IN THE SUPREME COURT OF OHIO
Colunibus Southern Company Case No. 09-2298
Appellant, Appeal from Public V. Utilities Commission of Ohio
The Public Utilities Commission of Ohio, Public Utilities Commission of Ohio Appellee. Case No. 08-917-EL-SSO
MERIT BR1EF AND APPENDIX OF APPELLANT COLUMBUS SOUTIIERN POWER COMPANY
Matvin I. Resnik (0005695) Ricliard Cordray (0038034) Counsel of Record Attonrey General of Ohio Kevin F. Duffy (0005867) Duane W. Luckey (0023557) Steven "T. Nonrse (0046705) Chief, Public Utilities Section Matthew J.Satterwhite (0071972) Werner L. Margard 111 (0024858) Anrerican Electric Power Service Thomas G. Lindgren (0039210) Corporation John H.Jones(0051913) I Riverside Plaza, 29Floor Assistant Attorneys General Colutnbus, Ohio 43215-2373 180 East Broad Street Telephone: (614) 716-1606 Columbus, Ohio 43215-3793 Facsimile: (614) 716-2950 Teleplione: (614) 644-8698 miresnikr),aep.com Facsunile: (614) 644-8764 kfduffy^c^aep.com duane.luckey a yuc.statc.oh.us stnourseL^,aepeont. [email protected] m'tsatterwlute kaep^con thonras.lin Lrennpuc. state. oli.us l'o lm.iones(^pue.state.oh.us
Daniel R. Conway (0023058) Counsel for Appellee, Porter Wright Morris & Arthur LLP Public Utilities Cotnniission of Ohio 41 South lligh Street Columbus, Ohio 43215 Telephone: (614) 227-2270 Facsimilc: (614) 227-2100 dconwa cJ orterwright.com
Counsel for Appellant, Colutnbus Southern Power Company Samuel C. Randazzo (0016386) Janine L. Migden-Ostrander (0002310) (Counsel oCRecord) Consuniers' Counsel Lisa G. McAlister (0075043) Terry Etter (0067445) Joseph M. Clark (0080711) Counsel of Record McNees Wallace & Nuriclc LLC Maw•een R. Grady (0020847) 21 East State Street, 17"' Floor Assistant Consumers' Counsel Columbus, Ohio 43215 Offiee of the Ohio Consumers' Counsel Telephone: 614-469-8000 10 West Broad Street, Suite 1800 Facs imil e: 614-469-4633 Columbas, Ohio 43215-3485 sarn c^mwncmh.com Telephone: 614-466-8574 [email protected] Facsimile: 614-466-9475 iclark(c)mwncmh.com etter(a)occ.statc.oh.us pady_r @occ.state.oh.us Counsel for Intervening Appellee, Industrial Energy Users-Ohio Counsel for Intervening Appellee, Office of the Ohio Consrnners' Counsel
David F. Boehm Michael L. Kurtz Boelun Kurtz & Lowry 36 East Seventh Street, Suite 1510 Cincimlati, Ohio 45202 Tel ephone: 513 -421-22 5 5 Facsimile: 513-421-2764 dboefin(cJ,BKLlawftrm.com mkurtz(ci)BKLlawfirm. com
Counsel for Intervening Appellee, Oliio Energy Group TABLE OF CONTENETS
Page
TABLE OF AUTHORITIF,S ...... ii
STATEMENT OF FACTS AND OF THE CASE ...... 1
STANDARD OF REVIEW ...... 7
ARGU MENT ...... 8
Proposition of Law No. 1
When the Public Utilities Commissiou of Ohio considers an application for approval to sell or transfer generating assets which never have been included in the electric distribution atility's plant-in-service for rate making purposes at the same time it considers the utility's Electric Security Plan application, it is unlawfid for the Commission to deny the authority to sell or transfer those assets and at the same time refuse to allow, as part of the Electric Security Plan, an adjustment for costs associated with maintaining and operating those same assets ...... 8
CONCLUSI ON ...... 15
APPENDIX
PROOF OF SERVICE TABLE OF AUTHORITIES
CASES
AT&T Comn2unications of Ohio, Inc. v. Piub. Util. Comm. (2000), 88 Ohio St. 3d 549, 555 ...... 7
Constellation IVewF,nergy, Inc. v. Pub, Util. Comm. (2004), 104 Ohio St.3d 530 ...... 7
Discoaent Cellular, Inc. v. Pub. Util. Comm., 112 Ohio St. 3d 360, 2007-Ohio-53, ¶51 ...... 13
Monongahela Power Co. v. Pub. Util. Comm. (2004), 104 Ohio St.3d 571 ...... 7
Myer.s v. Pub. Util. Comna., (1992), 64 Ohio St.3d 299, 302 ...... 7
Ohio Consumers' Counsel v. Pub. UtiC. Contrn. (2009), 121 Ohio St. 3d 362, 365...... 7
O&io F,dison Co. v. Pub. Util. Contm. (1997), 78 Ohio St. 3d 466, 469 ...... 7
Tongren v. Pub. Util. Comm. (1999), 85 Ohio St. 3d 87, 88 ...... 13
OHIO REVISED CODE SECTIONS
R.C. 4903.13 ...... 7 R.C. 4909.05 ...... 9 R.C. 4909.15 ...... 9, 12 R.C. 4909.19 ...... :...... 9 R. C. 4928.141 ...... 1,8 R.C. 4928J 42 ...... 1, 8 R.C. 4928.143 ...... 1, 7, 9, 10, 13 R.C. 4928.17 ...... 2, 3, 5, 6, 8,9 OHIO ADMINISTRATIVE CODE
Sec. 4901:1-37-09, Ohio Admin. Code ...... 4
MISCELLANEOUS
Ponner R.C. 4928.17 ...... 2
ii IN TIIE SUPREME COURT OF OHIO
Columbus Southern Company Case No. 09-2298
Appellant, Appeal from Public V. Utilities Commission of Ohio
The Public Utilities Commission of Ohio, Public Utilities Commission of Ohio Appellee. Case No. 08-917-EL-SSO
MERIT BRIEF AND APPENDIX OF APPELLANT COLUMBUS SOUTHERN POWER COMPANY
STATEMF,NT OF FACTS AND OF THE CASE
With the enactrnent of Am. Sub. S. B. 221 (SB 221) by Ohio's 127"' General
Assembly, Ohio's electric distribution companies were required by R.C. 4928.141 (A) to
"apply to the public utilities coinmission to establish the standard service offer in accordance with section 4928.142 or 4928.143 of the Revised Code. ..." Appellant
Columbus Southern Power Company (CSP) and its affiliate Ohio Power Company, both of which are electric utility operating company subsidiaries of American Electric Power
Company, lnc., each filed applications with the Public Utilities Connnission of Ohio
(Commission) for approval of Electric Security Plans (ESP) under R.C. 4928.143. These applications were filed on July 31, 2008, fne effective date of 5B 221. (CSP App. p. 37).
In addition to seeking approval of its proposed ESP, CSP sought approval for the sale or transfer of certain of its generating assets. Commission appi-oval of the sale or transfer was nceessitated by an amendment made by SB 221 to the veision of R.C. 4928.17 (E) enacted as part of Am. Sub. S.B. 3 (SB 3). Prior to this particular amendment, R.C. 4928.17 (E) provided that:
Notwithstauding section 4905.20, 4905.21, 4905.46, or 4905.48 of the Revised Code, an electric utility may divest itself of auy generating asset at any timc without commission approval, subject to the provisions of Title XLIX of the Revised Code relating to the transfer of transmission, distribution, or ancillary service provided by such generating asset. (emphasis added).
Former R.C. 4928.17 (E); CSP App. p. 23 (Enrphasis added).
Division (E) was an appropriate complement to the remainder of R.C. 4928.17 wliich was enacted in 1999 as part of Am. Sub. S. B. 3, (SB 3), and which was an integral part of the General Assembly's restructuring the regulation of Ohio's electric utilities, particularly the newly effective competitive electric generation function of those utilities.
This Section required, and continues to require, a cotporate separation plan that at a minimum:
"[provides for] competitive retail electric service ... t1u•ough a fully separated affiliate of the utility;" "satisfies the public interest in preventing unfair competitive advantage;" and "is sufficient to ensure that the utility will not extend any undue preference or advantage to any affiliate, division, or part of its own business engaged in the business of supplying the competitive retail electric service ... and to ensure that any such affrliate, division, or part will not receive undue preference or advantage from any affiliate, division, or part of the business engaged in [the] business of supplying the noncompetitive retail electric service."
R.C. 4928.17 (A) (1) (2) and (3); CSP App. p. 20.
While SB 221 did not make any changes to the underlying requirement for corporate separation of the generation funetion from the utiiity's noncompetitive fiinctions, division (E) was amended to read as follows:
2 No electric distribution utility shall sell or transfer any generaling asset it wholly or partly owns at airy time without obtaining prior conunission approval.
R.C. 4928.17 (E); CSP App. p. 21.
In the intervening years between the enactment of' SB 3 and SB 221, CSP
acquired two generating facilities. The Waterford Energy Center (Waterford) was purchased on September 28, 2005 and the Darby Electric Generating Station (Darby) was
purchased on Apri125, 2007. (Cos. Ex. 2A, p. 42; CSP Supp. p. 4).
At the time Waterford and Darby were purchased, CSP's expectation under the
then-cunrent lcgal structure of regulation in Ohio was that generation service would be
priced at market rates staiting at the end of 2008 and that electric utilities could continue
to be perniitted to freely transfer gencrating units to and from the distribution utility
without approval of the Commission. In other words, CSP purchased Waterford and
Darby as "merchant plants" and undertook the attendant risk that market rates for
generation service would produce i-evemre below the level needed to support the
investments, either during a given time period or overall during the i-eniaining life of tlie
plants. This situation stands in stark contrast to a regulated utility's investment in the
purchase or constniction of similar generating units, where the regulated utility would be
guaranteed not only the return of the investment but also the opporCunity to eaan a
reasonable return on that investment.
As referenced above, CSP sought authority to sell or transfer these units in
aonjrmctioti with its ESP application. CSP set out in its testimony why it was appropriate
to pennit CSP to sell or transfer these facilities. Chief among these reasons was that
CSP's rates, currentiy and in the past, have never included recovery for CSP's return on
3 or of its investments in Waterfoi-d and Darby. (1d.). Tnstead, these facilities were acquired as "merehant" plants. As alluded to above, CSP took the risk that in the cornpetitivc retail generation niarket provided for under SB 3, these plants would succeed in an enviromnent based on market pricing as opposed to rates set by Conimission regulation. (Tr. X, pp. 229, 230; CSP Supp. pp. 1-2). Further, the amendment to division
(E) :
could not have been more of a reversal of state law. Upto July 30, 2008, a utility could divest generating assets without Cominission approval. As of July 31, 2008, prior Commission approval of such a sale or transfer is required. Many argued during the legislative debates over S.B. 221 that this represents an appropriate change in public policy with respect to generating assets that liad been the basis for rates that customers have been paying, i.e., used and useful for rate base purposes. While I do not agree with these arguments that same argument camiot be made regarding the Darby and Waterford facilities. Therefore, I believe it is appropriate for the Cornuiission to grant CSP, as part of the ESP, the authority to sell or transfer those generating assets.
(Cos. Ex. 2 A, pp. 42, 43; CSP Supp. pp. 4-5.)
In its March 18, 2009 Opinion and Order addressing CSP's application for
approval of its ESP and for approval of authority to sell or transfer the Waterford and
Darby facilities, the Commission denicd the authority to sell or transfer those facilities
and directed CSP to "file a separate application, in accordance with the Commission's
rules, at the time that it wishes to sell or transfer these generating facilities." (Opinion
and Order, p. 52; CSP App. p. 83). The specific rule to which the Commission referred
(Sec. 4901:1-37-09, Ohio Admin. Code), was not adopted by the Commission until
Septernber 17, 2008 and then was modified on rehearing on February 11, 2009, obviously
well after CSP's July 31, 2008 application had been filed for authority to sell or transfor
4 under R.C. 4928.17 (E). Moreover, the rules did not become effective until April 2,
2009, afler the March 18, 2009' Opinion and Order.
In any event, CSP was not left without sonic relief. The Commission went on to provide the following:
The Comniission, however, recognizes that these generaling assets have not and are izot included in rate base and, thus, [CSP] caimot collect any expenses related thereto, even if the facilities... have been used for the benefit of Ohio customers. If the Coimnission is going to require that [CSP] retain these generating assets, then the Commission should also allow [CSP] to recover Ohio customers' jurisdictional share of any costs associated with maintaining and operating such facilities. Aceordingly, we find that while [CSP] still own[s] the generating facilities [it] should be allowed to obtain recovery for the Ohio customers' jurisdictional share of any costs associated therewith. Tlrus, we believe that any expense related to these generating facilities ... that are not recovered in the FAC [Fuel Adjustinent Clause] shall be recoverable in the non-FAC portion of the gencration rate as proposed by [CSP]."
(Opinion and Order, p. 52; CSP App. p. 83.) In light of the revenue recovery associated
with the Waterford and Darby facilities that the Commission authorized in its Opinion
and Order, CSP did not seek rehearing of the Commission's denial of the requested
authority to sell or transfer these facilities.' Intervening Appellee, Industrial Energy
Users-Ohio (IEU), however, sought rehearing of, among other issues, "the Conmiission's
authorization of a rate increase for recovcry of costs of ownership and otlier interests in
generating assets...." (tEU April 16, 2009 Application for Rehearing, p, ii; CSP App. p.
184). CSP opposed lEUs' request for rehearing on this issue at pages I1 and 12 of its
Memorandum Contra Intervenors' Application for Rchearing. (CSP App. pp. 306-307).
ln its July 23, 2009 Entry on Rehearing the Commission revcrsed its prior ruling
on this issue. The Commission held:
` CSP witness, Mr. Baker, testified in support of the level of the ESP adjustinent for Darby and Waterford. (Cos. Ex. 2E, pp. 20, 21; CSP Supp. pp _7-8).
5 After further eonsideration, the Coinmission finds TEU's arguments persuasive and grants rehearing on the issue of recovery of costs associated with maintaining and operating the Waterford Energy Center and the Darby Electric Generating Station facilities through the non-FAC portion of the generation rate. The Colnpanies have not demonstrated that their curzent revenue is inadequate.to cover the costs associated with the generating facilities, and that those costs should be recoverable thi-ough the non-FAC portion of the generation rate from Ohio customers. We therefore, direct AEP-Ohio to modify its ESP and rernove the annual recovery of $51 million of expenses including associated carrying charges related to these generation facilities.
(Entry on Reheaiing; July 23, 2009, pp. 35, 36 CSP App. pp. 148-149).
Given the Commission's reversal, CSP filed an application foi- rehearing on July
31, 2009. (CSP App. pp. 350). CSP argued that since the Commission revoked CSP's authoiity to recover its customers' jurisdictional share of the costs associated with maintaining and operating the Waterford and Darby facilities, the Commission should coneu rently exercise its authority under R.C.4928.17 (E), to anthorize CSP to sell or transfer these two facilities. In its November 4, 2009 Second Entry on Rehearing the
Conunission repeated its position set fbrth in its July 23, 2009 Entry on Rehearing that
CSP had not demonstrated that the ESP revenue was inadequate to cover costs associated with the Waterford and Darby facilities. (CSP App. p. 175). On December 22, 2009,
CSP filed its Notice of Appeal with this Court, focusing on this single issue concerning the Commission's ruling on the authority to sell or transfer the Darby and Waterford facilities vis a vis CSP's recovery of costs associated with those facilities.2
'Notices of Appeal from the satne Commission orders are pending in Case No. 09-2022.
6 STANDARD OF REVIEW
This Court has "complete and independent power of review as to all questions of law" in appeals from the commission. Ohio Edison Co. v. Pub. Util. Comm. (1997), 78
Ohio St. 3d 466, 469. See also Ohio Consrtmers' Co-unsel v. Pub. Util. Conuu. (2009),
121 Ohio St. 3d 362, 365. Pursuant to B.C. 4903.13, a Cotnmission order will be reversed, vacated, or modified by this court when, upon consideration of the record, the coui-t finds the order to be unlawful or unreasonab'le. Ohio Consumers' Coainsel v. Pub.
Util. Comrn. (2009), 121 Ohio St. 3d 362, 365. See also Constellation NewEnergy, Inc. v.
Pub. Util. Corntn. (2004), 104 Ohio St.3d 530. In order to reverse or modify a
Commission decision as to questions of fact, the Court must find that the record does not contain sufficient probative evidence or find that the Commission's decision was inanifestly against the weight of the evidence or so clearly unsuppoited by the record as to show misapprehension, mistake, or willful disregard of duty. Monongahela Power Co. v. Pub. Util, Comm. (2004), 104 Ohio St.3d 571 quoting AT&T Communications of Ohio,
Inc. v. Pub. Util. Conina. (2000), 88 Ohio St. 3d 549, 555. The appellant bears the burden of demonstrating that the Comtnission's decision is against the manifest weight of the evidence or is clearly unsupported by the record. Id. Furthermore, the Court will not reverse a Commission order absent a sliowing by the appellant that it has been or will be harmed or prejudiced by the order. Myers v. Pub. Util. Comm., (1992), 64 Ohio St.3d
299, 302.
7 ARGUMENT
PROPOSITION OF LAW NO. 1
When the Public Utilities Commission of Ohio considers an application for approval to sell or transfer generating assets which never have been included in the electric distribution utility's plant-in-service for rate making purposes at the same time it considers the utility's Electric Security Plan application, it is unlawful for the Commission to deny the authority to sell or transfer those assets and at the same tinie refuse to allow, as part of the Electric Security Plan, an adjustment for costs associated with maintaining and operating those same assets.
R.C. 4928.141 (A) required Electric Distribution Utilities (EDU) to apply to the
Commission to establish a Standard Service Offer (SSO) in accordance with either R.C.
4928.142 (for a Market Rate Offer - MRO) or R.C. 4928.143 (for an Electric Security
Plan -- ESP). While the EDU could file an MRO application and ESP application simultaneously, the first SSO application at a minimum had to include an application for an ESP. R.C. 4928.141 (A); CSP App. p. 10.
With the enactment of SB 221, however, the opportunity for market-based retail generation rates evaporated for CSP, absetlt being able to transfcr the Waterford and
Darby tmits out of the regulated utility. One alteiroative for establishing the SSO was through a Market Rate Offer (MRO) under R.C. 4928.142. For those electric utilities, such as CSP, that had Connnission authorization under R.C. 4928.17 (C), to remain functionally separated for an interim period, the MRO alternative fell far short of market- based rates. R.C. 4928.142 (D), provides that for a company that as of July 31, 2008 owned operating elect -ic generating facilities that had been used and useful in Ohio, the amount of the MRO that could actually reflect market prices would be phased in over at least five years.
8 Att ESP-based SSO under R.C. 4928.143, provides for the Conimission to set rates that are not deternuned under the traditional cost-of-serviceh-etm-n on investment
fornlula set out in R.C. 4909.15. The contents of an ESP are addressed in R.C. 4928.143
(B) (1) and (2). 'The ESP "shall include provisions relating to the supply and pricing of
electric generation service." Further, the ESP "may provide for or include, "without
lizzzitation (eniphasis added)," any of the following:.... The statute goes on to a non-
exclusive list of nine adjustments that may be included in the ESP.
CSP's ESP application addressed provisions relating to its supply ot'electric
generation service. As relevatit to this appeal, it invoked the Commission's jurisdiction
under R.C.4928.17 (E) to authorize the sale or transfer of the Waterford and Darby
facilities. If CSP was permitted to transfer the units out of the regulated utility, they
could sell power at markct rates - as was originally permitted by law at the time the
assets were pin-chased by CSP. 'I'his was a fair result, especially given that CSP's
ratepayers had never paid any of the costs relating to the purchases,
It is iniportant to understand that the Commission's decision-making process in
ESP proceedings is markedly differeut than its traditional rate maknig process under R.C.
