Behalf of Southwestern Electric Power Company, Docket No. EL17-89-000, at p 1 (Sept. 15, 2017) (“SWEPCO Complaint”).

41 Answer of the Midcontinent Independent System Operator, Inc., Docket No. EL17-89-000, at p 11 (Oct. 12, 2017).

42 Ex. SUHANIC-1 at 6:14-18 (Suhanic Affidavit).

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Motion to Intervene and Protest of Entergy Services, Inc., Docket No. EL17-89-000, at pp 7-8 (Oct. 5, 2017) (“Entergy Protest”). The SWEPCO complaint in Docket No. EL17-89-000 is pending before this Commission.

18.

SWEPCO has continued the practices it agreed to in the Congestion Settlement but

has not adopted the effective hedging strategy for mitigating congestion costs—step c): the two daily virtual transactions for the amount of FTRs owned.43 According to Mr. Suhanic, this rejection of step c) imposes on Minden the ever-present risk that congestion charges could run as high as $372,000 per month.44 As he testifies, in the months from June to September 2016, this represented the potential for a monthly swing by up to 32%.45 Even though the load has changed, the volatility risk remains.46 Such volatility imposes financial hardships, such as carrying large capital reserves, for a this small budget-driven municipal utility. In addition, SWEPCO’s refusal to perform the effective congestion hedging strategy deprives Minden of any value from its payment of MISO congestion charges.47 C.

Related Proceedings in which SWEPCO’s or its Sister Company’s ROE is at Issue

19.

Two recent complaints have challenged SWEPCO’s ROE. On June 5, 2017, East

Texas Electric Cooperative, Inc. (“ETEC”) filed a complaint in Docket No. EL17-76-000 against Public Service Company of Oklahoma (“PSO”), SWEPCO, AEP Oklahoma Transmission Company, and AEP Southwestern Transmission Company (collectively “AEP West Companies”)

43

Ex. SUHANIC-1 at 6:1-5 (Suhanic Affidavit).

Ex. SUHANIC-1 at 6:1-3 (Suhanic Affidavit); Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategy).

45 Ex. SUHANIC-1 at 8:23-9:4 (Suhanic Affidavit).

46 Ex. SUHANIC-1 at 6:9-13 (Suhanic Affidavit).

47 Ex. SUHANIC-1 at 7:18-8:2 (Suhanic Affidavit).

44

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challenging the 10.70% ROE as unjust and unreasonable.48 The Complainants asserted that the AEP West Companies’ ROE should be no higher than 8.36%. Additionally, on August 31, 2017, ETEC and North Texas Electric Cooperative, Inc. filed a complaint in Docket No. EL17-85-000 against SWEPCO.49 These customers argued that the 11.1% ROE used in their PSAs was no longer just and reasonable. Instead, the customers asserted that the just and reasonable ROE was 8.41%.

20.

American Municipal Power, Inc., Blue Ridge Power Agency, Craig-Botetourt

Electric Cooperative, Indiana Michigan Municipal Distributors Association, Indiana Municipal Power Agency, Old Dominion Electric Cooperative, and Wabash Valley Power Association, Inc. filed a complaint in Docket No. EL17-13-000 on October 27, 2016, challenging as unjust and unreasonable the 10.99% ROE used in the transmission formula rates of specific AEP operating and transmission companies servicing load in the “eastern” part of AEP’s system. 50 These customers aver that the correct ROE for these specific AEP East Companies is 8.32%. Although SWEPCO is a subsidiary of AEP, SWEPCO is not among the named respondents in this complaint.

21.

Minden does not desire to consolidate this Complaint with Docket Nos. EL17-13-

000, EL17-76-000, or EL17-85-000, but asks this Commission to take notice that with the filing of this Complaint, four cases will be pending before the Commission asserting that the ROE for SWEPCO and its parent company are unjust and unreasonable.

48

Complaint of East Texas Electric Cooperative, Inc., Docket No. EL17-76-000 (June 5, 2017).

Complaint of East Texas Electric Cooperative, Inc. and Northeast Texas Electric Cooperative, Inc., Docket No. EL17-85-000 (Aug. 31, 2017).

50 Joint Complaint of American Municipal Power, Inc., Docket No. EL17-13-000 (Oct. 27, 2016).

49

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D.

Wind Catcher Energy Connection Project and SWEPCO’s Right to Collect Stranded Costs Under the PSA

22.

On July 31, 2017, SWEPCO submitted an application with the Louisiana Public

Service Commission (“LPSC”) to approve its acquisition and construction of the Wind Catcher Energy Connection Project (“Wind Catcher Project”).51 The Wind Catcher Project consists of a 2,000 MW nameplate (1,900 MW delivered) wind farm (“Wind Facility”) in the Oklahoma Panhandle and a 350 to 380 mile 765 kV dedicated generation tie line (“Gen-Tie Line”).52 The Gen-Tie line will traverse Oklahoma and connect the Wind Facility to the AEP SPP load zone in Tulsa, Oklahoma.53 23.

The Wind Catcher Project will be jointly owned by SWEPCO and its affiliate

Public Service of Oklahoma (“PSO”) at 70 percent and 30 percent respectively.54 The total estimated cost of the Wind Catcher Project is $4.526 billion, with SWEPCO’s share totaling $3.168 billion.55 SWEPCO will own 1,400 MW nameplate (1,330 MW delivered) of wind capacity at a cost of $2.031 billion.56 SWEPCO’s share for the Gen-Tie line is $1.137 billion.57 24.

SWEPCO states that the Wind Catcher Project will provide significant cost savings

to its customers. In particular, SWEPCO claims that capturing the full value of Federal Production

51

Application of Southwestern Electric Power Company (SWEPCO) for Expedited Certification and Approval of the Acquisition of Certain Renewable Resources and the Construction of a Generation Tie Pursuant to the 1983 and/or 1984 General Orders, Docket No. U-34619 (July 31, 2017) (“SWEPCO LPSC Application”). SWEPCO and its affiliate Public Service Company of Oklahoma (“PSO”) also submitted applications for approval of the Wind Catcher Project in Oklahoma, Arkansas, and Texas.

52 SWEPCO LPSC Application, at pp 1-2.

53 SWEPCO LPSC Application, at p 2.

54 SWEPCO LPSC Application, at p 5.

55 SWEPCO LPSC Application, at T. Brice Testimony, 12:1-9.

56 SWEPCO LPSC Application, at T. Brice Testimony, 9:5-9, 12:1-9.

57 SWEPCO LPSC Application, at T. Brice Testimony, 12:1-9.

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Tax Credits (“PTCs”) will benefit Louisiana ratepayers.58 To be eligible for the full value of PTCs, the Wind Catcher Project must be in commercial operation prior to January 1, 2021.59 SWEPCO projects that construction for the Wind Catcher Project will be completed by December 2020.60 As such, SWEPCO has requested LPSC approval of the Wind Catcher Project by April 30, 2018.61 25.

Significant concern about the potential excess capacity created by the Wind Catcher

Project was expressed by the LPSC Staff in filed testimony: Q. HAS SWEPCO SHOWN A SPECIFIC CAPACITY NEED FOR THE PROJECT? A. No. SWEPCO completed an IRP [Integrated Resource Plan] in Louisiana in 2016, which contained a preferred portfolio of resources and a preferred plan of how to achieve that portfolio (the “Preferred Plan”). The Preferred Plan’s Capacity, Demand and Reserves Forecast for 2021 showed Total Capability of 5,172 MW and a corresponding 18.9% reserve margin compared to the SPP required 12% Reserve Margin. From 2021 through 2034 the Preferred Plan’s Reserve Margin never drops below 15.0%. In comparison, in response to Staff Data Request 1-25 the Company provided a Capability, Demand and Reserves Forecast”, which shows a Base Case Reserve Margin (i.e. without the [Wind Catcher] Project) of 21.7% in 2021 (5,076 MW Total Capability.). [footnote omitted] This Base Case Reserve Margin falls no lower than 12.4% for the entire period covered by the IRP. [footnote omitted] Importantly, both the IRP Preferred Plan and the Base Case illustrate that without this [Wind Catcher] Project, there is no immediate need for capacity.

Direct Testimony of R. Lane Sisung on Behalf of the Staff of the Louisiana Public Service Commission, LPSC Docket No. U-34619, at 14:3-15:10 (Jan. 22, 2018). Additionally, the Administrative Law Judge reviewing PSO’s application for the Wind Catcher Project at the Oklahoma Corporation Commission determined that the Wind Catcher Project was “not

58

SWEPCO LPSC Application, at p 13.

SWEPCO LPSC Application, at Chodak Testimony, 11:17-12:1.

60 SWEPCO LPSC Application, at p 4.

61 SWEPCO LPSC Application, at pp 2-3. SWEPCO and PSO have also requested expedited approval of the Wind Catcher Project at the Arkansas, Oklahoma, and Texas state commissions.

Id. at p 3.

59

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needed to supply capacity for meeting future demands, renewable energy goals, or any future regulations of carbon emissions.”62 26.

On December 21, 2017, SWEPCO filed with the Commission revisions of its PSAs

with the Hope Water and Light Commission (“Hope”) and City of Bentonville, Arkansas (“Bentonville”) to incorporate the Wind Catcher Project costs in their contracts.63 SWEPCO proposed amendments to the Hope and Bentonville PSAs to: 1) include Gen-Tie line costs in the formula rates; 2) recover ARO balances for renewable wind projects; 3) establish regulatory liability to defer a portion of the value of the PTCs from 2024 to 2030; 4) include FERC Account 456 (Other Electric Revenues) in the formula rate; and 5) modify the formula rate to increase Hope and Bentonville’s Current Customer Share of Off-System Sales for Resale Margins to 90 percent.64 SWEPCO’s filing, however, proposes no changes in the Hope and Bentonville PSAs to protect either municipality from excessive Stranded Cost payments in the event that the Wind Catcher Project results in excess capacity on SWEPCO’s system. The current PSAs provide no prohibition, relief, or other protection against constructing and passing through the high costs of excess capacity or the legacy costs of expensive generation (Turk) and improvements to other fossil fuel generating stations where expensive environmental improvements have been made during the most

62

Report and Recommendation of the Administrative Law Judge, Cause No. PUD 201700267, at p 13 (Feb. 12, 2018).

63 Amended and Restated Power Supply Agreement Between Southwestern Electric Power Company and Hope Water and Light Commission, Docket No. ER18-499-000 (Dec. 21, 2017) (“Hope Amended PSA”); Amended and Restated Power Supply Agreement Between Southwestern Electric Power Company and City of Bentonville, Arkansas, Docket No. ER18500-000 (Dec. 21, 2017) (“Bentonville Amended PSA”).

64 Hope Amended PSA, Transmittal Letter at pp 4-6; Bentonville Amended PSA, Transmittal Letter at pp 4-6 (Dec. 21, 2017); see also Southwestern Electric Power Company Request to Defer Action in Hope PSA Amendment, Docket No. ER18-499-000 (Feb. 14, 2018); Southwestern Electric Power Company Request to Defer Action in Bentonville PSA Amendment, Docket No. ER18-500-000 (Feb. 14, 2018).

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recent five years. Like Minden’s PSA, the Hope and Bentonville PSAs permit SWEPCO to file for Stranded Costs in the event that a municipality terminates its contract.65 Minden anticipates SWEPCO will file amendments to the Minden PSA over its objections to recover its Wind Catcher costs, devoid of any mitigation against the potential payment of excess Stranded Cost payments.

IV.

COMPLAINT A.

SWEPCO’S Current ROE is Unjust and Unreasonable 1.

27.

Based Upon Minden’s Prima Facie Evidence, the Commission Should Set for Hearing the Issue of Whether SWEPCO’s Existing ROE is Unjust and Unreasonable

Minden’s evidence, presented by Mr. Parcell, shows that the Commission-preferred

DCF method produces a ROE in the range of 6.06% to 10.33% (8.20% median and 8.19% midpoint), and that the median, midpoint, and upper end of this range is well below the currentlyauthorized 11.1% ROE in the PSA66 establishing, prima facie, that the existing ROE in the PSA is unjust and unreasonable. In Emera Maine v. FERC,67 the United States Court of Appeals for the District of Columbia Circuit said that: [W]hile showing that the existing rate is entirely outside the zone of reasonableness may illustrate that the existing rate is unlawful, that is not the only way in which FERC can satisfy its burden under section 206.

854 F.3d at 24 (citation omitted). Minden’s evidence “illustrates” that the existing rate is unlawful according to the court’s standard and more than justifies setting this matter for further proceedings consistent with Section 206.

28.

To advance to hearing, the Commission does not require a complainant to prove,

as an initial matter, that an existing rate is unjust, unreasonable, and unduly discriminatory beyond

65

Hope Amended PSA § 7.03(b); Bentonville Amended PSA § 8.03(b); Minden PSA § 7.03(b).

Ex. PARCELL-1 at 12:1-5 (Parcell Affidavit).

67 Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017) (“Emera Maine”).

66

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a genuine dispute of material fact. Rather, the complainant must establish a prima facie case that the existing rate may be unjust, unreasonable, or unduly discriminatory for FERC to set the matter for hearing. 68 Minden’s evidence accomplishes this objective by showing that the existing rate is outside of the zone of reasonableness produced by the FERC’s DCF analysis.69 29.

That a tariff provision implementing a particular rate was at one time determined

just and reasonable “does not preclude the Commission from later reviewing the tariff provision to determine whether it continues to be just and reasonable.”70 An existing rate that falls within a zone of reasonableness might nevertheless be considered unjust and unreasonable. 71 Further, “the Commission has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE in a FPA section 206

68

Ameren Servs. Co. v. Midwest Indep. Transmission Sys. Operator, Inc., 121 FERC ¶ 61,205, at P 33 (2007) (“Ameren”); see also Southern Co. Servs., Inc., 43 FERC ¶ 61,003, at 61,013 n. 6 (1988) (“As the proponent of an order from the Commission, [complainant’s] burden is one of going forward with evidence in support of a prima facie case, not the burden of ultimate persuasion.”) (citing Southern Cal. Edison Co., 41 FERC ¶ 61,188, at 61,492 (1987)). “[T]he burden imposed is one of coming forward with a prima facie case, not the ultimate burden of persuasion. Id. [Therefore,] once complainants presented a prima facie case for relief, the burden shifts to the respondent . . . to make a persuasive defense.” Id. 69 See Ass’n of Bus. Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., 156 FERC ¶ 61,060, at P 28 (2016) (finding that the Complainant’s DCF study that produced a zone of reasonableness in which the existing ROE did not fall was sufficient evidence to establish hearing and settlement procedures).

70 Ameren, 121 FERC ¶ 61,205, at P 33.

71 See Bangor Hydro-Electric Co., 122 FERC ¶ 61,038, at P 11 (2008) (cited favorably in Emera Maine). The Commission stated: When the Commission identifies a ‘zone of reasonableness’ in a particular case, it identifies a range that reflects the ‘substantial spread between what is unreasonable because it is too low and what is unreasonable because it is too high.’ However, not every rate within this ‘substantial spread’ would necessarily be just and reasonable if charged. Certain rates, though within the zone, may not be just and reasonable given the circumstances of the case.

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proceeding.”72 As the U. S. Supreme Court stated in Bluefield Water Works & Improvement Co. v. Public Serv. Commission,73 “a rate of return may be reasonable at one time, and become too high or too low by changes affecting opportunities for investment, the money market, and business conditions generally.”74 Minden has satisfied its burden of going forward with sufficient evidence to justify further evaluation as to the justness and reasonableness of the existing ROE.75 If the complainant makes this showing, the Commission must then determine a new just and reasonable rate.76 30.

In a Section 206 complaint proceeding, the complainant challenging an unjust and

unreasonable rate must “go forward” with sufficient prima facie evidence that the existing rate is unjust, unreasonable, or unduly discriminatory to warrant further investigation.77 Minden has

Belmont Mun. Light Dep’t v. Cent. Me. Power Co., 162 FERC ¶ 61,035, at P 6 (2017); East Tex. Elec. Coop., Inc. v. Southwestern Elec. Power Co., 161 FERC ¶ 61,222, at P 32 (2017); N.C. Elec. Membership Corp. v. Duke Energy Carolinas, L.L.C., 155 FERC ¶ 61,048, at P 29 (2016); Bangor Hydro-Elec. Co., 122 FERC ¶ 61,038, at PP 10-15 (2008).

73 262 U.S. 679, 693 (1923) (“Bluefield”).

74 Id. 75 Golden Spread Elec. Coop., Inc. v. S.W. Pub. Serv. Co., 151 FERC ¶ 61,126 (2015) (asserting that the burden of going forward with prima facie evidence is less stringent than the ultimate section 206 burden of proving that an existing rate is unjust and unreasonable such that a singlestage DCF analysis could be sufficient to establish a prima facie case that the existing rate was unjust and unreasonable).

76 Advanced Energy Mgt. Alliance v. FERC, 860 F. 3d 656, 663 (D.C. Cir. 2017) (quoting Md. Pub. Serv. Comm’n, 632 F.3d at 1285 n.1) (“It is the Commission’s job – not the petitioners – to find a just and reasonable rate.”); see also Emera Maine, 854 F.3d 9, 24 (D.C. Cir. 2017) (“[S]ection 206 required FERC to make an explicit finding that Transmission Owners’ existing rate was unjust and unreasonable before proceeding to set a new rate.”).

77 Md. Pub. Serv. Comm’n v. PJM Interconnection, L.L.C., 123 FERC ¶ 61,169, at P 31 (2008); Ameren, 121 FERC ¶ 61,205, at PP 32-34, 94 (2007) (“We find that complainants have raised sufficient grounds to warrant an investigation.”); Mich. Elec. Transmission Co., L.L.C., 116 FERC ¶ 61,164, at p 61,708 (2006); UNITIL Power Corp. v. Pub. Serv. Co. of N.H. & Northeast Utilities, 61 FERC ¶ 61,055, at p 61,287 (1993) (“The question we must answer at this stage of the proceeding is whether UNITIL has presented sufficient evidence of PSNH’s costs so that we may assess whether a trial-type, evidentiary hearing is warranted.”).

72

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satisfied this standard. Minden’s evidence provides ample justification for an investigation into whether the existing ROE is unjust and unreasonable. Moreover, whether the DCF analysis is prepared by a complainant or a respondent, FERC is not mandated to “accept as just and reasonable all ROEs within the [DCF] zone of reasonableness.”78 Rather, when the evidence of DCF zones of reasonableness differs among the parties, the Commission sets the matter for hearing to make its own assessment of the “particular circumstances” of the case before it selects an appropriate ROE.79 The Commission has made clear that “those circumstances are precisely the sort of ‘issues of material fact’ that the Commission, in its discretion, may choose to assess in a trial-type evidentiary hearing.”80 FERC is not required to accept each and every point within a DCF zone of reasonableness as “coextensive” with the “just and reasonable standard” under the Federal Power Act, but FERC is required to evaluate the justness and reasonableness of an existing rate if a complainant comes forward with a prima facie case that the existing rate is no longer just and reasonable.81 31.

Financial markets have changed considerably in the years since 2010 when the

Commission approved SWEPCO’s 11.1% ROE, but fundamental ratemaking principles have not.

Jurisdictional rates must still be just, reasonable, and not unduly discriminatory.82 The “protection of consumers from exorbitant rates” continues to be the goal of public utility regulation.83

Emera Maine, 854 F.3d at 23-24 (stating that “rates within the zone of reasonableness are not per se just and reasonable.”).

79 Id. at 23.

80 Belmont Mun. Light Dep’t v. Cent. Me. Power Co., 162 FERC ¶ 61,035, at P 7 (2017) (explaining that setting a matter for hearing is a “means for gathering information that will assist [the Commission] in evaluating whether [an] existing ROE is unjust and unreasonable.”).

81 Id. at 23.

82 16 U.S.C. § 824d (2017).

83 Am. Pub. Power Assoc. v FPC, 522 F.2d 142, 147 (D.C. Cir. 1975) (Bazelon, J. concurring); Washington Gas Light Co. v. Baker, 188 F.2d 11, 15 (D.C. Cir. 1950) (referencing U. S. Supreme 78

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Establishing “just and reasonable” rates requires the Commission to balance the interests of both investors and consumers within a “zone of reasonableness” so that investors are fairly compensated and the public interest, both existing and foreseeable, is appropriately protected. 84 A return on equity must still produce a return to the equity owner that is commensurate with returns on investments in other enterprises having corresponding risks, sufficient to assure confidence in the financial integrity of the enterprise, and sufficient to allow the enterprise to “maintain credit and to attract capital.”85 As the U.S. Supreme Court stated, a fair rate of return must meet the following standards: What annual rate will constitute just compensation depends upon many circumstances and must be determined by the exercise of a fair and enlightened judgment, having regard to all relevant facts. A public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are realized or anticipated in highly profitable enterprises or speculative ventures. The return should be reasonably sufficient to assure confidence in the financial soundness of the utility, and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties.

Bluefield, 262 U.S. 679, 692-93 (1923).

2.

Minden’s ROE Analysis Demonstrates that SWEPCO’s Current ROE Produces Unjust and Unreasonable Rates and that a Just and Reasonable ROE is No Higher than 8.20%

Court cases dating back to 1890); see also Fed. Power Comm’n v. Memphis Light, Gas, & Power, 411 U. S. 458, 474 (1973) (“Under Hope Natural Gas, rates are ‘just and reasonable’ only if consumer interests are protected and if the financial health of the pipeline in our economic system remains strong.”).

84 Washington Gas Light Co., 188 F.2d at 15; see also Permian Basin Area Rate Cases, 390 U.S. 747, 766, 792 (1968); Wis. Pub. Power Inc. v. FERC, 493 F.3d 239, 262 (D.C. Cir. 2007).

85 Fed. Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944).

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32.

The Commission has adopted a preferred methodology for analyzing just and

reasonable returns on equity for jurisdictional services that is based upon applying a DCF analysis to a proxy group of comparable risk utilities.86 The Commission changed its approach on the DCF methodology in Opinion 531 and these principles were also used in Opinion 551. Although Opinions 531, 531-A, and 531-B were vacated and remanded to FERC by the D.C Circuit, the DCF methodology established in Opinion 531 and relied upon by Mr. Parcell in his testimony was not altered by the court’s remand.87 Mr. Parcell’s attached testimony and exhibits describe his DCF analysis of SWEPCO’s current ROE and demonstrate that the ROE in the PSA is excessive because it is well above the median, midpoint, and high end of the zone of reasonableness produced by the Commission’s preferred DCF method. His analysis demonstrates that a just and reasonable ROE for SWEPCO is 8.20%.

33.

Complying with the U.S. Supreme Court guidelines in Bluefield, Mr. Parcell began

his analysis by examining changes in general economic conditions since SWEPCO’s current ROE was set in 2010. According to Mr. Parcell, this analysis is necessary because the cost of capital for both fixed-cost (debt and preferred stock) components and common equity is determined in

86

Opinion No. 531, Coakley v. Bangor Hydro-Elec. Co., 147 F.E.R.C. ¶ 61,234 (2014), order on paper hearing, Opinion No. 531-A, 149 F.E.R.C. ¶ 61,032 (2014), order on reh’g, Opinion No. 531-B, 150 F.E.R.C. ¶ 61,165 (2015), vacated and remanded sub nom, Emera Maine, 854 F.3d 9 (2017). The Court vacated and remanded the Opinion 531 series of opinions to FERC for further proceedings, but the criteria for proxy group selection and the use of the two-step growth rate in the DCF were not disturbed on appeal. See also Opinion No. 551, Assoc. of Bus. Advocating Tariff Equity v. Midcontinent Independent Sys. Operator, 156 F.E.R.C. ¶ 61,234 (2016), reh’g pending.

87 See Belmont Mun. Light Dep’t v. Cent. Maine Power Co., 159 F.E.R.C. ¶ 63,039, at P 10, Docket No. EL16-64-000 (2017) (concurrence of ALJ Glazer) (“Emera Maine did not eliminate the Commission’s adoption . . . of the “two step” DCF analysis.”).

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part by current and prospective economic and financial conditions.88 Mr. Parcell concludes that the cost of capital for regulated utilities has declined in recent years.89 34.

Mr. Parcell describes the DCF analysis he performed, applying guidelines approved

by the Commission. He began his analysis by selecting a group of proxy electric utility companies with risk profiles similar to SWEPCO by using the following criteria identified by the Commission in Opinion 531:90 (1)

A national comparable group of electric utilities covered by Value Line;

(2)

Electric utilities that paid dividends over the past six months and did not reduce dividends during this period;

(3)

Electric utilities with Moody’s and S&P corporate credit ratings within one level above or below the rating of the utility under evaluation. In Opinion 531 the Commission used the range of A- to BBB (NETO, the subject utility, had ratings of BBB+); and

(4)

Electric utilities that are not engaged in merger or acquisition (“M&A”) activity significant enough to distort the DCF inputs.

Applying these criteria resulted in a national group of 16 companies.91 35.

To identify companies with risks comparable to SWEPCO, Mr. Parcell noted that

SWEPCO’s current Standard & Poor’s (“S&P”) corporate credit rating is A- and its current Moody’s Investors Service (“Moody’s”) rating is Baa2.92 Therefore, in compliance with Opinion 531, he used the S&P range of BBB+ to A and the Moody’s range of Baa3 to Baa1 as the screening

88

Ex. PARCELL-1 at 16:16-17:4 (Parcell Affidavit).

Ex. PARCELL-1 at 19:13-20 (Parcell Affidavit).

90 Opinion No. 531, 147 F.E.R.C. at PP 92, 102, 107, 112, 114; Ex. PARCELL-1 at 24:12-25:4 (Parcell Affidavit).

91 Ex. PARCELL-1 at 26:12-14 (Parcell Affidavit); Ex. PARCELL-5 (Calculation of Dividend Yield Component); Ex. PARCELL-6 (Calculation of DCF Rates); Ex. PARCELL-7 (Long Term Projections of GDP Growth).

92 Ex. PARCELL-1 at 25:5-10 (Parcell Affidavit).

89

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criterion for the selection of proxy companies for SWEPCO (i.e., one rating “notch” above and below SWEPCO’s S&P and Moody’s rating).93 According to Mr. Parcell, SWEPCO’s rating falls within the middle of the range of ratings of the proxy group companies. He concluded that as a result, SWEPCO has similar risk to the proxy group companies.94 36.

Mr. Parcell derived a ROE for each of his proxy group companies by using the

Commission’s preferred two-step growth DCF formula:95 DCF 

D (1  .5 g )  [( g s x 2)  g1 ] / 3 P

where: D/P = dividend yield based upon the current annualized dividends per share (“DPS”) and the average stock prices for the six-month period July 2017–December 2017; g = a two-stage growth rate comprised of the average of short-term (weighted two-thirds) and long-term (weighted one-third) expected growth; gs = short-term growth, suing EPS 5-year projections; and, gl = long-term growth in GDP = 4.34 percent, as developed on Exhibit No. PARCELL-7.

Consistent with the Commission’s Opinion 531, Mr. Parcell would have excluded any DCF results that are less than 100 basis points above the yield on BBB rated public utility debt (5.23%), but there were no such results.96 Mr. Parcell excluded two companies that had a negative short-term EPS growth rate forecast.97 This produced a proxy group of 14 companies.98

93

Ex. PARCELL-1 at 25:10-13 (Parcell Affidavit).

Ex. PARCELL-1 at 26:13-14 (Parcell Affidavit).

95 Ex. PARCELL-1 at 26:18-27:7 (Parcell Affidavit).

96 Ex. PARCELL-1 at 27:9-13 (Parcell Affidavit); Ex. PARCELL-6 (Calculation of DCF Rates).

97 Ex. PARCELL-1 at 27:13-14 (Parcell Affidavit).

98 Ex. PARCELL-1 at 27:14 (Parcell Affidavit).

94

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37.

Applying the Commission’s methodology, Mr. Parcell determined the “zone of

reasonableness” to be 6.06% (the low-end ROE of his proxy group) to 10.33% (the high-end ROE of his proxy group).99 He then determined the median of these DCF values to be 8.20% and the midpoint to be 8.19%.100 According to Mr. Parcell, setting SWEPCO’s ROE as the median value of his DCF’s “zone of reasonableness” complies with Commission precedent because it reflects the cost of equity for a single electric utility of average risk.101 38.

SWEPCO’s current ROE results in an overpayment to SWEPCO of approximately

$405,000 per year, compared to Mr. Parcell’s recommended ROE. The overpayment shows how an unjust and unreasonable ROE results in exorbitant rates. As Mr. Parcell’s DCF analysis shows, SWEPCO’s current ROE exceeds what is “reasonably sufficient to assure confidence in the financial soundness of the utility” and “adequate, under efficient and economical management, to maintain and support its credit and enable it to raise money necessary for the proper discharge of its public duties.”102 As a result, SWEPCO’s rate for power supply service violates Section 206’s “just and reasonable standard” and is unlawful.103 In setting jurisdictional rates, not even a little unlawfulness is permitted.104 Moreover, the parties’ reservation of their rights to change the PSA by filing a Section 205 or Section 206 proceeding subject to the “just and reasonable” standard

99

Ex. PARCELL-1 at 27:15-17 (Parcell Affidavit).

Ex. PARCELL-1 at 27:15-17 (Parcell Affidavit); Ex. PARCELL-6 (Calculation of DCF Rates).

101 Ex. PARCELL-1 at 11:14 to 12:3-5 (Parcell Affidavit); see also Pub. Serv. Co. of N.M., 142 FERC ¶ 61,168, at P 28 (2013), order on reh’g, 143 FERC ¶ 61,227, at PP 12-13 (2013).

102 Bluefield, 262 U.S. 679, 693 (1923).

103 16 U.S.C. § 824e (2017) (“[A]ny rate[s] [or] charge[s] [made], demanded, or [received] by any public utility for [or in connection with] the transmission or sale [of electric energy] subject to the jurisdiction of the Commission . . . shall be just and reasonable” and any such rate or charge that is not just and reasonable is hereby declared to be unlawful.).

104 Fed. Power Comm’n v. Texaco Inc., 417 U.S. 380, 399 (1974).

100

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demonstrates their intent that the contract is sufficiently flexible to reflect changing financial circumstances in the power supply market.105 39.

SWEPCO’s current ROE has upset the balance of investor/consumer interests that

rates set by the Commission under the FPA must achieve. The Commission must act to restore this balance by finding that the existing ROE is unjust and unreasonable, and by reducing SWEPCO’s current ROE to a level no higher than 8.20%.

3.

40.