Chapter 4909. There is no valuation of property under R.C. 4909.05 in an ESP
proceeding; nor is there a Staff Report of Investigation prepared in an ESP as it is for
compliance witli R.C.4909.19. An ESP proceeding has no date certain or test year, as
would be required in traditional rate making under R.C. 4909.15 (B). A "fair and
reasonable rate of return," which the Comniission "shall determine" in traditional rate
making is mentioned in R.C. 4928.143, but only in conjunction with an ESP provision
9 regarding the EDU's distribution infrastructlire modernization plan.3 Of great signiiicance to this appeal, an ESP does not involve the Commission's determination of the ovei-all cost to the utility of rendering service, or the gross amiual revenue to wliich the EDU is entitled by 1'ollowing the formula set out in R.C. 4909.15 - dollar amount of return on investment to whicli the utility is entitled plus the cost of rendering service.
Instead of the establishcd rate making formula in R.C. 4909.15, the General
Assemblydirccted the Commission to make but one detennination. R.C. 4928.143 (C)
directs that the Commission "by order shall approve or modify and approve an
application [for an ESP] if it finds that the electrie security plan so approved, including its
pricing and all other terms and conditions, including any deferrals and any future
recovery of defei-rals, is more favorable in the aggregate as eonipared to the expected
results that would otherwise apply under section 4928.142 of the Revised Code."
(Emphasis a(ided).
That's it. No rate base, no date certain, no test year, no cost of service, no formula
for the Conunission to follow. The simply-stated required determination for the
Comanission to make is whettier the ESP is better than the results expected under an
MRO. CSP does not minimize the expertise the Commission needs to bring to bear on
this deternlination. However, there is no place in the ESP versus MRO comparison for
reverting back to the traditional rate making formula as if SB 3 and SB 221 never had
been enacted.
Given the legislative reversal in SB 221 away froni the switch to mar-ket rates that
had been provided in SB 3, CSP's inlterest to retain the Waterfoi-d and Darby facilities as
j R.C. 4928.143 (B) (2) (h) provides for the recovery of costs related to the modernization plan, including ajust and reasonable rate of return on such infi-astructriire modernization.
10 merchant plants had become pointless. Not only could CSP not realize the market value of the electricity produced by these units, but, unless it could achieve au adjustment to its
ESP based on the costs associated with those plants, CSP's generation rates woiild not provide recovery of those plant costs.
'Tlierefore, CSP's ESP application includcd the request for authority to sell or transfer the Waterford and Daiby facilities. Related to that portion of its application,
CSP's witness, Mr. Baker, testified that: "[i]f the Cotnpanies through a Commissioit
order are prohibited from transferring these plants or entitlements then any expense not
recovered by the FAC [Fuel Adjustrnent Clause] should be recovered in the non-EAC
rate." (Cos. Ex. 2E. p. 21; CSP Supp. p. 8).
In the exercise of its statutory obligation to weigh the proposed ESP, "in the
aggregate" to deternnine whether it was more favorable than the results expected from an
MRO, the Commission held that CSP "should file a separate application, in accordance
with the Conmiission's rules, at the time that it wishes to sell or transfer these generation
facilities." (Opinion and Order, p. 52; CSP App. p. 83). The Commission went on,
however, to further modify CSP's proposed ESP. The Connnission ruled that if it were:
going to require that [CSP] retain these generating assets, then the Commission should also allow [CSP] to recover customers' jurisdictional share of any costs associated with maintaining and operating such facilities. Accordingly, we fnd that while [CSP] still own[s] the generating facilities, they should be allowed to obtain recovery for the Ohio customers' jurisdictional share of any costs associated therewith. Thus, we believe that any expense related to these generating facilities ... that are not recovered in the FAC [Fuel Adjustment Ciause] shall be recoverable in the non-FAC portion of the generation rate as proposed by [CSP].
(Id. ).
11 The Commission's further modification to the ESP to build in to the ESP an amount of revenue attributed to those facilities' service to CSP's customers was lawful and rebalanced the value of the ESP in the aggregate. It is important to note that the amount of revenue the Commission included in the ESP attributable to the Waterford and
Darby facilities was not the product on some overall "gross annual revenue to which the utility is entitled," as is the test under R.C. 4909.15 (B). There was no finding that absent these revenues being authorized as parf of the ESP CSP's revenues would be inadequate to cover costs associated witli Waterford and Darby. Instead, the Commission's grant of an additional revenue adjustment in the ESP associated with Waterford and Darby was based on the sinzple fairness that if CSP were required to retain these facilities, it should be able to realize some revemie stream fi•om the customers who benefit from the facilities. Moreover, even with this additional aniount of revenue iuclnded in the ESP, the Commission applied the proper statutory test and found "that the ESP, including its pricing and all other terms and conditions, including deferrals and future recovery of deferrals, as modified by this order, in more favorable in the aggregate as compared to the expected results that would otherwise apply under Section 4928.142, Rcvised Code."
(Opinion and Order, p. 72; CSP App p. 103).
On rehearing, however, the Commission inexplicably reverted to the traditional rate maldng concepts contained in R.C. Chapter 4909. The Commission faulted CSP for not demonstrating that which CSP was not required to demonstrate. As the Comniission stated, CSP has not "demonstrated that [its] current revenue is inadequate to cover the costs associated with the generating facilities, and that those costs should be recoverable through the non-FAC portion of the generation rate from Ohio customers." (July 23,
12 2009 Entry on Rehcaring, p. 35; CSP App. p. 148). The Coimnission's reference to the adequacy of current revenues is uniquely based in the traditional cost-of-service/rate of return on investment rate making concepts of R.C. Chapter 4909. It has no place in evaluating a proposed, or in this casc, Coimnission-modified ESP under R.C. 4928.143.
The proper standard under SB 221 for determining whether to revoke the previously
authorized recovcry of revenue related to these generating facilities would have been for
the Commission to decide whethcr, with the allowance of the revenue recovery, the ESP,
in the aggregate, was not more favorable than the result expected under an MRO at the
time the Conimission issued its original Opinion and Order. The Commission's
responsibility on rehearing was to determine if its initial order was in error. ln any event,
the Commission`s reversal on rehearing made no tnention of the statutory test.
The Commission is a creature of statute and has no authority to act beyond its
statutorypowers. Discount Cellular, Inc, v. Pub. Util. Cornin., 112 Ohio St. 3d 360,
2007-Ohio-53, ¶51; Tongren v. Pub. Cltil. Comun. (1999), 85 Ohio St. 3d 87, 88 ("Thc
Commissiou, as a creature of statute, has and can exercise only the authority conferred
upon it by the General Assembly.") Based on this well-established principle, the
Coinmission's reliance on traditional rate making concepts to reverse its earlier position
was unlawful.
The efPcet of these Conimission orders is that despite having denied CSP the
authority to sell or transfer the Waterford and Darby facilitics as part of CSP's proposed
ESP, the Commission unlawfully and unreasonably denied CSP the authority to recover,
as part of its ESP, costs associated with its ownership of those facilities. Withholding
authority to sell or transfer these facilities, whilc at the same time withholding authority
13 to recover the costs associated with these facilities, is unlawful and unreasonable. As the
Coimnission itself stated in its initial decision, if authority to sell or transfer the facilities were witliheld, "then the Commission should also allow [CSP] to recover Ohio customers' jurisdictional share of any costs associated with maintaining and operating
such facilities," (Opinion and Order, p. 52; CSP App. p. 83).
14 CONCLUSION
"t'he Court shotiild reverse this limited portion of the Commission's ESP order and rehearing entries and direct the Commission to eitlzer authorize the sale or transfer of the
Waterford and Darby facilities, or authoiize the revenue recovery associated with those facilities as the Commission originally authorized.
Resgctfull,^^subnOad,
A/\^ rvin T. Resnik (0005695) Counsel of Record Kevin F. Duffy (0005867) Steven T. Nourse (0046705) Matthew J.Satterwhite (0071972) Ameiican Electric Power Seivice Corporation I Riverside Plaza, 29'h Floor Columbus, Ohio 43215-2373 Telephone: (614) 716-1606 Facsimile: (614) 716-2950 miresnilc(a ae .comcom [email protected] stnourse(cdaep.com misattcrwhiteg.aep . oom
Daniel R. Conway (0023058) Porter Wright Morris & Arthur LLP 41 South High Street Columbus, Ohio 43215 Telephone: (614) 227-2270 Facsimile: (614) 227-2100 dconwavCa)norterwriWht.coui
Counsel for Appeilant, Columbus Southern Power Company
15 APPENDIX APPENDIX - TABLE OF CONTENTS
R. C. 4903.13 ...... 1
R.C. 4909.05 ...... 2
R.C. 4909.15 ...... 4
R. C. 4909.19 ...... 8
R. C. 4928.141 ...... 10
R.C. 4928.142 ...... 11
R.C. 4928.143 ...... 15
R.C. 4928.17 ...... 20
Former R. C. 4928.17 ...... 22
Notice of Appeal of Columbus Southern Power Conipany...... 24
Altachment A to Notice of Appeal: March 18, 2009 ...... 31 Opinion and Order in Case Nos. 08-917-EL-SSO and 08-918-EL-SSO ......
Attact meut B to Notice of Appeal: March 30, 2009 Entry Nacnc Pro Tunc in Case Nos. 08-917-EI-SSO atid 08-918-El-SSO ...... 109
Attaclnnent C to Notice of Appeal: July 23, 2009 Entry on Rehearing in Case Nos. 08-917-EL-SSO and 08-918-EL-SSO ...... 113
Attachment D to Notice of Appeal: August 26, 2009 Entry on Rehearing ...... 169
Attachinent E to Notice of Appeal: November 4, 2009 Second Entry on Rehearing ...... 173
Application for Rehearing and Memorandum in Support of Induslrial Energy Users-Ohio, April 16, 2009 ...... 182
Columbus Southern Power Company's atid Ohio Power Company's Application for Rchearing, April 17, 2009 ...... 245 Columbus Southern Power Coinpany'sand Ohio Power Company's Memoranduns Contra Intervenors' Application for Rehearing, April 27, 2009 ...... 293
Columbus Southern Power Company's and Ohio Power Company's Application for Rehearing, 7uly 31, 2009 ...... 350
Ohio Admin. Code 4901:1-37-09 ...... 355
PROOF OF SERVICE 4903.13 Reversal of final order - notice of appeal.
A final order made by the public utilities commission shall be reversed, vacated, or modified by the supreme court on appeal, if, upon consideration of the record, such court is of the opinion that such order was unlawfal or unreasonable. The proceeding to obtain such reversal, vacation, or modification shall be by notice of appeal, filed witli the public utilities coinmission by any party to the proceeding before it, against the commission, setting forth the order appealed froni and the errors complained of. The notice of appeal shall be served, unless waived, upon the cbairman of the connnission, or, in the event of his absenec, upon any public utilities commissioner, or by leaving a copy at the office of the eoniinission at Columbus. The court may permit any interested party to intervene by cross-appeal.
Effective Date: 10-01-1953 4909.05 Report of valuation of property.
As used in this section:
(A) A "lease purchase agreement" is an agreement pursuant to which a public utility leasing property is required to make rental paytnents for the term of the agreement and either the utility is granted the right to purchase the property upon the completion of the tenn of the agreement and upon the payment of an additional fixed sum of money or title to the property vests in the utility upon the making of the Final rental payinent.
(B) A "leaseback" is the sale or transfer of property by a public utility to another person contemporaneously followed by the leasing of the property to the public utility on a long- term basis. The public utilities connnission shall prescribe the fonn and details of the valuation report of the property of each public utility or railroad in the state. Such report shall include all the kinds and classes of property, with the value of each, owned or ccld by eacli public utility or railroad used and useful for the service and convenience of the public. Such report shall contain the following facts in detail:
(C) The original cost of each parcel of land owned in fee and in use at the date certain determined by the commission; and also a statement of the conditions of acquisition, whether by direct purchase, by donation, by exercise of the power of eminent domain, or otherwise;
(D) The actual acquisition cost, not including periodic rental fees, of rights-of-way, trailways, or otlier land rights held by virtue of easements, leases, or other forms of grants of rights as to usage;
(E) The original cost of all other kinds and classes of property used and useful in the rendition of service to the public. Such original costs of property, other than land owned in fee, shall be the cost, as determined to be reasonable by the commission, to the person that first dedicated the property to the public use and shall be set forth in property accounts and subaccounts as prescribed by the commission. To the extent that the costs of property comprising a coal research and development facility, as defined in section 1555.01 of the Revised Code, or a coal development project, as defined in section 1551.30 of the Revised Code, have been allowed for recovery as Ohio coal research and development costs under section 4905.304 of the Revised Code, none of those costs shall be included as a cost of property under this division.
(F) '1'he cost of property constituting ail or part of a project leased to or used by the utility under Chapter 165., 3706., 6121., or 6123. of the Revised Code and not included under division (E) of this section exclusive of any interest directly or indirectly paid by the utility with respect thereto whether or not capitalized;
(G) In the discretion of the commission, the cost to a utility, in an amount determined to be reasonable by the commission, of property constituting all or part of a project leased to the utility under a lease purchase agreement or a leaseback and not included under
2 division (E) of this section exclusive of any interest direet'ly or indirectly paid by the utility with respect thereto whether or not capitalized;
(H) The proper and adcqnate reserve for depreciation, as determined to be reasonable by the conlmission;
(1) Any stimis of money or property that the coinpany may have received as total or partial defrayal of the cost of its property;
(J) The valuation of the property of the conlpany, which shall be the sum of the amounts contained in the report pursuant to divisions (C), (D), (E), (F), and (G) of this section, less the sum of the amounts contained in the report pursLiant to divisions (H) and (I) of this section. The report shall show separately the property used and useful to such public utility or railroad in the furnishing of the service to the public, and the property held by such public utility or railroad for other purposes, and such other items as the commission considers proper. The coinmission may require an additional report showing the extent to which the property is used and useful. Such reports shall be filed in the office of the cominission for the infonnation of the governor and the general asseinbly.
Effective Date: 01-01-2001
3 4909.15 Fixation of reasonable rate.
(A) The public utilities commission, when fixing and determining just and reasonable rates, fares, tolls, rentals, and charges, shall detennine:
(1) The valuation as of the date certain of the property of the public utility used and useful in rendering the public utility service for which rates are to be fixed and detennined. 'Phe valuation so determinied shail be the total value as set forth in division (7) of section 4909.05 of the Revised Code, and a reasonable allowance for materials and supplies and cash working capital, as determined by the conlmission. The commission, in its discretion, may include in the valuarion a reasonable allowance for construction work in progress but, in no event, may such an allowance be made by the commission until it has deterniined that the particular construetion project is at least seventy-five per cent complete. In detennining the percentage coinpletion of a particular construction project, the commission shall consider, among other relevant criteria, the per cent of time elapsed in construction; the per cent of construction funds, excluding allowance for funds used during constcuction, expended, or obligated to such construction funds budgeted where all such funds are adjusted to reflect current purchasing power; and any physical inspection perfonned by or on behalf of any party, including the commission's staff: A reasonable allowance for constniction work in progress shall not exceed ten per cent of the total valuation as stated in this division, not including such allowance for construction work in progress. Wllere the commission permits an allowance for construction work in progress, the dollar value of the project or portion thereof included in the valuation as construction work in progress shall not be included in the valuation as plant in service until such time as the total revenue effect of the construction work in progress allowance is offset by the total revemie effect of the plant in service exclusion. Carrying charges calculated in a marmer similar to allowance for funds used during construction shall accrue on that portion of the project in service but not reflected in rates as plant in service, and suoh accrued carrying charges shall be included in the valuation of the property at the conclusion of the offset period for purposes of division (J) of section 4909.05 of the Revised Code. From and after April 10, 1985, no allowance for construction work in progress as it relates to a particular construction project shall be reflected in rates for a period exceeding forty-eight consecutive months commencing on the date the initial rates reflecting such allowance become effective, except as otherwise provided in this division. The applicable maximum period in rates for an allowance for construction work in progress as it relates to a particular constiucfion project shall be tolled if, and to the extent, a delay in the in-service date of the project is caused by the action or inaction of any federal, state, county, or municipal agency having jurisdiction, where such action or inaction relates to a change in a rule, standard, or approval of such ageney, and where such action or inaction is not the result of the failure of the utility to reasonably endeavor to comply with any rule, standard, or approval prior to such change. In the event that such period expires before the project goes into service, the conunission shall exclude, from the date of expiration, the allowance for the project as construction work in progress from rates, except that the cotmnission may extend the expiration date up to twelve months for good cause shown. In the event that a utility has peimanently canceled, abandoned, or terminated constniction of a project for which it was previously
4 pennitted a construction work in progress allowance, the commission immediately shall exclude the allowance for the project from the valuation. In the event that a construction work in progress project previously included in the valuation is removed froin the valuation pursuant to this division, any revenues collected by the utility from its customers after April 10, 1985, that resulted from such prior inclusion shall be offset against future revenues over the same period of time as the project was included in the valuation as construction work in progress. The total revenue effect of such offset shall not exceed the total revenues previously collected. In no event sball the total revcnue effect of any offset or offsets provided under division (A)(1) of this section exceed the total revenue effect of any construction work in progress allowance.
(2) A fair and reasonable rate of return to the utility on the valuation as determined in division (A)(1) of this section;
(3) The dollar annual reti.irn to which the utility is entitled by applying the fair and reasonable rate of return as determined under division (A)(2) of this section to the valuation of the utility detennined under division (A)(1) of this section;
(4) The cost to the utility of rendering the public utility service for the test period less the total of any interest on cash or credit refunds paid, pursuant to section 4909.42 of the Revised Code, by the utility during the test period.
(a) Federal, state, and local taxes iniposed on or measured by net income may, in the discretion of the commission, be computed by the normalization method of accountnig, provided the utility maintains accounting reserves that reflect differences between taxes actually payable and taxes on a normalized basis, provided that no determination as to the treatinent in the rate-making process of such taxes shall be made that will result in loss of any tax depreciation or other tax benefit to which the utility would otherwise be entitled, and further provided that such tax benefit as redounds to the utility as a result of such a computation may not be retained by the conipany, used to fund any dividend or distribution, or utilized for any pui-pose other than the defrayal of the operating expenses of the utility and the defrayal of the expenses of the utility in connection with construction work.
(b) The amount of any tax credits granted to an electric light company under section 5727.391 of the Revised Code for Ohio coal bunied prior to January 1, 2000, shall not be retained by the company, used to fund any dividend or distribution, or utilized for any purposes othcr than the defrayal of the allowable operating expenses of the company and the defrayal of the allowable expenses of the company in connection with the installation, acquisition, construction, or use of a compliance facility. The amount of the tax credits granted to an electric light company under that section for Ohio coal burned prior to January 1, 2000, shall be returned to its customers within three years after initially claiming the credit tluough an offset to the company's rates or fuel coniponent, as determined by the commission, as set forth in schedules filed by the company under section 4905.30 of the Revised Code. As used in division (A)(4)(c) of this section, "compliance facility" has the same meaning as in section 5727.391 of the Revised Code.
5 (B) The commission shall compute the gross amiual revenues to which the utility is entitled by adding the dollar ainount of return under division (A)(3) of this section to the cost of retidering the public utility service for the test period under division (A)(4) of this section.
(C) The test period, unless otherwise ordered by the commission, shall be the twelve- month period beginning six nionths prior to the date the application is filed and ending six months subsequent to that date. In no event shall the test period end more than nine months subsequent to the date the application is filed. The revenues and expenses of the utility shall be determined during the test period. The date certain shall be not later than the date of filing.