After Issuing an Order Finding that the Existing ROE is Unjust and Unreasonable, the Commission Should Issue an Order Summarily Reducing SWEPCO’s ROE to a Just and Reasonable Level or Set the Determination of SWEPCO’s Just and Reasonable ROE for an Evidentiary Hearing

Minden respectfully requests that, on the strength of sufficient prima facie evidence

presented in this Complaint, that the Commission issue a summary finding in conformance with Section 206 that SWEPCO’s existing ROE is unjust and unreasonable.106 41.

After making an explicit finding that the existing rate is unjust and unreasonable,107

Minden requests that the Commission summarily determine that the just and reasonable ROE is no higher than 8.20%, as presented in its evidence.

4.

42.

The Commission Should Establish the Earliest Possible Refund Date

In cases in which the Commission orders an investigation upon a complaint, Section

206(b) requires the Commission to set a refund effective date that is no earlier than the date of the

105

See PSA §§ 4.05, 15.03.

See Atlantic Path 15, L.L.C., 133 FERC ¶ 61,153, at P 22 (2010) (“[W]e affirm that the Commission retains discretion to make up-front ROE determinations if the record before it is sufficient to make such a summary finding.”).

107 Emera Maine, 854 F.3d 9, 24 (D.C. Cir. 2017) (“[S]ection 206 require[s] FERC to make an explicit finding that [an] existing rate [is] unjust and unreasonable before proceeding to set a new rate.”).

106

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complaint’s filing nor later than five months after that filing.108 In the Opinion 531 and Opinion 551 proceedings, the Commission set the refund date as the filing date, citing its “general policy of providing maximum protection to customers.”109 Minden respectfully submits that the filing date of this Complaint is the appropriate refund effective date for SWEPCO’s ROE. B.

SWEPCO Violates the PSA and Possibly the Public Interest by Failing to Effectively Hedge Minden’s Congestion Charges Through the MISO

43.

Minden requests that FERC enforce the PSA pursuant to Sections 306 and 309 in

such a manner as to require SWEPCO to use best practices to produce just, reasonable, predictable, and less volatile congestion charges to Minden through MISO, or terminate the PSA as violating the public interest. Minden requests an order from FERC requiring SWEPCO to, at a minimum, implement the following hedging strategy, as recommended by its consultant (and endorsed by Entergy):110 •

Nominate positive ARRs in MISO on Minden’s behalf.

•

Convert these positive ARRs into FTRs.

•

Enter into two daily virtual transactions for the amount of FTRs owned to own a hedge on the real time LMP spread.111

If FERC finds that the PSA does not compel SWEPCO to undertake the above three-part effective congestion hedging strategy, then Minden requests FERC to terminate the PSA as violating the 108

16 U.S.C. § 824e (2017).

Opinion No. 531, 147 FERC ¶ 61,234, at P 26 (2014) (citing Seminole Elec. Coop., Inc. v Fla. Power & Light Co., 65 FERC ¶ 61,413, at p 63,139 (1993)); Opinion No. 551,156 FERC ¶ 61,234 (2016); see also Cities of Anaheim v. Trans Bay Cable L.L.C., 146 FERC. ¶ 61,100, at P 27 (2014); Canal Elec. Co., 46 FERC ¶ 61,153, at p 61,539 (1989).

110 See Motion to Intervene and Protest of Entergy Services, Inc., Docket No. EL17-89-000, at pp 7-8 (Oct. 5, 2017).

111 Ex. SUHANIC-1 at 6:7-7:3 (Suhanic Affidavit); Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

109

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public interest because it produces drastically volatile Real-Time congestion charges brought about

by Entergy joining MISO several years after Minden entered the contract, substantially changing the financial risks. The heightened risk imposed upon Minden from the MISO congestion charges, combined with SWEPCO’s unwillingness (or inability) to hedge the charges, creates “substantial harm” to Minden sufficient to satisfy the stricter “public interest standard” of review required to change the term of the PSA.112 FERC Should Enforce the “Agency” and “Implementation” Provisions of the PSA by Requiring SWEPCO to Effectively Hedge Minden’s Congestion Risk

1.

i.

44.

Minden Experiences Substantial Cost and Risk from SWEPCO’s Failure to Hedge MISO Congestion Charges Effectively

As a budget driven municipal utility, Minden is primarily concerned that costs be

predictable,113 but the limited hedging strategy presently employed by SWEPCO unnecessarily leaves Minden blindly exposed114 to as much as $372,000 per month in increased charges, an amount causing “large” swings in the range of 32% for a single bill,115 whereas an effective congestion hedging strategy would reduce this risk to less than $20,000 per month.116 The usual purpose of a long-term contract such as the PSA is to ensure predictable, relatively stable rates; however, with the advent of the MISO wheel, this goal has been thwarted. The formula rate

112

PSA § 15.03(a). See El Paso Natural Gas Co., 99 FERC ¶ 61,244, at p 62,000 (2002) See SUHANIC-1 at 5:7-18 (Suhanic Affidavit) (stating that ACES determined that Minden’s congestion charges were extremely volatile, and ACES was consulted by Minden to develop an effective hedging strategy to minimize Minden’s risk).

114 Minden does not have access to Real Time data and thus has no notice or capacity to mitigate the potential congestion charges with load changes.

115 Ex. SUHANIC-1 at 8:23-9:2 (Suhanic Affidavit); Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

116 See Ex. SUHANIC-1 at 6:4-5 (Suhanic Affidavit) (exclaiming that step three of the hedging strategy would have led to a cost of $19,000); Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

113

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contract does not produce stable rates; more often than not, Minden has had to cough up more money after the true up. Minden stands on a precipice each month waiting to learn whether it will get socked with a nasty surprise congestion invoice. This amount of uncertainty takes its toll on a municipality the size of Minden, adds to working capital requirements, may result in suspension or delay of other projects, or increase borrowing costs to ensure sufficient funds on hand to meet the fluctuating bills.117 45.

Mr. Suhanic explains that hedging practices for congestion charges are different

when both sides of the pseudo-tie are part of ISO markets. Thus, upon Entergy joining MISO, Minden’s exposure to real time congestion required a more “robust management strategy” than when Minden simply paid a known tariff rate to Entergy. Mr. Suhanic states: The interaction of congestion and pseudo-tied loads, or resources in a locational marginal (“LMP”) market, is very different than in a non-LMP market.

A pseudo-tie removes a load or resource from one Balancing Area and puts it in another, using firm transmission service and changes to telemetry. In a traditional market, such as the Entergy market before MISO integration, a pseudo-tie may be a straightforward way to join loads under one Balancing Authority. However, when both sides of a pseudo-tie are part of LMP markets, there are new exposures that can be more cumbersome to manage, specifically the real-time congestion risk, as discussed earlier in my testimony. As such, before Entergy became part of MISO, Minden paid the transmission service cost, a known and mostly fixed charge, to Entergy. However, post-MISO integration, Minden now faces an additional risk of real-time congestion charges that require a robust management strategy.

Ex. SUHANIC-1 at 8:10-19 (Suhanic Affidavit).

46.

Minden’s expert consultant Mr. Suhanic concluded that the effective strategy for

hedging Minden’s congestion through the MISO wheel is the three-part strategy outlined above.118 Mr. Suhanic analyzed three different hedging strategies with the understanding that Minden’s

117

Ex. SUHANIC-1 at 9:9-14 (Suhanic Affidavit).

Ex. SUHANIC-1 at 5:10-6:5 (Suhanic Affidavit); Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

118

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primary goal is to keep costs as stable as possible.119 He found that failure to implement any hedging strategy carries extreme risk for Minden in the range of $408,000 in any given month.120 The following three strategies were analyzed with the results showing that the effective strategy is the three-part strategy outlined above.

•

Effective Hedging Strategy (Minden Preferred Strategy): Convert ARRs to FTRs and undertake two daily virtual transactions. o Monthly results range from a cost of $19,000 to a benefit of $129,000. o Monthly standard deviation is $38,000. o Mitigates real time exposure as much as possible, remaining risk is due to load volumes varying, whereas FTRs and ARRs are fixed quantities.

•

Riskier (Basis of May 2017 Settlement Agreement): Convert ARRs to FTRs and do not make a virtual transaction. o Monthly results range from a cost of $372,000 to a benefit of $229,000. o Monthly standard deviation of $92,000. o FTRs hedge congestion somewhat in Day-Ahead market, but Minden is still exposed to Real-Time market fluctuations.

•

Most Risky (SWEPCO’s strategy starting June 1, 2016): Do not convert ARRs and do not make a virtual transaction o Monthly results range from a cost of $408,000 to a benefit of $303,000. o Monthly standard deviation of $145,000. o Fully exposed to Real Time congestion.121

Although the parties settled their dispute as to the amount of MISO congestion charges through the period ending May 31, 2017, from that day afterward and continuing to the present, the parties continue to disagree.

47.

SWEPCO absolves itself of responsibility for Minden’s highly volatile congestion

charges alleging in its complaint in Docket No. EL17-89-000 that MISO is to blame for improperly

119

See SUHANIC-1 at 5:7-18 (Suhanic Affidavit) (explaining that ACES was hired by Minden to develop an effective hedging strategy to minimize Minden’s risk).

120 See SUHANIC-1 at 5:17-23 (Suhanic Affidavit); Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

121 Ex. SUHANIC-3 at 1 (ACES’s Analysis of Minden Hedging Strategies).

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implementing its tariff.122 Even Entergy in its Answer to SWEPCO’s Complaint expressed a belief that a robust strategy such as the one recommended by Mr. Suhanic could keep Minden’s costs to a reasonable, predictable level.123 Minden requests decisive FERC action requiring SWEPCO effectively hedge MISO congestion charges. ii.

48.

The PSA Requires SWEPCO to Effectively Hedge MISO Congestion Charges for Minden

SWEPCO’s failure to effectively hedge Minden’s MISO congestion charges

contravenes the PSA. As the PSA provides, SWEPCO operates as Minden’s “agent” in arranging NITS through both SPP and MISO. 124 AEP entered into a pseudo-tie contract with MISO for Minden’s load with a delivery start date of December 19, 2013.125 As outlined in the PSA, SWEPCO and Minden have cooperated on the “implementation” of the PSA, such that SWEPCO “registered” Minden’s load with SPP and has remained “responsible for all scheduling and settlement activities related to such load and resource.”126 SWEPCO and Minden even worked together to reach a shared compromise on the unreasonably high congestion charges imposed on Minden’s service through MISO between December 19, 2013, and May 31, 2017.127 Accordingly,

122

Formal Complaint of American Electric Power Service Corporation on Behalf of Southwestern Electric Power Company, Docket No. EL17-89-000 (Sept. 15, 2017).

123 See Motion to Intervene and Protest of Entergy Services, Inc., Docket No. EL17-89-000, at pp 7-8 (Oct. 5, 2017).

124 PSA § 3.02.

125 See Ex. SUHANIC-4 (Form of Transaction Specification Sheet) (“Providing Service to Minden, LA via pseudo-to [sic] to the CSWS balancing authority in the Southwest Power Pool.”

Page 1, item 02. “Capacity and energy will be provided by AEPM via a pseudo-tie.” Page 1, item 05.); see also Answer of the Midcontinent Independent System Operator, Inc., Docket No. EL1789-000, at Tab B (Oct. 12, 2017) (Minden Network Integrated Transmission Service Agreement).

126 PSA § 5.01.

127 See SWEPCO-Minden PSA Amendment, FERC Docket No. ER17-1895-000, at Attachment C, p 1 (June 23, 2017).

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SWEPCO’s failure to effectively mitigate MISO congestion risk runs afoul of its “agency” and “implementation” duties in the PSA. As an agent for Minden, SWEPCO has a fiduciary duty to act on Minden’s behalf with MISO and SPP in carrying out its agency duty.128 The wheel through MISO is unavoidable to the “implementation” of the PSA129 and the law of agency requires SWEPCO to take Minden’s directions in effectively hedging the congestion charges.130 SWEPCO’s failure in this regard violates the PSA and should be remedied by FERC’s application of Sections 306 and 309.131 49.

If SWEPCO is unable or unwilling to perform the two daily virtual trades, Minden

could conceivably contract with a third-party supplier to provide this service, but this contravenes the intention of a “full requirements contract.” Moreover, given Minden’s small size and that it already has a power supplier in SWEPCO, it is unlikely that any third-party is able or willing to

See Amtrak v. Veolia Transp. Servs., 791 F. Supp. 2d 33, 47 (D.D.C. 2011) (stating that “[an] agent has a fiduciary duty to act loyally for the principal’s benefit in all matters connected with the agency relationship.”) (quoting Restatement (Third) of Agency § 8.01 (2006)); Gross v. Akin, 599 F. Supp. 2d 23, 32 (D.D.C. 2009) (exclaiming that an agent has a duty to its principal “to act solely for the benefit of the principal in all matters concerned with the agency.”); Restatement (Third) of Agency § 1.01 (2006) (“Agency is the fiduciary relationship that arises when one person (a ‘principal’) manifests assent to another person (an ‘agent’) that the agent shall act on the principal's behalf and subject to the principal's control, and the agent manifests assent or otherwise consents so to act.”).

129 See PSA § 5.01.

130 See Amtrak, 791 F. Supp. 2d at 47 (concluding that the principles of agency law permitted Amtrak, as the principal, to “control and direct” the agent in the performance of its duties).

131 See San Diego Gas & Elec. Co. v. Sellers of Energy & Ancillary Servs., 96 FERC ¶ 61,120, at p 61,510 (exclaiming that Section 309 authorizes the Commission “to use means of regulation not spelled out in detail, provided the agency’s action conforms with the purposes and policies of Congress and does not contravene any terms of the [FPA].”) (quoting Niagara Mohawk Power Corp. v. FERC, 379 F.2d 153 (1967)); N. Natural Gas Co. v. FERC, 785 F.2d 338, 341 (D.C. Cir. 1986) (stating that Section 16 of the Natural Gas Act “NGA,” the counterpart to Section 309 of the FPA, “unquestionably” grants FERC “broad authority so as to do equity consistent with the public interest . . . [and] consider equitable principles.”) (citing Columbia Gas Transmission Corp. v. FERC, 750 F.2d 105, 109 (D.C. Cir. 1984)).

128

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provide the service at a feasible cost.132 As Mr. Suhanic explains, “Minden is too small a load to build these capabilities effectively outside of [its] full requirements provider.”133 2.

50.

In the Alternative, if FERC Does Not Mandate SWEPCO to Conduct the Effective Congestion Hedging Strategy then the PSA Should be Terminated as Contrary to the Public Interest

The PSA was operating satisfactorily to both parties until Entergy joined MISO,

causing both sides of the pseudo-tie to be part of LMP-markets. As of May 31, 2017, the parties have no mutual understanding of their scope of duties with respect to MISO congestion hedging.

As Mr. Suhanic explains, “the interaction of congestion and pseudo-tied loads, or resources in a [] LMP market, is very different than in a non-LMP market” and are more “cumbersome to manage” when both sides of the pseudo-tie are part of LMP markets.134 If FERC finds that the PSA does not require SWEPCO to effectively hedge MISO congestion charges, then the PSA should be terminated as contrary to the public interest.

51.

In the absence of a finding that the PSA mandates use of the effective congestion

hedging strategy, these changed circumstances render the PSA contrary to the public interest, thus satisfying the heightened standard of review required by the PSA for contract termination.135 As now implemented by SWEPCO, the PSA exposes Minden to extreme fluctuations in costs, with possible swings as much as 32% or more per month.136 Moreover, without a more robust hedging strategy, the PSA affords Minden no value from MISO congestion payments that it makes to SWEPCO. As Mr. Suhanic explains, the “‘value’ of congestion payments loosely goes back to

132

Ex. SUHANIC-1 at 7:4-17 (Suhanic Affidavit).

Ex. SUHANIC-1 at 7:16-17 (Suhanic Affidavit).

134 Ex. SUHANIC-1 at 8:10-17 (Suhanic Affidavit).

135 PSA § 15.03(a).

136 Ex. SUHANIC-1 at 8:23-9:2 (Suhanic Affidavit).

133

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MISO real-time market participants” but “[c]urrently, Minden derives no value from these payments.”137 This not only harms Minden financially, but strips away the objective of the congestion regulatory scheme to incentivize Minden’s behavior by imposing these charges.

52.

This changed regulatory environment is analogous to when the Commission

invoked the stricter “public interest” standard to allow recovery of Stranded Costs after the implementation of open access in Order 888 because of “legislative or regulatory changes that could not be anticipated” at the time the contracts were signed.138 The Commission stated in Order No. 888-A: [W]e do not interpret the public interest standard as practically insurmountable in extraordinary situations such as this one where historic statutory and regulatory changes have converged to fundamentally change the obligations of utilities and the markets in which they and their customers will operate. *

*

*

We believe that protective action in the public interest is particularly necessary where, as here, a utility’s rates could become insufficient because of fundamental changes in the industry that largely result from legislative or regulatory changes that could not be anticipated.

Order No. 888-A, FERC Stats. & Regs., ¶ 31,048, at PP 135-36, 143 (1997). Although it would be an exaggeration to claim that Minden’s distress is brought about by “historic” regulatory changes, it is nevertheless clear that the regulatory evolution of Entergy joining MISO has created

137

Ex. SUHANIC-1 at 7:22-8:2 (Suhanic Affidavit).

Order No. 888-A, Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Stats. & Regs., ¶ 31,048, at P 143 (1997) (“Order No. 888-A”), order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub. nom, Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom., New York v. FERC, 535 U.S. 1 (2002).

138

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this confusing situation139 where both sides of the pseudo-tie are in different LMP markets and “fundamentally changed the obligations” of SWEPCO and Minden in a manner neither of them fully anticipated in the plain language of the PSA. Indeed, SWEPCO harbors the impression that MISO is not properly applying its tariff and is the cause of (in SWEPCO’s phrasing) Minden’s “unjust, unreasonable and unduly discriminatory costs.”140 The degree of uncertainty brought about by Entergy joining MISO has rendered the PSA contrary to the public interest, and it must be terminated if a more robust hedging strategy is not mandated thereunder.

53.

The situation is somewhat akin, on a much smaller scale, to that faced by El Paso

Natural Gas Company when the Commission justified changes to the utility’s contract under the “public interest” standard stating that the contract “is no longer just and reasonable because it results in regular reductions of firm service” and “shippers have sustained substantial harm.”141 Exposing Minden unnecessarily to significant congestion volatility risk without a reasonable hedge constitutes “substantial harm,” especially considering that the contract term extends another ten years until 2028.

54.

Accordingly, if FERC finds that it cannot or should not require SWEPCO to enter

into the three-part effective hedging strategy, the PSA should be terminated as contrary to the public interest.

139

See PJM Interconnection, L.L.C., 161 FERC ¶ 61,313, at P 3 (2017) (explaining that while historically pseudo-tied resources did not cause serious issues, the significant increase in pseudotied volumes over the past few years has created market and reliability challenges).

140 See SWEPCO Complaint at p 1.

141 El Paso Natural Gas Co., 99 FERC ¶ 61,244, at p 62,000 (2002) (“[O]nly in extraordinary circumstances, and only where the public interest so requires, will the Commission order contract modification.”); see also UDC v. FERC, 88 F.3d 1105, 1131 (D.C. Cir. 1996), cert. denied, 520 U.S. 1224 (1997) (“[T]he Commission has plenary authority to limit or proscribe contractual arrangements that contravene the relevant public interests.”).

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C.

Unjust, Unreasonable, and Discriminatory Provisions of the PSA Should be Amended

56.

The PSA provisions discussed in this Section may, by the terms of the PSA, be

amended by Minden petitioning FERC under Section 206.142 1.

57.

The Formula Rate Should be Amended to Address “Excess” Accumulated Deferred Income Tax Arising from the Changed Federal Corporate Tax Rate

As explained in detail by Minden witness Ms. Slater, the PSA template does not

contain a provision for the refund or flowback of the excess accumulated deferred income taxes created by the Tax Act’s rate reduction.143 The PSA provides that ratepayers pay SWEPCO’s taxes, even those taxes that SWEPCO is authorized to defer paying to the taxing authority. The tax rate when the deferred taxes were collected is now lower than the tax rate when SWEPCO makes the tax payment, creating an “excess” accumulated deferred income tax balance. As required by previous FERC guidance, “utilities [should] transfer the excess/deficient deferred taxes to ratepayers through reductions/increases in utility service rates over the period of the remaining life of the capital assets that gave rise to such deferred taxes.”144 The PSA, however, does not include a mechanism for converting the excess accumulated deferred income taxes into a regulatory liability that is then flowed through to Minden. Accordingly, the PSA should be amended to ensure that the excess accumulated deferred income taxes are properly recorded as a regulatory liability and that they are flowed back to Minden as soon as possible. To do otherwise is unjust and unreasonable because it permits SWEPCO to be enriched by the amount of taxes prepaid by ratepayers that are no longer due to the taxing authority. 145 Minden requests FERC to

142

PSA §15.03.

Ex. SLATER-1 at 9:12-13 (Slater Affidavit).

144 Ex. SLATER-1 at 8:24-9:2 (Slater Affidavit).

145 See Ex. SLATER-1 at 9:15-17 (Slater Affidavit).

143

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order that the excess accumulated deferred income taxes be a regulatory liability and that SWEPCO flow back the excess deferred income taxes to Minden through the PSA. The annual impact to Minden of properly flowing back the excess accumulated deferred income taxes is approximately $75,000 per year.146 2.

58.

SWEPCO Should Be Required to Update its Depreciation Study and the PSA Should Be Amended to Base Depreciation Expense on a Wholesale Depreciation Study

SWEPCO has not updated its FERC jurisdictional depreciation study since 1983.

This is unjust and unreasonable not only because SWEPCO depreciation rates have declined,147 but also because SWEPCO’s more recent depreciation rates based on depreciation studies filed at the state commissions are considerably lower than the thirty-five-year-old depreciation rates being used for the FERC jurisdictional portion of the PSA depreciation expense.148 As Ms. Slater states, the potential impact to Minden from revising the depreciation rates is an annual reduction of more than $100,000 per year.149

Ms. Slater explains that SWEPCO’s 1983 FERC jurisdictional

depreciation rates are, on average across SWEPCO’s nine generation plants, 80% higher than the depreciation rates approved most recently by the Texas state commission.150 Accordingly, as Ms. Slater explains “[a] revised set of FERC approved wholesale depreciation rates based upon a current depreciation study is long overdue.”151

146

Ex. SLATER-1 at 12:17-19, 30: Table 2 (Slater Affidavit).

Ex. SLATER-1 at 19, Table 1, showing significant decline in annual composite depreciation rates by functional class from 2009 to 2016.

148 Ex. SLATER-1 at 18:21-20:15 (Slater Affidavit). See generally Va. Elec. & Power Co., 11 FERC ¶ 63,028, at 65,163-164 (1980) (stating that depreciation studies should be performed at “frequent intervals, with equally frequent adjustments of rates . . . to avoid gross distortions and unjust charges.”), order on initial decision, Opinion No. 118, 15 FERC ¶ 61,052 (1981).

149 Ex. SLATER-1 at 22:16-23:5 (Slater Affidavit).

150 Ex. SLATER-1 at 20:2-4 (Slater Affidavit).

151 Ex. SLATER-1 at 18:22 to 19:1 (Slater Affidavit).

147

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59.

As a second adjustment, the PSA should be amended to require SWEPCO’s rates

to be based entirely on FERC jurisdictional depreciation rates, rather than based on depreciation rates comprised of a composite of rates from four different jurisdictions—FERC, Texas, Arkansas, and Louisiana.152 The PSA is “intended to produce a FERC wholesale cost of service, [but] the use of composite multi-jurisdictional depreciation rates from SWEPCO’s various retail state jurisdictions is inconsistent with that intent.”153 Minden is not jurisdictional to these other state commissions and cannot participate in setting the depreciation rates adjudicated there.154 Accordingly, Minden requests FERC to order an amendment to the PSA sufficient to require SWEPCO to use a reasonably updated FERC jurisdictional depreciation study as set forth in the affidavit of Minden witness Ms. Slater.155 3.

60.

SWEPCO Should Stop Double Collection of Depreciation Expense on Contra-AFUDC and Refund Any Amounts Collected in Prior Periods

SWEPCO has inappropriately applied “depreciation rates to a depreciable base that

has not been adjusted for the contra AFUDC.” 156 The PSA already addresses excluding AFUDC from CWIP for rate base, but should be amended, if necessary, to clearly eliminate any possibility of “double collection” on certain AFUDC that should have been excluded from the depreciable base of plant that previously had CWIP in rate base. The PSA already provides that: [T]he Company will adjust its production invested capital to recognize that under this Agreement, certain percentages of CWIP have been included in rate base formulas. The effect of this adjustment will be to recognize the fact that the formulas shall not include any allowance for funds used during construction (“AFUDC”) on the amounts included in rate base as CWIP.

152

Ex. SLATER-1 at 14:8-15:10 (Slater Affidavit).

Ex. SLATER-1 at 15:15-17 (Slater Affidavit).

154 Ex. SLATER-1 at 16:14-16 (Slater Affidavit).

155 Ex. SLATER-1 at 21:1-9 (Slater Affidavit).

156 Ex. SLATER-1 at 24:2-3 (Slater Affidavit).

153

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PSA § 4.06. As Ms. Slater explains, this directive should involve “not only [] plant-in-service for rate base purposes, but also for depreciation.”157 Failing to adjust contra-AFUDC out of the Turk Power Station depreciable base, for example, results in an overstated depreciation expense of about $4 million per year.158 Accordingly, Minden requests that the PSA be amended, if necessary, to clarify that this contra-AFUDC adjustment should be made when calculating annual rates. If FERC rules that this is already required by the PSA, Minden requests that under Sections 306 and 309 that FERC order SWEPCO to recalculate all annual true-ups from the inception of the PSA that incorrectly include contra-AFUDC in the depreciable base, and refund the monies, with interest to Minden.

4.

61.

The PSA Should be Amended to Offset Rate Base for Unfunded Reserves

The PSA is unjust and unreasonable in failing to provide a credit to rate base for

certain cost-free customer-contributed capital that is accumulated for accounting purposes, but to which SWEPCO is entitled unrestricted access until a qualifying event occurs. 159 As Minden consultant Ms. Slater explains, utilities often create reserves to pay expenses for which the timing and magnitude are not precisely known.160 SWEPCO has evidently established at least seven unfunded reserves for items as diverse as supplemental executive retirement plan to accrued mine reclamation.161 Others may exist as well.162 Ms. Slater determined by reviewing the accumulated deferred income tax (Account 190) in SWEPCO’s workpapers that SWEPCO is accruing reserves for these items that “should give rise to unfunded reserves being built up and recorded in FERC

157

Ex. SLATER-1 at 24:11-12 (Slater Affidavit).

Ex. SLATER-1 at 24:12-15 (Slater Affidavit).

159 Ex. SLATER-1 at 26:3-27:4 (Slater Affidavit).

160 Ex. SLATER-1 at 25:6-8 (Slater Affidavit).

161 Ex. SLATER-1 at 26:3-18 (Slater Affidavit).

162 Ex. SLATER-1 at 26:8-9 (Slater Affidavit).

158

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Accounts 228.1-228.4 and/or 242.�163 The PSA, however, is unjust and unreasonable for not containing a provision that offsets rate base for these unfunded reserves.164 The PSA, by this omission, unfairly fails to account for the customer-funded capital that SWEPCO may use for free until the contingency occurs requiring the funds. Accordingly, Minden requests FERC to order that the PSA be amended to reduce rate base for these and any other unfunded reserves that may arise.

5.

62.

SWEPCO Should Exclude Non-Production Related CWIP from Rate Base and Refund Any Amounts Collected in Prior Periods

Minden consultant Ms. Slater identified CWIP in the PSA annual true-up relating

to transmission, general plant, or intangible plant that does not belong in the PSA production rate.165 To the extent that the PSA is unclear in whether it allows costs unrelated to production in the PSA, Minden seeks an amendment of the PSA to clarify that these types of CWIP should be excluded from the PSA. To the extent that existing FERC policy as applied to the PSA forbids the inclusion of non-production related CWIP in the annual rate, Minden requests that FERC order SWEPCO pursuant to Sections 306 and 309 to recalculate the annual rates properly by eliminating these non-production amounts dating from the inception of the PSA until the time of the FERC order; and refund any overcollections to Minden with interest.

6.

63.

A Set of Protocols Should be Inserted to Guide the Parties’ Annual Review of the Formula Rate in Accordance with Current FERC Guidance

Minden respectfully requests that the PSA be amended to conform to current best

practices with respect to protocols for formula rates. In 2014, the Commission Staff set forth

163

Ex. SLATER-1 at 26:3-6 (Slater Affidavit).

See Ex. SLATER-1 at 26:6-7 (Slater Affidavit).

165 Ex. SLATER-1 at 28:4-6 (Slater Affidavit).

164

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policy guidance on Formula Rates and Protocols for Formula Rates.166 The PSA §§ 4.13 and 4.14 address the parties’ procedure for providing annual updates to the formula rate in comparison to actuals, and some limited information exchanges, including, importantly, that SWEPCO retains the burden of proof for maintaining the justness and reasonableness of any input that is the subject of a complaint proceeding. However, a comparison between the FERC best practice standards and the PSA reveals instances in which the PSA does not conform to these current FERC standards. Accordingly, the PSA should be amended to require SWEPCO to: a) provide notice of changes in accounting standards to Minden along with each annual trueup; b) provide assurances to Minden of the reasonableness of projected costs; and c) require that the workpapers are transparently linked to the FERC Form 1. The Formula Rate references workpapers, but sample workpapers are not included in the PSA sample Formula Rate.

7.

64.

The Projected Excess Capacity Associated with the Planned Wind Catcher Project Renders the PSA’s Lopsided Stranded Cost Obligation Unjust and Unreasonable; the PSA Should be Amended to Ensure that Minden is Never Required to Pay a Termination Payment for Excess Capacity Installed During the PSA’s Term

The PSA allows either party to declare an Event of Default and an Early

Termination Date if, among other reasons, the other party fails “to perform any material covenant or obligation” of the PSA.167

The Non-Defaulting Party shall have the right to suspend

performance and to exercise available remedies in court, but only SWEPCO has the right to recover “Stranded Costs” from Minden if Minden is the Defaulting Party. Because default scenarios are

166

See FERC Staff Guidance on Formula Rate Updates (July 17, 2014); see also Empire Dist.