(D) When the comnrission is of the opinion, after hearing and after making the determinations under divisions (A) and (B) of this section, that any rate, fare, charge, toll, rental, schedule, classification, or service, or any joint rate, fare, charge, toll, rental, schedule, classification, or service rendered, charged, demanded, exacted, or proposed to be rendered, charged, demanded, or exacted, is, or will be, tmjust, unreasonable, unjustly discriininatory, unjustly preferential, or in violation of law, that the service is, or will be, inadequate, or that the maxiunum rates, charges, tolls, or rentals chargeable by any such public utility are insufficient to yield reasonable compensation for the service rendered, and are mijust and unreasonable, the commission shall:
(1) With due regard among other things to the value of all property of the public utility actually used and useful for the convenience of the public as determined under division (A)(1) of this section, excluding from such value the value of any franchise or right to own, operate, or enjoy the same in excess of the amount, exclusive of any tax or annual charge, actually paid to any political subdivision of the state or eomlty, as the consideration for the grant of such franchise or right, and excluding any value added to such property by reason of a monopoly or merger, with due regard in determining the dollar annual return under division (A)(3) of this section to the necessity of making reservation out of the income for surplus, depreciation, and contingencies, and;
(2) With due regard to all such other matters as are proper, according to the facts in each case,
(a) Including a faii- and reasonable rate of return detemained by the commission with reference to a cost of debt equal to the actual embedded cost of debt of such public utility,
(b) But not including the portion of any periodic rental or use payments representing that cost of property that is included in the valuation report under divisions (F) and (G) of section 4909.05 of the Revised Code, tix and determine the just and reasonable rate, fare, charge, toll, rental, or service to be rendered, charged, demanded, exacted, or collected for the performance or rendition of the service that will provide the public utility the allowable gross annual revenues under division (B) of this section, and order such just and reasonable rate, fare, charge, toll, rental, or service to be substituted for the existing one. After such determination and order no change in the rate, fare, toll, charge, rental,
6 schedule, classification, or service shall be made, rendered, charged, demanded, exacted, or changed by such public utility without the order of the comrnission, and any other rate, fare, toll, charge, rental, classification, or service is prohibited.
(E) Upon application of any person or any public utility, and after notice to the parties in interest and opportunity to be heard as provided in Chapters 4901., 4903., 4905., 4907., 4909., 4921., and 4923. of the Revised Code for other hearings, has been given, the comniission may rescind, alter, or amend an order fixing any rate, fare, toll, charge, rental, classification, or service, or any other order made by the commission. Certified copies of such orders shall be served and take effect as provided for original orders.
Effective Date: 11-24-1999
7 4909.19 Publication - investigation.
Upon the filing of any application for increase provided for by section 4909.18 of the Revised Code the public utility shall forthwith publish the substance and prayer of such application, in a form approved by the public utilities commission, oncc a week for three consecutive weeks in a newspaper published and in general circulation throughout the territory in which such public utility operates and affected by the matters referred to in said application, and the commission shall at once cause an investigation to be made of the facts set forth in said application and the exhibits attached thereto, and of the matters coimected therewith. Within a reasonable time as determined by the comniission after the filing of such application, a written report shall be made and filed with the commission, a copy of wliich shall be sent by certified mail to the applicant, the mayor of any inunicipal corporation affected by the application, and to such other persons as the commission deems interested. If no objection to such report is made by any party interested within tliirty days after such filing and the mailing of copies tliereof, the coimnission shall fix a date within ten days for the fmal hearing upon said application, giving notice thereof to all parties interested. At such hearing the commission shall consider the matters set forth in said application and make sueh order respecting the prayer thereof as to it seezns just and reasonable. If objections are filed witli the commission, the commission shall cause a pre-hearing conference to be held between all parties, intervenors, and the cominission staff in all cases involving more than one hundred thousand customers. If objections are filed with the commission within thirty days after the filing of such report, the application shall be promptly set down for hearing of testimony before the coinmission or be forthwith referred to an attorney examiner designated by the commission to take all the testimony with respect to the application and objections which may be offered by any interested party. The commission shall also fix the time and place to take testimony giving ten days' written notice of such time and place to all parties. Tlie taking of testimony shall commence on the date fixed in said notice and shall continue from day to day until completed. The attorney examiner may, upon good cause shown, grant continuances for not more than three days, excluding Saturdays, Sundays, and holidays. The eommission may grant continuances for a longer period than tln-ee days upon its order for good cause shown. At any hearing involving rates or charges sougbt to be increased, the burden of proof to show that the increascd rates or charges are just and reasonable shall be on the public utility. When the taking of testimony is completed, a full and complete record of such testimony noting all objections made and exceptions taken by any party or counscl, shall be made, signed by the attomey examiner, and filed with the coinmission. Prior to the fornlal consideration of the application by the conimission and the rendition of any order respecting the prayer of the application, a quorum of the comtnission shall consider the reconni eiided opinion and order of the attorney examiner, in an open, formal, public proceeding in which an overview and explanation is presented orally. Thereafter, the conlmission shall make such order respecting the prayer of such application as seeins just and reasonable to it. In all proceedings before the commission in which the taking of testimony is required, except when heard by the commission, attorney examiners shall be assigned by the commission to talce such testimony and fix the time and place therefor, and such testimony shall be taken in the manner prescribed in this section. All testimony shall be under oath oi-
8 affinnation and taken down and transcribed by a reporter and made a part of the record in the case. The commission may hear the testimony or any part thereof in any case without having the same referred to an attorney examiner and may take additional testimony. Testimony shall be taken and a record made in accordance with. such general rules as the commission prescribes and subject to such special instructions in any proceedings as it, by order, directs.
Effective Date: 01-11-1983
9 4928.141 Distribution utility to provide standard service offer.
(A) Begiuniing January 1, 2009, an electric distribution utility shall provide consumers, on a comparable and nondiscriminatory basis within its certified territory, a standard service offer of all competitive retail electric services necessary to maintain essential electric service to consumers, including a firm supply of electric generation service. To that end, the electric distribution utility shall apply to the public utilities conimission to establish the standard service offer in accordance with section 4928.142 or 4928.143 of the Rcvised Code and, at its discretion, may apply simultaneously under both sections, except that the utility's first standard service offer application at minimum shall include a filing under section 4928.143 of the Revised Code. Only a standard service offer authorized in accordance with section 4928.142 or 4928.143 of the Revised Code, shall serve as the utility's standard service offer for the purpose of compliance with this section; arid that standard service offer shall seive as the utility's default standard service offer for the purpose of section 4928.14 of the Revised Code. Notwithstanding the foregoing provisiou, the rate plan of an electric distribution utility shall continuc for the purpose of the utility's compliance with this division until a standard service offer is first authorized under section 4928.142 or 4928.143 of the Revised Code, and, as applicable, pursuant to division (D) of section 4928.143 of the Revised Code, any rate plan that extends beyond December 31, 2008, shall continue to be in effect for the subject electric distribution utility for the duration of the plan's term. A standard service offer under section 4928.142 or 4928.143 of the Revised Code shall exclude any previously authorized allowances for transition costs, with such exclusion being effective on and after the date that the allowance is scheduled to end under the utility's rate plan.
(B) The commission shall set the time for hearing of a filing under section 4928.142 or 4928.143 of the Revised Code, send written notice of the hearing to the electric distribution utility, and publish notice in a newspaper of general circulation in each county in the utility's certified territory. The eommission shall adopt rules regarding filings under those sections.
Effective Date: 2008 SB221 07-31-2008
10 4928.142 Standard generation service offer price - competitive bidding.
(A) For the puipose of complying with section 4928.141 of the Revised Code and subject to division (D) of this section and, as applicable, subject to the rate plan requirement of division (A) of section 4928.141 of the Revised Code, an electric distribution utility may establish a standard service offer price for retail electric generation service that is delivered to the utility undcr a market-rate offer.
(1) The market-rate offer shall be determined through a competitive bidding process that provides for all of the following:
(a) Open, fair, and transparent coinpetitive solicitation;
(b) Clear product definition;
(c) Standardized bid evaluation criteria;
(d) Oversight by an indepcndent third party that shall design the solicitation, administer the bidding, and ensure that the criteria specified in division (A)(1)(a) to (e) of this section are met;
(e) Evaluation of the submitted bids prior to the selection of the least-cost bid winner or winners. No generation supplier shall be prohibited from participating in the bidding process.
(2) The public utilities commission shall modify rules, or adopt new rules as necessary, concerning the conduct of the competitive bidding process and the qualifications of bidders, which rules shall foster supplier participation in the bidding process and shall be consistent with the requirements of division (A)(1) of this section.
(B) Prior to initiating a competitive bidding process for a markei-rate offer under division (A) of this section, the electric distribution utility shall file an application with the eoinmission. An electric distribution utility may file its applieation with the eomniission prior to the effcctive date of the commission rules rcquired under division (A)(2) of this section, and, as the commission detennines neeessary, the utility shall immediately conform its filing to the rules upon their taking effect. An application under this division shall detail the electric distribution utility's proposed compliance with the requirements of division (A)(1) of this section and with commission rules under division (A)(2) of this section and demonstrate that all of uie following requirements are met:
(1) The electric distiibution utility or its transmission service affiliate belongs to at least one regional transmission organization that has been approved by the federal energy regulatory conimission; or there otherwise is comparable and nondiscriminatory access to the electric transmission grid.
11 (2) Any such regional transmission organization has a market-monitor function and the ability to take actions to identify and mitigate market power or the electric distribution utility's market conduct; or a similar market monitoring funetion exists with commensurate ability to identify and monitor market conditions and mitigate conduct associated witli the exercise of market power.
(3) A published source of infoimation is available publicly or through subscription that identifies pricing information for traded electricity on- and off-peak energy products that are contracts for delivery beginning at least two years from the date of the publication and is updated on a regular basis. The commission shall initiate a proceeding and, within ninety days after the application's filing date, shall detemiine by order whether the electric distribution utility and its market-rate offer meet all of the foregoing requirernents. If the finding is positive, the electric distribution utility may initiate its competitive bidding process. If the finding is negative as to one or more requirements, the conimission in the order shall direct the electric distiibution utility regarding how any deficiency may be remedied in a timely manner to the commission's satisfaction; otherwise, the electric distribution utility shall withdraw the application. However, if such remedy is made and the subsequent fmding is positive and also if the electric distribution utility made a simultaneous filing under this section and section 4928.143 of the Revised Code, the utility shall not initiate its competitive bid until at least one hundred fifty days afler the filing date of those applications.
(C) Upon the completion of the competitive bidding process authorized by divisions (A) and (B) of this section, including for the purpose of division (D) of this section, the commission shall select the least-cost bid winner or winners of that process, and such selected bid or bids, as prescribed as retail rates by the cormnission, shall be the electric distribution utility's standard service offer unless the commission, by order issued before the third calendar day following the conclusion of the competitive bidding process for the market rate offer, deterniines that one or more of the following criteria were not met:
(1) Each portion of the bidding process was oversubscribed, such that the amount of supply bid upon was greater than the amount of the load bid out.
(2) There were four or more bidders.
(3) At least twenty-five per cent of the load is bid upon by one or more persons other than the electric distribution utility. All costs incurred by the electric distribution utility as a result of or related to the competitive bidding process or to procnring generation service to provide the standard service offer, inchiding the costs of energy and capacity and the costs of all other products and services procured as a result of the competitive bidding process, shall be timely recovered through the standard service offer price, and, for that purpose, the commission shall approve a reconciliation mechanisrn, other recovery niechanism, or a combination of such mechanisins for the utility.
(D) The first application filed under this section by an electric distribution utility that, as orJuly 31, 2008, directly owns, in whole or in part, operating electric generating facilities
12 that had been used and useful in this state shall require that a portion of that utility's standard service offer load for the first five years of the market rate offer be competitively bid under division (A) of this section as follows: ten per cent of the load in year one, not more than twenty per cent in year two, thirty per cent in ycar three, forty per cent in year four, and fifty per cent in year five. Consistent with those percentages, the commission shall determine the actual percentages for each year of years one through fivc. The standard service offer price for retail electric generation service wider this first application shall be a proportionate blend of the bid price and the generation service price for the reinaining standard service offer load, which latter price shall be equal to the elcctric distribution utility's most recent standard service offer price, adjusted upward or downward as the comxnission determines reasonable, relative to the jurisdictional portion of any known and measurable changes from the level of any one or more of the following costs as reflected in that most recent standard service offer price:
(1) The electric distribution utility's prudently incurred cost of fiiel used to produce electricity;
(2) Its prudently incurred purchased power costs;
(3) Its prudently incun-ed costs of satisfying the supply and demand portfolio requirements of this state, including, but not limited to, renewable energy resource and energy efficiency requirenients;
(4) Its costs prudently incurred to comply with environmental laws and regulations, with consideration of the derating of any facility associated with those costs. In making any adjustment to the most recent standard service offer price on the basis of costs described in division (D) of this section, the commission shall inelude the benefits that may become available to the electric distribution utility as a result of or in connection with the costs included in the adjustment, including, but not limited to, the utility's receipt of emissions credits or its receipt of tax benefits or of other benefits, and, accordingly, the commission may irnpose such conditions on the adjustment to ensure that any such benefits are properly aligned with the associated cost responsibility. The commission shall also determine how such adjustments will affect the electric distribution utility's return on common equity that may be achieved by those adjustments. The commission shall not apply its consideration of the rettun on common equity to reduce any adjustments authorized under this division unless the adjustinents will cause the electric distribution utility to earn a return on connnon equity that is significantly in excess of the return on common equity that is eamed by publicly traded companies, including utilities, that face comparable business and financial risk, with such adjustments for capital structure as may be appropriate. The burden of proof for demonstrating that sigiuficantly excessive earnings will not occur shall be on the electric distribution utility. Additionally, the commission inay adjust the electric distribution utility's most recent standard service offer price by such just and reasonable amount that the commission determines necessary to addi-ess any emergency that threatens the utility's financial integrity or to ensure that the resulting revenue available to the utility for providing the standard seivice offer is not so inadequate as to result, directly or indirectly, in a taking of property without
13 compensation pursuant to Section 19 of Article I, Oliio Constitution. The electric distribution utility has the burden of demonstrating that any adjustment to its most recent standard service offer price is proper in accordance with this division.
(E) Beginning in the second year of a blended price under division (D) of this section and notwithstanding any other requirement of this section, the commission may alter prospectively the proportions specified in that division to mitigate any effect of an abrupt or significant change in the electric distribution utility's standard service offer price that would otherwise result in general or with respect to any rate group or rate schedule but for such alteration. Any such alteration shall be made not more often than annnally, and the commission shall not, by altering those proportions and in any event, including bccause of the length of time, as authorized under division (C) of this section, taken to approve the market rate offer, cause the duration of the blending period to exceed ten years as counted from the effective date of the approved market rate off'er. Additionally, any such alteration shall be limited to an alteration affecting the prospective proportions used during the blending period and shall not affect any blending proportion previously approved and applied by the cornmission under this division.
(F) An electric distribution utility that has received commission approval of its first application under division (C) of this section shall not, nor ever shall be authoiized or reqrtired by the commission to, file an application under section 4928.143 of the Revised Code.
Effective Date: 2008 SB221 07-31-2008; 2008 HB562 09-22-2008
14 4928.143 Application for approval of electric security plan - testing.
(A) For the purpose of complying with section 4928.141 of the Revised Code, an electric distribution utility may file an application for public utilitics commission approval of an electric security plan as prescribed under division (B) of this section. The utility may file that application prior to the effective date of any niles the conunission may adopt for the purpose of this section, and, as the commission determines necessary, the utility immediately slrall conform its filing to those rules upon their taking effect.
(B) Notwithstanding any other provision of Title XLIX of the Revised Code to the contrary except division (D) of this section, divisions (I), (7), and (K) of section 4928.20, division (E) of section 4928.64, and section 4928.69 of the Revised Code:
(1) An electric security plan shall include provisions relating to the supply and pricing of electric generation service. In addition, if the proposed electric security plan has a term longer than three years, it may include provisions in the plan to permit the commission to test the plan pursuant to division (E) of this section and any transitional conditions that should be adopted by the commission if the comnzission terminates the plan as authorized under that division.
(2) The plan may provide for or include, witlrout limitation, aiy of the following:
(a) Automatic recovery of any of the following costs of the cleetiic distribution utility, provided the cost is prudently incurred: the cost of fuel used to generate the electricity supplied under the offer; the cost of purchased power supplied under the offer, including the cost of energy and capacity, and including purchased power acquired from an affiliate; the cost of emission allowances; and the cost of federally mandated carbon or energy taxes;
(b) A reasonable allowance for construction work in progress for any of the electric distribution utility's cost of constructing an electric generating facility or for an environmental expenditure for any electric generating facility of the electric distribution utility, provided the cost is incun-ed or the expenditure occurs on or after 7anuary 1, 2009. Any such allowance shall be subject to the construction work in progress allowance limitations of division (A) of section 4909.15 of the Revised Code, except that the comrnission inay authorize such an allowance upon the incurrenee of the cost or occurrence of the expenditure. No such allowance for generating facility construction shall be authorized, however, unless the commission first determines in the proceeding that there is need for the facility based on resource planning projections submitied by the electric distribution utility. Further, no such allowance shall be authorized unless the facility's construction was sourced through a competitive bid process, regarding which process the commission may adopt rules. An allowance approved under division (B)(2)(b) of this section shall be established as a nonbypassable surcharge for the life of the facility.
15 (c) The establishment of a nonbypassable surcharge for the life of an electric generating facility that is owned or operated by the electric distribution utility, was soruced through a competitive bid process subject to any such rules as the conunission adopts under division (B)(2)(b) of this section, and is newly uscd and useful on or after January 1, 2009, which surcharge shall cover all costs of the utility specified in the application, excluding costs recovered through a surcharge under division (B)(2)(b) of this section. However, no surcharge shall be authorized unless the commission first determines in the proceeding that there is need for the facility based on resource planning projections snbmitted by the electric distribution utility. Additionally, if a surcharge is authorized for a facility pursuant to plan approval Lmder division (C) of this section and as a condition of the contimiation of the surcbarge, the electric distribution utifity shall dedicate to Ohio consiuners the capacity and energy and the rate associated with the cost of that facility. Before the commission authorizes any surcharge pursuant to this division, it may consider, as applicable, the effects of any decornmissioning, deratings, and retirements.
(d) Terms, conditions, or charges relating to limitations on customer shopping for rctail electhic generation service, bypassability, standby, back-up, or supplemental power service, default service, carrying costs, amorlization periods, and accounting or deferrals, including future recovery of such deferrals, as would have the effect of stabilizing or providing certainty regarding retail electric service;
(e) Automatic increases or decreases in any eomponent of the standard service offer price;
(f) Provisions for the electric distribution utility to securitize any phase-in, inclusive of carrying charges, of the utility's standard service offer price, which phase-in is authorized in accordance with section 4928.144 of the Revised Code; and provisions for the recovery of the utility's cost of securitization.
(g) Provisions relating to transmission, ancillary, congestion, or any related service required for the standard service offer, including provisions for the recovery of any cost of sueh service that the electric distribution utility incurs on or after that date pursuant to the standai-d service offer;
(h) Provisions regarding the utility's distribution service, including, without limitation and notwithstanding any provision of Title XLIX of the Revised Code to the contrary, provisions regarding single issue ratemaking, a revenue decoupling mechanism or any other incentive ratemaking, and provisions regarding distribution infrastructure and modernization incentives for the electric distribution utility. The latter may include a long-term energy delivery infrastructure modernization plan for that utility or any plan providing for the utility's recovery of costs, including lost revenue, shared savings, and avoided costs, and a just and reasonable ratc of return on such infrastructure modernization. As part of its determination as to whether to allow in an electric distribution utility's electric security plan inclusion of any provision described in division (B)(2)(h) of this section, the coinmission shall examine the reliability of the electric distribution utility's distribution system and ensure that customers' and the electric
16 distribution utility's expectations are aligned and that the electric distribution utility is placnrg sufficient emphasis on and dedicating sufficient resources to the reliability of its distribution system.
(i) Provisions under wliich the electric distribution utility may implement economic development, job retention, and energy efficiency programs, which provisions may allocate program costs across all classes of customers of the utility and those of electric distribution utilities in the same holding company system.
(C)(1) The burden of proof in the proceeding shall be on the electric distribution utility. The commission shall issue an order under this division for an initial application under this section not later than one hundred fifty days after the application's filing date and, for any subsequent application by the utility imder this section, not later than two liundred seventy-five days after the application's filing date. Subject to division (D) of this section, the conunission by order shall approve or modify and approve an application filed under division (A) of this section if it finds that the electric security plan so approved, ineluding its pricing and all other terms and conditions, including any deferrals and any fiiture recovery of deferrals, is more favorable in the aggregate as conlpared to the expected results that would otherwise apply under section 4928.142 of the Revised Code. Additionally, if the commission so approves an application that contains a surcharge under division (13)(2)(b) or (c) of this section, the commission shall ensure that the benefits derived for any purpose for which the surcharge is established are reserved and made available to those that bear the surcharge. Otherwise, the commission by order shall disapprove the application.
(2)(a) If the commission modifies and approves an application rmder division (C)(1) of this section, the electric distribution utility may withdraw the application, thereby terininating it, and may file a new standard service offer under this section or a standard service offer under section 4928.142 of the Revised Code.
(b) If the utility terminates an application pursuant to division (C)(2)(a) of this section or if the comniission disapproves an application under division (C)(1) of this section, the conunission shall issue such order as is necessary to continue the provisions, terms, and conditions of the utility's most recent standard service offer, along with anyexpected increases or decreases in fuel costs from those contained in that offer, until a subsequent offer is authorized pursuant to this section or section 4928.142 of the Revised Code, respectively.
(D) Regarding the rate plan rc-quirernent of division (A) of section 4928.141 of the Revised Code, if an electric distribution utility that has a rate plan that extends beyond December 31, 2008, files an application under this section for the purpose of its conipliance with division (A) of section 4928.141 of the Revised Code, that rate plan and its terms and conditions are hereby incorporated into its proposed electric security plan and shalt continue in effect until the date scheduled under the rate plan for its expiration, and that portion of the electtic security plan shall not be subject to commission approval or disapproval under division (C) of this section, and the earnings test provided for in
17 division (F) of this section shall not apply until after the expiration of the rate plan. However, that utility may inelude in its electric security plan under this section, and the commission may approve, rnodify and approve, or disapprove subject to division (C) of this section, provisions for the inereinental recovery or the defeiral of any costs that are not being recovercd under the rate plan and that the utility incurs during that continuation period to comply with section 4928.141, division (B) of section 4928.64, or division (A) of section 4928.66 of the Revised Code.
(E) If an electric security plan approved under division (C) of this section, except one withdrawn by the utility as authorized under that division, has a term, exclusive of phase- ins or deferrals, that exceeds three years from the effective date of the plan, the commission shall test the plan in the fourth year, and if applicable, every fourth year therealter, to determine whether the plan, including its then-existing pricing and all other tenns and conditions, including any deferrals and any future recovery of deferrals, continues to be more favorable in the aggregate and during the remainnig term of the plan as compared to the expected results that would otherwise apply tmder section 4928.142 of the Revised Code. The commission shall also determine the prospective effect of the electric security plan to determine if that effect is substantially likely to provide the eleetric distribution utility with a return on common equity that is significantly in excess of the return on common equity that is likely to be eained by publicly traded companies, including utilities, that face comparable business and financial risk, with such adjustinents for capital structure as may be appropriate. The burden of proof for demonstrating that significantly excessive earnings will not occur shall be on the electric distribution utility. If the test results are in the negative or the commission finds that continuation of the electric security plan will result in a return on equity that is significantly in excess of the return on common equity that is likely to be earned by publicly traded companies, including utilities, that will face comparable business and financial risk, with such adjustments for capital structure as niay be appropriate, during the balance of the plan, the commission may tenninate the electric security plan, but not until it shall have provided interested parties with notice and an opportunity to be heard. The commission may impose such conditions on the plan's termination as it considers reasonable and necessary to accommodate the transition from an approved plan to the more advantageous alternative. In the event of an electric security plan's termination pursuant to this division, the commission shall pennit the continued deferral and phase-in of any amounts that occurred prior to that tennination and the recovery of thoseamounts as contemplated under that eleetric security plan.
(F) With regard to the provisions that are included in an electric securityplan under this section, the commission shall consider, following the end of each annual period of the plan, if any such adjustments resulted in excessive earnings as measured by whether the eam.ed return on comrnon equity of the electric distribution utility is significantly in excess of the return on common equity that was eamed during the same period by publicly traded companies, including utilities, that face comparable business and financial risk, with such adjustments for capital structure as may be appropriate. Corisideration also shall be given to the capital requirements of future committed investments in this state. The burden of proof for demonstrating that significantly excessive eainings did not occur
18 shall be on the electric distribution utility. If the commission finds that such adjustments, in the aggregate, did result in significantly excessive earnings, it shall require the electric distribution utility to rettirn to consumers the amount of the excess by prospective adjustments; provided that, upon making such prospective adjustments, the electric distribution utility shall have the right to terminate the plan and immediately file an application pursuant to section 4928.142 of the Revised Code. Upon tennination of a plan under this division, rates shall be set on the same basis as specified in division (C)(2)(b) of this section, and the conimission shall pelmit the continued deferral and pliasc-in of any amounts that occuiTed prior to ttlat termination and the recovery of those amounts as contemplated under that electric security plan. In making its detennination of significantly excessive earnings under this division, the commission shall not consider, directly or indirectly, the revenue, expenses, or earnings of any affiliate or parent company.
Effective Date: 2008 SB221 07-31-2008
19 4928.17 Corporate separation plans.
(A) Except as otherwise provided in sections 4928.142 or 4928.143 or 4928.31 to 4928.40 of the Revised Code and begimiing on the starting date of competitive retail electric service, no electric utility shall engage in this state, either directly or through an affiliate, in the businesses of supplying a noncompetitive retail electric service and supplying a competitive retail electiic service, or in the businesses of supplying a noncompetitive retail electric service and supplying a product or service other than retail electric service, unless the utility inrplements and operates under a corporate separation plan that is approved by the public utilities eonimission under this sectioii, is consistent witli the policy specified in section 4928.02 of the Revised Code, and achieves all of the following:
(1) The plan provides, at minimuin, for the provision of the competitive retail electric service or the nonelectric product or service through a fully separated affliate of the utility, and the plan includes separate accounting requirements, the code of conduct as ordered by the coinmission pursuant to a ntle it shall adopt under division (A) of section 4928.06 of the Revised Code, and such other measur•es as are necessary to effectuate the policy specified in section 4928.02 of the Revised Code.
(2) The plan satisfies the public interest in preventing unfair competitive advantage and preventing the abuse of market power.
(3) The plan is sufficient to ensure that the utility will not extend any lmdue preference or advantage to any affiliate, division, or part of its own business engaged in the business of supplying the competitive retail electric service or nonelectric product or seivice, including, but not limited to, utility resources such as trucks, tools, office equipment, office space, supplies, customer and marketing information, advertising, billing and mailiiig systems, personnel, and training, without compensation based upon fully loaded embedded costs charged to the affiliate; and to ensure that any such affiliate, division, or part will not receive undue preference or advantage from any affiliate, division, or part of the business engaged in business of supplying the noncompetitive retail electric service. No such utility, affiliate, division, or part shall extend such undue preference. Notwithstanding any other division of this section, a utility's obligation under division (A)(3) of this section shall be effective January 1, 2000.
(B) The commission may approve, modify and approve, or disapprove a corporate separation plan filed with the commission under division (A) of this section. As part of the code of conduct required under division (A)(1) of this section, the commission shall adopt rules pursuant to division (A) of section 4928.06 of the Revised Code regarding coiporate separation and procedures for plan filing and approval. The rules shall include limitations on affiliate practices solcly for the purpose of maintaining a separation of the affiliate's business from the business of the utility to prevent unfair cornpetitive advantage by virtue of that relationship. The rules also shall include an opportunity for any person having a real and substantial interest in the corporate separation plan to file specific objections to the plan and propose specific responses to issues raised in the
20 objections, which objections and responses the commission shall address in its final order. Piior to commission approval of the plan, the conunission shall afford a hearing upon those aspects of the plan that the commission detennines reasonably require a hearing. The commission may reject and require refiling of a substantially inadequate plan under this section.
(C) The commission shall issue an order approving or modifying and approving a corporate separation plan under this section, to be effective on the date specified in the order, only upon findings that the plan reasonably complies with the requirements of division (A) of this section and will provide for ongoing compliance with the policy specified in section 4928.02 of the Revised Code. However, for good cause shown, the commission may issue an order approving or modifying and approving a corporate separation plan tinder this section that does not comply with division (A)(l) of tlris section but con7plies with such functional separation requirements as the commission authorizes to apply for an interim period prescribed in the order, upon a finding that such alteinative plan will provide for ongoing compliance with the policy specified in section 4928.02 of the Revised Code.
(D) Any party may seek an amendment to a corporate separation plan approved under this section, and the comniission, pursuant to a request from any party or on its own initiative, may order as it considers necessary the filing of an ainended corporate separation plan to reflect changed circumstances.
(E) No electric distribution utility shall sell or transfer any generating asset it wholly or partly owns at any time without obtaining prior commission approval.
Effective Date: 10-05-1999; 2008 SB221 07-31-2008
21 Former Sec. 4928.17 effective 10-05-1999 through 07-31-08
(A) Except as otherwise provided in sections 4928.31 to 4928.40 of the Revised Code and beginning on the starting date of competitive retail electric service, no electric utility shall engage in this state, either directly or through an affiliate, in the businesses of supplying a noncompetitive retail eleethic service and supplying a competitive retail clectric service, or in the businesses of supplying a noncompetitive retail electric service and supplying a product or service other than retail electric service, unless the utility irnplements and operates under a corporate separation plan that is approved by the public utilities commission under this section, is consistent with the policy specified in scction 4928.02 of the Revised Code, and achieves all of the following:
(1) The plan provides, at minimum, for the provision of the eoinpetitive retail electric service or the nonelectric product or seivice through a fully separated afPiliate of the utility, and the plan includes separate accounting requirernents, the code of conduct as ordered by the eonimission pursuant to a rule it shall adopt under division (A) of section 4928.06 of the Revised Code, and such other measures as are necessary to effectuate the policy specified in section 4928.02 of the Revised Code.
(2) The plan satisfies the public interest in preventing unfair competitive advantage and preventing the abuse of market power.
(3) The plan is sufficient to ensure that the utility will not extend any undue preference or advantage to any affiliate, division, or part of its own business engaged in the business of supplying the competitive retail electric service or nonelectric product or service, including, but not limited to; utility resources such as trucks, tools, office equipment, office space, supplies, customer and marketing information, advertising, billing and riiailing systems, persomiel, and training, witliout compensation based upon fully loaded embedded costs charged to the affiliate; and to ensure that any such affiliate, division, or part will not receive undue preference or advantage from any affiliate, division, or part of the business engaged in business of supplying the noncompetitive retail electric service. no such utility, altiliate, division, or part shall extend such undue preference. notwithstanding any other division of this section, a utility's obligation under division (A)(3) of this section shall be effective.lanuary 1, 2000.
(B) The commission may approve, modify and approve, or disapprove a corporate separation plan filed with the comrnission under division (A) of this section. As part of the code of conduct required under division (A)(1) of this section, the comrnission shall adopt rules pursuant to division (A) of section 4928.06 of the Revised Code regarding corporate separation and procedures for plan filing and approval. The rules shall inelude lirnitations on affiliate practices solely for the purpose of maintaining a separation of the affiliate's business from the business of the utility to prevent unfair competitivo advantage by virtue of that relationship. The iules also shall include an opporlmiity for any person having a real and substantial interest in the corporate separation plan to file specific objections to the plan and propose specific responses to issues raised in the objections, which objections and responses the commission shall address in its final
22 order: Prior to comrnission approval of the plan, the commission shall afford a hearing upon those aspects of the plan that the commission determines reasonably require a hearing. The conunission may reject and require refiling of a substantially inadequate plan under this section.
(C) The commission shall issue an order approving or modifying and approving a corporate separation plan under this section, to be effective on the date specified in the order, only upon findings that the plan reasonably complies with the requirements of division (A) of this section and will provide for ongoing compliance with the policy specified in section 4928.02 of the Revised Code. However, for good cause shown, the commission may issue an order approving or modifying and approving a corporate separation plan under this section that does not comply with division (a)(1) of this section but complies with such functional separation requirements as the comznission authorizes to apply for an interizn period prescribed in the order, upon a finding that such alternative plan will provide for ongoing coinplianee with the policy specified in section 4928.02 of the Revised Code.
(D) Any party may seelc an amendment to a corporate separation plan approved under this section, and the cominission, pursuant to a reqtiest fi-om any party or on its own initiative, may order as it considers necessary the filing of an amended corporate separation plan to reflect changed cireumstances.
(E) Nohvithstanding section 4905.20, 4905.21, 4905.46, or 4905.48 of the Rcvised Code, an electric utility may divest itself of any gencrating asset at any time without commission approval, subject to the provisions of Title XLIX of the Revised Code relating to the transfer of transmission, dish-ibution, or ancillary service provided by such generating asset.
23 IN TCIF SUPREME COURT OF OHIO
Columbus Southet•n Power Company Case No.