Elec. Co., 148 FERC ¶ 61,030 (2014) (Commission Order mandating minimum protocol standards); Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ¶ 61,127 (2012), order on investigation, 143 FERC ¶ 61,149 (2013) (“MISO Investigation Order”), order on reh’g, 146 FERC ¶ 61,209 (2014), order on compliance, 146 FERC ¶ 61,212 (2014) (“MISO Compliance Order”).

167 PSA §§ 7.02, 7.03.

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often contested, it is not unusual for the “defaulting party” to claim that the other party is also in default—essentially asserting a crossclaim that each party is in default.

Accordingly, this

provision is lopsided and significantly undercuts Minden’s right to Early Termination. If Minden declared an Early Termination Date because SWEPCO was not performing a material covenant, SWEPCO could at any time thereafter declare Minden to be the Defaulting Party, thereby imposing undefined Stranded Cost risk on Minden for terminating a contract that SWEPCO is not performing. In a case such as here, where SWEPCO is not effectively hedging the MISO congestion charges, Minden may be justified in declaring an Event of Default; however, this Stranded Cost provision imposes a potential enormous risk on Minden that essentially renders the PSA a contract of adhesion. Thus, the PSA should be amended to provide specificity as to the applicable inputs into the Stranded Cost formula as permitted under PSA § 7.03(b) in an Event of Default so Minden can at least calculate the maximum exposure it might have by declaring an Event of Default. It is unjust and unreasonable that Minden is unable to calculate with reasonable specificity the maximum amount of its risk in Stranded Costs under an Early Termination scenario.

65.

Even more egregious is that the PSA could permit SWEPCO to add excess capacity

from the Wind Catcher Project, even though SWEPCO is aware that this capacity is excess, and include these costs in the Stranded Cost calculation. Although the Stranded Cost regulations provide a formula, [“Stranded Cost Obligation = (Revenue Stream Estimate minus Competitive Market Value) multiplied by Length of Obligation (reasonable expectation period)”],168 this could conceivably include excess capacity added during the PSA term. Thus, Minden seeks clarification,

18 C.F.R. § 35.26(c)(2)(iii) (2018). Although FERC’s Stranded Cost regulations provide a wholesale customer an opportunity to obtain a Stranded Cost estimate, his right is technically only available to customers with contracts predating 1994. 18 C.F.R. § 35.26(c)(4). As such, Minden is not entitled to this opportunity.

168

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through a PSA amendment, that the Revenue Stream Estimate element of the formula should not include any excess capacity added during the PSA term, and especially should exclude costs related to the Wind Catcher Project, a project that is more than likely to result in excess capacity during the term of the PSA.169 To include an iota of excess demand charges into the Stranded Cost Calculation turns the concept on its head and would be completely unjust and unreasonable.

66.

Second, Minden seeks clarification, through a PSA amendment, that the Length of

Obligation in the formula should be no more than three years—commensurate with SWEPCO’s termination rights.170 Having no named term is unjust and unreasonable.

67.

Without these amendments, the PSA is unjust and unreasonable because it does not

provide a reasonable self-help method for Minden to remedy SWEPCO’s poor performance or default under the PSA by declaring an Early Termination date. As established above in Section IV. B., SWEPCO failed to effectively hedge Minden’s MISO congestion charges through the MISO. Although Minden may claim that SWEPCO “failed to perform a material covenant or obligation” of the PSA and declare an Event of Default,171 Minden’s unilateral action could result in Minden paying undefined and potentially extravagant Stranded Costs for exercising this right.172 Without clarity in the Stranded Cost calculation, the PSA is unjust and unreasonable, and imposes lopsided risk on Minden for attempting to terminate a contract that SWEPCO is not performing.

169

Direct Testimony of R. Lane Sisung on Behalf of the Staff of the Louisiana Public Service Commission, LPSC Docket No. U-34619, at 14:3-15:10 (Jan. 22, 2018) (stating that the LPSC Staff does not believe that SWEPCO has shown a specific capacity need for the Wind Catcher Project).

170 PSA § 2.02.

171 See PSA § 7.01(d).

172 See PSA § 7.03(b).

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8.

68.

In These Circumstances, the PSA’s Prohibition on Minden’s Right to File a Price Squeeze Case is Contrary to the Public Interest and Should Be Changed

If FERC rules that the PSA does not mandate SWEPCO to perform the effective

congestion hedging strategy, the “public interest standard” of review requires that Minden be allowed to make a “price squeeze” claim against SWEPCO if MISO congestion volatility leads to a price squeeze such that Minden’s wholesale rates are significantly higher than the surrounding retail rates. In this section, Minden is not filing a “price squeeze” claim, but it is seeking to change the PSA so that Minden may bring a “price squeeze” claim using the less strict “just and reasonable standard” of review in the future if costs associated with the MISO congestion charges result in a price squeeze. The PSA provides that Minden may not seek to prove a price squeeze under the PSA so long as the monthly bill is calculated in accordance with the PSA, and that a party seeking to change this prohibition must prevail under the strict “public interest standard.”

[S]o long as [Minden’s] Monthly Bill is calculated in accordance with this Agreement, Customer shall not allege, in any FERC proceeding, that any of the rates charged hereunder result in price discrimination or anti-competitive effects.

Consistent with the foregoing, absent written agreement of the Parties, the standard of review for changes to . . . the above-enumerated provision[] unilaterally proposed by a Party . . . shall be the public interest standard of review.

PSA § 15.03(g) (citations omitted). If SWEPCO, for example, is willing to perform the effective congestion hedging strategy, but only for an exorbitant cost passed through to Minden, then Minden seeks the right to bring a “price squeeze” claim on just and reasonable grounds, rather than being restricted to proving that the charges violate the public interest. The requested PSA amendment is necessary because retaining the existing language is contrary to the public

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interest.173 Without the amendment, the PSA binds Minden to a price squeeze even though the costs causing the price squeeze are (in SWEPCO’s words) “discriminatory.”174 The PSA should be amended to allow Minden to make a “price squeeze” showing under the “just and reasonable standard” if the price squeeze is caused by costs associated with MISO congestion costs. The PSA is contrary to the public interest if it does not permit any means for redressing the discrimination identified by SWEPCO. V.

OTHER RULE 206 INFORMATION 69.

Minden hereby submits the following additional information required by Rule 206

of the Commission’s Rules of Practice and Procedure: A.

Good Faith Estimate of Financial Impact or Harm (Rule 206(b)(4))

70.

As noted above, Minden estimates that SWEPCO’s excessive ROE under the PSA

produces unjust and unreasonable rates that result in an overpayment to SWEPCO of approximately $405,000 annually.175

Moreover, Minden estimates that the unjust and

unreasonable provisions of the PSA that either require amendments or enforcement of existing provisions result in an annual cost to Minden of approximately $200,000 per year, when each issue is considered separately.176

Further, Minden calculates that the volatility impact to it of

SWEPCO’s failure to effectively hedge MISO congestion is as much as 32% per month, or a swing of $372,000 in costs or $229,000 in benefits each month.177

173

El Paso Natural Gas Co., 99 FERC ¶ 61,244, at p 62,000 (2002); see also UDC v. FERC, 88 F.3d 1105, 1131 (D.C. Cir. 1996), cert. denied, 520 U.S. 1224 (1997).

174 See SWEPCO Complaint at p 1.

175 Ex. SLATER-1 at 30: Table 2 (Slater Affidavit).

176 Ex. SLATER-1 at 30: Table 2 (Slater Affidavit).

177 Ex. SUHANIC-1 at 8:23-9:2 (Suhanic Affidavit).

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B.

Operational or Nonfinancial Impacts (Rule 206(b)(5))

71.

Minden is not aware of any specific practical, operational, or nonfinancial impacts

resulting from the matters Minden raises in this Complaint.

C.

Whether the Matters are Pending in Any Other FERC Proceeding or Forum (Rule 206(b)(6))

72.

Minden is not aware of any pending Commission proceeding challenging

SWEPCO’s ROE for requirements services under the PSA. However, as noted in Paragraph 19, two recent complaints have challenged SWEPCO’s ROE.178 Additionally, as mentioned in Paragraph 20, Minden is aware that a group of wholesale customers challenged SWEPCO’s sister companies’ transmission ROE in a pending complaint.179 Further, as stated in Paragraph 26, SWEPCO recently filed amendments to its PSAs with the Hope Water and Light Commission and City of Bentonville, Arkansas to address the Wind Catcher Project.180 C.

Specific Relief or Remedy Requested (Rule 206(b)(7))

73.

Minden seeks one or more orders from the Commission finding that SWEPCO’s

existing ROE of 11.1% is unjust and unreasonable; establishing a refund effective date as the date of this Complaint; finding that SWEPCO’s ROE applied in the PSA should be no higher than 8.20%; and ordering SWEPCO to pay refunds to Minden, plus interest, based on the difference

178

Complaint of East Texas Electric Cooperative, Inc. and Northeast Texas Electric Cooperative, Inc., Docket No. EL17-85-000 (Aug. 31, 2017); Complaint of East Texas Electric Cooperative, Inc., Docket No. EL17-76-000 (June 5, 2017).

179 See Joint Complaint of American Municipal Power, Inc., FERC Docket No. EL17-13-000 (Oct. 27, 2016).

180 Amended and Restated Power Supply Agreement Between Southwestern Electric Power Company and Hope Water and Light Commission, Docket No. ER18-499-000 (Dec. 21, 2017); Amended and Restated Power Supply Agreement Between Southwestern Electric Power Company and City of Bentonville, Arkansas, Docket No. ER18-500-000 (Dec. 21, 2017); see also Southwestern Electric Power Company Request to Defer Action in Hope PSA Amendment, Docket No. ER18-499-000 (Feb. 14, 2018); Southwestern Electric Power Company Request to Defer Action in Bentonville PSA Amendment, Docket No. ER18-500-000 (Feb. 14, 2018).

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between the requirements service rates for Minden using the current ROE and the ROE established as a result of this complaint.

74.

Minden seeks one or more orders from the Commission finding that the following

provisions of the PSA should be changed, and ordering SWEPCO to pay refunds to Minden, plus interest, based on the difference between the requirements service rates for Minden using the current provisions of the PSA and the rates established using the Minden-recommended amendments to the PSA from the date of the filing of this complaint. a. Amend PSA to permit flow back to Minden of excess accumulated deferred taxes brought about by the Tax Law. b. Amend PSA to require updated depreciation study; and to require depreciation expense to be based solely on the FERC jurisdictional depreciation study. c. Enforce or, if necessary, amend the PSA to stop double collection of depreciation expense on contra-AFUDC. d. Enforce or, if necessary, amend the PSA to forbid inclusion of non-production related CWIP in rate base. e. Amend PSA to provide an offset in rate base for unfunded reserves. f. Amend PSA to adopt formal protocols to control annual review process. g. Amend PSA stranded cost provision to eliminate any potential cost recovery of the Wind Catcher Project or any other excess capacity constructed during the PSA term. h. Amend the PSA to permit Minden to bring a price squeeze claim under the “just and reasonable standard� if such is caused by costs related to MISO congestion.

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75.

Minden seeks one or more orders from the Commission finding that the following

provisions of the PSA should be enforced (if they are not required to be changed), and ordering SWEPCO to pay refunds to Minden, plus interest, from the inception of the PSA in 2009 using the correct inputs to the PSA: a. Disallow double collection of depreciation expense on Contra-AFUDC. b. Disallow non-production related CWIP in rate base.

76.

Minden seeks one or more orders from the Commission finding that the PSA

mandates SWEPCO to implement the effective congestion hedging strategy; or, in the alternative, finding that continuation of the PSA without the effective congestion hedging strategy violates the public interest and justifies termination of the PSA, and terminating the PSA. D.

Documents Supporting Complaint (Rule 206(b)(8))

77.

In support of this complaint, Minden is submitting the testimony and supporting

exhibits and workpapers of David C. Parcell, President and Senior Economist of Technical Associates, Inc., Michele M. Slater, Senior Project Engineer with GDS Associates, and Kevin P. Suhanic, Director of Transmission Services, ACES. E.

Alternative Dispute Resolution (Rule 206(b)(9))

78.

Minden has requested SWEPCO in written and spoken communications to reduce

the ROE because it is excessive and results in overall rates that are unjust and unreasonable.

SWEPCO has flatly rejected these requests. Minden has made numerous repeated, but unsuccessful attempts to convince SWEPCO to implement an effective hedging strategy for MISO congestion, but SWEPCO has not gone further than nominating the ARRs and converting them to FTRs. Minden and SWEPCO have met regularly to explore how to mitigate transmission costs and risk and to explore other options to restore the balance and objectives of the contract, but to

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no avail. Minden has not specifically raised the contract issues mentioned in Paragraphs B and C of the Conclusion with SWEPCO. SWEPCO’s responses to Minden’s overtures made it clear that using the Commission’s Enforcement Hotline or Dispute Resolution services would not resolve this dispute.

VI.

SERVICE AND NOTICE 79.

In accordance with Rule 206(c), Minden has served a copy of this Complaint on

SWEPCO via electronic mail, through its counsel, simultaneously with the Complaint’s filing.

Attached hereto is a Form of Notice suitable for publication in the Federal Register in accordance with Rule 206(b)(10).

CONCLUSION AND REQUEST FOR RELIEF 80.

For the reasons stated herein, Minden respectfully requests that the Commission

summarily act as follows.

A.

Find that under Section 206 the ROE used in calculating SWEPCO’s rates for requirements service to Minden is unjust and unreasonable; set a new just and reasonable ROE for SWEPCO’s use in the PSA at no higher than 8.20%; establish the date of the filing of the Complaint as the refund effective date for this Complaint, and cause notice of the refund effective date to be published in the Federal Register; order SWEPCO to pay refunds, with interest, of the difference between the SWEPCO requirements service rates to Minden at the currently effective ROE and the ROE established in this proceeding, commencing with the refund effective date.

B.

Find under Section 206 that to remain just and reasonable, the PSA should be amended to achieve the following objectives:

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i. Flow back to Minden excess accumulated deferred taxes brought about by the Tax Law; ii. Require the filing of an updated depreciation study; and require the calculation of annual rates using FERC-jurisdictional depreciation study rather than a composite of state commission approved studies; iii. Stop double collection of depreciation expense on contra-AFUDC; iv. Stop including non-production related CWIP in the rate base; v. Offset rate base for unfunded reserves; vi. Adopt protocols to control annual review process; vii. Amend stranded cost provision to eliminate any potential cost recovery of the Wind Catcher Project; viii. Amend the PSA to permit Minden to bring a “price squeeze” claim using the “just and reasonable standard” (rather than the “public interest standard”) if the price squeeze results from costs related to MISO congestion.

C.

Find under Sections 306 and 309 that SWEPCO failed to properly implement the PSA and order SWEPCO to recalculate annual rates and refund any overcollections to Minden, with interest, dating from the inception of the PSA regarding the following issues: 1. SWEPCO should not have collected depreciation expense on contra AFUDC; 2. SWEPCO should have excluded non-production related CWIP from the rate base.

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D.

Find under Sections 306 and 309 that the PSA requires SWEPCO to use the effective hedging strategy for MISO congestion costs and order SWEPCO to perform that strategy for Minden; or in the alternative, find that the PSA violates the public interest by depriving Minden of an effective hedge for the congestion charges through MISO, and terminate the PSA.

E.

Grant such other relief as may be appropriate in the circumstances.

Respectfully submitted,

/s/ Jill M. Barker Kirk Howard Betts Jill M. Barker Mary-Kate Rigney Betts & Holt LLP 1100 17th St., N.W. Suite 901 Washington, D.C. 20036 202-530-3380 kbetts@bettsandholt.com jmb@bettsandholt.com mkrigney@bettsandholt.com Counsel for the City of Minden, Louisiana

February 28, 2018

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ATTACHMENT A FORM OF NOTICE

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UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

EL17-__-000

NOTICE OF COMPLAINT (

)

Take notice that on February 28, 2018, the City of Minden, Louisiana ("Complainant") filed a complaint against Southwestern Electric Power Company (“Respondent”) pursuant to Section 206 of the Federal Power Act seeking Commission order(s) finding (a) that the 11.1% return on equity used in calculating rates for requirements service pursuant to the Power Supply Agreement is unjust and unreasonable; setting a refund effective date as the date of the complaint; setting a new return on equity no higher than 8.20%; and ordering refunds, with interest; (b) that the PSA is unjust and unreasonable and should be amended in certain respects; (c) finding that the annual true-up may have violated the PSA and ordering refunds to the date of the inception of the PSA; (d) finding that the PSA requires SWEPCO to implement the effective MISO congestion hedging strategy; or, in the alternative, that the PSA violates the public interest by depriving Minden of an effective hedge for MISO congestion charges and justifies termination of the PSA; and (e) terminating the PSA. Complainant certifies that copies of the complaint were served on Respondent via electronic mail through its counsel.

Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission’s Rules of Practice and Procedure (18 CFR §385.211 and §385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. The Respondent’s answer and all interventions or protests must be filed on or before the comment date.

The Respondent’s answer, motions to intervene, and protests must be served on the Complainants.

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

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

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

Comment Date: 5:00 pm Eastern Time on (insert date).

Kimberly D. Bose, Secretary

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CERTIFICATE OF SERVICE I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Secretary of the Federal Energy Regulatory Commission.

Dated at Washington, D.C., this 28 day of February, 2018.

/s/ Mary-Kate Rigney Mary-Kate Rigney Betts & Holt LLP 1100 17th St., N.W. Suite 901 Washington, D.C. 20036 202-530-3380 mkrigney@bettsandholt.com Counsel for the City of Minden, Louisiana

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Exhibit No. PARCELL-1 Direct Testimony of David C. Parcell

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Exhibit No. PARCELL-1 UNITED STATES OF AMERICA Page No. 1 of 28 BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

DIRECT TESTIMONY AND EXHIBITS OF DAVID C. PARCELL ON BEHALF OF THE CITY OF MINDEN, LOUISIANA February 28, 2018

EL18-__-000

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Exhibit No. PARCELL-1 Page No. 2 of 28 TABLE OF CONTENTS I.

Introduction

II.

Recommendations and Summary

III.

Economic/Legal Principles and Methodologies

IV.

General Economic Conditions

V.

Selection of Proxy Group

VI.

Discounted Cash Flow Analysis

VII.

Return on Equity Recommendation

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Exhibit No. PARCELL-1 Page No. 3 of 28 LIST OF EXHIBITS Exhibit No.

Description

PARCELL-1

Direct Testimony of David C. Parcell

PARCELL-2

Qualifications of David C. Parcell

PARCELL-3

Economic and Financial Indicators

PARCELL-4

Selection of Proxy Group Members

PARCELL-5

Dividend Yields

PARCELL-6

DCF Cost Rates for Proxy Group Members

PARCELL-7

Long-Term Growth Rates of Gross Domestic Product

PARCELL-8

Workpapers Supporting Direct Testimony of David C. Parcell

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Exhibit No. PARCELL-1 Page No. 4 of 28 1

SUMMARY

2

The purpose of Mr. Parcell’s testimony, filed on behalf of the City of Minden, Louisiana

3

(“Minden”), is to evaluate the current cost of equity for the Southwestern Electric Power Company

4

(“SWEPCO”) in support of the Complaint of Minden to reduce SWEPCO’s base cost of equity

5

(“Base ROE”) recovered through the Power Supply Agreement (“PSA”) between SWEPCO and

6

Minden.

7

Mr. Parcell’s cost of equity analyses are based upon the two-step constant growth

8

discounted cash flow (“DCF”) model. In performing his DCF analyses, Mr. Parcell focuses on the

9

two-step growth and proxy group criteria cited by the Commission in “Opinion 531,”1 the

10

Commission’s orders on rehearing of this opinion, and “Opinion 551.”2

11

Mr. Parcell applies his DCF analyses to a group of 16 proxy electric utilities that were

12

selected using criteria consistent with Opinion 531. These proxy companies have similar credit

13

ratings to SWEPCO and thus have similar risk.

14 15

Using yield data over the six months ending December 31, 2017, and the two sources of expected growth preferred by the Commission [i.e., analysts’ forecasts of earnings per share

Opinion No. 531, Coakley v. Bangor Hydro-Elec. Co., 147 FERC ¶ 61,234 (2014) (“Opinion 531”), order on paper hearing, Opinion No. 531-A, 149 FERC ¶ 61,032 (2014) (“Opinion 531A”), order on reh’g, Opinion No. 531-B, 150 FERC ¶ 61,165 (2015) (“Opinion 531-B”), vacated and remanded sub nom, Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017) (“Emera Maine”).

The Court vacated and remanded the Opinion 531 series of opinions to FERC for further proceedings, but the criteria for proxy group selection and the use of the two-step growth rate in the DCF were not disturbed on appeal.

2 Opinion No. 551, Assoc. of Bus. Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, 156 FERC ¶ 61,234 (2016) (“Opinion 551”), reh’g pending.

1

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Exhibit No. PARCELL-1 Page No. 5 of 28 1

growth (short-term growth) and projections of growth of Gross Domestic Product (long-term

2

growth)], Mr. Parcell determines a cost of equity for the proxy group that results in a median value

3

of 8.20 percent (low DCF value of 6.06 percent and high DCF value of 10.33 percent). All of

4

these DCF results are less than the 11.1 percent Base ROE currently recovered by SWEPCO

5

through its PSA. Commission precedent for a single utility calls for the use of the median DCF

6

cost rate to be used as the Base ROE.

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Exhibit No. PARCELL-1 Page No. 6 of 28 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

EL18-__-000

DIRECT TESTIMONY AND EXHIBITS OF DAVID C. PARCELL ON BEHALF OF THE CITY OF MINDEN, LOUISIANA 1

I.

INTRODUCTION

2

Q.

PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS ADDRESS.

3

A.

My name is David C. Parcell. I am a Principal and Senior Economist of Technical

4

Associates, Inc. My business address is Suite 130, 1503 Santa Rosa Road, Richmond, Virginia

5

23229.

6

Q.

PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE.

7

A.

I hold B.A. (1969) and M.A. (1970) degrees in economics from Virginia Polytechnic

8

Institute and State University (Virginia Tech) and a M.B.A. (1985) from Virginia Commonwealth

9

University. I have been continuously employed by Technical Associates since 1970. The majority

10

of my consulting experience has involved the provision of cost of capital testimony in utility

11

ratemaking proceedings. I have previously testified in over 550 utility proceedings before some

12

50 regulatory agencies in the United States and Canada, including over 25 electric utility, natural

13

gas pipeline, and crude oil pipeline proceedings before the Federal Energy Regulatory Commission

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Exhibit No. PARCELL-1 Page No. 7 of 28 1

(“Commission” or “FERC”). A more complete description of my background and experience is

2

contained in Exhibit No. PARCELL-2.

3

Q.

WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?

4

A.

I have been retained by the City of Minden, Louisiana (“Minden”) to evaluate the base cost

5

of equity (“Base ROE”) for the Southwestern Electric Power Company (“SWEPCO”) in support

6

of the Complaint of Minden to reduce SWEPCO’s Base ROE recovered through the Power Supply

7

Agreement (“PSA”) between SWEPCO and Minden.

8

Q.

WHAT IS THE BASE ROE OF SWEPCO AT THIS TIME?

9

A.

The current Base ROE for SWEPCO, relative to its PSA, is 11.1 percent. This was

10

established in 2010 in connection with the implementation of the PSA.

11

Q.

12

DOES YOUR ANALYSIS INDICATE THAT THE BASE ROE IS UNJUST AND UNREASONABLE?

13

A.

14

SWEPCO, have declined significantly. It logically follows that the Base ROE should be lower

15

today than was the case in 2010.

16

Yes. Since the Base ROE was established in 2010, capital costs for utilities, such as

As is shown in my testimony, the current Base ROE for SWEPCO, as derived from an

17

application of the Commission-preferred discounted cash flow (“DCF”) model, is in a range of

18

6.06 percent to 10.33 percent (8.20 percent median and 8.19 percent mid-point). Both the median

19

and mid-point, as well as the upper end of this range are well below the currently-authorized 11.1

20

percent Base ROE of SWEPCO’s PSA. In addition, only two of the 14 DCF cost rates I derive

21

are higher than 10.0 percent.

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Exhibit No. PARCELL-1 Page No. 8 of 28 1

Q.

HAVE YOU PREPARED ANY EXHIBITS IN SUPPORT OF YOUR TESTIMONY?

2

A.

Yes, I have prepared five exhibits, with the first identified as Exhibit PARCELL-3 and the

3

last identified as Exhibit PARCELL-8. The information contained in my testimony and exhibits

4

is correct to the best of my knowledge and belief.

5

Q.

HOW IS YOUR DIRECT TESTIMONY ORGANIZED?

6

A.

My testimony is organized into seven parts as follows:

7

I.

Introduction

8

II.

Recommendations and Summary

9

III.

Economic/Legal Principles and Methodologies

10

IV.

General Economic Conditions

11

V.

Selection of Proxy Group

12

VI.

Discounted Cash Flow Analysis

13

VII.

Return on Equity Recommendation

14

II.

RECOMMENDATIONS AND SUMMARY

15

Q.

PLEASE SUMMARIZE YOUR RECOMMENDATIONS, BOTH FROM A

16

METHODOLOGICAL STANDPOINT AND AS TO THE COST OF CAPITAL

17

FOR SWEPCO.

18

A.

19

expressed a preference for the two-stage DCF methodology in proceedings involving public (i.e.,

20

electric) utilities. See Opinion 551,3 adhering to proxy group selection criteria and the two-step

3

My Base ROE recommendation is based on my understanding that the Commission has

Opinion No. 551, 156 FERC ¶ 61,234.

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Exhibit No. PARCELL-1 Page No. 9 of 28 1

DCF method adopted by the Commission in Opinions 531, 531-A and 531-B.4 In these Opinions

2

the Commission adopted a new return on equity methodology for public utilities and set forth the

3

precedential elements of its preferred approach for implementing the DCF methodology for a

4

public utility. In Emera Maine v. FERC, the Court of Appeals for the DC Circuit examined

5

Opinion 531, but did not address the Commission’s adoption of the two-step DCF method because

6

this aspect of Opinion 531 was not challenged.5 Therefore, the two-step DCF method continues to

7

be the appropriate methodology for examining electric utility ROEs.6 My analyses in this

8

proceeding conform to the Commission’s decisions in Opinion 551 and the 531 series of Opinions

9

regarding proxy group selection and two stage growth method, specific elements of the new

10

methodology that were not disturbed in Emera Maine.

11

Q.

12

WHAT IS YOUR UNDERSTANDING OF THE COMMISSION’S CURRENT ROE METHODOLOGY FOR PUBLIC UTILITIES?

13

A.

14

is to be applied in public utility cases.7 My understanding of the Commission’s current ROE

15

methodology, as well as my implementation of this ROE methodology in my analyses of

16

SWEPCO’s cost of equity, is based upon the following principles and directives:

4

As noted above, the Commission has changed its approach on the DCF methodology as it

Opinion No. 531, 147 FERC ¶ 61,234; Opinion No. 531-A, 149 FERC ¶ 61,032; Opinion No. 531-B, 150 FERC ¶ 61,165.

5 Emera Maine, 854 F.3d at 26-27 (vacating and remanding the Opinion 531 series of opinions to the Commission).

6 See Belmont Mun. Light Dep’t v. Cent. Maine Power Co., 159 FERC ¶ 63,039, at P 10, Docket No. EL16-64-000 (2017) (concurrence of J. Glazer) (“Emera Maine did not eliminate the Commission’s adoption . . . of the “two step” DCF analysis.”).

7 Opinion No. 531, 147 FERC ¶ 61,234, at P 7.

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Exhibit No. PARCELL-1 Page No. 10 of 28 1

The Commission now adopts the same two-step DCF methodology used in natural

2

gas and oil pipeline cases for public utilities.8

3 4

Proxy group composition – the relevant proxy group should be a national sample

5

of utilities classified by Value Line as electric utilities;9 that have corporate credit

6

ratings of both S&P and Moody’s that are within one notch of the respective electric

7

utility’s credit ratings;10 include companies that have paid dividends for at least six

8

months without a dividend cut;11 exclude companies that are engaged in merger

9

and acquisition activity significant enough to distort the DCF inputs;12 and exclude

10

companies whose DCF results do not pass threshold tests of economic logic.13 The

11

purpose of the proxy company selection process is to select a group of companies

12

with similar risk to the subject utility.

13 14

Dividend yield component – each proxy company’s dividend yield is determined

15

by calculating monthly average stock prices over a six-month period and dividing

16

these into the monthly annualized dividend rates and calculating a six-month

17

average dividend yield.14

8

Id. at P 39.

Id. at P 102.

10 Id. at P 107.

11 Id. at P 112.

12 Id. at P 114.

13 Id. at P 92.

14 Id.at P 77.

9

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Exhibit No. PARCELL-1 Page No. 11 of 28 1

Short-term growth rates – the short-term growth rate should reflect the five-year

2

IBES earnings per share (“EPS”) projections as published by Yahoo! Finance.15

3 4

Long-term growth rates – the long-term growth rate should reflect the projected

5

long-term growth in gross domestic product (“GDP”).16

6 7

Weighting of growth rates – short-term growth is weighted two-thirds and long

8

term growth is weighted one-third.17

9 10

Low-end outlier test – any proxy company DCF result is excluded if it is within

11

100 basis points of the most recent six-month average yield of public utility bonds

12

of the same rating as the subject electric utility.18

13 14

Placement of Utility’s ROE within zone of reasonableness – the Commission

15

typically sets the base ROE with regard to a single entity (i.e., SWEPCO) at the

16

median of the zone of reasonableness.19

15

Id. at P 89.

Id. at P 8.

17 Id. at P 39.

18 Id. at P 122.

19 Id. at P 26 (“If the proceeding involves a single company, the Commission sets the ROE for the electric utility at the median value of the range of reasonable returns.”) (citing Southern Cal. Edison Co. v. FERC, 717 F.3d 177, 183-87 (D.C. Cir. 2013) (emphasis added).

16

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Exhibit No. PARCELL-1 Page No. 12 of 28 1

Using this methodological approach, I have computed a range of ROE figures bounded

2

by a low of 6.06 percent and a high of 10.33 percent. The median ROE is 8.20 percent. These

3

are well below the 11.1 percent Base ROE in SWEPCO’s PSA. Consistent with Commission-

4

precedent, which states that the median DCF value is appropriate for a single entity, the 8.20

5

percent DCF value is proper for SWEPCO.

6

III.

ECONOMIC/LEGAL PRINCIPLES AND METHODOLOGIES

7

Q.

WHAT IS YOUR UNDERSTANDING OF THE ECONOMIC AND REGULATORY

8

PRINCIPLES WHICH UNDERLIE THE CONCEPT OF A FAIR RATE OF

9

RETURN FOR A REGULATED UTILITY? Regulated public utilities primarily have their rates established using the “rate base-rate of

10

A.

11

return” concept. Under this method, utilities are allowed an opportunity to recover their prudently

12

incurred operating expenses, taxes and depreciation, and are granted an opportunity to earn a fair

13

rate of return on the assets utilized (i.e., rate base) in providing service to their customers. The

14

rate base is derived from the assets side of the balance sheet as a dollar amount and the rate of

15

return is developed from the liabilities/owners’ equity side of the balance sheet as a percentage.

16

The rate of return is developed from the cost of capital, which is estimated by weighting the capital

17

structure components (i.e., debt, preferred stock, and common equity) by their percentages in the

18

capital structure and multiplying these by their cost rates. This outcome is also known as the

19

weighted cost of capital.

20

Technically, the fair rate of return is a regulatory and accounting concept which refers to

21

an ex post (i.e., after the fact) earned return on an asset base, while the cost of capital is an

22

economic and financial concept which refers to an ex ante (i.e., before the fact) expected or

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Exhibit No. PARCELL-1 Page No. 13 of 28 1

required return on a liability base. However, in regulatory proceedings, the two terms are often

2

used interchangeably, and I apply that usage in my testimony.

3

From an economic standpoint, a fair rate of return is normally interpreted to incorporate

4

the concepts of financial integrity, capital attraction, and comparable returns for similar risk

5

investments. These concepts are derived from economic and financial theory and are generally

6

implemented using financial models and economic concepts, such as the DCF methodology.

7

From a regulatory standpoint, two U.S. Supreme Court decisions are universally cited as

8

providing the legal standards for a fair rate of return. The first is Bluefield Water Works &

9

Improvement Company v. Public Service Commission of the State of West Virginia.

10

20

decision, the Court stated:

11

What annual rate will constitute just compensation depends upon many

12

circumstances and must be determined by the exercise of a fair and

13

enlightened judgment, having regard to all relevant facts. A public utility

14

is entitled to such rates as will permit it to earn a return on the value of the

15

property which it employs for the convenience of the public equal to that

16

generally being made at the same time and in the same general part of the

17

country on investments in other business undertakings which are attended

18

by corresponding risks and uncertainties; but it has no constitutional right

19

to profits such as are realized or anticipated in highly profitable enterprises

20

or speculative ventures. The return should be reasonably sufficient to assure

20

262 U.S. 679 (1923) (“Bluefield�).

In this

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Exhibit No. PARCELL-1 Page No. 14 of 28 1

confidence in the financial soundness of the utility, and should be adequate,

2

under efficient and economical management, to maintain and support its

3

credit and enable it to raise the money necessary for the proper discharge of

4

its public duties. A rate of return may be reasonable at one time, and

5

become too high or too low by changes affecting opportunities for

6

investment, the money market, and business conditions generally.21 The second decision is Federal Power Commission v. Hope Natural Gas Company.22 In

7 8

this decision, the U.S. Supreme Court stated:

9

The rate-making process under the [Natural Gas] Act, i.e., the fixing of ‘just

10

and reasonable’ rates, involves a balancing of the investor and consumer

11

interests . . . . From the investor or company point of view it is important

12

that there be enough revenue not only for operating expenses but also for

13

the capital costs of the business. These include service on the debt and

14

dividends on the stock. By that standard the return to the equity owner

15

should be commensurate with returns or investments in other enterprises

16

having corresponding risks. That return, moreover, should be sufficient to

17

assure confidence in the financial integrity of the enterprise, so as to

18

maintain its credit and to attract capital.23

19

This case affirmed the primary standards of the Bluefield case, as well as the importance

21

Id. at 692-693.

320 U.S. 591 (1944) (“Hope”).

23 Id. at 603.

22

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Exhibit No. PARCELL-1 Page No. 15 of 28 1

of taking consumer interests into account.

2 3

The Bluefield and Hope decisions, as well as subsequent cases which cite these decisions, have identified three economic parameters relevant to the determination of a fair rate of return:

4

1.

Comparable earnings;

5

2.

Financial integrity; and

6

3.

Capital attraction.

7

Q.

WHAT IS THE COMMISSION’S PREFERRED APPROACH TO THE

8

DETERMINATION OF THE COST OF COMMON EQUITY FOR PUBLIC

9

UTILITIES?

10

A.

The Commission has, for a number of years, expressed a preference for the DCF

11

methodology for use in estimating the cost of equity for public utilities. Since the Commission’s

12

1978 decision in Minnesota Power and Light Co.,24 FERC has relied on the DCF as its principal

13

methodology. The Commission has also relied upon the DCF as its principal methodology for

14

interstate natural gas and oil pipelines. As noted above, in Opinion 531 the Commission indicated

15

that it is now applying the same DCF methodology that it has historically applied to natural gas

16

and oil pipelines to public utilities.

17

The Commission-preferred formulation for the DCF method (as originally applied to gas

18

and oil pipelines) was initially delineated in Opinion 414-A,25 using the following DCF formula: DCF 

19 20

where: 24 25

D (1  .5 g )  [( g s x 2)  g1 ] / 3 P

D/P = average dividend yield for latest six month period

3 FERC ¶ 61,045 (1978).

Transcontinental Gas Pipeline Corp., 84 FERC ¶ 61,084 (1998).

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Exhibit No. PARCELL-1 Page No. 16 of 28 1 2 3 4 5 6 7 8 9 10 11 12

This methodology has been followed by the Commission in interstate natural gas pipeline

13

cases since Opinion 414-A. As noted in Opinion 531, this is now the preferred DCF methodology

14

for public utilities and was adopted in Opinion 551.26

15

IV.

GENERAL ECONOMIC CONDITIONS

16

Q.

ARE

g = average growth rate gs = short-term growth, as measured by median 5-year EPS (earnings per share) projections, as tabulated by IBES

gl = long-term growth, as measured by average estimates of GDP (gross domestic product) growth for period 5-20 years into future, as tabulated by EIA, Social Security Administration, and IHS Global Insight

17

ECONOMIC

AND

FINANCIAL

CONDITIONS

IMPORTANT

IN

DETERMINING THE COSTS OF CAPITAL FOR A PUBLIC UTILITY?

18

A.

Yes. The costs of capital for both fixed-cost (debt and preferred stock) components and

19

common equity are determined in part by current and prospective economic and financial

20

conditions. At any given time, each of the following factors has an influence on the costs of

21

capital:

22

•

The level of economic activity (i.e., growth rate of the economy);

23

•

The stage of the business cycle (i.e., recession, expansion, or transition);

24

•

The level of inflation;

25

•

The level and trend of interest rates; and,

26

Opinion No. 551, 156 FERC ¶ 61,234 (2016).

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Exhibit No. PARCELL-1 Page No. 17 of 28 •

1 2

Current and expected economic conditions.

My understanding is that this position is consistent with the Bluefield decision that noted

3

“[a] rate of return may be reasonable at one time and become too high or too low by changes

4

affecting opportunities for investment, the money market, and business conditions generally.”27

5

Q.

6

WHAT INDICATORS OF ECONOMIC AND FINANCIAL ACTIVITY DID YOU EVALUATE IN YOUR ANALYSES?

7

A.

8

period because it permits the evaluation of economic conditions over four full business cycles

9

plus the current cycle allowing for an assessment of changes in long-term trends. Consideration

10

of economic/financial conditions over a relatively long period of time allows me to assess how

11

such conditions have had impacts on the level and trends of the costs of capital. This period also

12

approximates the beginning and continuation of active rate case activities by public utilities that

13

generally began in the mid-1970s.

14

I examined several sets of economic statistics from 1975 to the present. I chose this time

A business cycle is commonly defined as a complete period of expansion (recovery and

15

growth) and contraction (recession). A full business cycle is a useful and convenient period over

16

which to measure levels and trends in long-term capital costs because it incorporates the cyclical

17

(i.e., stage of business cycle) influences and, thus, permits a comparison of structural (or long-

18

term) trends.

27

Bluefield, 262 U.S. 679, 693 (1923).

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Exhibit No. PARCELL-1 Page No. 18 of 28 1

Q.

2 3

PLEASE DESCRIBE THE TIMEFRAMES OF THE FOUR PRIOR BUSINESS CYCLES AND THE CURRENT CYCLE.

A.

The four prior complete cycles and current cycle cover the following periods:

4 Business Cycle Expansion Cycle Contraction Period 1975-1982 Mar. 1975-July 1981 Aug. 1981-Oct. 1982 1982-1991 Nov. 1982-July 1990 Aug. 1990-Mar. 1991 1991-2001 Mar. 1991-Mar. 2001 Apr. 2001-Nov. 2001 2001-2009 Nov. 2001-Nov. 2007 Dec. 2007-June 2009 Current July 2009 Source: The National Bureau of Economic Research, “U.S. Business Cycle Expansions and Contractions.”28 5 6

Q.

DO YOU HAVE ANY GENERAL OBSERVATIONS CONCERNING THE

7

RECENT TRENDS IN ECONOMIC CONDITIONS AND THEIR IMPACT ON

8

CAPITAL COSTS OVER THIS BROAD PERIOD?

9

A.

Yes, I do. From the early 1980s until the end of 2007, the United States economy

10

enjoyed general prosperity and stability. This period was characterized by longer economic

11

expansions, relatively tame contractions, low and declining inflation, and declining interest rates

12

and other capital costs.

13

However, in 2008 and 2009 the economy declined significantly, initially as a result of the

14

2007 collapse of the “sub-prime” mortgage market and the related liquidity crisis in the financial

15

sector of the economy. Subsequently, this financial crisis intensified with a more broad-based

16

decline initially based on a substantial increase in petroleum prices and a dramatic decline in the

17

U.S. financial sector, culminating with the collapse and/or bailouts of a significant number of

28

http://www.nber.org/cycles/cyclesmain.html.

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Exhibit No. PARCELL-1 Page No. 19 of 28 1

well-known institutions such as Bear Stearns, Lehman Brothers, Merrill Lynch, Freddie Mac,

2

Fannie Mae, AIG and Wachovia. The recession also witnessed the demise of national companies

3

such as Circuit City and the bankruptcies of automotive manufacturers Chrysler and General

4

Motors.

5

This decline has been described as the worst financial crisis since the Great Depression

6

and has been referred to as the “Great Recession.” Beginning in 2008, the U.S. and other

7

governments implemented unprecedented actions to attempt to correct or minimize the scope and

8

effects of this recession.

9

The recession reached its low point in mid-2009, when the economy began to expand

10

again, although at a slow and uneven rate. However, the length and severity of the recession, as

11

well as a relatively slow and uneven recovery, indicate that the impacts of the recession have

12

been and will be felt for an extended period of time.

13

Q.

14

PLEASE DESCRIBE RECENT AND CURRENT ECONOMIC AND FINANCIAL CONDITIONS AND THEIR IMPACT ON THE COSTS OF CAPITAL.

15

A.

16

investment returns and a corresponding reduction in capital costs. This decline is evidenced by a

17

decline in both short-term and long-term interest rates and the expectations of investors and is

18

reflected in cost of equity model results (such as DCF, CAPM and CE). Regulatory agencies

19

throughout the U.S. have recognized the decline in capital costs by authorizing lower returns on

20

equity for regulated utilities in each of the last several years.29

29

One impact of the Great Recession has been a reduction in actual and expected

Regulatory Research Associates, “Regulatory Focus.” October 26, 2017.

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Exhibit No. PARCELL-1 Page No. 20 of 28 1

Exhibit No. PARCELL-3 shows several sets of relevant economic and financial statistics

2

for the cited time periods. Page 1 contains general macroeconomic statistics, page 2 shows

3

interest rates, and page 3 contains equity market statistics.

4

Page 1 shows that in 2007 the economy stalled and subsequently entered a significant

5

decline, as indicated by the lower growth rate in real (i.e., adjusted for inflation) Gross Domestic

6

Product (“GDP”), lower levels of industrial production, and an increase in the unemployment

7

rate. This recession lasted until mid-2009, making it a longer-than-normal recession, as well as a

8

much deeper recession. Since then, economic growth has been somewhat erratic, and the

9

economy has grown slower than in prior expansions.

10

Page 1 also shows the rate of inflation. As reflected in the Consumer Price Index

11

(“CPI”), inflation rose significantly during the 1975-1982 business cycle and reached double-

12

digit levels in 1979-1980. The rate of inflation has declined substantially since 1981. Since

13

2008, the CPI has been 3 percent or lower, with both 2014 and 2015 being below 1 percent and

14

2016 being 2.1 percent. It is thus apparent that the rate of inflation has generally been declining

15

over the past several business cycles. Recent and current levels of inflation are at the lowest

16

levels of the past 35 years, which is reflective of lower capital costs.30

30

The rate of inflation is one component of interest rate expectations of investors, who generally expect to receive a return in excess of the rate of inflation. Thus, a lower rate of inflation has a downward impact on interest rates and other capital costs.

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Exhibit No. PARCELL-1 Page No. 21 of 28 1

Q.

2

WHAT HAVE BEEN THE TRENDS IN INTEREST RATES OVER THE FOUR PRIOR BUSINESS CYCLES AND AT THE CURRENT TIME?

3

A.

Page 2 shows several series of interest rates. Both short-term and long-term rates rose

4

sharply to record levels in 1975-1981 when the inflation rate was high. Interest rates have

5

declined substantially in conjunction with the corresponding declines in inflation since the early

6

1980’s.

From 2008 to late 2015, the Federal Reserve System (“Federal Reserve”) maintained the

7 8

Federal Funds rate (i.e., short-term interest rate) at 0.25 percent, an all-time low. The Federal

9

Reserve has subsequently raised the Federal Funds rate on five occasions between December of

10

2015 and December of 2017.31 The Federal Reserve also purchased U.S. Treasury securities to

11

stimulate the economy.32

12

As seen on page 2, since 2013 both U.S. and corporate bond yields declined to their

13

lowest levels in the past four business cycles and in more than 35 years. Even with the

14

“tapering” and eventual ending of the Federal Reserve’s Quantitative Easing program, as well as

15

the Federal Reserve’s raising of the Federal Funds rate, interest rates have remained low.

16

Currently, both government and utility long-term lending rates remain near historically low

17

levels, again reflective of lower capital costs.

31

These were December 2015, December 2016, March 2017, June 2017, and December 2017..

This is referred to as Quantitative Easing which was comprised of three “rounds”. In “round” 3, known as QE3, the Federal Reserve initially purchased some $85 billion of U.S. Treasury Securities per month in order to stimulate the economy. The Federal Reserve eventually “tapered” its purchase of U.S. Treasury securities through October 2014, at which time Quantitative Easing ended.

32

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Exhibit No. PARCELL-1 Page No. 22 of 28 1

Q.

2

WHAT DOES EXHIBIT NO. PARCELL-3 SHOW FOR TRENDS OF COMMON SHARE PRICES?

3

A.

4

prices were essentially stagnant during the high inflation/high interest rate environment of the

5

late 1970s and early 1980s. The 1983-1991 business cycle and the more recent cycles witnessed

6

a significant upward trend in stock prices. The beginning of the recent financial crisis saw stock

7

prices decline precipitously as stock prices in 2008 and early 2009 were down significantly from

8

peak 2007 levels, reflecting the financial/economic crisis. Beginning in the second quarter of

9

2009, prices recovered substantially and ultimately reached and exceeded the levels achieved

10

prior to the “crash.” On the other hand, recent equity markets have been somewhat volatile.

11

Q.

12

Page 3 shows several series of common stock prices and ratios. These indicate that stock

WHAT CONCLUSIONS DO YOU DRAW FROM YOUR DISCUSSION OF ECONOMIC AND FINANCIAL CONDITIONS?

13

A.

Recent economic and financial circumstances have differed from any that have prevailed

14

since at least the 1930s. In conjunction with the Great Recession, there was a decline in capital

15

costs and returns which significantly reduced the value of most retirement accounts, investment

16

portfolios and other assets. One significant aspect of this has been a decline in investor

17

expectations of returns33 even with the return of stock prices to levels achieved prior to the

18

“crash.”34 This is evident in several ways: (1) lower interest rates on bank deposits; (2) lower

See, e.g., Kiplinger’s Personal Finance, “Investors Brace for Smaller Gains, Focus on LongTerm,” August 30, 2015.

34 See e.g., Vanguard News & Perspectives. “Stabilization, Not Stagnation: Expect Modest Returns,” March 30, 2017, www.personal.vanguard.com/us/insights/artical/infographicstabilization-032017.

33

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Exhibit No. PARCELL-1 Page No. 23 of 28 1

interest rates on U.S. Treasury and utility bonds; and (3) lower authorized ROEs by regulatory

2

commissions. Finally, as noted above, utility bond interest rates are currently at levels below

3

those prevailing prior to the financial crisis of late 2008 to early 2009 and are near the lowest

4

levels in the past 35 years. Even with the increase in long-term rates in late 2016, utility bond

5

yields still remain well below the levels prevailing at the beginning of 2016. Furthermore, long-

6

term utility bond rates in 2017 decreased, notwithstanding the Fed’s increase in short-term rates

7

as evidenced by the December 2017 yield on BBB-rated utility bonds (i.e., 4.14 percent) being

8

below the levels prevailing at the beginning of 2017 (i.e., 4.62 percent), as shown on my Exhibit

9

No. PARCELL-3.

10

Q.

11

HOW DO THESE ECONOMIC/FINANCIAL CONDITIONS IMPACT THE DETERMINATION OF A COST OF EQUITY FOR REGULATED UTILITIES?

12

A.

The costs of capital for regulated utilities have declined in recent years. For example, the

13

current interest costs that utilities pay on new debt remain near the low point of the last several

14

decades. In addition, the results of the traditional cost of equity models (i.e., DCF, CAPM and

15

CE) are lower than was the case prior to the Great Recession. In light of this, it is not surprising

16

that the average equity returns authorized by state regulatory agencies have declined and

17

continued to decline through 2017, as follows: 35 Year 2007 2008 2009 2010 2011 35

Electric 10.31% 10.37% 10.52% 10.29% 10.19%

Natural Gas 10.22% 10.39% 10.22% 10.15% 9.91%

Regulatory Research Associates, “Regulatory Focus”, October 26, 2017, General Rate Cases.

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Exhibit No. PARCELL-1 Page No. 24 of 28 2012 2013 2014 2015 2016 2017 (3Q)

10.01% 9.81% 9.75% 9.60% 9.60% 9.63%

9.93% 9.68% 9.78% 9.60% 9.53% 9.75%

1 2

V.

SELECTION OF PROXY GROUP

3

Q.

HOW HAVE YOU APPROACHED THE ISSUE OF SELECTING A PROXY

4

GROUP FOR ESTIMATING THE COST OF COMMON EQUITY OF THE

5

SWEPCO? Consistent with the Commission’s general practice, it is customary to select a group of

6

A.

7

electric utility proxy companies to which the DCF methodology is applied. Cost of capital

8

witnesses, including myself, have traditionally evaluated a “proxy group” of publicly-traded

9

companies that are engaged in electric utility operations. The purpose of selecting a proxy group

10

is to develop a set of companies who have similar risk to the subject utility; whose DCF results

11

can then be applied as the cost of equity for the subject utility.

12

Q.

13

WHAT APPROACH HAS THE COMMISSION TAKEN IN ITS MOST RECENT DECISIONS REGARDING THE COMPOSITION OF THE PROXY GROUP?

14

A.

In Opinion 531, the Commission identified a number of criteria it considered relevant in

15

selecting a proxy group for electric utilities. The Commission stated that the following criteria

16

were being used in selecting a proxy group for electric utilities:

17

(1)

A national comparable group of electric utilities covered by Value Line;

18

(2)

Electric utilities that paid dividends over the past six months and did not

19

reduce dividends during this period;

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Exhibit No. PARCELL-1 Page No. 25 of 28 1

(3)

2

level above or below the rating of the utility under evaluation; and

3

(4)

4 5

Electric utilities with Moody’s and S&P corporate credit ratings within one

Electric utilities that are not engaged in merger or acquisition (“M&A”) activity significant enough to distort the DCF inputs.

Q.

6

HOW HAVE YOU ESTABLISHED A PROXY GROUP OF COMPANIES IN THE CURRENT PROCEEDING?

7

A.

8

SWEPCO. This is shown on Exhibit No. PARCELL-4. As this indicates, the credit ratings of

9

SWEPCO are currently A- by Standard & Poor’s (“S&P”) and Baa2 by Moody’s Investors Service

10

(“Moody’s”). As indicated above, Commission-precedent indicates that proxy group members for

11

SWEPCO should have S&P ratings of BBB+, A-, or A (i.e., within one “notch” of SWEPCO’s A-

12

rating) and Moody’s ratings of Baa3, Baa2 or Baa1 (i.e., within one “notch” of SWEPCO’s Baa2

13

rating).

14

I began the selection of a proxy group by identifying and examining the credit ratings of

I identified all of the companies that are identified by Value Line as “electric utilities.”

15

These 40 companies are shown on Exhibit No. PARCELL-4. I then screened these 40 companies

16

using the selection criteria cited by the Commission in Opinion 531 and adopted by the

17

Commission in Opinion 551.

18

The first screening criterion I considered is the set of credit ratings of the potential proxy

19

companies. As noted above, Exhibit No. PARCELL-4 indicates the corporate credit ratings for

20

each of the 40 companies. Using the Opinion 531 criteria, it is appropriate to apply a screen of

21

credit ratings of BBB+ to A for S&P and Baa3 to Baa1 for Moody’s. Twenty of the 40 companies

22

have credit ratings that satisfy this screening criteria.

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Exhibit No. PARCELL-1 Page No. 26 of 28 1

The second screening criterion is the payment of dividends over the past six months with

2

no reduction of dividends over this period. No potential proxy companies were eliminated due to

3

this screening criterion.

4

The third screening criterion is whether a potential proxy company is “engaged in merger

5

and acquisition activity significant enough to distort the DCF inputs.” This screening criterion

6

lacks the quantitative specificity of the other screening criteria. I have listed on Exhibit No.

7

PARCELL-4 the M&A activity that Value Line reports as involving public utility M&As. As can

8

be seen from Exhibit No. PARCELL-4, three potential proxy companies are eliminated due to

9

M&A activity. Finally, one company (Avangrid) was only formed in late 2015 as a result of a

10

merger at the behest of its parent company, Iberdrola S.A. (a Spanish entity). No financial data

11

exists prior to that time. This company is not “publicly traded” in the same way as the other United

12

States based proxy companies because it is 81.5% owned by its foreign parent. The above screens

13

result in a proxy group made up of 16 electric utilities. This set of 16 companies has similar or

14

comparable risk to SWEPCO.

15

VI.

DISCOUNTED CASH FLOW ANALYSIS

16

Q.

PLEASE DESCRIBE YOUR DCF CALCULATIONS.

17

A.

My DCF calculations are shown in Exhibit Nos. PARCELL-5, PARCELL-6, and

18

PARCELL-7. I use the DCF model that the Commission employs: DCF 

19 20 21 22 23

where:

D (1  .5 g )  [( g s x 2)  g1 ] / 3 P

D/P = dividend yield based upon the current annualized dividends per share (“DPS”) and the average stock prices for the six month period July 2017 to December 2017;

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Exhibit No. PARCELL-1 Page No. 27 of 28 1 2 3 4 5

g = a two-stage growth rate comprised of the average of short-term (weighted two-thirds) and long-term (weighted one-third) expected growth;

6 7 8 9

gl = long-term growth in GDP = 4.34 percent, as developed on Exhibit No. MIN-7.

Q.

DID YOU EXCLUDE ANY DCF RESULTS FROM YOUR ANALYSES?

10

A.

Yes, I did. Consistent with the Commission’s Opinion 531, I would have excluded

11

any DCF results that are less than 100 basis points above the yield on BBB rated public utility debt

12

(i.e., 5.23 percent) for the past six-months (July 2017 – December 2017), as shown on Exhibit No.

13

MIN-6. There were no such DCF results. I did exclude two companies who had a negative short-

14

term EPS growth rate forecast. This left a proxy group for DCF-purposes of 14 companies.

15

Q.

PLEASE DESCRIBE YOUR DCF RESULTS.

16

A.

My DCF results, as shown on Exhibit No. MIN-6, can be summarized as follows:

gs = short-term growth, using EPS 5-year projections; and

Proxy Group

Low

High

Mid-Point

Median

6.06%

10.33%

8.19%

8.20%

17 18

All of the above DCF results are well below the 11.1 percent Base ROE in SWEPCO’s

19

PSA.

20

VII.

RETURN ON EQUITY RECOMMENDATION

21

Q.

PLEASE

22

SUMMARIZE

YOUR

DCF

RESULTS

AND

YOUR

RECOMMENDATIONS. My DCF analysis reflects the application of the Commission’s two-step constant growth

23

A.

24

DCF methodology to my proxy group. This produced DCF values of well below SWEPCO’s Base

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Exhibit No. PARCELL-1 Page No. 28 of 28 1

ROE in its PSA.

2

Q.

3

WERE YOU RECENTLY INVOLVED IN ANY OTHER PROCEEDINGS INVOLVING SWEPCO?

4

A.

5

Deregulation (“CARD”) in a SWEPCO proceeding before the Texas Public Utility Commission

6

(Docket No. 46449). In that proceeding, I recommended a return on equity for SWEPCO of 9.3

7

percent, relative to the 10.0 percent return on equity requested by the Company in that proceeding.

8

Q.

9

Yes. On April 25, 2017 I filed testimony on behalf of the Coalition Advocating Reasonable

WHY DID YOU RECOMMEND A RETURN ON EQUITY IN THE TEXAS RETAIL PROCEEDING THAT IS HIGHER THAN YOUR RECOMMENDATION

10

IN YOUR CURRENT TESTIMONY?

11

A.

The reason for the difference in my respective recommendations is primarily due to the

12

specific directives that FERC provides for applying its preferred DCF methodology. In my current

13

testimony, I am implementing the FERC methodology carefully and consistently with recent

14

precedents, even though the output differs from my recommendation in the Texas retail

15

proceeding. I have conducted my current DCF analyses using the methodology that FERC has

16

directed for use in establishing the return on equity for electric utilities. It would be unfair and

17

create regulatory uncertainty for FERC apply different methodologies among similar utilities. As

18

a result, the Texas recommendation is not comparable to my FERC recommendation, as the

19

procedure and process for establishing each are different and unique to each jurisdiction.

20

Q.

DOES THIS CONCLUDE YOUR PRE-FILED TESTIMONY?

21

A.

Yes, it does.

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Exhibit No. PARCELL-2 Qualifications of David C. Parcell

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Exhibit No. PARCELL-2 Page No. 1 of 6 BACKGROUND AND EXPERIENCE PROFILE DAVID C. PARCELL, MBA, CRRA PRESIDENT/SENIOR ECONOMIST EDUCATION 1985 1970 1969

POSITIONS Present 2007-2016 1995-2007 1993-1995 1972-1993 1969-1972 1968-1969

M.B.A., Virginia Commonwealth University M.A., Economics, Virginia Polytechnic Institute and State University, (Virginia Tech) B.A., Economics, Virginia Polytechnic Institute and State University, (Virginia Tech)

Principal, Technical Associates, Inc. President, Technical Associates, Inc. Executive Vice President and Senior Economist, Technical Associates, Inc. Vice President and Senior Economist, C. W. Amos of Virginia Vice President and Senior Economist, Technical Associates, Inc. Research Economist, Technical Associates, Inc. Research Associate, Department of Economics, Virginia Polytechnic Institute and State University

ACADEMIC HONORS Omicron Delta Epsilon - Honor Society in Economics Beta Gamma Sigma - National Scholastic Honor Society of Business Administration Alpha Iota Delta - National Decision Sciences Honorary Society Phi Kappa Phi - Scholastic Honor Society PROFESSIONAL DESIGNATIONS Certified Rate of Return Analyst - Founding Member RELEVANT EXPERIENCE Financial Economics -- Advised and assisted many Virginia banks and savings and loan associations on organizational and regulatory matters. Testified approximately 25 times before the Virginia State Corporation Commission and the Regional Administrator of National Banks on matters related to branching and organization for banks, savings and loan associations, and consumer finance companies. Advised financial institutions on interest rate structure and loan maturity. Testified before Virginia State Corporation Commission on maximum rates for consumer finance companies.

Testified before several committees and subcommittees of Virginia General Assembly on numerous banking matters.

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Exhibit No. PARCELL-2 Page No. 2 of 6 Clients have included First National Bank of Rocky Mount, Patrick Henry National Bank, Peoples Bank of Danville, Blue Ridge Bank, Bank of Essex, and Signet Bank.

Published articles in law reviews and other periodicals on structure and regulation of banking/financial services industry.

Utility Economics -- Performed numerous financial studies of regulated public utilities. Testified in over 550 cases before some fifty state and federal regulatory agencies.

Prepared numerous rate of return studies incorporating cost of equity determination based on DCF, CAPM, comparable earnings and other models. Developed procedures for identifying differential risk characteristics by nuclear construction and other factors.

Conducted studies with respect to cost of service and indexing for determining utility rates, the development of annual review procedures for regulatory control of utilities, fuel and power plant cost recovery adjustment clauses, power supply agreements among affiliates, utility franchise fees, and use of short-term debt in capital structure.

Presented expert testimony before federal regulatory agencies Federal Energy Regulatory Commission, Federal Power Commission, and National Energy Board (Canada), state regulatory agencies in Alabama, Alaska, Arizona, Arkansas, California, Connecticut, Delaware, District of Columbia, Florida, Georgia, Hawaii, Illinois, Indiana, Kansas, Kentucky, Maine, Maryland, Mississippi, Missouri, Nebraska, Nevada, New Hampshire, New Jersey, New Mexico, North Carolina, Ohio, Oklahoma, Ontario (Canada), Pennsylvania, South Carolina, Texas, Utah, Vermont, Virginia, West Virginia, Washington, Wisconsin, U.S. Virgin Islands, and Yukon Territory (Canada).

Published articles in law reviews and other periodicals on the theory and purpose of regulation and other regulatory subjects.