Appellant, Appeal from Public V. Utiiities Commission of Ohio
The Public Utilities Commissiott of Ohio, : Public Utilities Contmission of Ohio Appellee. Case No. 08-917-F,i SSO
NOTICE OF15iPPFAL OF COLUMBUS SOUTHERN POWER COMPANY
iVlarvin 1. Resnik (0005695) Richard Cordray (0038034) Cowisel of Record lAttorney General of Ohio Steven T. Nou.rse (0046705) Duane W. Luc[iey (0023557) Kevin F. Duffy (0005867) Clriet, Public (Jtilities Section Ameriean Electric Porver Service tiWerner L. Margard (0039210) Corporatiou John.H.7ones(0051913) I Riverside Plaza, 29°i Floor 'fhonias G. Lindgren (0039210) C:olumbus, Ohio 4321 5-23 73 Assistant Attorneys Gereral Telephone: (614) 716-1606 189 'Fast Broad Streot Facsimile: (614) 716-2950 Columbus, Ohio 43215-3793 ni i r^sli il^r^, aep_co^l Telephone: (614) 644-8698 stnotu-se a?ae ^.[ cc^ni Facsimilc: (614) 644-8764 cPdutF c .ae com T)uai2e.luclcey@j?uc stateoh-us Thocnaalind ren c puc.statc.oh.us Daniel R. Conway (0023058) Werncraiiaruard(r^),Puc.slate.oh.us Poiter Wriglit Morris & Atthur 7ohn..lanes rl puc.siatc.oh?us Huntington Centcr 41 South 1Iigli Street Connsel for Appellee, Cohitnbns, Ohio 42315 Public Utilities Comn3issiou of Ohio Fz:.Y: (614) 227-2100 cie oa;cv^ysr7^ ortenvrinhtcom
C:ourisel fot' Appellant, Colnmbus Southern Power Company
t3r ?;:[)tlR (' ;rwI b^{^i(°Nix: ;."Of,(i i, OF
24 NOTCCE OF APP.[:AL OF APPEi.LANT COLUR' Appellant, Colrunbus Southern Power Company ("CSP" or "Appellant"), hereby gives notice of its appeal, pursuart to R.C. 4903.11 and 4903.13, and Supreme Court Rule of Practice 11, Section 3(B), to the Supreme Court of' Oltio and Appellee, the Public UtiIities Commission of Ohio (Y.omnussion"), from an Opinio3i and Order entered on Nlarch 18, 2009 (Attachnient A), an Bntry Nunc Pro Tunc entored on March 30, 2009 (Attachment 13), an Fnt7y on Rehearing, entered on July 23, 2009 (Aitachment C), an Entry on Rehearing entered mi August 26, 2009 (Attachinent D), and a Second Lntry on Rehcaring entered on November 4, 2009 (Attachment E), in PUCO Case No. 08-917-EL- SSO. That case involved an application fil.ed by CSP to establish att Electric Security Plan pursuant to R.C. 4928.143 and for autltority to sell or transfer certain gene.rating assets pursuant to R.C. 4928.17. Tn its .hily 23, 2009 Entry on Reltearing, the Commission granted reliearing rcgarding an issue raised on rehearing by an intervenor in the proceeding below. CSP actively opposed that intervenor's rcliearing request and the Commission's granting oP that rehcaring reciuest harmed CSP's interests. Appellant timely filed its Application for itehcaring ol' Appellee's Jtily 23, 2009 Entry on Rehearing in accordance with R-C_ 4903.10. After consideration of CSP's application for rehearing, the Co nmission denied t.hat rehearing request on November 4, 2009. The assignments of error listed below were raised in Appellants' Application fi>r 12ehearing. 2 25 The Commission's Opinion and Ordcr and Entries on Rehearing are unlawfal and tmreasonable in multiple reslreels. 1. The C'otntnission utila.wfully and unreasonably denicd CSP the autliority to sell or transfer certain genet'ating assets (Vtiraterford Lticrgy Center and Darby Electric (icnerating Center) as part of CSP's proposed I;iectric Security Plan. 2. The Commission unlawfully and unreasonably denied CSP the authority Lo recover, as part of its Electric Security Plan, costs associated «ith its ownership of the Waterford Energy Center and Darby Electric Generating Station. 3. ff-the Corntnissio3i were going lo require CSP to retairt tlxe Waterford Energy Center and Darby Electric Generating Statiun, "then the Cornmission should also allow (CSPI to recover Ohio custorners' ,jurisdictional share of ziny costs associated with maintaining and operai'u7g such facilities -" (Opinion and Order, p. 52). The Connnission's failure to either atthorize the sale or transfer of those generating assets or to authorize reeovety of costs from custorners is unlawful and unreasonable. WITEREPORTi, Appellant respectfully subinits that Appellee's lyfarch 18, 2009 Opinion and Order, as modified by its July 23, 2009 a^id Novembcr 4, 2009 Tntries on 7teheaiing are unlawftil, unjust, and unreasonable and should be reversed. Cotmnissi.oti Case No. 08-917-E?T. SSO should be remancled to the Commission with instructions to correct the errors complained of herein. 3 26 Respeetftd subniitted, Marvin 1. Resnik (0005695) Counsel of R.ecord Steven T. Nourse (0046705) Kevin F. Duffy (0005867) Ainorican Efectric Power Co7l)oration 1 RivetsidePlaza, 29`" Floor ColumUus, Ohio 43215-2373 Teleplione:(6l4) 716-1606 Facsi711ile: (614) 716-2950 mixesnilc cz?acg,coiri sinourse r)aen_ootn l:filulT r,aet^.com Daniel R. Conway Porter Rrright Morris & Arthur Huntington Center 41 South Iligh Stree[ Cotumbns, Ohio 42315 Fax: (614) 227-2100 dcanwa ^l orter^vii^l2t.com Counsel for Appellant, Columbus Sottthern PowOf Conlpany 4 27 PROOF OF SERVICE' i certify that Col3mibus So e-n Pov^=er Conipany's Notice of Appeal was served by First-Class U.S. Mail upon counsel for all parties to the proceecling before the Public Utiliti Coinmission of C}hio identified below and pursuant to Seetion 4903.13 of the Ohio Revised Code, this 22°`l day ot'Dccember, 2009. /.VI--^F 113-1-4 f, Marvin I. Resnik, Counsel for Alipellant Janine L. Migden-Osirander Richard Cordray Consumers' Counsel Ol io Attorney General Maureen 1L Gt'ady Duane W. Luckey 1'erry L. Pitter Section Chief Michael E. ltlzkodvski Thomas l.indgren Richard C. Rcese Warner L. Margard Office oYthe Ohio Corisunters' Counsel John H.Jones 10 West I3road Street, Suite 1800 Assistant Attoniey Gencral Coluinbus, Ohio 43215-3485 180 F.ast Broad Street Columbus, Ohio 43215 C:l i Iton A. Vince Samuel C. ItanciaG.zo Douglas G. Bonner Lisa G. McAlister Daniel D. 13an1owski Joseph M. Clark Emma F. Hand McNees, Wallace & Nurick, L1.C Sonnenschein Nath & Rosenthal LLl' 21 East State Sti'eet, 17°i Floor 1301 K Strect NW Columbus, Ohio 43215-4228 Suite 600 East Tower Washington, DC 20005 David F. Boehm John W. Bentine Michael L, Ktntz Mark S. Yurick Boehni Kurtz & Lowry Matthew S. White 36 East Scventh Street, Suite 1510 Chester, Wilcox & Saxhe, LLP Cincinnati, Ohio 45202 65 Hast State Street Suite 1000 Coltnnbus, Ohio 43215-4213 28 David C. Rinebolt Barth Royer Collcon L. Mooncy Langdon D. Scli 231 West Lima Street Bel I &Royer 33 Sout.h Grant Avenuc PO Box 1793 Findlay, Ohio 45839-1793 Columbus, Ohio 43215-3927 M. Itoward Petricoff Gregory Dunn Stepben M. Howard Christopher L. Miller Nlike Settineri Andre T. Pottei- Schalfeistein, Zox & Dunn Co., LPA Betsy L. Elde' Vorys, Sater, Seymour & 1'ease 250 West Street 52 East Gay Street Columbus, Ohio 43215 Columbus, Ohio 43216-1008 Thomas J. O'IIricn Clrace C. Wang McDent?ott, Will & Etnery, I.I.P Sally W, Bloomfield 600 Thirteeuth Strcet, NW 13nokcr & Eckler 100 SouthThird Street Washington, DC 20005 Columbus, Ohio 43215-3620 Miohael R. Smalz Bobby Singli lose.ph E. Maskovyak Integry's Energy Ohio State Legal Serviee Association 300 West Wilson Bridge 1Zoad 555 Buttles Avcnue Wottliington, Ohio 43085 Columhus, Ohio 43215 Cynthia A. Fonner Kevin Schmidt Constellation Energy Cixoup, Tnc. Ohio Manufactures' Association 550 West Washington Blod., Suite 3000 33 North 11igh Street Columbus, Ohio 43215-3005 C:hicago, Ill.i 7ois 60661 Larry Crearhardt Richard L. Sites General Counsel Chief Logal Counsel Ohio I'arm Burcau Fcderation C>hio Hospital Association 155 East 13road Strcet, 15°i Floor 280 North High Street Columbus, Ohio 43215-3620 PC)13ox 182383 Columbus, Ohio 43218-2383 K. Lawrence Fleniy W. Eelchard Giegoty Will & Emery LLP Counsel of Recrnd McDermott 50 West Broatl Street #2117 28 State Street Columbus, Ohio 43215 Boston, MA 02109 Douglas M. Mancino McDermott Will & Emery, LLI' 2049 Century Park East, Suite 3800 Los Angeles, CA 90067 29 CEA'1TFICATL OF RILING I hereby ccrtify that, in accordance with Supzem.e Court Rule of Pxsustice XIV, Section. 2 (C)(2), Columbus Southern Power Conipany's Notice of Appeal has been ftlec€ with the docketing division of the Public Utilities Comnussioti of Ohio and w.itb the Cliaii nan of the Public UtiliLies Cominission of Ohio by leaving a copy at tlre office of tl,e Cl airtnan in Columbus, Ohio, in accordance with Rules 4901-1-02 (A) and 4901-1 - 36 of tbe Ohio Adininistrative Code, on December 22°a, 2009, Marvin I. Resnik Couusel for Appellant, Columbus SouthemPower C,ompany 30 ATTACHMENT A A'I'TACTTIVIEN'P A BEFORE THE PLIBLIC LITII.ITIES COINM[S.SI{}N OF OHIa Inthe Mafiter of the Application of Cplurnbua Southern.Power Company for Approval of an Flectrzc Security I'Ian; an Ainendment to Case TSo. 08-917-EGSSQ its Corporate Separation Plaii; and the Sale or 1'ransfer of Certain Gen.eratingAssets. } In tlie Matter of the Application of Ohio Pawer Companp for Approval of itsBl.eclric } Case Np. 0$-918-EI.,,.S9O Security Plan; aztd an 1Smendment to its ) Corporate Separatinn E'Ian. t7PINION AND C)RL}Ekt 4magcse appearing are axt T2tia is to aartify thtLt tTSe arYd eam^Z9te .r.e^.-GCueC3on at s case file a04^4rate burtiuaeag= dtid=Mnt delivered in i:He r6^'aIa.r course at M^rt^-I Techxsia3an^_,^^w _^_ 17ata Prnce^t^aed 32 t}8-417-F.L-.^'^.SC3 and Q8-918-SIr.SSO '2- APPEARANCES : ...... 4 ...... -...... ,...... ,...... 6 OPINIOIV : ...... 6 l. HISTORY OF PROC.EEDINGS . A. Summay of the Local Public Hearings ...... 7 B. procedural lVfa#ers...... 7 ...... 7 1. Motion to Strike ...... 8 2. M+'stion for AEP-Ohio to Cease and Desist . Il. DISCIISSION ...... ---- ...... 9 A. Applicable Law...... 9 ...... 12 B. State I'olicy - Secti.on 4928.Q2, Revi9ed Code ... C. Application Overview...... 13 III. GENERA'CIoN ...... ,...... 13 A. Fuel Adjustment Qause (FAC) ...... 13 ...... 14 t. FAC Costs ...... 15 (a) Market Purchases .. (b) Off-System Sales (OSS) ...... 16 (c) Alternate Energy Portfolio Standards (including Renewable ...... 18 l;nergy Credit roP^ *ram)...... 2. FAC Saseline ...... 1$ 3. FAC Deferrals...... 20 13. Incremental Caxrying Cost for 2001-2008 Environmental Investment and the ...... 24 Carrying Cost Rate ...... 28 C. Annual Non-PAC Increases ...... 30 IV. DISTRIBU'1'lON ...... A. Annual Distribution Increases ...... 30 1. Enhanced Service Reliability Plan (ESRP) ...... 3d (a) Enhanced vegetation initiative ...... 31 (b) Enhanced underground cable i.nitiative ...... 31 ...... 31 (c) Distribution automation (DA) initiative (d) Enhanced overhead inspection and mitigat[on initiative.....,.. 31 2. GridSMART ...... :...... 34 B. Riders ...... :...... 38 1. Pravider of Last Resort (POLR) Rider ...... 3^ 2. Regalatory Asset Rider ...... 3. Energy Efficiency; Peak Demand Reduction, Demand Response, and ...... 41 Interraptible Capabilities (a) Energy Efficiency and Peak Dernand Reduction ...... 41 (b) Baselines and Benclunarks...... 41 (c) Energy Efficiency and Peak Demand Reduelion I'rograms.... 44 (d) Interruptible Capacity ...... 45 33 08-917-EL-SS0 and (}8-918-&I.-SSO r 4. Econon-ic Development Cost Recovery Rider and the Partnership with Ohio Fund ...... 47 C. I,ine Extensions ...... 48 . 49 V. T'RANSMISSION ...... ,....,...... ,...... V I. OTI-IE n ISS'[7PS ...... 50 A. Corporate Separation ...... :...... 50 1. Functional Separation ...... 50 2, Trarwffer of Generating Assets ...... 51 B. Possible Early Plant Clostares ...... 52 C. Pj.M Deinand Response Program.s ...... :...... :...... 53 D, Integrated Gasification Combined Cycle (IGCC')...... 58 E. Alternate Feed 6ervice ...... 59 F. Net Energy Metp.ring Service ...... 40 G. Green Pricing and I2enewable Energy Credit Purchase Programs ...... 62 H. Gavin Scrubber Lease...... 63 1. Section V.E (Interim Plan) ...... 64 VIl. SIGNIFICANTLY EXCESSIVE EAI2h1INGS'TFST (SEET) ...... 65 VIIl. MfiO V. ESP ...... »,...... I)C. CONCLUSION ...... 72 FINDINGS OF FACT AND CdNCLUSIOMS OF LAW :...... 73 ORDER :...... 74 34 48-917-HL-SSO and 013-918-EL-SSO -1- The Comntission, considering the above-entitled applications and the record in these proceedings, hereby issues its opinion and order in this maties'. APPEARANCPS: Marvin I. Resnik and Steven T. Nourse, American Electric Power Service Corporation, One Riverside Plaza, Cohzndras, CShio'3215, and Porter, Wright, Morris & Artliur, by Daniel R. Conway,'11 South High Street, Colurnbus, Olv.o 4S215, on behalf of Columbus Southern Power Company and Ohio Power Company. Richard Cordray, Attortiey General of the State of Ohio, by Duane W. Luckey, Section Chief, and Warner L. Margard, John H. Jones, and `Ihomas G. Lindgren, Assistant Attorneys General,13D East tiroad Street, Columbus, Ohio 43215, on behalf of the Staff of the Public Utilities Commission of Ohio. Janine L. Migden.-Ostrander, the Office of the Ohio Consumers' Counsel, by Maurcen R. Grady, "1'erry L. Etter, Jacqueline Lake Roberts, Michael E. Idzkowslti and Richard C. Reese, Assistant Consumers' Counse1,10 West Broad Street, Columbus, Ohio 43215-3485, on behalf of the residential utility consumers of Cotunibus Southern Company and Oluo Power Company. Boelun,lCurtz & Lowry, by David B. Boehm and Michael L. ICurtz, 36 East Seventh Street, Suite 1510, Cincinnati, O1uo 45202, on behalf of Ohio Hnergy Group. Citester, Wilcox & Saxbe, LL:P, by]olut W. Bentui.e, Mark S, Yurick, and Matthew S. White, 65 East State Street, Suite 1000, Columbus, {7hio 43215-4213, on behalf of The Kroger Contpany. McNees, Wallace & Nurick, LLC, by Samuel C. Randazzo, Lisa G. McAlister, and Joseph M- Clark, 21 East State Stxeet,17th Floor, Columbus, Ohio 43215-4228, on behalf of Industrial Energy Users-O2uo. David C, Ritiebolt and Colleen L. Mooney, 231 West Lima Street, P.O. Bdx 1793, Findlay, Ohio 45839-1793, on behalf of Uhio Partners for Affordable Finergy. Bell & Royer Co., LPA, by Barth E. Royer, 33 South Grant Avenue, Columbus, Ohio 41215-3927, on belalf of Ohio -T^tvironmental Council and I7ominion Retail, Inc. Vorys, Sater, Seymour & Pease, LLP, by M. Howard Petrfcoff, Mike Settinerl and Betsy L. Elder, 52 East Gay Street, Columbus, Ohio 43216-1008, and Bobby Singh, Tntegxys Energy, 300 West Wilson Bridge Road, Worthington, Ohio 430$5, on behalf of Integrys Energy. 35 -5- 08-917-ELSS0 and 08-918-EL,-SS0 Vorys, Sater, Seymour & Pease, LLP, by M. Howard Petricoff, Mike Settineri a*td Betsy L. Elder, 52 kast Gay Street, Columbus, Ohio 43216-1008, and Cynthia A. Ponner, Coiistetlation Energy Group, Inc., 550 West Washington Boulevard, Suite 3000, C.hif'ago, lllinois 60661, on behalf of Constellation NewEnergy, Inc., and Constellation Energy Cou-tmodities Group, Inc. Vorys, Sater, Seymour & Pease, LLP, by M. Howard Petricoff, Mike Settineri and Betsy L. Elder, 52 East Gay Street, Columbus, Ohio 43216-1008, on belialf of EnerNoc, Inc. and Consumer Powerline, Inc. Schottenstein, Zox & Du.rut Co., LPA, by Gregory H. Dunn, Christopher L. Miller, and Andre T. Porter, 250 tivest Street, Coluanbus, Ohio 43215, on behalf of the Association of Independent Collel;es and Uxuvexsities of Ohio. I3ricker & Eckler, Thomas J. O'Brien, 100 South Tiurd Street, Columbus, Ohio, and Richard L. Sites, 155 East Broad Street, 15th Floor, Columbus, Ohio 43215-3620, on behalf of O1do Hospital Association. Iell & Royer Co., LPA, by Langdon D. BetI, 33 South Grant Avenue, Columbus, ► {?hio 43215-3927, and Kevin Schmidt, 33 North High Sireet, Calumbus, Ohio 43215+3005, on behalf of Ohio Manufacturers' Association. Vorys, Sater, Seymour & Pease, LLP, by M. Howard PetricofE and Stephen M. Iioward, 52 East Gay Street, Columbus, Ohio 43216-1008, on behalf of Direct Energy Services, I.LC. McDermott, Will & Eniery, LLP, by Grace C. Wung, 600 Tlhirteenth Street, N.W., Washington, D.C.. 20005, on behalf of Wal-Mart Siores East, LP, and Sam's East, Tnc., Ll', Macy's, Inc., and BJ's Wholesale Club, Inc, Vorys, Sater, Seymour & Pease, LLP, by M. Howard Petricoff and Stephen M. I Ioward, 52 East Gay Street, Columbus, Ohio 43216-1008, on behalf of C>hio Association of School Business Officials, Ohio School Boards Association, and Buckeye Association of School Administrators. Nlichael R. Smalz and Joseph E. Ivfaskovyak, Ohio State Legal Services Association, 555 Buttles Avenue, Columbus, Ohio 43215, on behalf of Appalachian T'aopie's Ac6on Coalition. 36 -6- 08-917-EL-SSC) and 0&91S-I3LrSSO {7FINION; 1. IiISTC7RX OF PROCEEDINGS Ch, July 31, 2008, Columbus Southern Power Company (CSP) and Ohio Power Conrpany (OP) (joindy, AEF-Ohio or the Companies) filed an application for a standard service offer (55C)) pursuant to Section 4928.141, Revised Code. The application is for an electric secutity plan (E5P) in accordance with Section 4928.143, Revised Code. By entries issued August 5, 2008, and September 5, 2008, the procedural schedule ul this matter was established, including the scheduling of a technical confexence and the evidentiary hearing. A technical conference was held regarding AEP-OhWs application on August 19, 2008. A prehearing conference was held on November 10, 2008, and the evidentiary hearinl; commenced on November 17, 2008, and concluded on Deceniber 10, 2008. The Commission also scheduled five local public hearings tliroughout the Companies' service area. The following parties were granted intervention by entries dated September 19, 2008, and October 29, 2008: Ohio Energy Group (OEG); the Office of the Ohio Consumers' Counsel (OCC), Kroger Company (Kroger); Olvo xnvironmental Council (OEC); Industrial Energy C7sers-Ohio (fEU); Ohio Partners for Affordable Energy (OPAE); Appalachian People's Action Coalition (APAC); Ohio Hospital Association (OHA); Constellation NewFnergy, Inc. and Constellation Energy Commodities Group, Inc. (Constellation); 17ominion Retail, Inc. (Dominion); Natural Resources Defertse Council (NRDC); Slerra Club - Ohio Chapter (Sierra); National Energy Marketera Association (NEMA); Integrys Energy Serv4ce, Inc. (Integrys); Direct Energy Services, LLC (13irect Fnexggy); Ohio Manufacturers Association (OMA); tjhio Farm Bureau Federation (OFBF); American Wind Energy Association, Wind on Wires, and Ohio Advance Energy (Wind F^tergy); Ohio Association of School Business Officials, Ohio School Boards Association, and Buckeye Association of School Administrators (collectively, Schools); Ormet Primary Aluininum Corporation (Ormet); Consumer Powerlirne; Morgan Stanley Capital Group Inc.; Wal-Mart Stores East, LP and Sam's East, Inc., Macy's, Inc., and BJ's Wholesale Club, Inc. (collectively, Cornmercial Group); EnerNoc, Inc.; and the Association of Independent Colleges and Universities of Qhio. At the hearing, AFP-Ohio offered the testimony of 11 witnesses in support of the Companies' application, 22 witnesses testified on behaif of various inte, venors, and 10 witnesses testified on behalf of Staff. At the local public hearings lield in thl.s matter, 124 witnesses testified. £riefs were filed on December 30,2008, and reply briefs were filed on January 14, 2009. 37 08-9I7-121L, 6SU and 08-918-5`LrSSO A. Summarr of the Local T'ublic Hearin^s Five local public hearings were held in order to aliow C.SI''s and OP's customere the opportunity to express their opuuons regarding the issues in this proceeding. The hearings were held in the evenings in Marietta, Canton, I.ima, and Columbus. Adclitionally, an afternoon hearing was lield in Colu.rxtbus, At those hearings, public testimony was heard from 21 customers in Marietta, 21 customers in Canton, 17 customers in Lima, 25 customers at the afternoon hearing in Columbus and 40 customers at the evening hearing in Columbus. In addition to the public testimony, numerous letters were flled in the docket by custc>m.ers stating coneern about the applications. `i'he principal concern expressed by customers, both at the public hedring9 and in letters, was over the increases in customer rates that wotdd result from the approval of the bSi' applications. Witnes,aes stated that any increase in xates would negatively impact Iow-incoine customers, the elderly, and those on fixed incomes. Customers cited the recent downturn in the economy as the primary source of their apprehension. It was noted by many at the hearings that customers are also facing increases in other utility charges, gasoline, food., and medical expenses and that the proposed increases would cause undue hardsiup. On the other hand, some witnesses at the public hearings and in the letters filed in the docket acknowledged AEI'-Ohio as a good corporate partner in their respective conununit[es. B. Procedural Mattees 1. Motion to 9trike On January 7,2069, AEP-Qhio filed a motion to strike a section of the brief jointly filed by OCC and Sierra (collectively, tX:EA). More specificalty, ASP-Ohio filed to strike „ the sentence starting on line 2 of page 63 ( in fact,_' ] througli the first two lines of page 64, including footnotes 244 to 248. AEP-Ohio argues that the above-cited portioat of OCEA's brief, regarding the deferral of fuel expenses and the carrying eharges and the tax effect thereof, relies upon testirnony offered by OCCC witness Effron in ttxe PirstEnergy Distribution Case.i AEp-Ohio notes that W. Effron was not a witness in this ESP proceeding and, therefore, was not available for the Companies, or any other party, to croas-exaxnine. Accordingly, the Companias argue that consideration of Mr. Lffron`s testimony in this matter would be a denial of the Companies` due process rights, and request that the specified portion of C)CCpA's brief be stricKen. On )anuary 14, 2009, OCC filed a memorandum contra the motion to strilce, OCC agreed to withdraw the second and tliird sentences on page 63, the qupted testisnony of Mr. Effron on page 63, and footnotes 244 to 248 on pages 63 and 64. . However, OCC contends that AEPAhia's Ede9on Computty, Case In re Ohio Edison Concpnny, The QeoelQnd EIec&7c Illuminating Company, atut To[edo No. 07-551=ELAiR et az?. (FirstEnergq Disuibution Case). 