Clients served include state regulatory agencies in Alaska, Arizona, Delaware, Georgia, Mississippi, Missouri, New Hampshire, North Carolina, Ontario (Canada), South Carolina, U.S. Virgin Islands, Virginia and Washington; consumer advocates and attorneys general in Alabama, Arizona, District of Columbia, Florida, Georgia, Hawaii, Illinois, Indiana, Kansas, Kentucky, Maryland, Nevada, New Jersey, New Mexico, Ohio, Oklahoma, Pennsylvania, South Carolina, Texas, Utah, Vermont, Virginia, and West Virginia; federal agencies including Defense Communications Agency, the Department of Energy, Department of the Navy, and General Services Administration; and various organizations such as Bath Iron Works, Illinois Citizens' Utility Board, Illinois Governor's Office of Consumer Services, Illinois Small Business Utility Advocate, Wisconsin's Environmental Decade, Wisconsin's Citizens Utility Board, Old Dominion Electric Cooperative, and industrial customers.

Insurance Economics -- Conducted analyses of the relationship between the investment income earned by insurance companies on their portfolios and the premiums charged for insurance.

Analyzed impact of diversification on financial strength of Blue Cross/Blue Shield Plans in

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Virginia.

Exhibit No. PARCELL-2 Page No. 3 of 6

Conducted studies of profitability and cost of capital for property/casualty insurance industry.

Evaluated risk of and required return on surplus for various lines of insurance business.

Presented expert testimony before Virginia State Corporation Commission concerning cost of capital and expected gains from investment portfolio. Testified before insurance bureaus of Maine, Massachusetts, New Jersey, North Carolina, Rhode Island, South Carolina and Vermont concerning cost of equity for insurance companies.

Prepared cost of capital and investment income return analyses for numerous insurance companies concerning several lines of insurance business. Analyses used by Virginia Bureau of Insurance for purposes of setting rates.

Special Studies -- Conducted analyses which evaluated the financial and economic implications of legislative and administrative changes. Subject matter of analyses include returnable bottles, retail beer sales, wine sales regulations, taxi-cab taxation, and bank regulation. Testified before several Virginia General Assembly subcommittees.

Testified before Virginia ABC Commission concerning economic impact of mixed beverage license.

Clients include Virginia Beer Wholesalers, Wine Institute, Virginia Retail Merchants Association, and Virginia Taxicab Association.

Franchise, Merger & Anti-Trust Economics -- Conducted studies on competitive impact on market structures due to joint ventures, mergers, franchising and other business restructuring. Analyzed the costs and benefits to parties involved in mergers. Testified in federal courts and before banking and other regulatory bodies concerning the structure and performance of markets, as well as on the impact of restrictive practices.

Clients served include Dominion Bankshares, asphalt contractors, and law firms.

Transportation Economics -- Conducted cost of capital studies to assess profitability of oil pipelines, trucks, taxicabs and railroads. Analyses have been presented before the Federal Energy Regulatory Commission and Alaska Pipeline Commission in rate proceedings. Served as a consultant to the Rail Services Planning Office on the reorganization of rail services in the U.S. Economic Loss Analyses -- Testified in federal courts, state courts, and other adjudicative forums regarding the economic loss sustained through personal and business injury whether due to bodily harm, discrimination, non-performance, or anticompetitive practices. Testified on economic loss to a commercial bank resulting from publication of adverse information concerning solvency.

Testimony has been presented on behalf of private individuals and business firms.

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Exhibit No. PARCELL-2 Page No. 4 of 6 MEMBERSHIPS American Economic Association Virginia Association of Economists Richmond Society of Financial Analysts Financial Analysts Federation Society of Utility and Regulatory Financial Analysts Board of Directors 1992-2000 Secretary/Treasurer 1994-1998 President 1998-2000 RESEARCH ACTIVITY Books and Major Research Reports "Stock Price As An Indicator of Performance," Master of Arts Thesis, Virginia Tech, 1970 "Revision of the Property and Casualty Insurance Ratemaking Process Under Prior Approval in the Commonwealth of Virginia," prepared for the Bureau of Insurance of the Virginia State Corporation Commission, with Charles Schotta and Michael J. Ileo, 1971 "An analysis of the Virginia Consumer Finance Industry to Determine the Need for Restructuring the Rate and Size Ceilings on Small Loans in Virginia and the Process by which They are Governed," prepared for the Virginia Consumer Finance Association, with Michael J. Ileo, 1973 State Banks and the State Corporation Commission: A Historical Review, Technical Associates, Inc., 1974 "A Study of the Implications of the Sale of Wine by the Virginia Department of Alcoholic Beverage Control", prepared for the Virginia Wine Wholesalers Association, Virginia Retail Merchants Association, Virginia Food Dealers Association, Virginia Association of Chain Drugstores, Southland Corporation, and the Wine Institute, 1983.

"Performance and Diversification of the Blue Cross/Blue Shield Plans in Virginia: An Operational Review", prepared for the Bureau of Insurance of the Virginia State Corporation Commission, with Michael J. Ileo and Alexander F. Skirpan, 1988.

The Cost of Capital - A Practitioners’ Guide, Society of Utility and Regulatory Financial Analysts, 2010 (previous editions in 1991, 1992, 1993, 1994, 1995 and 1997).

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Exhibit No. PARCELL-2 Page No. 5 of 6 Papers Presented and Articles Published "The Differential Effect of Bank Structure on the Transmission of Open Market Operations," Western Economic Association Meeting, with Charles Schotta, 1971 "The Economic Objectives of Regulation: The Trend in Virginia," (with Michael J. Ileo), William and Mary Law Review, Vol. 14, No. 2, 1973 "Evolution of the Virginia Banking Structure, 1962-1974: The Effects of the BuckHolland Bill", (with Michael J. Ileo), William and Mary Law Review, Vol. 16, No. 3, 1975 "Banking Structure and Statewide Branching: The Potential for Virginia", William and Mary Law Review, Vol. 18, No. 1, 1976 "Bank Expansion and Electronic Banking: Virginia Banking Structure Changes Past, Present, and Future," William and Mary Business Review," Vol. 1, No. 2, 1976 "Electronic Banking - Wave of the Future?" (with James R. Marchand), Journal of Management and Business Consulting, Vol. 1, No. 1, 1976 "The Pricing of Electricity" (with James R. Marchand), Journal of Management and Business Consulting, Vol. 1, No. 2, 1976 "The Public Interest - Bank and Savings and Loan Expansion in Virginia" (with Richard D. Rogers), University of Richmond Law Review, Vol. 11, No. 3, 1977 "When Is It In the 'Public Interest' to Authorize a New Bank?", University of Richmond Law Review, Vol. 13, No. 3, 1979 "Banking Deregulation and Its Implications on the Virginia Banking Structure," William and Mary Business Review, Vol. 5, No. 1, 1983 "The Impact of Reciprocal Interstate Banking Statutes on The Performance of Virginia Bank Stocks", with William B. Harrison, Virginia Social Science Journal, Vol. 23, 1988 "The Financial Performance of New Banks in Virginia", Virginia Social Science Journal, Vol. 24, 1989 "Identifying and Managing Community Bank Performance After Deregulation", with William B. Harrison, Journal of Managerial Issues, Vol. II, No. 2, Summer 1990 "The Flotation Cost Adjustment To Utility Cost of Common Equity - Theory, Measurement and Implementation," presented at Twenty-Fifth Financial Forum, National Society of Rate of Return Analysts, Philadelphia, Pennsylvania, April 28, 1993.

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Exhibit No. PARCELL-2 Page No. 6 of 6 Biography of Myon Edison Bristow, Dictionary of Virginia Biography, Volume 2, 2001.

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Exhibit No. PARCELL-3 Economic and Financial Indicators

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Exhibit No. PARCELL-3 Page 1 of 3

ECONOMIC INDICATORS

Year

Real GDP* Growth

Industrial Production Growth

Unemployment Rate

1975 1976 1977 1978 1979 1980 1981 1982

-0.2% 5.4% 4.6% 5.6% 3.2% -0.2% 2.6% -1.9%

1975 - 1982 Cycle -8.9% 8.5% 7.9% 7.7% 7.6% 7.1% 5.5% 6.1% 3.0% 5.8% -2.6% 7.1% 1.3% 7.6% -5.2% 9.7%

7.0% 4.8% 6.8% 9.0% 13.3% 12.4% 8.9% 3.8%

1983 1984 1985 1986 1987 1988 1989 1990 1991

4.6% 7.3% 4.2% 3.5% 3.5% 4.2% 3.7% 1.9% -0.1%

1983 - 1991 Cycle 2.7% 9.6% 8.9% 7.5% 1.2% 7.2% 1.0% 7.0% 5.2% 6.2% 5.2% 5.5% 0.9% 5.3% 1.0% 5.6% -1.5% 6.8%

3.8% 3.9% 3.8% 1.1% 4.4% 4.4% 4.6% 6.1% 3.1%

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

3.6% 2.7% 4.0% 2.7% 3.8% 4.5% 4.5% 4.7% 4.1% 1.0%

1992 - 2001 Cycle 2.9% 7.5% 3.3% 6.9% 5.2% 6.1% 4.7% 5.6% 4.5% 5.4% 7.2% 4.9% 5.8% 4.5% 4.4% 4.2% 3.9% 4.0% -3.1% 4.7%

2.9% 2.7% 2.7% 2.5% 3.3% 1.7% 1.6% 2.7% 3.4% 1.6%

2002 2003 2004 2005 2006 2007 2008 2009

1.8% 2.8% 3.8% 3.3% 2.7% 1.8% -0.3% -2.8%

2002 - 2009 Cycle 0.3% 5.8% 1.2% 6.0% 2.6% 5.5% 3.3% 5.1% 2.2% 4.6% 2.5% 4.6% -3.5% 5.8% -11.5% 9.3%

2.4% 1.9% 3.3% 3.4% 2.5% 4.1% 0.1% 2.7%

2010 2011 2012 2013 2014 2015 2016 2017

2.5% 1.6% 2.2% 1.7% 2.4% 2.6% 1.5% 2.3%

Current Cycle 5.5% 3.1% 2.9% 2.0% 3.1% -0.7% -1.2% 1.8%

9.6% 8.9% 8.1% 7.4% 6.2% 5.3% 4.9% 4.4%

Consumer Price Index

1.5% 3.0% 1.7% 1.5% 0.8% 0.7% 2.1% 2.1%

*GDP=Gross Domestic Product Source: Council of Economic Advisors, Economic Indicators, various issues.

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Exhibit No. PARCELL-3 Page 2 of 3

INTEREST RATES

Year

Prime Rate

US Treasury T Bills 3 Month

US Treasury T Bonds 10 Year

Utility Bonds Aa

Utility Bonds A

Utility Bonds Baa

1975 1976 1977 1978 1979 1980 1981 1982

7.86% 6.84% 6.83% 9.06% 12.67% 15.27% 18.89% 14.86%

5.84% 4.99% 5.27% 7.22% 10.04% 11.51% 14.03% 10.69%

1975 - 1982 Cycle 7.99% 7.61% 7.42% 8.41% 9.44% 11.46% 13.93% 13.00%

9.44% 8.92% 8.43% 9.10% 10.22% 13.00% 15.30% 14.79%

10.09% 9.29% 8.61% 9.29% 10.49% 13.34% 15.95% 15.86%

10.96% 9.82% 9.06% 9.62% 10.96% 13.95% 16.60% 16.45%

1983 1984 1985 1986 1987 1988 1989 1990 1991

10.79% 12.04% 9.93% 8.33% 8.21% 9.32% 10.87% 10.01% 8.46%

8.63% 9.58% 7.48% 5.98% 5.82% 6.69% 8.12% 7.51% 5.42%

1983 - 1991 Cycle 11.10% 12.44% 10.62% 7.68% 8.39% 8.85% 8.49% 8.55% 7.86%

12.83% 13.66% 12.06% 9.30% 9.77% 10.26% 9.56% 9.65% 9.09%

13.66% 14.03% 12.47% 9.58% 10.10% 10.49% 9.77% 9.86% 9.36%

14.20% 14.53% 12.96% 10.00% 10.53% 11.00% 9.97% 10.06% 9.55%

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

6.25% 6.00% 7.15% 8.83% 8.27% 8.44% 8.35% 8.00% 9.23% 6.91%

3.45% 3.02% 4.29% 5.51% 5.02% 5.07% 4.81% 4.66% 5.85% 3.44%

1992 - 2001 Cycle 7.01% 5.87% 7.09% 6.57% 6.44% 6.35% 5.26% 5.65% 6.03% 5.02%

8.55% 7.44% 8.21% 7.77% 7.57% 7.54% 6.91% 7.51% 8.06% 7.59%

8.69% 7.59% 8.31% 7.89% 7.75% 7.60% 7.04% 7.62% 8.24% 7.78%

8.86% 7.91% 8.63% 8.29% 8.16% 7.95% 7.26% 7.88% 8.36% 8.02%

2002 2003 2004 2005 2006 2007 2008 2009

4.67% 4.12% 4.34% 6.19% 7.96% 8.05% 5.09% 3.25%

1.62% 1.02% 1.38% 3.16% 4.73% 4.41% 1.48% 0.16%

2002 - 2009 Cycle 4.61% [1] 4.01% 4.27% 4.29% 4.80% 4.63% 3.66% 3.26%

7.19% 6.40% 6.04% 5.44% 5.84% 5.94% 6.18% 5.75%

7.37% 6.58% 6.16% 5.65% 6.07% 6.07% 6.53% 6.04%

8.02% 6.84% 6.40% 5.93% 6.32% 6.33% 7.25% 7.06%

2010 2011 2012 2013 2014 2015 2016 2017

3.25% 3.25% 3.25% 3.25% 3.25% 3.26% 3.51% 4.10%

0.14% 0.06% 0.09% 0.06% 0.03% 0.06% 0.33% 0.94%

5.24% 4.78% 3.83% 4.24% 4.19% 4.00% 3.73% 3.82%

5.46% 5.04% 4.13% 4.47% 4.28% 4.12% 3.93% 4.00%

5.96% 5.57% 4.86% 4.98% 4.80% 5.03% 4.69% 4.38%

Current Cycle 3.22% 2.78% 1.80% 2.35% 2.54% 2.14% 1.84% 2.33%

[1] Note: Moody's has not published Aaa utility bond yields since 2001.

Sources: Council of Economic Advisors, Economic Indicators; Mergent Bond Record.

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Exhibit No. PARCELL-3 Page 3 of 3

STOCK PRICE INDICATORS

S&P NASDAQ Composite [1] Composite [1]

S&P D/P

S&P E/P

4.31% 3.77% 4.62% 5.28% 5.47% 5.26% 5.20% 5.81%

9.15% 8.90% 10.79% 12.03% 13.46% 12.66% 11.96% 11.60%

1,190.34 1,178.48 1,328.23 1,792.76 2,275.99 2,060.82 2,508.91 2,678.94 2,929.33

4.40% 4.64% 4.25% 3.49% 3.08% 3.64% 3.45% 3.61% 3.24%

8.03% 10.02% 8.12% 6.09% 5.48% 8.01% 7.42% 6.47% 4.79%

DJIA

1975 - 1982 Cycle 802.49 974.92 894.63 820.23 844.40 891.41 932.92 884.36

1975 1976 1977 1978 1979 1980 1981 1982

1983 - 1991 Cycle 1983 1984 1985 1986 1987 1988 1989 1990 1991

265.79 322.84 334.59 376.18

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

415.74 451.21 460.33 541.72 670.83 872.72 1,085.50 1,327.33 1,427.22 1,194.18

1992 - 2001 Cycle 599.26 3,284.29 715.16 3,522.06 751.65 3,793.77 925.19 4,493.76 1,164.96 5,742.89 1,469.49 7,441.15 1,794.91 8,625.52 2,728.15 10,464.88 2,783.67 10,734.90 2,035.00 10,189.13

2.99% 2.78% 2.82% 2.56% 2.19% 1.77% 1.49% 1.25% 1.15% 1.32%

4.22% 4.46% 5.83% 6.09% 5.24% 4.57% 3.46% 3.17% 3.63% 2.95%

2002 2003 2004 2005 2006 2007 2008 2009

993.94 965.23 1,130.65 1,207.23 1,310.46 1,476.66 1,220.89 946.73

2002 - 2009 Cycle 1,539.73 9,226.43 1,647.17 8,993.59 1,986.53 10,317.39 2,099.03 10,547.67 2,263.41 11,408.67 2,577.12 13,169.98 2,162.46 11,252.61 1,841.03 8,876.15

1.61% 1.77% 1.72% 1.83% 1.87% 1.86% 2.37% 2.40%

2.92% 3.84% 4.89% 5.36% 5.78% 5.29% 3.54% 1.86%

2010 2011 2012 2013 2014 2015 2016 2017

1,139.31 1,268.89 1,379.56 1,642.51 1,930.67 2,061.20 2,092.39 2,448.22

Current Cycle 2,347.70 10,662.80 2,680.42 11,966.36 2,965.77 12,967.08 3,537.69 14,999.67 4,374.31 16,773.99 4,943.49 17,590.61 4,982.49 17,908.08 6,231.28 21,741.91

1.98% 2.05% 2.24% 2.14% 2.04% 2.10% 2.19%

6.04% 6.77% 6.20% 5.57% 5.25% 4.59% 4.17%

491.69

[1] Note: this source did not publish the S&P Composite prior to 1988 and the NASDAQ Composite prior to 1991.

Source: Council of Economic Advisors, Economic Indicators, various issues.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-4 Selection of Proxy Group Members

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-4 Page 1 of 1

SELECTION OF PROXY GROUP MEMBERS

COMPANY

Southwestern Electric Power Co Range of Ratings 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

ALLETE, Inc. Alliant Energy Corp.

Ameren Corp.

American Electric Power Co. Avista Corporation Avangrid, Inc. Black Hills Corporaton CMS Energy Corporation CenterPoint Energy, Inc. Consolidated Edison, Inc. DTE Energy Company Dominion Energy, Inc. Duke Energy Corporation Edison International El Paso Electric Company Entergy Corporation Eversource Energy Exelon Corporation FirstEnergy Corp.

Great Plains Energy Corp.

Hawaiian Electric Industries, Inc. IDACORP, Inc. MGE Energy Inc. NextEra Energy, Inc. NorthWestern Corporation OGE Energy Corp.

Otter Tail Corporation PG&E Corporation PNM Resources PPL Corporation Pinnacle West Capital Corp.

Portland General Electric Co. Public Service Enterprise Group SCANA Corporation Sempra Energy Southern Company Vectren Corporation Westar Energy, Inc. WEC Energy Xcel Energy Inc.

1/ Source: Standard & Poor's website. .

2/ Source: Moody's website.

Credit Ratings S&P 1/ Moody's 2/

A-

Other

Inclusion In Proxy Group

Baa2

A to BBB+ Baa1 to Baa3 BBB+ ABBB+ ABBB BBB+ BBB BBB+ AABBB+ BBB+ ABBB+ BBB BBB+ A BBB BBBBBB+ BBBBBB

A3 Baa1 Baa1 Baa1 Baa1 Baa1 Baa2 Baa1 Baa1 A3 Baa1 Baa2 Baa1 A3 Baa1 Baa2 Baa1 Baa2 Baa3 Baa2 Baa2 Baa1

ABBB ABBB BBB+ BBB+ AABBB BBB+ BBB+ BBB+ BBB+ ABBB+ AA-

Baa1 A2 A3 Baa2 A3 Baa3 Baa2 A3 A3 Baa1 Baa3 Baa1 Baa2 A2 Baa1 A3 A3

Credit ratings do not match SWEPCo ratings plus/minus one "notch"

Pending acquisition by Hydro One Formed in December of 2015 in connection with a merger, no prior data Credit ratings do not match SWEPCo ratings plus/minus one "notch"

Credit ratings do not match SWEPCo ratings plus/minus one "notch"

Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch"

Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch" Pending acquisition of Westar; credit ratings do not match Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch" Not rated Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch"

Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch"

Pending acquisition of Oncor Electric Delivery Credit ratings do not match SWEPCo ratings plus/minus one "notch" Pending acquisition by Great Plains Energy Credit ratings do not match SWEPCo ratings plus/minus one "notch" Credit ratings do not match SWEPCo ratings plus/minus one "notch"

No Yes Yes Yes No No No Yes Yes No Yes Yes Yes No No Yes Yes No No No No No No Yes No No No No Yes Yes No No Yes Yes No Yes No No No No

1 2 3

4 5 6 7 8

9 10

11

12 13

14 15 16

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-5 Dividend Yields

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-5

Page No. 1 of 4

CALCULATION OF DIVIDEND YIELD COMPONENT PROXY GROUP

Stock Prices Company

Alliant Energy Corp.

July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

Dividends

Yield

High

Low

Average

Latest Q

Annual

Monthly

$41.66 $43.23 $43.69 $43.97 $45.55 $45.38

$39.36 $40.50 $41.16 $41.05 $42.88 $42.18

$40.51 $41.87 $42.43 $42.51 $44.22 $43.78

$0.315 $0.315 $0.315 $0.315 $0.315 $0.315

$1.26 $1.26 $1.26 $1.26 $1.26 $1.26

3.11% 3.01% 2.97% 2.96% 2.85% 2.88%

Average

2.96%

Ameren Corp.

July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$56.67 $60.79 $60.91 $62.14 $64.89 $64.35

$55.11 $58.48 $59.24 $59.91 $63.19 $61.32

$0.440 $0.440 $0.440 $0.440 $0.440 $0.458

$1.76 $1.76 $1.76 $1.76 $1.76 $1.83

3.19% 3.01% 2.97% 2.94% 2.79% 2.99% 2.98%

American Electric Power Co. July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$70.81 $74.29 $74.59 $74.90 $77.93 $78.07

CMS Energy Corporation July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$47.02 $48.98 $49.11 $48.92 $50.85 $50.25

CenterPoint Energy, Inc.

$53.54 $56.16 $57.56 $57.67 $61.48 $58.28

$66.11 $70.08 $69.93 $69.55 $73.56 $72.94

$68.46 $72.19 $72.26 $72.23 $75.75 $75.51

$0.590 $0.590 $0.590 $0.590 $0.620 $0.620

$2.36 $2.36 $2.36 $2.36 $2.48 $2.48

3.45% 3.27% 3.27% 3.27% 3.27% 3.28% 3.30%

$45.34 $45.98 $45.92 $45.82 $47.76 $46.76

$46.18 $47.48 $47.52 $47.37 $49.31 $48.51

$0.333 $0.333 $0.333 $0.333 $0.333 $0.333

$1.33 $1.33 $1.33 $1.33 $1.33 $1.33

2.88% 2.81% 2.80% 2.81% 2.70% 2.75% 2.79%

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-5

Page No. 2 of 4

CALCULATION OF DIVIDEND YIELD COMPONENT PROXY GROUP

Stock Prices Company

July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

Dividends

Yield

High

Low

Average

Latest Q

Annual

Monthly

$28.34 $30.12 $30.45 $29.97 $30.07 $30.17

$26.98 $27.61 $28.90 $28.60 $28.20 $27.75

$27.66 $28.87 $29.68 $29.29 $29.14 $28.96

$0.268 $0.268 $0.268 $0.268 $0.268 $0.268

$1.07 $1.07 $1.07 $1.07 $1.07 $1.07

3.88% 3.71% 3.61% 3.66% 3.68% 3.70% 3.71%

DTE Energy Company July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$108.00 $112.58 $113.71 $113.27 $116.21 $116.74

Dominion Energy, Inc. July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$77.57 $80.67 $79.95 $82.13 $84.34 $85.30

Duke Energy Corporation July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$85.33 $87.95 $88.40 $88.64 $91.80 $89.72

$104.19 $106.16 $106.21 $106.21 $109.58 $107.58

$106.10 $109.37 $109.96 $109.74 $112.90 $112.16

$0.825 $0.825 $0.825 $0.825 $0.825 $0.825

$3.30 $3.30 $3.30 $3.30 $3.30 $3.30

3.11% 3.02% 3.00% 3.01% 2.92% 2.94% 3.00%

$75.40 $76.56 $76.23 $75.75 $80.01 $80.11

$76.49 $78.62 $78.09 $78.94 $82.18 $82.71

$0.755 $0.755 $0.755 $0.755 $0.770 $0.770

$3.02 $3.02 $3.02 $3.02 $3.08 $3.08

3.95% 3.84% 3.87% 3.83% 3.75% 3.72% 3.83%

$82.72 $84.65 $83.40 $83.52 $87.56 $83.65

$84.03 $86.30 $85.90 $86.08 $89.68 $86.69

$0.855 $0.890 $0.890 $0.890 $0.890 $0.890

$3.42 $3.56 $3.56 $3.56 $3.56 $3.56

4.07% 4.13% 4.14% 4.14% 3.97% 4.11% 4.09%

Entergy Corp July 2017

Average

$77.19

$74.83

$76.01

$0.870

$3.48

4.58%

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-5

Page No. 3 of 4

CALCULATION OF DIVIDEND YIELD COMPONENT PROXY GROUP

Stock Prices Company

Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

Dividends

Yield

High

Low

Average

Latest Q

Annual

Monthly

$80.22 $80.49 $87.00 $87.95 $87.09

$75.73 $75.98 $75.01 $84.85 $79.66

$77.98 $78.24 $81.01 $86.40 $83.38

$0.870 $0.870 $0.870 $0.890 $0.890

$3.48 $3.48 $3.48 $3.56 $3.56

4.46% 4.45% 4.30% 4.12% 4.27%

Average

4.36%

Eversource Energy July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$61.56 $63.87 $64.19 $62.84 $66.15 $66.12

NextEra Energy, Inc. July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$146.88 $151.28 $151.60 $156.80 $159.28 $159.40

$59.55 $60.37 $60.01 $59.59 $61.98 $61.68

$60.56 $62.12 $62.10 $61.22 $64.07 $63.90

$0.475 $0.475 $0.475 $0.475 $0.475 $0.475

$1.90 $1.90 $1.90 $1.90 $1.90 $1.90

3.14% 3.06% 3.06% 3.10% 2.97% 2.97% 3.05%

$138.00 $145.36 $144.70 $145.62 $148.37 $152.68

$142.44 $148.32 $148.15 $151.21 $153.83 $156.04

$0.983 $0.983 $0.983 $0.983 $0.983 $0.983

$3.93 $3.93 $3.93 $3.93 $3.93 $3.93

2.76% 2.65% 2.65% 2.60% 2.56% 2.52% 2.62%

PNM Resources July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$39.60 $42.95 $43.05 $43.80 $45.55 $46.00

July 2017 Aug 2017

$38.64 $39.81

$37.23 $39.85 $40.30 $40.05 $42.20 $39.75

$38.42 $41.40 $41.68 $41.93 $43.88 $42.88

$0.243 $0.243 $0.243 $0.243 $0.243 $0.243

$0.97 $0.97 $0.97 $0.97 $0.97 $0.97

2.53% 2.35% 2.33% 2.32% 2.22% 2.27% 2.34%

PPL Corp $37.19 $38.35

$37.92 $39.08

$0.395 $0.395

$1.58 $1.58

4.17% 4.04%

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-5

Page No. 4 of 4

CALCULATION OF DIVIDEND YIELD COMPONENT PROXY GROUP

Stock Prices Company

Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

Yield

High

Low

Average

Latest Q

Annual

Monthly

$39.90 $38.55 $37.35 $36.99

$37.61 $37.09 $35.87 $30.74

$38.76 $37.82 $36.61 $33.87

$0.395 $0.395 $0.395 $0.395

$1.58 $1.58 $1.58 $1.58

4.08% 4.18% 4.32% 4.67%

Average

4.24%

Public Service Enterprise Group July 2017 $45.36 Aug 2017 $47.47 Sept 2017 $47.01 Oct 2017 $49.70 Nov 2017 $53.20 Dec 2017 $53.28 Average

$41.67 $44.73 $45.05 $46.05 $49.17 $50.71

SCANA Corporation July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$67.99 $68.35 $60.77 $50.22 $46.89 $45.78

$60.00 $59.34 $48.32 $42.75 $41.15 $37.10

Southern Company July 2017 Aug 2017 Sept 2017 Oct 2017 Nov 2017 Dec 2017 Average

$48.05 $50.08 $50.80 $52.59 $53.51 $52.00

Source: Yahoo! Finance.

Dividends

$43.52 $46.10 $46.03 $47.88 $51.19 $52.00

$0.430 $0.430 $0.430 $0.430 $0.430 $0.430

$1.72 $1.72 $1.72 $1.72 $1.72 $1.72

3.95% 3.73% 3.74% 3.59% 3.36% 3.31% 3.61%

$64.00 $63.85 $54.55 $46.49 $44.02 $41.44

$0.613 $0.613 $0.613 $0.613 $0.613 $0.613

$2.45 $2.45 $2.45 $2.45 $2.45 $2.45

3.83% 3.84% 4.50% 5.27% 5.57% 5.92% 4.82%

$48.71 $47.69 $47.88 $48.62 $50.80 $47.92

$48.38 $48.89 $49.34 $50.61 $52.16 $49.96

$0.580 $0.580 $0.580 $0.580 $0.580 $0.580

$2.32 $2.32 $2.32 $2.32 $2.32 $2.32

4.80% 4.75% 4.70% 4.58% 4.45% 4.64% 4.65%

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-6 DCF Cost Rates for Proxy Group Members

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-6 Page 1 of 1

CALCULATION OF DISCOUNTED CASH FLOW RATES USING JULY -- DECEMBER 2017 STOCK PRICES AND CURRENT EPS FORECASTS PROXY GROUP

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Alliant Energy Corp.

Ameren Corp.

American Electric Power Co. CMS Energy Corporation CenterPoint Energy, Inc. DTE Energy Company Dominion Energy, Inc. Duke Energy Corporation Entergy Corp Eversource Energy NextEra Energy, Inc. PNM Resources PPL Corp Public Service Enterprise Group SCANA Corporation Southern Company

JulyDec. 2017 Adjusted Yield Yield

Growth Rates Short-Term

Long-Term

Weighted Average

7.05% 7.00% 2.77% 7.44% 7.58% 4.91% 3.64% 3.23% neg 5.92% 8.04% 6.05% neg 1.43% 5.50% 2.33%

4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34% 4.34%

6.15% 6.11% 3.29% 6.41% 6.50% 4.72% 3.87% 3.60% 4.34% 5.39% 6.81% 5.48% 4.34% 2.40% 5.11% 3.00%

9.20% 9.18% 6.65% 9.29% 10.33% 7.79% 7.77% 7.76% 8.79% 8.52% 9.52% 7.88% 8.67% 6.06% 10.06% 7.72%

Low

High

Mid-Point

Median

6.06%

10.33%

8.19%

8.20%

A

Baa

Jul 2016 Aug 2017 Sep 2017 Oct 2017 Nov 2017 Dec 2017

3.99% 3.86% 3.87% 3.91% 3.83% 3.79%

4.36% 4.23% 4.24% 4.26% 4.16% 4.14%

Average

3.88%

4.23%

2.96% 2.98% 3.30% 2.79% 3.71% 3.00% 3.83% 4.09% 4.36% 3.05% 2.62% 2.34% 4.24% 3.61% 4.82% 4.65%

3.05% 3.07% 3.36% 2.88% 3.83% 3.07% 3.90% 4.17% 4.46% 3.13% 2.71% 2.40% 4.33% 3.66% 4.94% 4.72%

DCF Cost DCF Cost

DCF Cost Rates

Proxy Group Bond Yields

9.20% 9.18% 6.65% 9.29% 10.33% 7.79% 7.77% 7.76% 8.52% 9.52% 7.88% 6.06% 10.06% 7.72%

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-7 Long-Term Growth Rates Of Gross Domestic Product

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-7 Page 1 of 3

LONG-TERM PROJECTIONS OF GROSS DOMESTIC PRODUCT GROWTH Social Security Administration

Year

Real GDP

GDP Index

Nominal GDP

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054

2.80% 2.70% 2.40% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20%

2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20%

5.00% 4.90% 4.60% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40%

Year

2055 2056 2057 2058 2059 2060 2061 2062 2063 2064 2065 2066 2067 2068 2069 2070 2071 2072 2073 2074 2075 2076 2077 2078 2079 2080 2081 2082 2083 2084 2085 2086 2087 2088

Average

Source: 2016 OASDI Trustees Report.

Real GDP GDP Index

2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.00% 2.0% 2.0% 2.0%

2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20% 2.20%

Nominal GDP

4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.20% 4.20% 4.20% 4.20%

4.35%

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-7 Page 2 of 3

LONG-TERM PROJECTIONS OF GROSS DOMESTIC PRODUCT GROWTH Energy Information Administration

Annual Growth (2016-2050): Real GDP

2.1%

GDP Chain-type Price Index

2.1%

Nominal GDP Growth

4.2%

Source: Energy Information Administration, Annual Energy Outlook 2017 with Projections to 2050.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-7 Page 3 of 3

L0NG-TERM GROSS DOMESTIC PRODUCT GROWTH RATES

Source

Projected GDP Growth

Social Security Administration

4.35%

Energy Information Administration

4.20%

Global Insight 1/

4.46%

Average

4.34%

1/ Mr. Parcell does not have access to this source. In this testimony, he has used the IHS Global Insight forecast of GDP growth from the Testmony of Staff Witness Keyton, Exhibit S-5, Schedule 9, Page 9, in Docket No. 15-45. /

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Workpapers Supporting Direct Testimony of David C. Parcell

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 1 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 2 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 3 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 4 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 5 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 6 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 7 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 8 of 56

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. PARCELL-8 Page No. 9 of 56

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Exhibit No. PARCELL-8 Page No. 10 of 56

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Exhibit No. SLATER-1 Direct Testimony of Michele M. Slater

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Exhibit No. SLATER-1 Page No. 1 of 30 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

DIRECT TESTIMONY AND EXHIBITS OF MICHELE M. SLATER ON BEHALF OF THE CITY OF MINDEN, LOUISANA

February 28, 2018

EL18-__-000

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Exhibit No. SLATER-1 Page No. 2 of 30 LIST OF EXHIBITS Exhibit No.

Description

SLATER-1

Direct Testimony of Michele M. Slater

SLATER-2

Qualifications of Michele M. Slater

SLATER-3

Depreciation Double Collection Issue

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Exhibit No. SLATER-1 Page No. 3 of 30

UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

EL18-__-000

DIRECT TESTIMONY AND EXHIBITS OF MICHELE M. SLATER ON BEHALF OF THE CITY OF MINDEN, LOUISANA 1

Q.

PLEASE STATE YOUR NAME, TITLE, BUSINESS ADDRESS.

2

A.

My name is Michele M. Slater. I am a Senior Project Engineer with GDS Associates, Inc.

3

(“GDS”) in the Rates and Regulatory group. My business address is 111 N. Orange Avenue, Suite

4

750, Orlando, FL 32801. GDS is a multi-disciplined engineering and consulting firm that provides

5

technical and financial consulting services to municipal and cooperative electric utilities, public

6

service commissions, large consumers of electricity, and others.

7

Q.

8 9

PLEASE

DESCRIBE

YOUR

EDUCATIONAL

AND

PROFESSIONAL

BACKGROUND. A.

I earned a Bachelor of Mechanical Engineering with a Certificate of Energy Engineering

10

from the Georgia Institute of Technology in 1987, and a Master in Business Administration from

11

Tulane University, Beta Gamma Sigma Honor Society in 2003.

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Exhibit No. SLATER-1 Page No. 4 of 30 1

I have more than twenty-five years of experience in the electric utility industry, with over

2

twenty years providing consulting services in both the regulated and deregulated environments.

3

The majority of my work has been associated with the economic and secure operation of pooled

4

generation and transmission resources, including evaluation, development, and implementation of

5

power supply and transmission arrangements between or among utilities including the adoption of

6

new FERC requirements. I have also been involved in numerous litigation support activities,

7

including the critiquing of opposing testimony and arguments, and the preparation of expert

8

testimony for other witnesses. A statement of my background and qualifications, summarizing my

9

utility experience, is included herein as Exhibit No. SLATER-2.

10

Q.

WHAT IS THE PURPOSE OF YOUR AFFIDAVIT?

11

A.

The purpose of my affidavit is to support the complaint (“Complaint”) of the City of

12

Minden, Louisiana (“Minden”) contesting issues related to the formula rate under its existing full

13

requirements Power Supply Agreement (“PSA”) with Southwestern Electric Power Company

14

(“SWEPCO”). My testimony will describe and quantify certain issues identified through GDS’

15

prior analysis and review of the formula rate under the PSA. Additionally, my testimony will

16

address two other issues, the first being the impact of the Tax Cuts and Jobs Act of 2017 (“Tax

17

Act”) on the formula rate under PSA,1 and the second being the impact of the recommended Return

18

on Equity (“ROE”) as submitted by Minden witness Mr. David Parcell. Specifically, my testimony

19

will:

20

•

Describe the necessary amendments to the formula rate that are needed to address “excess” accumulated deferred income tax (“ADIT”) that arises from the recently enacted Tax Act,

21

1

Tax Cuts and Jobs Act of 2017, Pub. L. No. 115-97 (2017).

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Exhibit No. SLATER-1 Page No. 5 of 30 1

which reduced the federal corporate income tax rate from 35% to 21% and became

2

effective January 1, 2018; •

3

Quantify the cost impacts to Minden of the recommended ROE (as determined by Mr.

4

Parcell, Exhibit No. PARCELL-1), in comparison to the 11.1% stated ROE currently in

5

effect under the PSA; •

6

Provide rationale for the contention that SWEPCO should update its wholesale

7

depreciation rates and submit its depreciation study to the Federal Energy Regulatory

8

Commission (“FERC” or “Commission”) for approval, as it is readily apparent that the

9

current FERC-approved depreciation rates are significantly out-of-date and overstated when compared to SWEPCO’s recently approved retail depreciation rates;

10 •

11

Describe and demonstrate the impact of SWEPCO’s miscalculation of depreciation

12

expense resulting in a “double collection” of allowance for funds used during construction

13

(“AFUDC”) which results in an over-recovery of depreciation expense; •

14 15

Describe the omission in the formula rate of a rate base offset for “unfunded reserves,” and the impact of including in rate base this customer-contributed capital; and

•

16

Discuss SWEPCO’s incorrect inclusion of certain non-production related construction work in progress (“CWIP”) in rate base.

17 18

Q.

WHAT IS THE RELATIONSHIP BETWEEN MINDEN AND SWEPCO?

19

A.

Minden is a municipal electric utility serving the City of Minden, Louisiana, and is a

20

wholesale customer of SWEPCO. Minden receives “Requirements Service” according to the

21

capacity and energy formula rates included in the PSA.

22

Q.

WHAT IS YOUR RELATIONSHIP TO MINDEN?

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Exhibit No. SLATER-1 Page No. 6 of 30 In November 2016, GDS was engaged by Betts & Holt LLP (“Betts & Holt”), Minden’s

1

A.

2

FERC counsel, to perform an analysis of Minden’s PSA with SWEPCO. GDS was asked to: (i)

3

focus on identifying the primary drivers of the cost increases in the capacity formula rates over

4

prior rate years (2010-2016); (ii) identify any inconsistencies, errors, or potential violations of

5

FERC rate making policies; and (iii) recommend areas of the contract that are worthy of challenge

6

by Minden. In January 2018, Betts & Holt informed GDS that Minden intended to file a complaint

7

at FERC regarding the formula rate under the PSA and sought the services of GDS to provide

8

support for portions of the Complaint. I was requested to sponsor such testimony.

9

Q.

PLEASE PROVIDE A SUMMARY OF GDS’ INITIAL ASSESSMENT OF MINDEN’S PSA WITH SWEPCO.

10 11

A.

The assessment showed an 80% increase in the capacity rate from 2010 through 2016. The

12

single largest primary driver of the capacity rate increases was the increase in the gross plant in-

13

service, due to the addition of SWEPCO’s majority ownership of Turk Power Station in late 2012,

14

which in turn directly impacts the return on rate base, depreciation expense, taxes other than

15

income taxes, and income tax.

16

To identify potential issues with the formula rates, GDS reviewed the Cost of Service

17

Formulas set forth in Exhibit B of the PSA. In addition, GDS reviewed SWEPCO’s FERC filings

18

related to CWIP, Post-Retirement Benefits Other than Pensions (“PBOP”), Post-Employment

19

Benefits (“PEB”), FERC Form No. 1s (“FERC Form 1”) for the applicable years, and various other

20

regulatory filings involving SWEPCO. As a result of such review, GDS identified the following

21

key issues related to the existing formula rate under the PSA:

22 23

i.

Outdated Wholesale Jurisdictional Depreciation Rates and Use of WeightedAverage Retail Jurisdictional Depreciation Rates;

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Exhibit No. SLATER-1 Page No. 7 of 30 1

ii.

Over-recovery of contra AFUDC in Depreciation Expense;

2

iii.

Omission of a Rate Base Component for Unfunded Reserves in the Formula; and

3

iv.

Improper Inclusion of Non-Production CWIP in Rate Base.

4

Q.

HAVE YOU IDENTIFIED ANY ADDITIONAL ISSUES AFFECTING THE PSA SINCE GDS’ INITIAL ASSESSMENT?

5 6

A.

7

federal corporate income tax rate is reduced from 35% to 21%.2 For the formula rate template

8

under the PSA, the corporate income tax rate is an input that can be updated just like any FERC

9

Form 1 input or other data input. Therefore, the change to the corporate income tax rate will flow

10

through the formula which will reduce the income tax expense and result in a corresponding

11

decrease to the revenue requirement. For the 2018 formula rate true-up, it is expected that

12

SWEPCO will revise the federal corporate income tax rate in the formula from 35% to 21% and

13

the primary effects will be reflected in the form of a refund on 2018 estimated charges.

14

Q.

15

Yes. Since the initial assessment, the Tax Act came into effect. Under the Tax Act the

ARE THERE ANY OTHER CONSEQUENCES OF THE TAX ACT WHICH GIVE RISE TO CHANGES TO THE FORMULA RATE?

16

A.

Yes, there are secondary impacts to the tax rate changes that will not be reflected in the

17

formula rate update without adjustments to various FERC account balances and an amendment to

18

the formula template.

19

FERC jurisdictional utilities typically collect through their rates sufficient funds for both

20

current and future payments of income taxes. Prior to the Tax Act, the amounts collected were

21

calculated on the premise that future payments for deferred taxes would be made at a 35% federal

2

Tax Cuts and Jobs Act of 2017, Pub. L. No. 115-97 (2017).

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Exhibit No. SLATER-1 Page No. 8 of 30 1

corporate income tax rate. However, with future federal tax obligations reduced to a 21% rate, the

2

balance of ADIT will now exceed that which will be owed.

3

To properly account for the change to the corporate income tax rate, utilities will need to

4

make certain adjustments to the balances for income taxes accrued (FERC Account 236 – Taxes

5

accrued) and the balances in ADIT (FERC Accounts 190, 282 and 283), and reflect a flowback of

6

the excess deferred income taxes in rates.

7

For Federal or State Income Tax rate changes, FERC has previously provided guidance in:

8

(1) Docket No. AI93-5-000 – FERC: Accounting Matters, Item 8. – Changes in Tax Law or Rates;

9

and (2) Commission Order No. 144 in Docket No. RM80-42, Item 6, Tax Rate Changes. In

10

addition, FERC’s regulations at 18 C.F.R. § 35.24 (2018) codifies Tax Normalization for public

11

utilities and addresses changes in tax rates. This FERC regulation states in section (c) Special

12

Rules that tax normalization accounting rules are applicable

13 14 15 16

(1)(ii) If, as a result of changes in tax rates, the accumulated provision for deferred taxes becomes deficient in or in excess of amounts necessary to meet future tax liabilities as determined by application of the current tax rate to all timing difference transactions originating in the test period and prior to the test period.

17 18 19

(2) The public utility must compute the income tax component in its cost of service by making provision for any excess or deficiency in deferred taxes described in subparagraphs (1)(i) or (1)(ii) of this paragraph.

20

18 CFR 35.24(c) (2018). To return the excess/deficient ADIT to ratepayers that results from any

21

change in either the Federal or State Income Tax rates, a public utility must compute “the income

22

tax component as if the amounts of timing difference transactions recognized in each period for

23

ratemaking purposes were also recognized in the same amount in each such period for income tax

24

purposes.”3 That is, under the tax normalization accounting rules, utilities would transfer the

3

18 CFR 35.24(d) (2018).

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Exhibit No. SLATER-1 Page No. 9 of 30 1

excess/deficient deferred taxes to ratepayers through reductions/increases in utility service rates

2

over the period of the remaining life of the capital assets that gave rise to such deferred taxes.

3

For this recent change in tax law, a utility will need to create a regulatory liability for the

4

difference between the previously deferred income taxes, related to the plant depreciation and

5

other things that give rise to deferred taxes, accrued at the 35% tax rate and what would have been

6

the deferred income taxes accrued at the new 21% tax rate. The excess ADIT that was previously

7

recorded in Accounts 190, 282, and 283 would be reclassified as a new accounting entry to

8

Account 283 as the ADIT related to that regulatory liability. The utility would then be required to

9

request FERC authorization to amortize that regulatory liability and to include the related

10

amortization as an adjustment to income taxes for the flowback of the excess deferred income

11

taxes. As the regulatory liability is amortized, the related ADIT in Account 283 would be reduced.

12

In SWEPCO’s case, the current formula template does not contain a provision for the

13

refund or flowback of excess deferred income taxes. Further, SWEPCO would need to perform

14

the requisite accounting changes and seek FERC authorization to amortize the resulting regulatory

15

liability. Without these steps and revisions to the formula, Minden will be overpaying for service

16

under the PSA, and SWEPCO will reap a windfall from the reduction in federal corporate income

17

tax rates.

18

Q.

ARE YOU ABLE TO QUANTIFY THE ANNUAL IMPACT OF THE TAX ACT’S

19

CHANGE TO THE FEDERAL CORPORATE INCOME TAX RATE ON SWEPCO

20

CAPACITY AND ENERGY CHARGES?

21

METHODOLOGY.

IF SO, PLEASE DESCRIBE THE

Yes, SWEPCO’s annual true-up for calendar year 2016 service under the PSA is used as

22

A.

23

the initial starting point to determine the estimated dollar value impacts of all quantifiable issues

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Exhibit No. SLATER-1 Page No. 10 of 30 1

to be addressed in my testimony, including the impact of the Tax Act. The first tab in the true-up

2

workbook “Minden 16a_cc” is titled “INPUT,” and, as the name implies, contains all the input

3

variables used to calculate the charges under the tariff. An annual summary of capacity and energy

4

charges is contained in Schedule BG, tab “BG.” The tabs titled “B1 - B2” though “B23,” “BL_1”

5

and “BL_2-3” contain the remaining schedules with supporting calculations. Any changes made

6

to the inputs or the schedule calculations will automatically be reflected in the resulting revenue

7

requirement and rates.

8

Thus, the primary impact of the reduction in the federal corporate income tax rate is

9

produced by changing the input value for the Federal Income Tax Rate, found on the INPUT tab

10

(cell C140), from 35% to 21% and keeping all other inputs constant.

11

As the update to the federal income tax rate is expected to occur as a matter of protocol

12

and the resulting reduction in annual costs a given, I consider the resulting revenue requirement

13

and rates reflecting the Federal Income Tax Rate input set to 21% to be the base case from which

14

the impacts of the remaining issues I discuss in this testimony will be measured.

15

To address the secondary impact, that is the excess deferred income taxes due to the

16

reduction in federal tax rate, a few additional calculations were necessary to impute or approximate

17

the total excess ADIT and to capture the annual flowback of the excess deferred taxes.

18

As I described in the preceding issue description, to adhere to tax normalization

19

regulations, the utility must compute the income tax component in its cost of service by making

20

provision for any excess in deferred taxes due to the tax rate change. The Tax Act provides

21

direction to address this issue in Section 1561 Limitation on Accumulated Earning Credit in the

22

Case of Certain Controlled Corporations. Preferentially, the excess ADIT is normalized using the

23

average rate assumption method (“ARAM”), where “[t]he average rate assumption method is the

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Exhibit No. SLATER-1 Page No. 11 of 30 1

method under which the excess in the reserve for deferred taxes is reduced over the remaining

2

lives of the property as used in its regulated books of account which gave rise to the reserve for

3

deferred taxes.”4 If however, “the taxpayer’s books and underlying records did not contain the

4

vintage account data necessary to apply the average rate assumption method, the taxpayer will be

5

treated as using a normalization method of accounting if, with respect to such jurisdiction, the

6

taxpayer uses the alternative method for public utility property that is subject to the regulatory

7

authority of that jurisdiction.”5 Under the alternative method “the taxpayer (i) computes the excess

8

tax reserve on all public utility property included in the plant account on the basis of the weighted

9

average life or composite rate used to compute depreciation for regulatory purposes, and (ii)

10

reduces the excess tax reserve ratably over the remaining regulatory life of the property.” 6 This

11

alternative method is often referred to as the Reverse South Georgia method.

12

Because Minden is not in possession of the SWEPCO’s vintage account data, I estimated

13

tax normalization using the alternative method. First, the amount of excess ADIT to be refunded

14

to customers was calculated by taking the difference between the total accumulated deferred taxes

15

accumulated at the 35% federal income tax rate and the calculated value of deferred taxes at the

16

21% federal income tax rate. Next, a series of calculations were performed to arrive at the total

17

number of years over which the excess is returned to the customers—the amortization period. The

18

average asset life was calculated based on the gross plant in service and depreciation expense

19

reflected in SWEPCO’s 2016 formula rate. The average remaining life of the gross plant in service

20

was determined based on the corresponding accumulated depreciation reserve that was reflected

4

Tax Cuts and Jobs Act of 2017, Pub. L. No. 115-97, § 1561(d)(3)(B) (2017).

Id. at § 1561(d)(2)(B).

6 Id. at § 1561(d)(3)(C).

5

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Exhibit No. SLATER-1 Page No. 12 of 30 1

in the 2016 formula rate. The annual amount to be amortized is arrived at by dividing the excess

2

ADIT by the years of remaining asset life. The resulting annual amount is grossed-up to include

3

corporate income taxes. As a flowback to customers, this grossed-up annual amortization of

4

excess ADIT is subtracted from the income tax expense component of the cost of service. The

5

annual amortization of this excess ADIT is subsequently removed from ADIT balances, thereby

6

increasing rate base accordingly.

7

Q.

WHAT WAS YOUR DETERMINATION OF THE IMPACTS OF THE

8

REDUCTION IN FEDERAL INCOME TAX RATE FROM 35% TO 21% ON THE

9

RATES CHARGED TO MINDEN? As previously discussed, I used SWEPCO’s annual true-up for calendar year 2016 service

10

A.

11

under the PSA as a proxy for evaluating the impacts of each of the issues that have been identified.

12

SWEPCO billed Minden $4,427,895 for capacity, $5,028,860 for energy, totaling $9,456,754

13

overall, averaging 6.34 cents/kWh over 149,061 MWh. The result of revising the Federal Income

14

Tax rate from 35% to 21% is a reduction of approximately $332,000 in annual charges (from

15

$9,456,754 to $9,124,347), or 3.5%. To reiterate, this case is used as the base case for comparison

16

purposes for all other issue impacts.

17

The impact of amending the formula rates template to account for the amortization of

18

SWEPCO’s production related excess ADIT with an annual flowback to customers is an estimated

19

$74,740, or an additional .8% reduction in annual charges to Minden.

20

Q.

PLEASE QUANTIFY THE IMPACTS TO MINDEN’S ANNUAL CHARGES

21

UNDER THE PSA WITH THE LOWER RATE OF ROE AS RECOMMENDED BY

22

WITNESS MR. PARCELL.

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Exhibit No. SLATER-1 Page No. 13 of 30 1

A.

On behalf of Minden in this current docket, Mr. Parcell contemporaneously filed testimony

2

that evaluates the current cost of equity for SWEPCO in support of the Complaint to reduce

3

SWEPCO’s base cost of equity (“Base ROE”) recovered through the PSA. As detailed in his

4

testimony (Exhibit No. PARCELL-1), Mr. Parcell’s cost of equity analyses are based upon the

5

two-step constant growth discounted cash flow (“DCF”) model. In performing his DCF analyses,

6

Mr. Parcell focuses on the two-step growth and proxy group criteria cited by the Commission in

7

“Opinion 531,”7 the Commission’s orders on rehearing of this opinion, and “Opinion 551.”8

8

Commission precedent for a single utility calls for the use of the median DCF cost rate to be used

9

as the Base ROE. Mr. Parcell’s analyses determined a Base ROE for the proxy group that results

10

in a median value of 8.2%,9 which is significantly less than the 11.1% Base ROE currently

11

recovered by SWEPCO through the PSA.

12

The impact of the recommended ROE to the rates charged under the PSA is two-fold. First,

13

ROE is a component of the weighted average cost of capital (“WACC”). In SWEPCO’s case,

14

ROE drives 48.16% of the WACC which in turn determines the allowed return on rate base.

15

Second, the WACC has a ripple effect in that it determines the effective income tax rate and the

16

subsequent income tax calculated on the return on rate base. Both the allowable return on rate

Opinion No. 531, Coakley v. Bangor Hydro-Elec. Co., 147 FERC ¶ 61,234 (2014) (“Opinion 531”), order on paper hearing, Opinion No. 531-A, 149 F.E.R.C. ¶ 61,032 (2014) (“Opinion 531-A”), order on reh’g, Opinion No. 531-B, 150 FERC ¶ 61,165 (2015) (“Opinion 531-B”), vacated and remanded sub nom, Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017) (“Emera Maine”). The Court vacated and remanded the Opinion 531 series of opinions to FERC for further proceedings, but the criteria for proxy group selection and the use of the two-step growth rate in the DCF were not disturbed on appeal.

8 Opinion No. 551, Assoc. of Bus. Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, 156 FERC ¶ 61,234 (2016) (“Opinion 551”), reh’g pending.

9 Exhibit PARCELL-1 at 5:2-4 (Parcell Affidavit).

7

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Exhibit No. SLATER-1 Page No. 14 of 30 1

base and income tax are components of the total revenue requirement. Thus, reducing the ROE

2

reduces both the allowable return on rate base and the income tax expense.

3

As ROE is an input to the PSA formula rate template, calculating the impact of reducing

4

the current ROE from 11.1% to 8.2% is performed by changing the input value for the ROE, found

5

on the INPUT tab (cell C412), and keeping all other inputs constant. The total reduction to Annual

6

Capacity and Energy charges to Minden under the PSA is an estimated $405,082, or 4.4% of the

7

adjusted Base Case annual charges of $9,124,347.

8

Q.

RETURNING TO THE ISSUES IDENTIFIED BY GDS IN THEIR 2016

9

ASSESSMENT, PLEASE DESCRIBE THE INITIAL ISSUES REGARDING THE

10

DEPRECIATION RATES CURRENTLY USED IN SWEPCO’S FORMULA RATE.

11

A.

Depreciation rates are used to calculate an annual depreciation expense and are applied to

12

the depreciable plant base over the lives of the assets to determine such expense. Depreciation

13

expense is a component of the annual production fixed costs. In SWEPCO’s case, depreciation

14

expense represents roughly 18% of the total annual production fixed costs. Numerous variables

15

contribute to the final allowed depreciation rates, including the type of asset, or specific

16

component, expected life of the asset or component, and vintage of the study. Typically, a utility

17

performs a depreciation study and submits the study to the applicable jurisdiction for approval for

18

use in ratemaking. It is generally understood that depreciation rates are approved by each

19

jurisdiction for use within that jurisdiction alone.

20

The total company depreciation rates used in the PSA are the weighted composite average

21

rates of four jurisdictions: FERC–Wholesale, Arkansas, Louisiana, and Texas jurisdictions.

22

SWEPCO’s Arkansas, Louisiana, and Texas jurisdictions are retail jurisdictions regulated by the

23

respective State commissions. Throughout the life of the PSA, the composite depreciation rates

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Exhibit No. SLATER-1 Page No. 15 of 30 1

used in the cost of service formula have varied as the individual state-approved rates have changed.

2

In contrast, it appears that the last time a SWEPCO wholesale depreciation study was performed

3

and approved by FERC for use in wholesale rates was in the ER83-68 docket. Depreciation rates

4

have been steadily decreasing over the past ten years, but the FERC jurisdiction rates remain

5

unchanged. Maintaining these outdated FERC–Wholesale depreciation rates in the cost of service

6

calculation unnecessarily inflates the costs charged to Minden under the PSA. Revised wholesale

7

depreciation rates reflective of analyses are long overdue. Thus, there are two overlapping issues

8

with the depreciation rates currently used by SWEPCO in their PSA: (i) the use of the multi-

9

jurisdictional depreciation rates; and (ii) the origin and vintage of the FERC–Wholesale

10

depreciation rates.

11

Q.

12

PLEASE EXPLAIN THE FIRST ISSUE YOU HAVE IDENTIFIED WITH MULTIJURISDICTIONAL DEPRECIATION RATES.

13

A.

As stated, SWEPCO uses a composite of weighted average jurisdictional depreciation rates

14

under the PSA to determine total company depreciation rates and depreciation expense. Because

15

the SWEPCO formula rate is intended to produce a FERC wholesale cost of service, the use of

16

composite multi-jurisdictional depreciation rates from SWEPCO’s various retail state jurisdictions

17

is inconsistent with that intent. Nonetheless, this practice of using multi-jurisdictional depreciation

18

rates has persisted in SWEPCO filings.

19

Pursuant to the PSA formula rate, SWEPCO relies on the depreciation expense reported on

20

page 336 of its FERC Form 1. The PSA Exhibit B Cost of Service Formulas Page 16a (tab B16a

21

of the PSA formula rate template), “Calculation of Total Company Weighted Average

22

Depreciation Rates,” provides the currently approved depreciation rates for each of SWEPCO’s

23

jurisdictions, for each production plant, by plant account. Exhibit B Page 16a also includes the

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Exhibit No. SLATER-1 Page No. 16 of 30 1

allocation factors for each of the four jurisdictions which, when applied to the corresponding

2

depreciation rates for each jurisdiction and summed, result in the total company depreciation rates

3

by subaccount. The FERC–Wholesale depreciation rates are weighted at approximately 20% of

4

this composite, with the remainder comprised of the state jurisdiction approved rates for retail

5

service in Texas, Arkansas, and Louisiana. Footnotes to SWEPCO’s current PSA Exhibit B16a

6

(as filed June 23, 2017, in Docket No. ER17-1895-000) identify the effective or approved date and

7

source docket for each state’s approved retail depreciation rates: Louisiana steam production

8

effective October 15, 2007, Order No. U-23327-A; Louisiana general plant approved November

9

17, 1999, Order U-23029-A; Arkansas effective December 1, 2009, per settlement agreement

10

Docket 09-008-U; and Texas effective February 1, 2013, Docket 40443. The “Total Company”

11

depreciation rates listed in the last column on the current Exhibit B16a correspond to the

12

depreciation rates by plant and plant account in the 2016 Form 1, Depreciation and Amortization

13

of Electric Plant (Page 337).

14

There are several concerns with the use of a composite rate. First, Minden, as a wholesale

15

customer, does not have jurisdictional rights in SWEPCO’s various retail rate jurisdictions, yet is

16

subject to the outcome of any depreciation study that is filed with SWEPCO’s state commissions.

17

Among other things, each state jurisdiction determines its own criteria for the methodology in

18

determining the depreciation rates and sets its own objectives, ostensibly for the benefit of the

19

jurisdiction’s ratepayers. These criteria and objectives may or may not align with Commission

20

principles applied to wholesale transactions.

21

Second, the PSA applies allocation factors to each set of jurisdictional rates to produce the

22

total company weighted average depreciation rates. Under this approach, the state jurisdiction

23

with the highest allocation factor has the greatest influence over the total depreciation expense

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Exhibit No. SLATER-1 Page No. 17 of 30 1

incurred. The PSA does not provide an explanation to the origin or derivation of the depreciation

2

allocation factors.

3

Minden does not take issue with the current state jurisdiction depreciation rates per se; in

4

fact, Minden has benefitted by the lower state jurisdicitional depreciation rates under the current

5

construct of multi-jurisdicational composite rates. Rather, the issue is the process by which

6

Minden, as a wholesale customer taking requirements service pusuant to a wholesale contract, is

7

made reliant on the numerous state commissions taking action for the benefit of their retail

8

ratepayers.

9

Q.

PLEASE

EXPLAIN

THE

SECOND

ISSUE

YOU

HAVE

IDENTIFIED

10

REGARDING THE DEPRECIATION EXPENSE COMPONENT OF THE PSA

11

FORMULA RATE.

12

A.

The second issue is the origin and vintage of the FERC–Wholesale depreciation rates. As

13

previously stated, tab B16a of the PSA formula rate template provides the currently approved retail

14

state jurisdiction depreciation rates and for each of SWEPCO’s jurisdictions and FERC–Wholesale

15

depreciation rates, for each production plant, by plant account. While the footnotes provide a

16

legacy for the state jurisdictional rates, there is no docket reference provided for the approval of

17

the FERC–Wholesale depreciation rates, or any other reference to support their use in this PSA

18

formula. Further research into the origin of the FERC–Wholesale depreciation rates on my part

19

did not result in any evidence that a depreciation study had ever been performed by SWEPCO in

20

support of the FERC–Wholesale rates in the PSA, or that any justification for the use of these rates

21

in the PSA was provided to FERC.