38 08-917-EIrSSO and 08-918-EL-5S4 ^- tnation is overly broad and the remaitiing portion of the brief that AUI'-Ohio seeks to strike is appropriate legal arguinent regarding deferrals on a net-of-tax basis and, therefore, should renAain, AEl'-CHiio filed a reply on January 16, 20(19. AR'-Oldo first notes that because the memorandum contra was filed by OCC only and Sierra did not respond to the motion, it is not clear whether Sierra is also willing to withdraw the portions of the brief listed in the memorandtnn contra. Al?P-Qhio also argues that the remaining portion of this particular argument in QCEA.'s brief should be stricken with the renioval of the footnotes. With this removal, AEP-Ohio then argues that there is no longer any support in the brief for such arguiua.tts. By letter docketed January 22,200, Sierra confirmed that it joins CCC in OCC's withdrawal of the Iimited portiow of the OCEA brief as stated by CJCC in its January 14,2009, reply. The Commission gran.ts, in part, and denies, in part, AEP-C}hia"s motion to strike OCEA's brief. The Conamission agrees with AEP-Mo and OCC that the use of Mr; Effron's testimony filed in the Firstlinergy Distribution Case in this proceedfng was iriappropriate and, therefore, we accept OCC's and Sierra's withdrawal of that portion of their brief. As for the remaining portion of OCEA's brief that AEP-{)hio has requested to be stricken, we agree with CCC that the language that disru.sses the calculation of deferred fuel expenses on a net-of-tax basis could be construed to be legal argranent on brief, wfiich rationalized why the issue should be decided in OC.EA's favor. Moreover, we can surmise that if OCEA had recognized its error in the drafting stage of the brief, that OCEA would have drafted similar legal argcunents without referencing Mr. Efftori s testimony. Accord'angly, we will only strike the portions of OCEA's brief that t7CC and Sierra have agreed to withdraw. 2. Motion for AEP-Ohio to Cease and Desist On February 25,2009, Integrys filed a motion with the Commission requesting that the Commission direct Af;f'-Uhio to cease and desist the Companies' refusal to process 5S0 retail customer applications to enroil in the Interruptible Load for Reliability (ILR.) Program of PJM Interconn.ection, LLC (PJIvt). Integrys also filed a request for an expedited ruling; however, Integrys represented that counsel for AEP-Ohio objected to the exped'ztcd ruling request. Integrys is a registered curtailme.nt service provider with P]M and as such receives notices from PJM and coordinates with retail customers to cttrtail load. Integrys argues that retail customer pax'ticipation in I.'JM demand resporuse progi.am,> wa5 raised in the Contpanies` ESP application and has not yet been decided by ttie Cbmmission. For this reason, 3ntegrys contends that AEP-Ohio lacks the authority to refuse to process the ILR applications and the denial of the application vioIates the Cornpanies' tariffs. Two other curtailment service providers in the AEP-OUio service 39 -9- U8-917-EL-SS0 and Q8-928-EL-5SO territory, Constellation and KQREnergy, Ltd., filed memoranda in support of Integrys' motion.2 On March 2, 2009, A.EP-Ohio filed a memorandam contra the motion to cease and desist. AEP-Ohio affirms the argixments nrade in this proceeding to prohibit retail customers from participating in PJM's demand response programs. Further, ?.EP-C)hio argues, among otlier things, that despite the claims of Integrys andConstellation, AIiP- Ohio is providing, in a timely m-mner, the load data required for customer enrollment in the PJM ILR program, infomis the customer that AEP-Ohio is not consenting to the customer's participation iu1 the program, and discloses that the matter is currentty pending before the Coinrnission. On March 9, 2009, tntegiys and Coneteliation filed a withdrawal of the motion to direct AEP-Ohio to cease and desist. The inovants state that despite AF..P-Uhi.o's assertions that the applicants were not eligible to participate in PjM's demand response programs, P7M rejected AEP-Ohia's opposition to the ILR applications and processed the ILR applications. Integrys attd. Constellation further state that, except for two pending applications, all their castomers in the AEP-Ohio service terrmtory have been certified for participation in the PJM prograsns. As the parties ackn.owledge, this matter was presented for the Comzaission's consideration as part of the FSF application. The Commission, therefore, spceifically addresses and discusses the issues raised concerning SSO retail customer Paittcipation in PJ'M demand respoiise progra.ms at Section VLC of this opinion atid order. Accordingly, we grant Integrys' and Constellation's reqi.rest to rvithdraw their motion to cease and desist. it. DISCUSSION . A, Aovlicable Lacv Chapter 4928 of the Revised Code provides an integrated system of regutation in which specific provisions were designed to advance state policies of ensuring access to adequate, reliable, and reasonably priced electric service in the context of significant economic and environmental challenges. In reviewing ABP-C3hio's application, the Cocn*n.ission is cogni't.an.t of the challenges facing Ohioarns and the electric industry and will be guided by the policies of the state as established by the General Assearterly in Section 4928.02, Revised Code, which was amended by Senate Bill 221(S8 221)- Section 4928.02, Revised Code, states that it is the policy of the state, inter alia, to: r KOREnergy, Ltd., has not filed to intervene in t]+is procc edin& and, therefore, its memoranda in support avilE not be corisidered. 40 -1a 0£3-917-E1,SSO and 08-418-EL-,SSO t1) Ensure the availability to consumers of adequate, reliable, safe, efficient, nondiscriminatory, and reasonably priced retail electric service. (2) F.nsure the availability of unbundled and comparable retail electric service, (3) Ensure diversity of electric supplies and suppliers. (4) l:stcourage innovation and enarket aceess for cost effective supply- and demaztd-side retail electric s(rvice including, but not limited to, demand-side management (I)SM), tirne° differentiated pricing, and implementation of advanced metering infrastructure (AMf}. (5) Encourage cost-effective and efficient aecess to inforntatior+ regarding the operation of the transmission and distribution systems in order to promote both effective cu.stomer choice and the development of performance standards and targets for service quaiity. (6) Ensure effective retail competition by avoiding anticompetitive subsidies. (7) En.sure retail consunters protection against unreasonable sales practices, market deficiencies, and market power. (8) Provide a means of giving incentivea to technologies that can adapt to potential environmental mandates. (9) Encourage implementation of distributed generation across customer classes by reviewing arid updating rules governing issues such as intercorutect3on, standby charges, and' net metering. (10) Protect at-risk populations ineluding, but not linuted to, syhen considering the implementation of any new advamed energy or renewable energy resource. which now provides In addition, SB 221 amended Sec,'tion 492$•14, Revised eode, that an January 1, 2009, electric utilities must provide consurners with an S5t], eorLqisting of eitlier a market rate offer (MRO) or an ESP. The SSJ is to sexve as the electric ufiility's default SSO. 'I7.le law provides that electric utilities may apply simultaneously for both an 41 0$-917-EL-SSC3 and 08-918-EL-9SC) ^l- MR0 and an rSP; IZowever, at a rninunum, the first S'50 application must include an application for an ESP. Section 4928.142, Revised Code, specifically provides that an SSO shall exclude any previously authorized allowances for transition eosts, with such exclusion being effeetive on and after the date that the allowance is scheduled to end under the electric utility's rate plan. In the event an SSo is not authorized by January 1, 2009, 5ixtkon 4928.141, Revised Code, provides that the emient rate pian of an electric utility shall continue until an S90 is authorized under either Bection 4928•142 or 4928.143, Revised Code. AEP-Uhia s application in this proceeding proposes an ESP, pursuant to Section 4928.143, Revised Code. Paragraph (B) of Sect-ian 4928.141, Revised Code, requ,ires the Commission to hold a hearing on an application filed under Section 4928.143, Revised Code, to send notice of the hearing to the electric utility, and to publish notice in a newspaper of general circulation in each county in the electric utility's certifred ttmitory. Section 4928.143, Revised Code, sets out the requirements for an ESP. Under paragraph (B) of Section 4928.143, Revised Code, an &5P must include provisions reiatuig to the supply and pricing of generation service. The plan, according to paragraph (B)(2) of Section 4928.143, Revised Code, may also provide for the automatic recovery of certaln costs, a reasonable allowance for certain construction work in progress (C"I+ViI'), an unavoidable surcharge for the cost of certain new generation facilities, conditions or charges relating to customer shopping, automatic increases or decreases, provisions to allow securitization of any phase-in of the SSC) price, provisions relating to transmisssion- related costs, provisions related to distribution service, and provisions regarding economic development. The statnte provides that the Commission is required to approve, or moeiffy and the ESI', if the ESP, including its pricing and all other terma and conditions, approve including deferrals and future recovery of deferxals, is mare favorable in the aggregate as corapared to the expected results that would otherwise apply un.der Secdon 4928.142, Revised Code. In addition, the Conurdssion must reject an PSP that contains a surcharge for which for CWIP or for new generation facilities if the benefits derived for any purpose the surcharge is established are not reserved or u7ade available to those that bear the surcharge. The Comnrission may, ufrder Section 4928.144, Revised Code, order any just and reasonable phase-in of any rate or price established under Section 4928.141, 4928.142, or 1926.143, Revised Code, including carrying charges. If the Comrnission does provide for assets by adu^ orczui$^the a phase-in, it nrust also provide for the creation of regulato asa deferral of iricurred costs equal to the amount not collected, plus n'y g g amount, and shall authorize the deferral's collection through an unavoidable surcharge. 42 Q8-917-EL-9SC) and 08-918-EL.-S,SO -12 By finding and order issued September 17, 2008, in Case No. 08-777:SL-C]RU (W Rules Case), the Corn.mission adopted new rules concerning SBO, corporate separation, and reasonable arrangements for electric utilities pursuant to Sections 4928•06, 4928.14, 4928:17, and 4905.31, Revised Code. The rules adopted in the 65O Rules Case were subsequently amended by the eniry ott rehearing issued Pebruary 11, 2009. B. State 1'olicy `;eection 4928,0 2 Revl.sed Code AE11-0hio submits that, contrary to the views of the intervenoxs, Section 4928.02, does not impose additional requirements on an ESP and the hSP sliould Revised Code, not be modifiecl or rejected because it does not satisf,y all of the policies of the state. According to the Comparties, "[tJhe public interest is served if the;ESP is mose favorable (Cos. Br. at 15). in the aggregate than the expected results of an MRO" OI3A asserts that the Commission "must view the 'more favorable in the lens of the overriding 'public 'utterest; " and that the aggregate' standard through the public iztterest catmot be saved if the result is not reasonable (OHA Br. at 10). niust be more favorable in the aggregate and OPAE/ APAC seems to state that the Ml' comply with the state policy, but also t•ecoozes that state policies are to be used to guide Br. at 3). OEG agrees that the the Cormnission in its approval of an ESP (OPAE/APAC (OEG Br. at 1). policy objectives are required to be met prior to the approval of an ESP Group submits that costs must be properly allocated to ensure that the The Comatercial policies of the state are iitet, to improve price signals, and to ettsure effective retail competition (Convmeraal Gmup Br• at 5). In its reply brief, AEP-Ohio maintains that its proposed F.SP is consistent with the (N), ltevised Code, and is policy of the state as delineated in Sections 4928.02(A) through (Ccas. Reply Br. a 7). According to the "worthy of approval, without modification" the ESP advances the general policy objectives of the policy of the atate (Id. at Campardes, 6-4 Furtherinore, the Companies argue that the concerns raised by some intecvenors ould have regarding the impact of AEP-Ohio's ESP on the difficult economie conditions w the Corsunission ignore the statutory sfiandat'd for approving an. ESP and, instead, establish rates based on the current economic conditions (Cos. Reply Br. at 7). Whi1e the (e.g., fuel Companies believe that aspects of the proposed ESP address these concerns deferrals), they argue that their SSO must be established in accordance with applicable ESP statutory provisiom (ld.). in our oplydon and order issued in the As explained above, and previously PirstEziergy ESP proceeding,3 the Cornmission believes ihat the state policy codified by Revised Code, sets forth importatlt objectives, the General Assembly in Chapter 4928, Cornpmty, and the T'oteda Edfeon Cmfrpany, 8 In re Ohio E'disai Cnrnynnf The Clevatand Eteetric it?.umfnating ecember 19, 2DO8) (.FustEnergy MI' Cese). Case No. O£t-935-EL-SSC7, Opinion and Order nt'12 (D 43 13- 08-917-hL-S6C) and 08-918-EtrSSO which the Commission must keep in mind wl3en considering all Ca.^es filed pursuant to that chapter of the code. As noted in the FirstEnergy Es1' caSe, in deterzt3ining whether titie E5P meets the requirements of Section 4928.143, Revised Code, we take into consideration the policy pravisiotts of Section 4928.02, Revised Code, and we use these policies as a guide in our implementation of Section 4928.143, Revised Code. Accordingly, we agree with AEP-C3hio and will use these policies as a guide in our case, just as we did in the FirstEnergy ESP Case (Cos. TLeply'Br. at clecision-makhtg in this as well as 6)A The Conunission has reviewed the ESP proposal presented by AEP-Ohi4, the issues raised by the various intervenors, and xve believe that, with the m.odifications appropriately reached a conclusion advanclttg the putalic's set forth herc:in, we have interest. C. _Ap_plieation Ctverview In their application, the Companies are recluesting authority to establish en SSO zn the fosm of an ESP pursuant to the provisions of Sections 4928.141 and 4928.143, Revised Code. 'i he proposed ESP is to be effective for a tliree-year periW comrnencing january 1, 2009. Accord'utg to the Companies, pursuant to the proposed FsSP, the overall, estimated increases in total customer rates, including generation, traztigmission, and distribution, would be an average of 13.41 percent for CSP and 73 percent for L?P in 2009, and 15 percent in 2010 and 2011 for both CSP and OF (Cos. Ex. 1, Exhibit DMR-1). The Companies also propose a 15 percent cap per year an the total allowable increases for each customer rate schedule should the actual costs be higher than expected, excluding trapsmission costs and costs associated witli new govcrnntent mandates (Cos. App. at 6). III: GFNERATION A. Fuel Adu tMentCfause FAC The Cotnpanies contend that Section 4928.143(B)(2)(a), Revised Code, authorizes the implementation of a FAC mecharsism to recover prudently incurred costs associated with fuel, including consumabl.es related to environniental compliance, purchased power costs, emission allowances, and costs associated with carbon-based taxes and other carbon-related regulations (Cos. Ex. 7 at 4-7). the'F.SP must be used as a Euide to imptement 4 Some intervenors recog,nize that the state poticy objective provision (IEU Br, at 19; OPAE/Ai'AC Br. at 3). 44 -14- Q8-917-EIrS.SC) and 08-918-EI,6SO 1. FAC Costs The Companies proposed to include in the FAC mechanism types of costs recovered through the electric fuel component (EFC) previously used in C)tuo5 (Cos. Ex. 7 at 34). In addition to those types of costs, the Companies stated that Section chanis 4928,143(I3)(2)(a), Revised Code, provides for a broader cost-based adjustment We e r and that authorizes the inclusion of all prudently incurred fuel, p^chased po envixonmetrtai components (Id. at 4). Comganies' witness Nelson itemized and described the accounts that the Companies proposed to include in their PAC mechanism (Id, at 5-7), Staff, CCC, and Sierra support the FAC mechanism that wil3 be updated and sA Br. at 47-48, 67i687 OCC Ex.11 at 4-5, 31-40). reconciled quarterly (Staff. Ex. 8 at 3-4; C)Cl' Specifically, Staff witness Strom testified that the costs proposed to be recovered through the PAC mechanism aze appropriate and recovery of those costs through a FAC mechanism is logical (Staff Fx. 8 at 3). {?CC and 5ierra also agree that Section 4928:143(B)(2)(a), Revised Code, authorizes the enactment of a PAC mechanism to automatically recover certain prudently incurred costs (OCEA Br. at 47),.and UCC does not seem to oppose the list of categories of accounts proposed to be included in the PAC by Conipanies witness Nelson (OC:C Ex, 1.1 at 18-20). Additionally, Staff recommended that annuai reviews of the prudency and appropriateness of the accounting of FAC costs be conducted (Staff Ex. 8 at 3-I), and C1CC recommended that an interest charge be paid to customers on any over-recovered fuel costs in a quarterly period until the subsequent reconciliation occurs, similar to the carrying charge for any under-recovery that she believed the Companies were proposing to collect6 (OCC Ex. 11 at 4). Kroger and IEU, however, seem to state that a PAC mechanism cannot be established until a cost-of-service or earnings test is completed (KToger Br. at 9-10; IEU Br. at 12-15). TfiCT also questioned the appropriate term of the proposed PAC mechanism (IEU Br. at 13; Tr. Vol. I7( at 143- 146). Thx: Commiasion believes that the estabILshment of a FAC mechanism as part of an EESI' is authorized pursuant to Section 4928.143(B)(2)(a), Reviged Code, to recover prudently incurred costs associated with fue1, including consumables related to environmental compliance, purchased power costs, emission alIowances, and costs associated with carbon-based taxes and other carbon-related regulations. Given that the FAC mechanism is author.ized pursuant to the F•SP provision of 5B 221, we wfll limit our authorization., at this tinte, to the term of the'naI', See Sect3ons 4905.01(G), 4905.66 through 4905.69, and 4909.159, Revised Code (repealed 7anuary 1, 200'I); Chapter 4901:211, Ohio Administrative Code (p.A.C.) (rescinded November 2,7, 2003). 6 In A^H:P's Brief, ths Companies clarified that they darl not p!opose to eoIlect a caazrying charge on any FAC under-recovesy in one quarterly period until a reconciliation in the subsequent period occnrred. The only carrying charge that they proposed was on the FAC deferrals that would not be collected untif 2012-2018 (Cos. Br. at 27). 