22

In a separate docket, Docket No. ER07-1069-000, SWEPCO parent American Electric

23

Power Service Corporation (“AEP”) sought “to establish an up-to-date revenue requirement for

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Exhibit No. SLATER-1 Page No. 18 of 30 1

transmission services over the facilities of PSO and SWEPCO under the SPP Tariff and implement

2

a transmission cost of service formula rate.”10 The Commission conditionally accepted the revised

3

tariff sheets for filing and directed AEP to make a compliance filing, requiring AEP, among other

4

things, to state in the formula rate the Commission-approved depreciation rates and make a section

5

205 filing to change them.11 AEP asserted that it was unnecessary to set its proposed depreciation

6

rates for hearing because those depreciation rates were derived from the depreciation rates in

7

AEP’s Form 1. In the compliance order, the Commission took exception to AEP’s implication

8

that its depreciation rates may automatically adjust as long as the rates are found in its FERC Form

9

1.

10

In its compliance filing AEP stated:

11 12 13 14 15 16 17 18

“Regarding SWEPCO, the depreciation rates that generate the book expense included in the June 22 filing have not changed since 1999. SWEPCO operates in three separate retail jurisdictions (Arkansas, Louisiana and Texas). The depreciation rates utilized by SWEPCO on its books are composite depreciation rates by account that utilize the individual state approved depreciation rates. The practice of deriving a composite depreciation rate for SWEPCO from the average weighted effective depreciation rates approved in the retail jurisdictions was accepted by the Commission in Docket No. ER83-68-000 and most recently reviewed in a 1995 Commission audit.”

19

American Electric Power Service Corporation Compliance Filing, Docket No. ER07-1069-

20

002, at p 3 (Oct. 1, 2007).

21

In as much as I am unable to confirm otherwise, it appears that SWEPCO has not prepared

22

a wholesale depreciation rate study for approval by FERC since 1983. A revised set of FERC

10

American Electric Power Service Corporation, Revised Pro-Forma Tariff filing, Docket No. ER07-1069, at transmittal letter p 1 (June 22, 2007).

11

Order Conditionally Accepting and Suspending Revised Tariff Sheets and Establishing Hearing and Settlement Judge Procedures, Docket No. ER07-1069-000-000 (Aug. 31, 2007).

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Exhibit No. SLATER-1 Page No. 19 of 30 1

approved wholesale depreciation rates based upon a current depreciation study is long overdue.

2

SWEPCO has evidently prepared depreciation studies for its various state retail jurisdictions

3

numerous times since 2009, as evidenced by the various filings at FERC to incorporate state

4

jurisdictional depreciation rates.

5

depreciation rate by functional class. The following table demonstrates the steady downward trend

6

in depreciation rates across all classes since inception of the PSA.

In its FERC Form 1, SWEPCO provides the composite

Table 1 – SWEPCO Annual Composite Depreciation Rates12 Annual Composite Depreciation Rates

by Functional Class (in percentages) Year

Steam

2009 2010 2011 2012 2013 2014 2015 2016

2.7 1.9 2.1 2.2 2.2 2.2 2.2 2.1

Other Generation Transmission Distribution General 3.0 2.3 2.4 2.4 2.4 2.4 2.4 2.4

2.6 2.4 2.3 2.3 2.3 2.2 2.3 2.2

3.6 2.7 2.6 2.6 2.6 2.7 2.6 2.6

7.6 7.7 6.9 6.6 5.0 4.8 5.5 6.8

7

Since Minden is primarilly concerned with the depreciation rates for steam production

8

plants, I have compared the FERC–Wholesale depreciation rates for Turk, Pirkey, Arsenal Hill,

9

Flint Creek, Dolet Hills, Wilkes, Knox Lee, Lieberman, and Lone Star plants to the current Texas

10

PUC approved depreciation rates—the Texas rates being the most recently approved rates.

11

Without exception, the FERC–Wholesale depreciation rates are significantly higher than the Texas

12

Southwestern Electric Power Company, FERC Form No. 1, Notes to Financial Statement, 2009 through 2016 annual filings.

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Exhibit No. SLATER-1 Page No. 20 of 30 1

rates for every steam production plant, with differences ranging from 18% higher for Arsenal Hill

2

to 828% higher for Lone Star. Comparing the total average depreciation rates for Texas and FERC,

3

FERC-Wholesale depreciation rates are 80% higher than those recently approved by the Public

4

Utility Commission of Texas (“PUCT”). In fact, across the board, the FERC–Wholesale rates are

5

higher than all state jurisdiction steam production depreciation rates, with the exception of being

6

on par with Arkansas’s rates for Turk.

7

demonstrates the disparity between the current PUCT-approved depreciation rates by plant and the

8

FERC–Wholesale depreciation rates used by SWEPCO, whereby the weighted average FERC–

9

Wholesale rates are shown to be 80% higher than the weighted average Texas approved rates.

The bar graph on the following page (Figure 1)

10

FERC should order SWEPCO to prepare an updated depreciation study and file such study

11

with the Commission. Notwithstanding the issue I have with SWEPCO’s reliance on the weighted

12

average composite depreciation rates, assuming the updated FERC–Wholesale depreciation rates

13

come down to be more in line with SWEPCO’s retail jurisdictional depreciation rates, such lower

14

wholesale jurisdiction depreciation rates would effectively lower the reported depreciation

15

expense under the PSA, thus lowering rates charged to Minden.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-1 Page No. 21 of 30 Figure 1 – Comparison of FERC—Wholesale to Texas PUC Depreciation Rates Comparison of Average Depreciation Rates Texas PUC vs. FERC for SWEPCO Steam Production Plants 4.00%

3.50% 3.07%

Depreciation Rate

3.00%

2.50%

80% Higher

2.00% 1.71%

1.50%

1.00%

0.50%

0.00% Turk Plant

Pirkey

Texas PUC

Arsenal Hill Flint Creek Dolet Hills

FERC

Wilkes

Knox Lee

Average Texas PUC

Lieberman Lone Star

Average FERC

1

Q.

WHAT IS YOUR PROPOSED SOLUTION TO THESE DEPRECIATION ISSUES?

2

A.

I propose two possible solutions to address the depreciation rate issue. My first proposed

3

solution is two-fold: eliminate the use of SWEPCO’s composite jurisdictional depreciation rates

4

under the PSA formula rates and move to relying solely on approved FERC–Wholesale

5

depreciation rates based on a current depreciation study that cannot be changed absent a 205/206

6

filling.

7

Alternatively, a multi-jurisdictional composite rate solution must include FERC–

8

Wholesale depreciation rates reflecting a revised depreciation study and jurisdictional allocations

9

based upon a transparent mutually agreeable process.

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Exhibit No. SLATER-1 Page No. 22 of 30 1

Q.

ARE YOU SUGGESTING THAT SWEPCO CHANGE ITS REPORTING ON

2

PAGE 336 OF ITS FERC FORM 1 TO REPORT DEPRECIATION EXPENSE

3

BASED ON ONLY FERC-APPROVED DEPRECIATION RATES, IGNORING ITS

4

OTHER RETAIL JURISDICTIONS?

5

A.

6

expense that reflects a blend of their retail and wholesale jurisdictions that differ from the

7

depreciation expense calculated based upon Commission-approved composite depreciation rates

8

used in determining charges under wholesale contracts.13

9

Q.

10

No, many utilities report depreciation expense in their FERC Form 1 based on a composite

WILL THAT CHANGE TO DEPRECIATION EXPENSE AFFECT OTHER AREAS OF THE FORMULA RATE?

11

A.

Yes, changes to depreciation rates and subsequent changes to depreciation expense will

12

also affect accumulated depreciation balances and ADIT moving forward.

13

SWEPCO would provide a new set of schedules in the formula template that would provide the

14

back-up details of the wholesale basis inputs to the formula rate with reconciliation to FERC Form

15

1 reported balances and expenses.

16

Q.

I envision that

HAVE YOU EVALUATED THE POTENTIAL IMPACTS OF USING JUST ONE

17

SET OF FERC JURISDICTIONAL DEPRECIATION RATES, ASSUMING AN

18

UPDATE TO SWEPCO’S CURRENT FERC-WHOLESALE DEPRECIATION

19

RATES, AND IF SO, WHAT WOULD BE THE RESULT TO THE ANNUAL

20

PRODUCTION COST?

13

The Empire Dist. Elec. Co., 137 FERC ¶ 61,106, at P 3 (2011).

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Exhibit No. SLATER-1 Page No. 23 of 30 1

A.

2

depreciation rates similar to SWEPCO’s rates most recently approved by its state commission (the

3

PUCT approved SWEPCO’s depreciation rates on October 3, 2013, in PUC Docket 40443, with

4

rates made effective February 1, 2013), the result would lower total annual charges by an estimated

5

$117,435, or an additional 1.3% reduction in total annual charges to Minden.

6

Q.

7

Yes, assuming that an update to the FERC-Wholesale depreciation rates would produce

PLEASE DESCRIBE THE ISSUE IDENTIFIED AS DOUBLE COLLECTION RELATED TO DEPRECIATION AND AFUDC.

8

A.

Commission policy is clear on the treatment of AFUDC on included CWIP, that is, the

9

inclusion of CWIP in rate base requires the discontinuance of AFUDC capitalization in order to

10

avoid a double return on plant investment.14 The purpose for including CWIP in rate base is to

11

earn a return that is designed to cover construction-related financing costs. To also include

12

AFUDC capitalization for the same CWIP, results in the customers paying twice for the same

13

capital costs.

14

There appears to be some “double collection” related to depreciation expense on certain

15

AFUDC that should have been excluded from the depreciable base of plant that previously had

16

CWIP in rate base. SWEPCO’s depreciable base (as reported in the FERC Form 1, page 337,

17

column b) appears to reflect the gross plant investment prior to any adjustment for AFUDC

18

referenced by Section 4.06 of the PSA (which, in the industry, is referred to as “contra AFUDC”).

19

The contra AFUDC adjustment is necessary to reduce the plant-in-service investment (and

20

associated depreciation) related to CWIP in rate base under the PSA. Although SWEPCO,

21

pursuant to its annual FERC informational filings on CWIP, identifies the amount of this contra

14

18 C.F.R. 35.25(e) (2018).

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Exhibit No. SLATER-1 Page No. 24 of 30 1

AFUDC for purposes of adjusting rate base for return purposes under the PSA, the adjustment is

2

not carried through to depreciation. To the extent SWEPCO is applying depreciation rates to a

3

depreciable base that has not been adjusted for the contra AFUDC, they would essentially be

4

double collecting that portion of plant under the PSA. That is, in lieu of booking AFUDC, they

5

collected a return on CWIP in rate base. They should not be able to also collect depreciation

6

expense on the AFUDC avoided. This is clearly in violation of FERC ratemaking policy

7

referenced above.

8

simplified example of the double collection that illustrates SWEPCO’s misapplication of the

9

formula rate. Section 4.06 of the PSA clearly states, “the Company will adjust its production

10

invested capital to recognize that under this Agreement, certain percentages of CWIP have been

11

included in rate base formulas.” This directive not only involves plant-in-service for rate base

12

purposes, but also for depreciation. In the case of the Turk Power Station added in late 2012, for

13

which there was considerable CWIP in rate base under the PSA, there is an estimated $185 million

14

of contra AFUDC which has not been adjusted out of the depreciable base that is used for

15

computing depreciation expense, resulting in overstated depreciation expense of about $4 million

16

per year.

17

Q.

18

The attached example calculation (Exhibit No. SLATER-3) provides a

HAVE YOU CALCULATED THE IMPACT OF THIS ERROR IN SWEPCO’S FORMULA RATE AND THE VALUE TO MINDEN?

19

A.

Yes, by failing to reduce the contra AFUDC from the depreciable base, depreciation

20

expense is overstated. To account for this error, an estimate of the depreciation expense on the

21

$185 million in contra AFUDC was calculated using a weighted average depreciation expense,

22

from Schedule 16a.

23

Depreciation Expense on Schedule 16. The total reduction to Annual Capacity and Energy charges

This resulting depreciation expense was deducted from the Steam

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Exhibit No. SLATER-1 Page No. 25 of 30 1

to Minden under the PSA is estimated to be $32,929, or 0.4% of the adjusted Base Case annual

2

charges of $9,124,347.

3

Q.

PLEASE DESCRIBE THE ISSUE RELATED TO UNFUNDED RESERVES

4

IDENTIFIED IN THE ASSESSMENT AND ITS IMPACT ON THE ANNUAL

5

PRODUCTION COST.

6

A.

Regulated electric utilities often create reserves for unforeseen contingencies that might

7

require large outlays at one time, or for predictable events for which the timing and magnitude are

8

not precisely known. Examples of such reserves may include vacation accrual, sick leave accrual,

9

severance expense accrual, or injuries and damages accrual. Typically, such reserves are set up

10

either as a noncurrent liability in Account 228, or Miscellaneous current and accrued liabilities in

11

Account 242. Such reserves are established by the utility booking an estimated operating expense,

12

quite often to one of the administrative and general accounts (e.g., Account 925 Injuries and

13

Damages), to build up the reserve fund and establish a liability account to reflect this charge. These

14

accrual charges are routinely included in public utilities’ formula rates. When a qualifying event

15

occurs, the reserve fund is credited, and cash is reduced, rather than the cost of the actual event

16

being charged to an operating expense account at that time.

17

Often these reserves are unfunded; that is, the funds collected through rates are not set aside

18

in escrow to be used only when a qualifying event occurs. Instead, the accumulated cash is treated

19

as customer-contributed capital available for unrestricted use by the utility until an event occurs

20

that requires such cash to be used to pay for a qualifying event covered by a contingent liability.

21

These unfunded reserves are cost-free customer contributed capital on which the utilities should

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-1 Page No. 26 of 30 1

not be allowed to earn a return. The accrued amounts of such unfunded reserves should be

2

reductions to rate base.15

3

A review of the Account 190 ADIT in the workpapers to SWEPCO’s annual true-up for

4

calendar year 2016 (WP-8a) reveals that SWEPCO is apparently accruing reserves for several

5

items that should give rise to unfunded reserves being built up and recorded in FERC Accounts

6

228.1-228.4 and/or 242. However, there is currently no provision in the formula rate to offset rate

7

base for these reserves. These accounts in particular are being identified as they would typically

8

have accruing reserves in an Account 228. It is possible that there are other unfunded reserves in

9

addition to the accounts listed below, however, a more extensive review of supporting data is

10

necessary. Preliminarily, items identified in the 2016 actual true-up under Account 190 ADIT that

11

indicate SWEPCO is holding unfunded reserves are:

12

i.

602A Prov Worker’s Comp;

13

ii.

605E Supplemental Executive Retirement Plan;

14

iii.

605O Accrued PSI Plan Exp;

15

iv.

611E Accrued Mine Reclamation;

16

v.

611G Defd Compensation – Book Expense;

17

vi.

612Y Accrd Companywide Incentv Plan; and

18

vii.

613E Accrued Book Vacation Pay.

19

In order to appropriately compensate Minden for the use of these reserves, consistent with

20

accepted FERC ratemaking, rate base offsets should be set up in the rate template to recognize that

21

SWEPCO has “cost free” access to these funds. Specifically, the formula rate should contain line

15

Xcel Energy Southwest Transmission, 149 FERC ¶ 61,182, at P 97 (2014).

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Exhibit No. SLATER-1 Page No. 27 of 30 1

item credits for unfunded reserves which are deducted from the rate base to avoid SWEPCO’s

2

over-recovery of the revenue requirement. Additionally, supporting workpapers in the formula

3

rate template should demonstrate the accrual of reserves in FERC Accounts 228.1-228.4 and/or

4

242.

5

Q.

6

ARE YOU ABLE TO ESTIMATE THE FINANCIAL VALUE TO THE LACK OF OFFSET TO THE RATE BASE FOR UNFUNDED RESERVES?

7

A.

Yes. The value of the unfunded reserves is a conservative estimate, as it is based on the

8

balances of the above listed accounts only. From workpaper WP-8a, the balances in Account 190

9

are the accrued deferred income taxes on the items listed. Thus, the total accrued reserve balance

10

for each item is derived by dividing each item’s balance by the composite tax rate. Then, the

11

derived reserve balances are multiplied by the applicable allocation factor. In this case, 611E

12

Accrued Mine Reclamation is 100% allocated to Production Plant, and the remaining items are

13

allocated by the Labor Allocation Factor of 50.56%.

14

$12,750,281 to Capacity Rate Base and an estimated credit of $35,687,267 to Energy Rate Base,

15

for a total estimated adjustment to rate base of $48,437,548. To calculate the impact of these

16

credits to the final capacity and energy charges, the credits were applied to the rate base calculation

17

on Schedule B-5. The total reduction to Annual Capacity and Energy charges to Minden under

18

the PSA is estimated to be $34,775, or 0.4% of the adjusted Base Case annual charges of

19

$9,124,347.

20

Q.

The result is an estimated credit of

GDS’ 2016 ASSESSMENT ALSO IDENTIFIED AN ERROR IN THE SWEPCO

21

FORMULA RATE WHICH INCORRECTLY INCLUDED NON-PRODUCTION

22

RELATED CWIP IN THE RATE BASE. PLEASE DESCRIBE THIS ISSUE.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-1 Page No. 28 of 30 A review of SWEPCO’s recent annual FERC filings that submit support for the actual

1

A.

2

CWIP expenditures that SWEPCO includes in the PSA formula capacity rate, as referenced in

3

Section 4.07 of the PSA, identified the following minor findings.

4

SWEPCO has included in CWIP expenditures used in the PSA formula rate certain

5

construction projects that, in addition to production plant projects, appear to be transmission,

6

general plant, or intangible plant related. Although minor in amounts, SWEPCO did not provide

7

any justification in the PSA update for inclusion of CWIP for any projects that were not

8

“production related.” SWEPCO should remove those items from CWIP in rate base under the

9

PSA.

10

Q.

11

HAVE YOU CALCULATED AN ESTIMATED IMPACT TO THE ANNUAL PRODUCTION COST DUE TO THIS ERROR?

12

A.

At this juncture the impact did not warrant quantifying. As construction projects begin and

13

end, the specific projects comprising CWIP vary each year. As a result, a misappropriated

14

construction expenditure may only impact the PSA rates for a relatively brief period. Nonetheless,

15

the evidence of non-production expenditures brings into question the frequency with which

16

SWEPCO inaccurately includes non-production CWIP in the PSA formula rate. As such, this

17

issue warrants review and attention to ensure it does not become a trend which over time results

18

in “padding” the account.

19

Q.

HAVE YOU DETERMINED A COMBINED TOTAL OF IMPACTS TO THE

20

FORMULA RATE ANNUAL PRODUCTION COST WHICH REPRESENT ALL

21

OF THE QUANTIFIABLE ISSUES YOU HAVE DESCRIBED? IF SO, PLEASE

22

DESCRIBE YOUR ASSUMPTIONS AND METHODOLOGY IN ARRIVING AT

23

THAT TOTAL.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-1 Page No. 29 of 30 1

A.

2

impact of all quantifiable issues are summarized in the table below (Table 2). As stated earlier in

3

my testimony, the first issue addressed was the reduction in federal income tax rate. Since we

4

anticipate that the revised federal income tax rate will automatically be reflected in the next

5

formula rate true-up, the results of such are considered the base case, referred to here as “Base

6

Case 21%.� All subsequent calculated reductions to the formula charges resulting from addressing

7

each issue in this testimony are measured against Base Case 21%. The impact of each individual

8

issue was calculated using only those inputs and template adjustments necessary to model the issue

9

correction; all other inputs and calculations remained unaltered.

10

The results of the calculations to produce individual issue impacts and a combined total

Not all issues discussed in this testimony gave rise to unique calculations, as some required

11

assumptions based on professional experience and industry knowledge.

For example, the

12

calculation to measure the result of lowering the ROE from 11.1% to 8.2% only required a change

13

to the ROE input value, whereas in the case of the secondary impact of the reduction in Federal

14

Income Tax Rate, that is its effect on ADIT, the amortization period and annual flowback amounts

15

were determined by an average asset life and average depreciation. Although some issues present

16

the possibility of a range of assumptions, to most succinctly address each issue on its face, each

17

was evaluated using the most conservative or likely assumptions. Further, regarding the final issue

18

examined, inappropriate inclusion of non-production CWIP in rate base, addressing this issue is

19

more a matter of reporting transparency and process control. Quantifying this issue may require

20

questionable assumptions. Therefore, this issue was not quantified. Given that there is some

21

overlap among issues, the combined total of impacts is not the cumulative total of each individual

22

issue impact. The total combined reduction to Annual Capacity and Energy charges of all

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-1 Page No. 30 of 30 1

quantifiable issues to Minden under the PSA is estimated to be $645,169, or 7.1% of the Base Case

2

21% annual charges of $9,124,347.

Table 2 – Summary of Issues Summary of Estimated Annual PSA Charges

by Issue (in $)

Capacity Charges Energy Charges Total Billing

4,427,895 5,028,860 9,456,754

Reduction Reduction (%)

DoubleRevised Collection on Depreciation CWIP in Rates AFUDC

Base Case 21 w/ADIT Flowback

Lower ROE

4,112,777 5,011,570 9,124,347

4,039,234 5,010,372 9,049,606

3,728,721 4,990,544 8,719,265

3,995,342 5,011,570 9,006,912

332,407

74,740 0.8%

405,082 4.4%

117,435 1.3%

2016 True-Up Base Case (As Billed) 21%

Unfunded Reserves

Total Impact of All Issues

4,079,847 5,011,570 9,091,418

4,102,732 4,986,840 9,089,572

3,509,647 4,969,531 8,479,178

32,929 0.4%

34,775 0.4%

645,169 7.1%

3

Q.

DOES THIS CONCLUDE YOUR PRE-FILED TESTIMONY?

4

A.

Yes, it does.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-2 Qualifications Michele M. Slater

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit. No. SLATER-2 Page No. 1 of 2

EDUCATION Master of Business Administration, Tulane University, New Orleans, Louisiana.

Beta Gamma Sigma Honor Society Bachelor of Mechanical Engineering, Georgia Institute of Technology, Atlanta, Georgia.

EXPERIENCE Ms. Slater is an accomplished energy consultant with over two decades of experience in the electric utility industry. Ms. Slater has extensive experience in both regulated and de-regulated utility environments assisting clientele with their regulatory processes, market participation and planning.

Ms. Slater began her career with the Georgia Power Company as an assistant plant engineer at Plant Hatch.

Subsequently, she worked at Ebasco Services Inc. as an associate engineer where her work focused on plant system design. Ms. Slater then joined Slater Consulting where she gained substantial experience with economic and system analysis, and litigation support for utility and non-utility clientele, ultimately serving as both a Principal and Senior Consultant. More recently, she was employed with ScottMadden Management Consultants where she was primarily dedicated to their energy practice.

In August, 2016, Ms. Slater joined GDS as a Senior Project Engineer in the Orlando Rates and Regulatory Office. Since coming to GDS, Ms. Slater has been involved in a variety of projects in the areas of wholesale transmission rates, including cost of service and ancillary service charges; merger-related risks; and costrecovery negotiations. Recent projects include: 















Identification of potential financial impacts on Kansas Electric Power Cooperative due to the proposed GPE/Westar merger, particularly as related to its jointly-owned generation operating agreements, its partial requirements services agreement with Westar, and its SPP OATT transmission service.

Representation of wholesale transmission customer, ReEnergy Holdings LLC, in rate settlement negotiations with Emera Maine.

Evaluation of DEP’s proposed nuclear plant decommissioning cost allocation update and abandoned plant cost recovery for various North Carolina wholesale municipal customers.

Providing analysis to support NCEMPA and FPWC in negotiations with DEP to address recovery of coal ash compliance costs in anticipation of a FERC filing regarding amendments to the purchase power agreements.

Review and analysis of PacifiCorp’s proposed changes to Ancillary Service rates to address revised NERC standards on behalf of a joint customer group comprised of Utah Associated Municipal Power Systems, Utah Municipal Power Agency, Deseret Generation & Transmission Co-operative and Bonneville Power Administration. Responsibilities included analysis of impact of proposed rates, alternative cost development methodology of ancillary rates, and client representation at FERC settlement conferences and at technical meetings. (Docket Nos. ER17-219-000 and EL17-27-000 (consolidated)) Review of annual wholesale fuel factors filed by Mississippi Power Company, assuring adherence to the MPSC-approved process in Docket 16-UN-229, used to develop wholesale fuel cost recovery (FCR) factors on behalf of Cooperative Energy.

Developed estimates of financial impacts of the Tax Cut and Jobs Act 2017 for several clients taking wholesale service under formula or stated rate agreements.

Responsible for the review of the annual informational filings setting forth updated transmission charges of Central Maine Power Company (CMP), Emera Maine Bangor Hydro District (Emera BHD), and Emera Maine Public District (Emera MPD) on behalf of the Maine Public Utilities Commission to determine each Utility’s compliance with the requirements of the Utility’s tariff and the FERC system of accounts.

Verifying consistency with the Utility’s actual costs; reasonableness of costs and assumptions; and

1|M i c h e l e S l a t e r C V

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit. No. SLATER-2 Page No. 2 of 2



consistency with FERC precedent. Supported the MPUC with preliminary challenges and advised with settlement. (Dockets ER09-938-000, ER15-1434-000, and ER15-1429) Review and assessment of Entergy Services’ filing of revised service cost allocation formulae for their affiliates and associated companies service agreement to determine adverse impacts to wholesale customers taking service from Entergy affiliates, on behalf of Cooperative Energy, Arkansas Electric Cooperative Corporation, and East Texas Electric Cooperative. (Docket ER18-445)

ScottMadden Management Consultants, Atlanta, Georgia 2012-2015 Senior Associate  Led the assessment of four strategic programs at a leading ISO. Project included evaluating program performance against their intended purposes and industry best practices.  Worked with Operations teams of a federally owned utility corporation as part of a major organizational redesign effort to assess the impacts of the new organization structure.  Led the development of numerous corporate policies governing technical operations at a large, multistate transmission provider.

Slater Consulting, Atlanta, Georgia 1992-2012 Principal and Senior Consultant  Supported the defense of Cinergy in New Source Review (NSR) litigation brought by the EPA saving the utility hundreds of millions of dollars in environmental upgrade cost or capacity replacement costs.  Participated in the representation of the Official Committee of Equity Holders in the Mirant Chapter 11 bankruptcy, which resulted in stockholders retaining significant value in the emerging corporation.  Assisted a West Texas cooperative in determining monthly profitability arising from wholesale electric power sales into the southwest power pool electric market.  Assisted in the development of an estimate of lost net revenues associated with a multi-month large fossil unit outage in the northeastern ISO markets.  Provided Analysis and litigation support in landmark cases before the Georgia Public Service Commission which established Mid-Georgia Cogen, a 300MW cogeneration plant, as the state’s first Qualifying Facility (QF), and determined the avoided cost methodology in Georgia.

Ebasco Services Incorporated, Atlanta (Norcross), Georgia 1990-1992 Associate Engineer  Design Installation specifications for a Flue Gas Desulphurization System (FGDS) and Baghouse at Conemaugh Station, PA, for Clean Air Act compliance.  Designed Power Plant Systems with significant emphasis on writing design specifications requiring attention to detail regarding the adherence to industry standards and codes.

Georgia Power Company, Plant E.I. Hatch, Baxley, Georgia 1988-1989 Assistant Plant Engineer Oversight of daily operation and maintenance and major overhauls of reactor support systems. Planning and implementing major outage projects, including equipment replacement, system testing, safety reviews, and assessment of impacts on plant performance. Planning and supervision of repair and replacement activities including scheduling manpower, procuring parts and coordinating with other departments and personnel.

2|M i c h e l e S l a t e r C V

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-3 Depreciation Double Collection Issue

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SLATER-3 Page No. 1 of 1 DEPRECIATION DOUBLE COLLECTION ISSUE Simplified Ratemaking Example of Avoidance of Double Collecting of AFUDC when CWIP is in Rate Base Line Assumptions: 10% AFUDC Rate: 10% Rate Base Return: 5 Life of Asset (Years): 20% Depreciation Rate: 1 year Project Construction Period: All Direct Costs Expended on January 2 (to make the math easy) NO CWIP in Rate Base - Reference Case Construction Period 1,000 $ 100 $ 1,100 $

1 2 3

Direct Costs AFUDC Total CWIP on Dec 31

4 5 6 7 8 9

Depreciable Base --> Plant in Service at B/Y Depreciation Plant in Service at E/Y Average Rate Base $ Return on Rate Base $ Total Capital Related RR (Depreciation + Return)

Year 1

$ $ $ $ $ $

100% CWIP in Rate Base - Correct Ratemaking Treatment Construction Period 10 Direct Costs 11 AFUDC 12 Total CWIP on Dec 31 13 14 15 16 17 18

$ $ $

Year 1

$ $ $ $ $ $

100% CWIP in Rate Base - SWEPCO Ratemaking Treatment Construction Period

22 Plant in Service at B/Y 23 Depreciation 24 Plant in Service at E/Y 25 26 27 28

$ $ $

880 220 660 770 77 297

Year 2

$ $ $ $ $ $

660 220 440 550 55 275

Year 3

Year 4

$ $ $ $ $ $

440 220 220 330 33 253

Year 4

Year 5

$ $ $ $ $ $

220 220 110 11 231

$

Total 1,375

$

Total 1,350

$

Total 1,425

Year 5

1,000 200 800 900 90 290

$ $ $ $ $ $

800 200 600 700 70 270

$ $ $ $ $ $

$ $ $ $ $ $

400 200 200 300 30 230

$ $ $ $ $ $

200 200 100 10 210

Year 5

Year 4

Year 3

Year 2

Year 1

600 200 400 500 50 250

1,000 100 1,100

Depreciable Base -->

Adjustment to Rate Base for AFUDC (No Double Counting) Average Rate Base $ Return on Rate Base $ Total Capital Related RR (Depreciation + Return)

$ $ $ $ $ $

Year 3

1,000 1,000

Depreciable Base --> Plant in Service at B/Y Depreciation Plant in Service at E/Y Average Rate Base 100 $ Return on Rate Base 100 $ Total Capital Related RR (Depreciation + Return)

19 Direct Costs 20 AFUDC 21 Total CWIP on Dec 31

1,100 220 880 990 99 319

Year 2

100 100

$ $ $ $ $ $ $

1,100 220 880 (100) 890 89 309

$ $ $

880 220 660

$ $ $

660 220 440

$ $ $

440 220 220

$ $ $

220 220 -

$ $ $ $

(100) 670 67 287

$ $ $ $

(100) 450 45 265

$ $ $ $

(100) 230 23 243

$ $ $ $

(100) 10 1 221

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Direct Testimony of Kevin P. Suhanic

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 1 of 9 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

EL18-__-000

DIRECT TESTIMONY AND EXHIBITS OF KEVIN P. SUHANIC ON BEHALF OF THE CITY OF MINDEN, LOUISANA

February 28, 2018

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 2 of 9 LIST OF EXHIBITS Exhibit No.