45 -15- 48-917-Ei. SSO and 08-918-EtfSSd With regard to interest charges assessed on any over- or under-xecoveries for xAC costs within the quarterly period untit the subsequent reconciliation occurs, we agree with pCC witness Medine that symmetry should exist if interest charges were assessed can any under-recoveries (Tr. Vai, VI at 210). However, we do not conclude that any intezest charges on either over- or under-recoveries are necessary as a deterrent to the creation of over- or under-recoveries as CCC witness Medine suggests (Id, at 220-211). As proposed by the Companies and supported by others, the FAC mechanism includes a quarterly for the reconcitiation to actual FAC costs incurred, which will establish the new charge subsequent quarter. These quarterly acljustments combined with the annual review proposed by Staff to review the appropriateness of the accounting of the FAC costs and the prudency of decisions made are sufficient to control the over- or under-recoveries that may ocvur within a particular quarter. Therefore, we find that the FAC mechanism with quarterly adjustmerits as proposed by the Companies, as well as an annual prudency and accounting review reconunended by Staff, is reasonable and should be approved and implemented as set foxth herein. (a) Market Pumhases As part of the FAC costs, the Companies proposed to purchase incremental power on a "slice of the system basis" equal to 5 percent of each company's load in 2009, 10 percent in 2010, and 75 percent in 2011 (Cos. Fx. 2-A at 21). The Companies argue that while these purchases will be included in the FAC mechanism, as the appropriate recovery nrechanism for these costs, the purchases are per}{ tted as a d'scrchonary component of an ESP filing aut.hQrized by SecGion ^#928.145^2), Revised Code, which states: "The plan may provide for or include, wi,thout linutation, any of the following." AEP-{]2uo states that the (emphasis added) (Cas. Sr. at 37). To support its proposal, purchases reflect the continued transition to market rates and represent an appropriate recognition of the Companies' incorporation of the loads of Ormet Primary Aluminum Company (Orznet) and the certified territory formerly served by Monongaheta Power Coinpany (MonPower) (Cos. Ex. 2-A at 21-22). The Companies further assert that, durtng the ESP, they should be able to continue to recover a market-based generation price for serving these loads, as was previously authorized by the Comn.;ission during the RSP period. Staff supported market purchases suf€icient to meet the additional load responsibilities that the Companies assumed for the addition of the former MonPower cu.stomers and Ormet to the Companies' system, which equals approximately 7.5 percent of ilte Companies' total loads (Staff Ex. 10 at 5). However, based on the size of the additional load assumed by the Companies, Staff only recomtnended that the incremental power purchases equal, on average, 5 peTcent of each company's load in 2009, 7.5 percent in 2010, and 10 percent in 2011(Id.). 46 -16- 08-9I7-BL-5SC) and 0$-918-EL-4S0 Tiie Companies responded to Staff's reductian in the amount of market purchases by adding that the. Companies also intended to utilize their proposed levels of inarket purchases to encou.rage econantic development (Cos. Ex. 2-H at 7). power Various parties oppose the inclusion of incremental "slice of the system" purchases in AEP-Ohio's E5i'. OEG witness Kollen testified that the Commission should reject this provisian of AE['-Ohio's ESP because the Companies have not demonstrated a need for the excess generation pu.rcihased on the market to meet its existing load, and such "purchases are n`ot prLzdent because they witl uneconomically displace lower cost owned generation and cost-based purchased power that is available to meet Company their Iaads" (OEG Ex. 3 at 3,940). IBLI witness Sowser agrees that this portion of the OP should be rejected (IEU Ex. 10 at 9). Kroges witness Higgins also concurs, stating: "The only apparcnt purpose of these slice-of-systein purchases is to serve as a device for increasing prices charged to customers" (Kroger Ex. 1 at 9). OCEA concurs with the testimony offered by these intervenor witnesses (f3CFA Br. at 5.3-55). lntervenors also question this provision in light of the AEP Int.erconnoction Agreement (OEG Bx. 3 at 1(}- 14; OCEA Br. at 54-55). Given that AEP-Ohio has explicitly stated that the purchased power is not a prerequisite for adequately serving the additional load requirements assumed by AfiT°- Ohio when adding Ormet and the NfonPower customers to its systear (Cos. Tix. 2 I3 at 7), the Commission finds that Staff e rationale for the support of the proposal, as well as the recommendation for a reduction in the amount of purchased powex proposed to equal the additional load, fails. We strugg.le, along with the other parties, to find a rational basis to approve such a proposal in the absence of need. The Conunission notes that while we appxeciate A8I'-Ohio's willingness and cooperation with regard to the es have bee^ ab e and Monporver customers into its system, we believe that the Compa to prepare and plan for the additions to its system under the current regulatory scheme and have been conr.pensated durhig the transitional period. As for the reliance on the market purchases to promote economic development, the Conunission believes that this goal can be more appropriately adWeved throtzgh other mean.s as outlined in this opinion and order, the Conimission s recently adopted rules, and SB 221. Accordingly, we find that AEP-Ohio's FSP shall be rnodified to exclude this provision. (b) Off ^ystemSalesi!C^i 1'soger and OEG contend that FAC costs must be offset by a credit for OSpi margins, stating that othex }urisdictions govenjing other operatin.g companies of A8P Corporation require such an OS5 offset to revenue requirements (Kroger Br- at 11-12; Kroger Ex. I at 3, 9, 10; OEG Br, at 10; OEG Ex. 3 at 14-15, 16-17). Kroger argues that i.t is incongruent to allow a rate increase based on certain costs without examining AE['-Ohio's 47 -17- 08-917-EL-5SO and o8-918-EL-950 net costs to determine that AEP^Ohio s costs have actually increased (1Croger Br. at 11-12). were $146.7 mi.ltlon OEG notes that the Companies` profits for 2007 from off-system sales for OP and $124.1 million for CSP (OBG Ex. 3 at 14). OEG reasons that because the cost of the power pJ.airts used tn generate off-system sales are included in rates, al3 revenue fram the power plants should be a rate credit (OEG Br. 10). OCEA raises similar arguments to those of OEG and Kroger in its brief (ECEA Tlr• at 57-59). More specifically, OCEA argues that the Cornpanies' proposal to eliminate off-system szles expenses from Ohio catepayers is not equivalent to providing customets the benefit of off-system sales margins, OCEA notes tltat, ut other cases, the Commission lias rrequired electric uOties to share the benefits of off-systeni sales revenue with jurisdictional customers (OCEA Br. at 58-59). Staff did not take a posifion in regard to the intervenors' arguments to offset FAC costs by the (JSS margin. Staff, however, concluded that the costs sought to be recovered through the FAC are appropriate (Staff Ex.10 at 4; Staff Ex. 8 at 3; Staff Br..at 2). The Companies argue that an QSS offset to FAC charges is not required by Section 4928.143(B)(2)(a), Revised Cotie, or any other provision in SB 221 (Cos. Ex. 2-E at 8-9; Cos. Reply Br. at 12). The Companies also state that the regulatory or. statutory regimes in other states have no bcaring on Ohio or Ohio's statutory requixements (Id.). As to the OEG ar+d OCEA, the Companies argue that the intervenars other arguments raised by arguments ignore the fact that the Companies' ESP reduces the FAC and environmenmi carr3,ing cost expenses for AE.P-Ohio customers t'ased on the calculation of the pool capacity payments in the FAC and use of the pool allocation factor (Cos. Ex. 7, Exbibits PJN-2, P)N-2, PJN-b and PJN-8). Upon a review of the record in this case, the Commission is not pexsuaded by the intervenors' arguments. We do not belisve tha.t the testimony presented offered adequate justification for modifying the Companies' proposed ESP to offset OSS margins from the FAC costs. Section 4929.143($)(2)(a), Revised Code, specifically provides^ ^as^ed autamatic recovery, without limitation, of prudently incurred costs for fuel, p power, capacity cost and power acquired from an affiliate. . As recognized by the e Companies, the pertinent statutory provisions do not =n^that t^e>e be ang^f ^to ^e allowable fuel costs for any OSS margins. AdditioY Coxnpanies' ESP applicatlon, and thus, we are not persuaded by the arguments of Kroger regardtng how other jurisdictions handle OSS margins. Moreover, cons'istent with our discussion in 5ection VIt of our opinion and order, we do r.otbelieve that OSS should be a component of ehe Companies ESP, or factored into our decision in this proceeding. Tntervenors cannot have it both ways: they cannot request that 055 margins be ^a'edtted against the fuel costs (i.e., offset the expenses); and, at the same time, ask us to count the OSS margins as earnings for purposes of the significantly excessive earnings test (SEET) calculation 48 -18- 0$-917-EL.-SSO andll8-918-ELSSO (c} Altr^nate Ener Portfolio Standards ir^t'lu i Renewable ner Credt ro ^ Sectioz-t 4928.64, Revised Code, establishes alternative energy portfolio standards which consist of requireznents for both renewable energy and advanced energy resources. Section 4928.64(B)(2), Revised Code, introduces specific arnnual benchmaxks for rene•rrable energy resources and solar energy resources beginning in 2009. '1'luu Companies' FSP application included, as a part of the FAC costs, rec^erY ^ for renewable e.nergy purchases and renewable energy credits (RF^} F power reflected in Account 555 and RECs reflected in Account 557 (Cos. Ex l^d f 7,2009. ^a^ Tiie Companies stated that they plan to purchase almost all of the R.ECs requ 1'he Companies further state that they will enter iuito renewable energy p agreenents (RP1'As) to meet compliance requirements for the remainder of the ESP period, for wlvch they have already conducted a tequest for proposal (Cos. F.^c. 9 at 10-11}. 'I'he Companies also recognized that reeovery of such costs to comply with 5es'tion 4923.64(j3), Revised Code, is, as stated in the statute,avoidable. Therefore, the Companies explained that they intend to include alI of the renewable energy costa within the FAC mechanism and not as part of any FAC deferral. '['he Companies, however, recognized that their request for proposal and procurement practices for renewable energy wiIl be subject to a prudency review and the renewable purchases subject to a financial audit (Cos. Br. at 96-98). sa concern with the Coitrpanies' plan to include Staff and OPAE/Al'AC cxpre renewable energy purchases and REC.s as a coinponent of the FAC mechanism (Staff Ex. 4 at 6-7; Staff Br. at 4-5; OPAPs/ APAC Br. at 11). The Comnvssion notes that the renewable energy purchases and RECs requirements are based on Section 4928.64(E), Revised Code, and any recovery of such costs is, as the statute provides, bypassable. With the Companies recognition that such costs must be accounted for separately from fuel costs, and is not to be deferred, the Commission finds that Staff s and UPAE/.i1PAC's issue is adequately addressed. Accordingly, with that clarificati.on, the C°rrunission finds that this aspect of the Companies' ESp application is reasanable and should be adopted. 2. pAC Baseline The Companies proposed establislung a baseline FAC rate by identifying the FAC components of the current SSO. The Companie.s started with the $FC rates that were of unbundled as part of the electric transltion plan (EFP) proceedings (those in effect as October 5,19W) (step #1), and then added calendar year 1999 amounts for the additional fuel, purchased power, and environmental a.ccounts that are included In the requested 49 -]9- 08-917-E'L-SSd and Q8-918-Ei, SS(? FAC mechanisrn for this proceeding (1999 data from FERC poriu 1 and other f'rnaneia.l records were used as the base period for the additional components that were not in the frozen EFC rates) (step #2) (Cos. Bu. 7 at 8). The Companies then adjusted the 1999 firozen EFC rates (step #I) and the 1999-level rates developed for the additional components (step #2) for subsequent rate changes (step #3) to get the base FAC cocnpon:eztt that is equal to the fuel-related costs presently embedded in the Companies' most recent SSC) (i.e., the RSP) (Id.). The subseguent rate changes that occurred during the RSP period and reflected in step #3 of the Companies' calculation included annual increases of 7 percent for OP and 3 percent for C.SP, an increase in CSP's generation rate.s for 2007 by approximately 4.43 percent tbrough the Power Acquisition Rider, and a reduction in C3P's base period xAC rate by the amount of the Gavin Cap and mine investment shutdown cost recovery component 4hat was in QP's 1999 EFC rate given that the Regulatory Asset Charge (RAC) established in the E'I'P case expired (Id. at 9). Staff argued that the actual costs should be used in determining the FAC base.line arnd, therefore, recommended using 2007 actual data, escalated by 3 percent for CSP and 7 OF, as a reasonable proxy for 2008 (Staff fix. 10 at 3-4). Staff explained that percent for utilizing actual 2007 costs and updating them to 2009 is appropriate given that the m resulting amounts should be the costs that the Companies roduces a resultgthat fuel-related costs.(Id.). Additionally, Staff notes that thi.s P Posal p close to the result produced by utilizing the Companies' methodolog3' (Staff Br. at is very the use of 2008 actual fuel costs to establish the FAC baseline, QCC recommeiided (OCC Tsc.10 at 21- will be reeonciled to actual costs in the future FAC proceeding which esta too itness testified that her concern is that if the FA^ob^ s^ I be established too 14). OCC's w ( low, the base portion of the generation rates the non-FACopposed thepo "Cornpanies') use of 7999 high ((7CC Px.10 at 13). In its Brief, OPAE/APAC rates as the baseline atd seems to snpport C}CC's recanune.ndation to use 2008 fuel costs Companies' responded by explaining that they did not (©PAE/APAC Br. at 11-12). The use 1999 rates as the baseline, rather the 1999 level was just the starting point to Cos. Reply ft at 21). The Companies also stated that a variable calculating the baseline ( baseline was not appropriate as it would result in a variable tton-FAC generation rate as well since the non-FAC component of the current generation SSO was detertnined to be the residual after subtracting out the FAC component (Id.). As noted by OCC's vitne5s, the 2008 actual fuel costs were not lcnown at the time of the hearing (()CC Ex. 10 at 24). Thus, the Companies and Staff proposed methodologies to obtain a proxy for 2006 fuel costs. While both had a different startnt$ point to the calculation of the 2008 proxy, we agree that in the absence of known actual is appropriate to establish a baseline. Therefore, based on the evidence costs, a proxy presented, we agree with 5taff's resulting value as the appropriate FAC baseline. 50 08-917-LL-SSO and 08-918-15.,-85Q 3. PAC?rrals The Companies proposed to mitigate the rate impact on custolners of any FAC increases by phasing in their new FSP rates by defenting a portion af the annual incremental FAC costs during the F5P (Cos. App. at 4-5; Cos. Ex. 3 at 11; Cos. Ex.1 at 13- 15). The amount of the increznentai FAC expense that would be recovered from customers would be liraited so that total bill increases would not be more than 15 percent f or each of the ttuee years of the E9I' (ld.). The 15 percent target for FEiC does not iniclude cost increases associated with the transmission cost recovery rider (TM) or "'itt' any new goverLuiient mandates (the Companies' could apply to the Commission for recovery of cost.y incurred in conjlmction with compliance of new goveriunent mandates, including any Commission rules imposed a#ter the filing of the AEP-Chio application (Cos. App, at 6)). The Companies prciposed to periodically reconcile the FAC to actual costs, subject to the maximum phase-in rates (Cos. Ex. I at 14-15)- Under the Compaiv.es' proposal, any incremental FAC expense that exceeds the znaximum rate levels will be deferred. The Companies project the deferrals under the proposed BSP to be $146 million by Decetnlrer 31, 2011 for CSP and $554 miltion by December 31, 2011 for OP (Cos. Ex, 6, 8xhikrit LVA- 1). If the projected FAC expense in a given period is less than the maximam phase-in FfS.C rates, the Cornpareies proposed to give the Commission the option of charging the customer the actual FAC expezuse amount or increasing the FAC rates up to the maximum levels in order to reduce any existing deferred PAC expestse balance (Id.). Any deferred PAC expense remaining at the end of 2011 would be recovered, with a canying cost at the Weighted Average Cost of Capitat (WACC), as an unavoidable surcharge from 2(T12 to 2018 (id.). As noted previously, Staff, OCC, and Sierra support ihe FAC mechanism thatwiB be updated and reconciled cluarterly (Staff. Ex. 8 at 34; OCC Ex. at 11 at 4,5, 31,40; oCEA Br. at 47-48, 67-68). Staff, f3CC, and Sierra, however, oppose the creation of any Iong-term deferrals for fuel costs (Staff Ex. 10 at 5; OCFA Br. at 62). Sirnilarly, the Commercial recommended that "customers pay the fuI1 cost of fuel during the E5I'" Group (Comunercial Group Ex. I at 9). Constellation argued that the deferral proposal should be rejected because it masks the true cost of the £+SP generatio rr deferrals have effect nies artificially suppressing conservation, the carrying costs proposed by the Compa would be set at the Com.panies cost of capital, which would include equity, and cteferrecl ar-nounts (instead, customers customers do not want to pay interest on any would ratller pay when the costs are incurred so as to not pay the interest) (Constellation Br. at 8-9). Tbe Scbools also questioned the need for the phase-in of rates, as well as the avoiciability of the surclrarge that would be created to collect the deferred fuel costs, vdth carrying charges, from 2012 to 2018 (Schools Br. at 3). 51 08-917-EL-SS0 and 08-918-E1,-SSt? If the Conunission, however, authorizes such deferrals to levelize rates during the ESp period, St•aff, OCC, and Sierra believe that the deferrals shouTd be short-term deferrals that do not extend beyond the ESP period (Staff Ex. 10 at 5; OCEA Bn at 62). TEU also supports the use of a phase-in to stabilize rates, but does not believe that Section 4928.144, Revised Code, allows the deferrals to extend beyond the TsSP term (IEU Br. at 27-29). of WACC, staling that such an Furthermore, C)CC opposed the Companies' nse approach is not reasonable and results in excessive payments by customers (t7CC Fx.10 at 34). Through testimony, oCC asserts that the carrying charges on deferrals should be based on the current long-term coat of debt ({lCC Ex.14 at 34-35; Tr. Vol. VI at 157158). However, in its joint brief, OCC seems to have modified its position and is now arguing that the carrying charges should be calculated to reflect the short-term actual cost of debt, excluding equity (C)CEA Br. at 62). In reliance on QCC's testimony, Constellation submi.ts that it is appropriate to use the long-term cost of debt (Constellation fir, at 8). The Commercial Group also opposed the use of WACC; instead, Commercial Gxoup witness '-in deferrals entirely Corman recomntended that the Companies finance the FAC phase. with short teran debt given that the accruals are a temporary investment and not long- term capital (Conumercial Group Ex.1 at 9-11). Additionally, the Commercial Group and OCC argued that the deferred fuel expenses should be calculated to reflect the net of applicable deferred income taxes (Commercial Group Ex.1 at 9-10; OCEA Dr. at 63)• CoznYnercial Group witness Gorman testified that if a company does not recover the fuel expense in the year that it was incurred, the company will reduce its current tax expense and record a deferred tax obligation. The deferred tax obligation would then represent a temporary recovery of the fuel expense via a reduction to the current income tax expense (Commercial Group Ex. l at 10). Conunercial Group vvitness Gorman then goes on to recognize that the income tax will ultimatety have to be paid after the incremental fuel cost is recovered from customers, but states that, while deferred, the company will partially recover its deferred fuel balance through the reduced income tax eapense (ld.). 