Description

SUHANIC-1

Direct Testimony of Kevin P. Suhanic

SUHANIC-2

Qualifications of Kevin P. Suhanic

SUHANIC-3

ACES’s Analysis of Minden Hedging Strategies

SUHANIC-4

Form of Transaction Specification Sheet for Network Integration Transmission Service Between MISO and AEP for Service to Minden, May 31, 2013

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 3 of 9 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

Minden, Louisiana, Complainant v.

Southwestern Electric Power Company Respondent

) ) ) ) ) ) )

Docket No.

EL18-__-000

DIRECT TESTIMONY AND EXHIBITS OF KEVIN P. SUHANIC ON BEHALF OF THE CITY OF MINDEN, LOUISANA

1

Q.

PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.

2

A.

My name is Kevin P. Suhanic. I am the Director of Transmission Services for Alliance for

3

Cooperative Energy Services (“ACES”). My business address is 4140 West 99th Street, Carmel,

4

IN 46032. ACES is a nationwide energy management company providing a full suite of services

5

in the wholesale electricity markets, including trading, congestion management, consulting

6

services, and back office services to a wide swath of customers, concentrated on electric

7

cooperatives but also serving municipals, for-profit clients, and others.

8

Q.

PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND.

9

A.

I earned a Bachelors of Business Administration and Masters of Business Administration

10

from the University of Notre Dame. I have participated in numerous industry conferences,

11

trainings, and discussions.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 4 of 9 1

Q.

PLEASE BRIEFLY DESCRIBE YOUR PROFESSIONAL BACKGROUND.

2

A.

I have twelve years of experience working in the industry. I have been continuously

3

employed at ACES, providing and executing congestion management strategies across most of the

4

United States, working with Auction Revenue Rights (“ARRs”), Financial Transmission Rights

5

(“FTRs”) and their equivalents in the California Independent System Operator, Southwest Power

6

Pool (“SPP”), ERCOT, Midcontinent Independent System Operator (“MISO”) and PJM

7

Interconnection, L.L.C. (“PJM”) markets. I also work with physical transmission requests in these

8

markets and in other markets. I lead a team of nine managers, analysts, modelers, and engineers

9

in creating and effectuating successful congestion risk management strategies across these

10

markets. I also lead consulting projects for potential resource and load changes and the market

11

impacts of such changes. My current resume summarizing my utility experience is included herein

12

as Exhibit No. SUHANIC-2.

13

Q.

WHAT IS THE PURPOSE OF YOUR AFFIDAVIT?

14

A.

The purpose of my affidavit is to support the Complaint (“Complaint”) of the City of

15

Minden, Louisiana (“Minden”) contesting issues related to the congestion charges passed through

16

under its existing full requirements Power Supply Agreement (“PSA”) with Southwestern Electric

17

Power Company (“SWEPCO”). My testimony will describe and quantify congestion issues

18

identified through ACES’s November 2016 analysis (“November 2016 Analysis”) of Minden’s

19

congestion charges, and provide more detail about how the MISO Real Time Market congestion

20

risk creates significant risk to the City of Minden. I will also describe and how such risk would

21

typically be mitigated, as SWEPCO has not mitigated said risk in this instance.

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Exhibit No. SUHANIC-1 Page No. 5 of 9 1

Q.

WHAT IS YOUR RELATIONSHIP TO MINDEN?

2

A.

In October 2016, ACES was originally retained by counsel for Minden to provide analysis

3

into a sudden spike in Minden’s costs. ACES was provided several documents and data sets,

4

including the MISO Form of Transaction Specification Sheet for NITS for the pseudo-tie under

5

NS1005, Minden meter data, MISO congestion bills, and related data. This was further combined

6

with MISO market data that ACES captures from publicly available MISO postings.

7

ACES determined that Minden was facing extremely volatile congestion charges and

8

SWEPCO was informed of the issue. My analysis shows there were two main causes of this

9

volatility: 1) a change in SWEPCO’s ARR Self-Scheduling in MISO, the process in which ARRs

10

are converted to FTRs; and 2) the lack of a real-time hedging activities. I identified three steps to

11

create an effective hedging strategy of these congestion charges for Minden.

12

Q.

DID YOU PROVIDE MINDEN WITH A QUANTIFIED ANALYSIS OF THE

13

COSTS AND BENEFITS OF THREE DIFFERENT HEDGING STRATEGIES IN

14

NOVEMBER 2016?

15

A.

Yes, it is attached at Exhibit No. SUHANIC-3.

16

Q.

PLEASE EXPLAIN THE RESULTS OF YOUR ANALYSIS.

17

A.

I analyzed three distinct scenarios against historical congestion by month, representing

18

each step of the three-step process needed to minimize Minden’s risk. Step one is to nominate

19

valuable ARRs. Step two is to convert awarded ARRs to FTRs. Finally, step three is to enter into

20

two virtual transactions for quantities equal to the FTRs held, one at the MISO-SPP interface and

21

the other at the load.

22 23

My review showed that SWEPCO had been doing step 1 consistently, and that this strategy led to monthly charges ranging between a cost of $408,000 and a benefit of $303,000.

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Exhibit No. SUHANIC-1 Page No. 6 of 9 1

My review also showed that SWEPCO had done step 2 for some, but not all, periods and

2

that if done consistently, it would have led to monthly charges ranging between a cost of $372,000

3

and a benefit of $229,000.

4

Lastly, my review showed SWEPCO had never done step 3 and that this strategy would

5

have led to monthly charges ranging between a cost of $19,000 and a benefit of $129,000.

6

Q.

7

IF YOU WERE ASKED TO PROVIDE A SIMILAR ANALYSIS TODAY, WOULD YOUR METHODS BE THE SAME? IF NOT, WHY?

8

A.

I would use the same methods today.

9

Q.

IF YOU WERE ASKED TO PROVIDE A SIMILAR ANALYSIS TODAY, WOULD

10

YOU EXPECT A SIMILAR RESULT IN ORDER OF MAGNITUDE OF RISK TO

11

MINDEN?

12

A.

I would expect similar results, as I am not aware of any changes in MISO that would affect

13

this situation or my analysis.

14

Q.

DO YOU AGREE WITH THE HEDGING STRATEGY ENTERGY SUGGESTED

15

FOR MINDEN IN ANSWER TO THE SWEPCO COMPLAINT IN FERC DOCKET

16

NO. EL17-89-000?

17

A.

18

Entergy specifically states as follows:

19 20 21 22 23 24 25 26

Yes. It is the same strategy that I suggested for Minden in my November 2016 Analysis.

A virtual schedule allows a market participant to make a purchase or sale of energy in the MISO Day-Ahead market, “close out” the transaction in real time, and then pay the difference between the Day-Ahead and Real Time settlements. If properly managed, the use of virtual schedules could have greatly reduced [Minden’s] exposure to Real-Time congestion charges. This, combined with the ARRs/FTRs allocated to AEP, could have further reduced all congestion charges owed to MISO for its Minden load.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 7 of 9 1

Motion to Intervene and Protest of Entergy Services, Inc., Docket No. EL17-89-000, at pp. 7-8

2

(Oct. 5, 2017). I completely agree with Entergy that using virtual scheduling along with ARRs

3

and FTRs could significantly reduce Minden’s risk of paying MISO congestion charges.

4

Q.

IF SWEPCO CONTINUES TO REFUSE TO PROVIDE THIS SERVICE, COULD

5

MINDEN EASILY FIND A SUPPLIER OF THE HEDGING SERVICES, OR

6

COULD MINDEN PERFORM THE HEDGING SERVICE ITSELF? PLEASE

7

EXPLAIN.

8

A.

9

to manage the complex instruments present in the wholesale electric markets. To the extent risks

10

remain with the buyer, typically the full requirements provider will handle market interactions to

11

minimize that risk, as they have the infrastructure to do so. I am not aware of any instance where

12

a municipal load the size of Minden has the capability to directly transact in the MISO or SPP

13

markets daily while under a full requirements contract. I also find it unlikely that a service provider

14

who is not also serving energy to the load would provide such a service, as market interaction is

15

bundled into the full requirements costs. There is little incentive for a third-party provider to do

16

so at a reasonable rate. In the simplest terms, Minden is too small a load to build these capabilities

17

effectively outside of their full requirements provider.

18

Q.

19

Full requirements contracts are often sought by smaller entities without the sophistication

WHAT, IF ANY, VALUE ACCRUES TO MINDEN FROM MINDEN’S PAYMENT OF CONGESTION CHARGES IN MISO?

20

A.

For Minden, there is no value created by real-time congestion payments. If the Minden

21

load pocket was larger and more consistent, economic theory might point to a new resource being

22

installed in this location, but this is implausible at the current scope of the issues. The “value” of

23

congestion payments loosely goes back to MISO real-time market participants. This “value”

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 8 of 9 1

would be captured by Minden if SWEPCO entered into the virtual transactions advised in step

2

three of my recommended approach. Currently, Minden derives no value from these payments.

3

Q.

IS MINDEN SERVED VIA A PSEUDO-TIE MANAGED BY AEP?

4

A.

Yes, attached as Exhibit No. SUHANIC-4 is the contract that SWEPCO supplied to

5

Minden in a data request showing the transmission arrangements that SWEPCO made for

6

Minden’s load through MISO after Entergy joined MISO in 2013. I reviewed this as part of my

7

initial analysis.

8

Q.

9

DOES THE USE OF A PSEUDO-TIE CHANGE WHEN THE LOAD BECOMES PART OF AN ISO MARKET?

10

A.

The interaction of congestion and pseudo-tied loads, or resources in a locational marginal

11

price (“LMP”) market, is very different than in a non-LMP market. A pseudo-tie removes a load

12

or resource from one Balancing Area and puts it into another, using firm transmission service and

13

changes to telemetry. In a traditional market, such as the Entergy market before MISO integration,

14

a pseudo-tie may be a straightforward way to join loads under one Balancing Authority. However,

15

when both sides of a pseudo-tie are part of LMP markets, there are new exposures that can be more

16

cumbersome to manage, specifically the real-time congestion risk, as discussed earlier in my

17

testimony. As such, before Entergy became part of MISO, Minden paid the transmission service

18

cost, a known and mostly fixed charge, to Entergy. However, post-MISO integration, Minden now

19

faces an additional risk of real-time congestion charges that require a robust management strategy.

20

Q:

WOULD THIS BE A LARGE CHANGE IN MINDEN’S TOTAL BILL?

21

A:

Yes. In my initial review, I received invoice details covering June 2016 through September

22

2016. These invoices and details showed an average of $1,145,573 in billed charges excluding

23

MISO congestion for the period covering June 2016 through September 2016.

A $372,000

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-1 Page No. 9 of 9 1

variation in that bill due to congestion would calculate to an unexpected and unhedged 32%

2

increase in that cost, which could be characterized as a large change. Also, this is using the summer

3

billings which have higher MWh consumption, so such a charge in other periods could be an even

4

larger percentage of the total billing, which I have not reviewed.

5

Q.

WOULD A MUNICIPAL UTILITY SUCH AS MINDEN BE EXPECTED TO

6

EXPERIENCE SOME HARDSHIP ASSOCIATED WITH A VOLATILE

7

WHOLESALE RATE THAT MIGHT FLUCTUATE AS MUCH AS 32% FROM

8

THE TOTAL AVERAGE MONTHLY BILL?

9

A.

A less certain cost of energy and fluctuating results would add a burden to working capital

10

needs. Minden would need to hold excess cash or liquidity to ensure that it could pay the bills, as

11

there could be several months or even an extended period of much higher than expected costs. I

12

have not studied Minden’s balance sheet, but one could reasonably expect the need for such a

13

reserve could result in foregoing other projects that require working capital or incurring higher

14

borrowing costs.

15

Q.

DOES THIS CONCLUDE YOUR PRE-FILED TESTIMONY?

16

A.

Yes.

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-2 Qualifications of Kevin P. Suhanic

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-2 Page No. 1 of 1

Kevin P. Suhanic 15529 Brackenwood Ct. • Noblesville, IN • 46062 • (317) 567-1300 • ksuhanic@gmail.com

RELEVANT UTILITY EXPERIENCE • • • • • • •

Extensive experience with electric portfolio optimization, power price forecasting, and basis modeling Thorough knowledge of ISO/RTO markets nationwide; monthly interaction in several markets Led multiple client integrations into nodal market congestion management Power, capacity, and customized product pricing and evaluation experience Led many dynamic projects, from customer acquisition to project development through modeling and delivery Thorough working knowledge of power and energy derivatives (power options, spark spreads, etc.)

Demonstrated ability to manage staff, interface with clients, and work across functional areas to solve problems

EXPERIENCE ACES POWER MARKETING, INDIANAPOLIS, INDIANA DIRECTOR OF TRANSMISSION SERVICES, OCTOBER 2015 – PRESENT • Oversee all congestion and transmission strategies nationwide for over 40 portfolios • Lead all nodal business development efforts • Develop staff capabilities – often resulting in promotions to other areas of company • Lead a team of ten managers, analysts, and engineers in modeling future energy markets on both a fundamental basis and through nodal dispatch and market simulation • Present ARR and FTR concepts and issues to executives, boards of directors and other unfamiliar audiences MANAGER OF TRANSMISSION SERVICES, MARCH 2011 – SEPTEMBER 2015 • Direct team of three on congestion and transmission market activities in the MISO, SPP and ERCOT Markets • Create valuations of various nodal derivatives for a variety of customers • Advise clients on risk-mitigation strategies and overall portfolio risk • Continuously improve forecasting and risk assessment processes TRANSMISSION SERVICES –FTR MODELER AND SENIOR FTR MODELER, FEBRUARY 2007 – FEBRUARY 2011 • Provide valuations of energy derivatives to a variety of customers utilizing powerflow simulations, historical market information, and economic conditions • Manage all aspects of ARR and FTR process including source registration and addition/substitution • Review planned unit installations and network upgrades for long-term pricing impacts • Coordinate energy and transmission positions to assess risk and optimize market opportunities

PRICEWATERHOUSECOOPERS, CLEVELAND, OHIO AUDIT & BUSINESS ADVISORY SERVICES, JUNE 2005 – JANUARY 2007 • Performed audit program procedures and documentation in high risk environment for a Fortune 100 company • Analyzed accounts and accounting treatment during a financial restatement concurrent with a SEC investigation • Audited individual commercial rental properties for a national real estate developer • Performed a variety of diligence procedures related to new debt issuances and note conversions

EDUCATION UNIVERSITY OF NOTRE DAME, NOTRE DAME, INDIANA MASTERS OF BUSINESS ADMINISTRATION, Finance Concentration Notre Dame Fellowship Recipient GMAT: 710

GPA: 3.82

UNIVERSITY OF NOTRE DAME, NOTRE DAME, INDIANA BACHELORS OF BUSINESS ADMINISTRATION, Accountancy Major, Finance Concentration Semester Abroad in London, England GPA: 3.59

PROFESSIONAL CERTIFICATION COMMODITY TRADING ADVISOR (CTA) - SERIES 3 EXAM PASSED, REGISTERED CERTIFIED PUBLIC ACCOUNTANT IN OHIO - INACTIVE

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-3 ACES’s Analysis of Minden Hedging Strategies

20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Exhibit No. SUHANIC-3 Page No. 1 of 3

excellence in energy

To:

Betts and Holt / Jill Barker

From:

ACES Transmission / Kevin Suhanic

Date:

11/15/2016

Re:

Minden MISO Congestion

At the request of Betts and Holt, ACES performed a backcast of several strategies to manage Minden congestion exposure. ACES also reviewed the ARR, FTR and Congestion charges passed through to Minden and found periods where is appears Minden was not properly credited for FTRs that should have been held on their behalf. The first half of this memo will discuss the backcasted strategy, and the latter half will review the discrepancies found.

BACKCAST As a full requirements customer, it is assumed Minden has stability of costs as a primary goal.

The best way to avoid risk of excessive MISO congestion charges is to nominate positive ARRs (which has been done by Swepco), convert ARRs to FTRs (Swepco did this for a period of time, then stopped), and enter into a two daily virtual transactions for the amount of FTRs owned to own a hedge on the real time LMP spread. (Swepco has never done this.)

Three strategies were reviewed: Do not convert ARRs and do not make a virtual transaction:  Monthly results range from a cost of $408K to a benefit of $303K  Monthly Standard Deviation of $145K  Fully exposed to Real-Time Congestion Convert ARRs and do not make a virtual transaction:  Monthly results range from a cost of $372K to a benefit of $229K  Monthly Standard Deviation of $92K  FTRs hedge congestion somewhat in Day-Ahead, but still exposed to Real-Time Exposure Convert ARRs and undertake two virtual transactions:  Monthly results range from a cost of $19K to a benefit of $129K  Monthly Standard Deviation of $38K  Mitigates real-time exposure as much as possible, remaining risk is due to load volumes varying whereas FTRs and ARRs are fixed quantities

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Exhibit No. SUHANIC-3 Page No. 2 of 3

As the virtual transactions may be confusing, the following example should help: We will use the data for Hour 18 on 9/27/16 and 9/28/16. The transaction consists of a BUY at a very high price at the load node, CSWS.MINDEN, and a SELL at a very low price at the import node, CSWS. The extreme prices are to ensure both bids clear, as having only one or the other clear will create an ineffective hedge.

9/27/2016 Hour 18 In the Day-Ahead Market The 20.6 MW FTR settles for the Day-Ahead Congestion Spread of $8.43/MW, for revenue of $173.66 Buy 20.6 MWs at CSWS.MINDEN, cost is $40.75/MW (Day-Ahead LMP) totaling ($839.45) Sell 20.6 MWs at CSWS, revenue is $29.90/MW (Day-Ahead LMP) totaling $615.98 Total Day-Ahead Activity equals ($49.81) In the Real Time Market The 23.3* MW Schedule is charged the real-time congestion spread of $0.92/MW, totaling ($21.47) The 20.6 MW buy is sold back at CSWS.MINDEN, revenue is $27.48/MW (RT LMP) for $566.09 The 20.6 MW sale is bought back at CSWS, cost is $24.86/MW (RT LMP) for ($512.12) Total Real-Time Activity equals $32.50 All market activity equals ($17.31) for the hour.

If no hedges were in place market activity would be $173.66 + $(21.47) = $152.19

9/28/2016 Hour 18 In the Day-Ahead Market The 20.6 MW FTR settles for the Day-Ahead Congestion Spread of $1.40/MW, for revenue of $28.84 Buy 20.6 MWs at CSWS.MINDEN, cost is $32.48/MW (Day-Ahead LMP) totaling ($669.09) Sell 20.6 MWs at CSWS, revenue is $31.08/MW (Day-Ahead LMP) totaling $640.02 Total Day-Ahead Activity equals ($29.07) In the Real Time Market The 28* MW Schedule is charged the real-time congestion spread of $31.43/MW, totaling ($880.04) The 20.6 MW buy is sold back at CSWS.MINDEN, revenue is $76.15/MW (RT LMP) for $1,568.69 The 20.6 MW sale is bought back at CSWS, cost is $41.79/MW (RT LMP) for ($860.87) Total Real-Time Activity equals ($172.22) All Market Activity equals ($201.29) for the hour.

If no hedges were in place market activity would be $28.84 + $(880.04) = ($851.20) USING THE HEDGE STRATEGY REDUCES VOLATILITY, however some hours it would be more beneficial not to hedge, as is the case with any hedge. *Added 15 MWs due to influence of steam unit offsetting load number in actual data, example is only meant to be representative.

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Exhibit No. SUHANIC-3 Page No. 3 of 3

CONGESTION CHARGE REVIEW In the attached file, ACES estimates that Minden has not received credits totaling just over $1 Million, comprised of two distinct periods.

December 19, 2013 through May 31st, 2014:  MISO Allocated FTRs directly for this period in lieu of the annual ARR process, due to the midperiod start of the market. The data supplied do not show any credits for FTRs during this time, which we believe there should be credits for, similar to June 2014 – May 2016.  We are unable to determine the quantity that was awarded during this period without further data from Swepco, but using ARR allocation levels for the same period in the 2015/16 Planning Year, we estimate a value of $706K for this period that Minden should be due. The analysis can be updated if Swepco can provide actual FTR volumes.  Our values do not account for lost benefits from December 19 – December 31, 2013.

June 1, 2016 through September 30th, 2016 and ongoing:  Swepco switched from a hedging strategy to a riskier strategy of not self-converting ARRs. This does not seem prudent and it appears no congestion hedges were obtained, instead letting ARRs settle for cash while congestion exposure remained. (Swepco could have purchased FTRs rather than self-schedule, but they did not due this either.)  Swepco provided Minden $279K in credit for the ARR cash settlement, and caused Minden to lose $593K in FTR benefits during this period, for a net loss of $314K to Minden.  This only accounts for lost value through September 30, 2016, and losses are likely continuing to accrue.

Notes about Data: These figures may be slightly different than actuals due to rounding differences in underlying prices, how fractional megawatts are calculated, and due to the shifts for daylight savings time. None of these differences should be material.

Wherever possible, data provided by Swepco was utilized. However some data was used from other sources or inferred as follows:  MISO market data was used for real-time LMPs.  For the period prior to 6/1/2014, the “No conversion” and “ARR conversion” strategies were simulated. MISO awarded “allocated FTRs” directly for this period, however they could be used in either manner like ARRs during the period. This time period was calculated as follows: o It was assumed that FTRs were awarded in the same quantities as ARRs were for winter/spring 2015 – Swepco has not provided this data. o FTR funding levels were set to the average of the 3/1/2014 – 5/31/2014 data provided

by Swepco, data pre-3/3/2014 was not provided.

The ARR Clearing Price used in the “No conversion” strategy was set to the first auction price for that period – where the allocated FTRs could have been sold at the first opportunity.

Approximately $17K in value is unreconciled to the invoice support, which can be further analyzed with Swepco data should further data be obtained. ###

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Exhibit No. SUHANIC-4 Form of Transaction Specification Sheet For Network Integration Transmission Service Between MISO and AEP for Service To Minden, May 31, 2013

A~rtY1 NSIOO'S

otJL~ I tJ{j.p Form of TransactionSpecification Sheet for Network IntegrationTransmission Service Dated as of ~ 11. '?()13 A

Exhibit No. SUHANIC-4 Page No. 1 of 9

A-.

,

1.0

In accordance with the Service Agreement, dated as of l/v/{t.ÂŤ>i by and between the Midwest ISO and American Electric Power Service Corporation (Transmission Customer), the Transmission Customer requests a transaction of Network Integration Transmission Service.

2.0

Nature of Transmission Request: This request for Network Integration Transmission Service is due to Providing Service to Minden, LA via pseudo-to to the CSWS balancing authority in the Southwest Power Pool

3.0

Type of Transmission Service: The Network Integration Transmission Service requested is under the Tariff.

The Services requested are described as follows: Firm Network Integrated Transmission

Service from SPP to Minden,

LA.

Specific local facilities needed to provide the service are none

4.0

Term of Transaction: ~~~~~~~~~~~~~~~~~~~~ 5-years Start Date: December 19th, 2013 Termination Date: ~~~~~~~~~~~~~~~~~~December 19th, 2018

5 .0

Description of capacity and energy to be transmitted by Transmission Provider: Capacity and energy will be provided by AEPM via a pseudo-tie.

•

Exhibit No. SUHANIC-4 Page No. 2 of 9

Note: Include the electric control areas in which the transaction originates and terminates.

6.0

7.0

Point(s) of Receipt: _E_Es Delivering Party: _A_E_PM

_ _

Point(s) of Delivery: _E_E_s Receiving Party: AEPM

_

-------------------

8.0

Network Resources 8.l

Transmission Customer Generation Owned or Leased: Resource

Capacity

Capacity Designated As Network Resource

Designated Interfaces

CSWS Slice of System

48mw

CSWS Slice of System

CSWS/MISO interface

8.2

Transmission Customer Generation Purchased: Resource

Capacity

Capacity Designated As Network Resource

Designated Interfaces

NA

NA

NA

NA

Note: Attach operating information and description to comply with the Tariff and 18 CFR Section 2.20.

9.0

Network Load 9.1

Transmission Customer Network Load: Network Load

Transmission Voltage Level

48mw

115kV

•

9.2

Exhibit No. SUHANIC-4 Page No. 3 of 9

Description: a)

Receipt/Delivery Point Electrical Characteristics: Entergy's Minden Substation operating at 115kV.

Note: Please include a Single-Line Diagram if the Delivery Point has Direct Assignment Facilities or Wholesale Distribution Service is necessary. b)

Expected Transmission Profile: See Appendix A, for the Minden, LA Single-Line Diagram See Appendix B, for the expected transmission profile

Notes: (1) Provide seasonal peaks for the four latest periods.

(2) Provide average weekly load profiles for the four latest seasonal periods (in numbers and graphs). c)

Historical Load Information: See Appendix B Section 2

Notes: (1)

Provide monthly clock hour Coincident Peak Demands (at time of Local Balancing Authority Area System Demand) for each of the last twelve months.

(2) Provide monthly clock hour Non-Coincident Peak Demands (Network Load Highest Demand) for each of the last twelve months.

(3) Provide monthly energy for each of the last twelve months.

d)

Forecasted Load Information: See Appendix B Section 3

Note: (1) Provide projected summer and winter seasonal peak demands for each of the next ten (10) years.

(2) Provide projected energy for each of the next ten (10) years. e)

Interruptible Load: none

•

Exhibit No. SUHANIC-4 Page No. 4 of 9 10.0

Description of Transmission Customers Transmission System: none

11.0

Designation of party(ies) subject to reciprocal service obligation: csws

12.0

Name(s) of any Intervening Systems providing transmission service: csws

13.0

Party Responsible for Providing Real Power Losses: AEPM

14.0

Firmness of Service: Network Firm

15 .0

Reservation Priority: 7-FN

16.0

Deposit: ref Credit Analysis

Note: Please provide calculation.

17.0

Creditworthiness: Per Tariff, on file with Credit Department

•

Exhibit No. SUHANIC-4 Page No. 5 of 9 Any credit request should be addressed to the following:

18.0

Name:

James Ballantyne

Title:

Credit Analyst

Phone:

614-583-6737

Fax:

NA

E-mail:

jvballantyne@aep.com

Service under this Agreement may be subject to some combination of the charges detailed below, and will be determined in accordance with the terms and conditions of the Tariff.

18.1

Transmission Service Charge: Per Tarrif

18.2

System Impact and/or Facilities Study Charge(s): Per Tarrif

18.3

Network Upgrade: Per Tarrif

18.4

Direct Assignment Facilities Charge: Per Tarrif

18.5

Ancillary Services Charges: Self provided

18.6

Charges for Wholesale Distribution Service: none.

Note: See AttachmentWDS enclosed.

•

Exhibit No. SUHANIC-4 Page No. 6 of 9 18.7

Redispatch Charge: Per Tarrif

18.8

Power Factor Requirements (if applicable): Per Tarrif

19.0

20.0

Any notice or request made to the Transmission Customer regarding this Agreement shall be made to the following representative as indicated below: Name:

Kent Feliks

Title:

General Contact

Phone:

614-716-2379

Fax:

NA

E-mail:

kdfeliks@aep.com

The Tariff, Service Agreement and Network Operating Agreement are incorporated herein and made a part hereof.

•

Exhibit No. SUHANIC-4 Page No. 7 of 9 IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective authorized officials.

Transmission Customer By:4~

NaZJ<enf D. Feliks Title: Date:

General Contact May 31st, 2013

Planning Concurrence

Operations Concurrence By:

Date: Transaction Accepted AREF# -----The Midwest ISO executes this Transaction Specification Sheet and Network Operating Agreement subject to review by the Midwest ISO and the local Transmission Owner identifying any and all operating restrictions associated with this network service. Once identified, these operating restrictions will be added to the Network Operating Agreement.

The Midwest ISO will not be responsible for redispatch costs associated with this service until these operating restrictions are identified and included in the Network Operating Agreement with the Transmission Customer.

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APPENDIX B (Minden, LA) Section 1: Expected Transmission Profile:

YEAR MW 2014 43.6 2015 44.1 2016 44.9 2017 45.4 2018 45.8 Section 2: Historical Load, Previous 12 months May 2012 - April 2013: Monthly

Mav -12 June-12 Julv-12 Aug-12 Sep -12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13

Peak 34.7 39.8 41.9 39.8 40.0 25.5

19.1 21.3 23.5 19.9 19.8 25.7

MWH 15,269 17,671 19,256 19,161 15,405 11,527 10,463 11,581 12,026 10,283 10,782 10,745

Section 3: Forecasted Load Information: Season Winter '13-'14 Summer '14 Winter '14-'15 Summer '15 Winter '15-'16 Summer '16 Winter '16-'17 Summer '17 Winter '17-'18 Summer '18 Winter '18-'19 Summer '19 Winter '19-'20 Summer '20 Winter '20-'21 Summer '21 Winter '21-'22 Summer '22 Winter '22-'23 Summer '23

Peak 24.4 43.6 29.0 44.1 29.3 44.5 29.6 44.9 29.9 45.4 30.2 45.8 30.5 46.3 30.8 46.8 31.1 47.2 31.4 47.7

MWH 66.955 95,584 67,648 96,540 68,427 97,505 69, 111 98,480 69,802 99,465 70,500 100,459 71,205 101,464 71,917 102,479 72,637 103,503 73,363 104,539

Exhibit No. SUHANIC-4 Page No. 9 of 9

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20180228-5274 FERC PDF (Unofficial) 2/28/2018 4:54:28 PM

Document Content(s) Formal Complaint of the City of Minden, Louisiana.PDF.................1-61 D. Parcell Affidavit and Exhibits.PDF.................................62-172 M. Slater Affidavit and Exhibits.PDF..................................173-209 K. Suhanic Affidavit and Exhibits.PDF.................................210-236