'fo bolster their argument that deferred fuel expenses should be calculated on a net-of-tax basis, OCC and Sierra relied, in their brief, on a witness' testimony in an unrelated proceed`utg, which has been eujrsequently withdrawn as explained above. Neither OCC nor Sierra offered any record evidence to support its positior4 ACP-Ottio, on the other hand, argued that the calculation of carryi.ng charges for the deferrals should not be done on a net-of-tax basis. AEP-(7hio witatess Assante testified that l€rniting the application of the carrying cost rate to a net-of-tax balance of PAC deferrals improperly utilizes a traditional cost-of-service ratemaking approach in a generation pricing proceeding (Tr. Vol. IV at 158-160). Additionally, whfle the Companies proposed the phase-in proposal to help n-vitigate increases and believe that their proposal 52 -22- Q8-917-EL-5sO and 08-918-kLSSO is reasonable, in light of the opposition received from several parties, the Companies stated that they would accept a modification to their ESP that eluninated such deferrals (Cos. Repfy Br. at 41-42). To enswe rate or price stability for consumers, Section 4928,144, Revised Code, authorizes the Gommission to order any just and reasonable phase-in of any electric utility rate or price established pursuant to 4928.143, Revised Code, with carrying charges, through the creation of regulatory assets. Section 4928.144, Revised Code, also mandstes that any deferrals associated with the phase-in authorized by the Coinrnission sshall be collected through an unavo3dable surcharge. Section 4928.144, Revised Code, does s.tot, however, limit the time period of the phase-in or the recovery of the deferrals created by the phast-in througli the unavoidable surcharge. Contrary to OCC and others7 we believe that a phase-in of the increases is necessary to ensure rate or price stability and to rnitigate the impact on eustomers during this diffic:tilt economic period, even with the modifications to the PSF that we have made hereiir. To this end, the Commission appreciates the Companies' recognition that over 15 percent rate increases on customers' bi2ls would cause a severe hax`dship on customera. Nonctheless, given the current econo ac we ^^ise our auPh n^ty pursuant proposed by the Companies is toa high. . to 5ectiozl 4928.144, Revised Code, and find that the Companiea should phase-in any authorized iricrea.4es so as not to exceed, on a total bill basis, an increase of 7petcent for CSP and Spercent for OP for 2009, an increase of 6percent for CSP and 7percent for OP for 2010, and an increase of 6percent for CSP and 8percent for OP for 2011 are more appropriate levels. Based on the applicatimy as modified herein, the resulting i"creases amount to approximate overall average generation rates of 5.47 cents/kVJh and. 4.29 cents/kWh for CSP and OP, respectiveiy in 2009; 6.07 cents/kWh and 4.75 cents/kWh for CSP and OF, respectively, in 2010; and 6:31 cPnts/ktNh and 5.31 cer:ts/kWh for CS17' and CQP, respectively, in 2011. Any amount over the allowable total bill increase percentage ievels will be deferred pursnant to Section 4928.144, Revised Code, with carrying costs. If the PAC expense in a given period is less than the maxintum phase-in FAC rate established herein, the Companies shall begin amortization of the prior defex-red FAC balance a=ad increase the FAC rates up to the maximum levels allowed to reduce any existing deferred FAC expense balance, including carrying costs. As required by Section 4928.144, R.evised Code, any deferred FAC expeiue balance remaining at the end of 2011 shall be recovesed 7 See, e.g., pCC Reply Bx. at 45-467 ConsteIlatiozi Br. at 6-9. belie#' B IJutrierous letters filed in the docket bp various custolnexs cmf'rm our 53 -23- 0&-917-EL-SSC) and 08-918-EL-SSO via an unavoidable surcharge. We believe that this approach balances otu objectives of yeax with litttiting the total bill increases that customers will be charged in any one minirtmizing the deferrals and carrying charges collected from customeis. Based on the record in this proceeding, we do not find the intervenors' azguniertts concerning the calculation of the carrying charges persuasive. Instead, for purposes of a phase-in approach in which.t3te Cornpan'tes are expected to carry the fuel expenses electxic service already provided to the customers,9 we find that the incurred for Companies have met their burden of demonstrating that the carrying cost rate calculated based on the WACC is reasonable as proposed by the Cnmpanies. As explained previously, Section 4929144, Revised Code, provides the Cornml.'tsfon with discretion regarding the creation and duration of the phase-in of a rate or price established pursuant to Sectirms 4928.141 through 4928.143, Revised Code. The Cocnnn-dssion is not convinced by arguments that limit the collection of the deferrals to the term of the ESP. Limiting the phase-nL to the term of the P.SP may not enaure rate or price stability for consutners w'stttict that three-year period and may create excessive increases, wluch may defeat the purpose for estab9iskvng a phase in. The lindtation of any deferrals to the '6SP term may alsa negate the cap established by the Conurtission herein to provide stability tO consutnere. Therefore, we find that the collection of any deferrals, with carrying costs, created by the phasrin that are remauzing at the end of the EST' term shall occur from 2012 to 201& as necessary to recover the actual fuel expenses incurred plus carrying costs. Regarding C3CC's, 5ierra's, and the Carnmercial Group`s recamtnend^tio a ns^ af-tax tax deductibility of the debt rate be reflected in. the carrying chaz'ges basis,10 we have recentiy explained that this recomrnendation accounts for the deductibility of the debt rate, but does not acconnt for the fact that the revenaes coliected are tixable?1 If we were to adopt the net-of-tax recommendation, the Companies would not recover the fu.ll carrying charges on the authorized deferrals. We believe that this outcome would be inconsistent with the explicit directive of Section 4928.144, Revised 9 We agree with the Companies that this deas3on is consistent with our decision in the recentTCfiR and accounttng cases with regard to the calculation baeed on the long-term cost of debt See In re Cuittmbue ^^ Pomer Cor+tpany, Case No. 08.1202-EL-tTNC, and Sout7tern Porer Cornpany and Ohio ern Power C^^op^uvtee'^ ehrbeiiev tha (Decen7 her 17, 200t3) and In re CaCnrnbus Souti C n^'ith zegard to the 13©2-EL-UNC, Finding and Order (December 19, 2008). equity componenk these cases are distingssahable from the current F.57P prtoce.di:xg, wbew we uc establishing the stnndard 5ervice offer and requiring the Coaqanies ta defer ttte colteciiore of incurred generation costs associatcv3 with fuel over a tonger period. We also believe that thxs decision'' reasonable in light of our redu4tion to the Companies' pxop^ ed f^ FC^^ ^o ^^^^^wasa odiert^se effect of requirung the Companies to defer a higher pemen g proposed. 10 OCEA Br, at 63-64; Conwtercial Group Ex. I at 9-10. Tolerfo Edfson Co., Case No. 07-551-EI-AIR, et Tn m Ohio Edisun Co., The Clrts7und Electric Itiumirtuting Co.. ai., Opixlion atid Order at YO (January 21, 2009)- 54 -24- 08-917-EL-SSo and 08-918-EL-SSU Code: "If the conzmissiori s order includes such a phase-in, the order also shall provide for the creation of regulatory assets pursuant to generally accepted accounting principles, by authorizing the deferral of incurred costs equal to the amount not collected, plus carrying charges on that amount" Therefore, we find that the carrying charges on the should be calculated on a gross-of-tax rather ttan a net-of-tax basis in order TAC deferrals to ensure that the Companies recover their actual fuel c:xpenses. Accordingly, we modify the deferral provision of the Companies' ESP to lower the overall amount that may be charged to customers in any one year. th t4. incremantal Car in C st for 2001-2,U 8 E viro nental v _arryi.n^_C Cost Rate A coniponent of the non-FAC generation increase is the inccenental, ongoio.g carrying costs associated with envixonmentat investments made dur3ng 2001-2008. The Cocnpanies propose to include, as a part of their ESP, costs direetly r2lated to energy produced or purchased. While the Companies are not proposing to include the recovery of capital carrying costs on environmental capital investments in the FAC, the Companies. an, requesting recovery of carrying charges for the incremental amount of the ei-ivironmental investments made at their generating facilities from 2001 to 2008. The Companies' annual capital carrying costs for the inerenmental 2001-2008 envixonmental investments not currently rc:flected in rates equals $84 million for OP and $26 million for CSP. cumulat vc nviro7nmental capital expenditares for each company mulped by the carrying cost rate. Eacli company's capital expendituses in the k5P are determined by the expenditures made since the staxt of the mar'ket development period as offset by the estimate included in the Companies' xate stabitization plan (RSP) case, Case No. 04-169- EL-l3NC, and the environmental expenditures included in the Coinpanies' adjustments received in ttie RSP 4 Percent Cases;z (Cos. Ex. 7 at 15-17, Exivbits PjN-8, PjN-12). The Companies calculated the carrying cost rate based on levelized invesiment and depreciation over the 25-year iife of the environntenta}. investment. CSP and OF utilized a capital structure of 50 percent cominon equity and 50 percent debt to calculate the carrying charges, asserting that such is consistent with the capital structure as of March 31, 2008, and consistent with the expected capital structure during the 1ySP period. i ''- Short-terin debt mid the Gavin Lease were excluded from OF's capital stnacture. A^ l flhio asserts that such was the process in the RSP 4 Percent Cases. AEP-Obio also argues that, for ratemaking purposes, the Gavin I.ease is considered an operating lease as opposed to a component of rate base. Further, the Companies reason that the WACC incorporated a 10.5 percent RflS as used by the Cornmission in the pTeCeedu'g ta transfer Pawer Conipuny, Case Nos. Q7-123z-t.'t"In'1C, 07-2192- 12 In re Cbinmbus So«flrern Puwer Company and Ohio ZL-L1NC, and 07-1278-E3 -LTIVC (RSP 4 Percent Cases). 55 -23- 08-917-EL-SSO and 08-918-EL-SSO 16-17, MonPower's certified territory to C.SP ([vlonPower Transfer Casc)ts (Cos• Ex• 7 at 19, ahibit PjN-£S, Exhibits PJN-'f0 - PJl`.4-13; Cos, Ex. 7-B at 7). Staff testified that the Companies should be allowed to recover carrying costs as5ociated with capitalized 'uivestinenis tn comply with enviranmental requirements made between 2001-2008 that are not curren.tly reftected in rates (Staff Tvc. 6 at 2, 4-5). Staff confirmed that AFP-Ohio`s estimated revenue increases for incremental carrying costs associated with additional environmental investments in the a.mounts of $26 rt3llton for G5P and $84 miltion for OP are not eturent]y reflected in rates (Id.). OCEA and {7EG oppose the Companies' request for recovery of environmental carrying charges on investrnents made prior to January 1, 2". flFsC contends that the rates in the RSP Case islciuded recovery for environmental capital improvements made through December 31, 2008, as reflected in the RSP 4 Percent Cases. Further, OCEA and OEG argue that SB 221 onty permits the recovery of carrying costs associated with environmental expenditures that are pfvdently incurred and that occur on or after Ex. 10 at 32; January 1, 2009, pursuant to 5ection 4928.143(13)(2)(b), Revised Code (OCEA OEG Ex. 3 at 21). Thus, OCEA reasons that approval of such expenditures necessitates an after-the-fact review, which cannot be cors&idered in this proceeding. OEG, however, is not opposed to the Companies' increases due to environmentat capital additions made after January 1, 2009, in the ESP in accardance with Section 4928.143(B)(2)(b), Revised Code (qliG Hx. 3 at 20). OEG and Kroger argue that the Companies assertion that existuig rates do not reflect environmental carrying costs ignores the Compan3es' non- environmentai investment and the effects of accvtmulated depreciation and, fherefore, according to OEG and Kroger, fails to denlonstrate any net under-recovery of generation costs in total by the Companies (OEty Ex. 3 at 21; ICroger Ex. 1 at 10-11). OCEA and APAC/OPAE agree that the Companies have failed to demonstrate that they lack the earnings to make the cnvironrnental investments (OCEA Ex. 10 at 32; APAC/pPAH Br. at 5-6). assertg that there are several reasons that the Companies' atternpt Further, (JCEA to recover environmental carrying cost during the EST' is unlawfut. DCEA contends that it is retroactive ratemakSngu and Senate Bill 3, which was the gotrexning law from 7A01 to 200, included rate caps pursuant to Section 4928.34(A)(6), Revised Code, and the RSP, applicable to 2006 through 2008, included timitations on the rate increases. Therefore, the .her, t?Cf±A Companies can not collect now for costs incurred during those periods. 1^ua+' Tenitory in Ohio to Nte Columbus Paunr Cornpany's Certif+ctt 13 in the Matter of the Transfer ofMorumgaGsta Southern Pmuar Cmpmn'J, Case No. 05-765-EL-tA+1C. Be1i'f'sl. Co. (195'7), 76bOhio St. 25. 14 Keca Irtdtcstries, 7rac. v. Cincirnucti & Suburbm= 56 08-97.7-EL-SSO and 08-916-Eir33C3 -26- states that allowing for recovery of such environmental carry7ng cosis would also violate the Stipulation and the Commission`s order in the ETP case.15 OCEA argues that, should the Commission allow ABI'-Ohio to recover car'rying costs on enviroztrnental inveatments, the Cosnparnies carrying charges should be based on actual investments m.ade, isot actual and forecasted env"vro.nmental expenditures, and the carrying costs should be adjusted. More speci#icalty, OCEA. recommends that because the Companies failed to provide any support or explanation of the calculation of the property taxes or general and administrative components of the carrying, cost calculatian, the C:oizuiiission should nat grant recovery of these aspects of the Cornpanies request. Additioiiatly, OCEA and IECJ argue that the proposed carrying cost rates do not reflect actual financing for environmental investments, which could impact the calculation of the carrying cost rates (IEU Br. at 21-22, citing IHt3 Ex. 7 at 132133; Tr. VaI. X[ at 111-113; The carrying cost rates, according to IEU and UCEA, should be OCEA 13r. at 71-72). revised to reflect achti-tl financing, including the use of pollution control bonds that have been secured by the Companies (Id-). To support their argament, IEU and OCEA rely on Staff witness Cahaan who testified at the hearing that "if specific finaneing mechanisms can be identified that would be appropriate and applicable to the assets being financed, I see no reason why those shouldn't be specifically used"16 (IEU Br. at 21 22; t7CEA Br, at 72-73). However, Staff witness Cahaan also stated that "CA]t the time when we looked at the carrying cost calculations it seemed reasonabie, given the cost of debt and cost of equity of the company,"17 which is consistent with his prefiIed testimony that said: "I have examui.ed the carrying costs rates provided to Mr. Soliman atYd found them to be re,asonable" (Staff Ex. 20 at 7). (jCgA also recommends that the carrying costs for deferrals of environmental costs be revised to reflect aGtuat short-term cost of debt, as opposed to WACC as proposed by the Companies, and that the calculated carry.ing charges should not be based on the original cost of the environmental investment but at cost minus depreciation. Thus, QCEA argues that the Companies are seeking a return on and a return of their investment as would be the case under traditional ratemakfng, but overstating the depreciation the carrying cost rates, 13.98 percent for OP and component. OCEA also advocates that 14.94 pen;ettt for CSP, are too high in light of the econontic environment at this tinte Finally, 0CEA wges the Comn-dssion to offset the Companies' (OCFA Br. at 73-74). request frn' carrying charges by the Section 199 provision of the Intermal Revenue Code (Section 199). 6ection 199 allows the Companies to take a tax deduction for °qualified production activities income" equal to 6 percent in 2009 and 9 percent in 2010 and Companyfdr Appnrart Application of Cotum6us Southern Pocoer Comparrg aru! Ohio pozoer rg In t7ir Maf tcr of t&e Case N. 99-1729-ES,-EfT' artt149- of T)wir Elrctric Trnnsitiore Plans and far Receipt of Transition Rwenues, 1?30-F[.FsTP, Opinion and Order (5eptemiser 28. 2000). 1s fr, rzot, xn at 237. 77 Id, 57 08-917-$L-,_O and 08-918-EIrSSO -27- thereafter. IEU, OEG, and OCEA request that the Commission adjust the carrying costs for the Section 199 deduction as the Comnlission has found appropriate in the Conmpanies' 07-63 Case1$ andin the FiretF.nergy LP Case. OCEA argues that whi.le Section 4928143(B)(2)(a), Revised Code, allows the Companies to automatically recovet' the cost of federally mandated carbon or energy taxes, which will be passed on to ctLstomers, custoiners should be afforded the benefits of the Section 199 tax deduction (OCEA Br. at 74-75; lEU Br. at 21; lEU Ex.10 at 6; OEG Ex. 3 at 23). 7.2te Companies emphasize that their request for carry.uig costs is for the incremental carrying charges on the 2001-2008 investments that the Companies wlll incur post-January 1, 2009. AEP-Oh.to explainled that the carrying costs themselves are the costs that the Companies will incur after January 1, 2009, and, therefore, the Ccunpanies reason that the "without limitation" language in Section 4928,1.93 I3 2, Revised Cocle, su {p} zts their request (Tr. `Val. XIV at 93, 114). AEP-Ohio stres.ses tl^t Section 4928.143 B 2, Revised Code, is the basis for the carcying cost request as opposed to paxagraph (B}(2)(a) ot Section 4928.143, Revised Code, as OCEA and OEG claim and, therefore, the arguments as to retraactive ratemaking are nxisplaced (Cos. Repiy' Br. at 29,31D). Further, the Cocnpanies insist that 5ection 492$.143(S)(2)(b), Revised Code, supports their request, as the carrying charges are necessary to recover the ongoing cost of investmente in environmental facilities aztd equipment that are esvsential to keep the generation units operating. The Companies assert that the operating costs of their generation units remain ivell below the cost of securing the power on the market (i:os. Ex. 7 B at 7). As to the claims that the carrying costs are overstated, the Companies claim that the levelized depreciation approach used by the Companfes is better for customers than traditional ratema.king given the relative newness of the environmental investments (Tr. Val. V at 55-56; Tr. Vol. VIi at 22-23). The Companies also argue that the Coenpanies' investments in environmental compliance equipment during 2001-2008 were not factored into the rates unbundled in 2000 and capped under the MT' case as atleged, The rate increase approved, as part of the RSP, and the R5P 4 Percent Cases did not, according to the Companies, provide recovery of the carrying coats to be incurred duxing the ESl' (Cos. Fx. 7, Exhibits PJN-8 - PJN-9 and PJN-12). The Companies reply that the period intervenorsl request to adjust carrying eharges for the Section 199 deduction is flawed. AEP-Ohio states that the Section 199 deduLflon is not a reduction to the statutory tax rate used in the WACC, a fact which AEP-C)hio assertshas been recognized by FERC and the Financial Accounting Standards $oard. The Compailses further note that IP,U Vol. Bowser indeed confirmed that Section 199 does not reduce the statutory tax rate (Tr. The Companies also argue, and IEU witness Bowser agreed, that the Xl at 271-273). Section 199 tax deduction is applicable to AEP Corporation as awhole and not to each operating subsidiary. The Companies note, therefore, that any deduction available to Compmty, Case No. 07-63-HGUNC, C3pud.on and 18 Irz re Cblunibus Smitheni Power Cvmpaay mad Ohfo Puwer Order (October 3,2007) (07-63 Cnse), 58 -28- 08-917-EL-SSO and 0£I-918-B1.-SSO tS,Ep-Ohio is reduced if one of the other AEP Corpoxatian operating affiliates is not eligible for the Section 199 deductIon (Cos. Br. 36; Tr. Vol. )Ci at 2b6-267}. Accordingly, the Companies state that P.EP-Ohio has not been able to take the fufl deduction (Tr. Vol. XIV at 115417)- Further, the Companies argue that the intervenors have niisinterpreted the Comniission s decision in the FirstEnergy ESP Case to imply that the Commifision made an adjustment to account for the Section 199 deduction. For these reasons, the Companies request that the Com.rnission reconsider adjustixag carrying charges for the potential Section 199 deduction. Upon review of the record, we agree with Staff that AEPd)hio should be allowed to recover the incremental capital carrying costs that wiU be incurred after January 1, 2009, on past environmental investnients (2001-2008) that are not presently reflected in the Conlpanies' existing rates, as contemplated in. AEF-{?hso s I2SP Case. Further, the CommissSon finds that tis decision regarding tlte rec°verY of continuing carrying costs on environmental iaxvestrnents, based on the WACC, is consistent with our decis9on in the 07-63 Case aild the Rcai' 4 Percent Cases. Aaditioria.lty, we agree with S4riff that the leveiized carrying cost rates proposed by AEP-()hio are reasonable and, therefore, should be approved. We further find, as we concluded in the FirstEriergy ESP Case, that adequate modifications to the Compardes` ESP application have been made in this order to account for the possibility of any applicable Section 199 tax deductions. C. Azunial Non-PAC lncrcases The Companies proposed to increase the non-FAC portion of their generation rates by 3 percent for CSP and 7 percent for OP for each year of the ESP to provide a recovery mechanism for increasing costs retated to matters such as carrying costs associated with new envirorunental investments made during the ESP perlod, increases sn the general scipated, non-mandated generation- costs of providing generation service, and unant' related cost increases. Specifically, as part of this automatic increase, the Companies intend to recover thc carrying costs associated with anticipated environmental investments that wi1l be necessary duxing the E,iP period (2009-2011) (Cas. Br. at 27; Cos. Reply Br. at 46-49). The Companies ar,gued that the annual increases axe not cost-based and are avoidable for those customers who shop. The Companies also proposed two exceptions to the fixed, annual increases, one for generation plant closures and the other for QI''s lease associated with the scrubber at the Gavin Plant, wh'sch would require additional Commission approval during the ESP. After establishing the PAC coznponent of the current generation 580 to get a FAC baseline, the Companies determined that the rernainder of the current generation SSO ivauld be the non-FAC base component. The intervenors oppose automatic annual increases in the non -RAC component of the generation rate, and argue that any generation increases should be cost-based (IEU Br. 59 08-917-EL-SSO and q8-918-ET.-SSO -20^ at 24; OPAE/ APAC Br. at 6; QkiG Br, at 12; C?CEA Dr. 29-31). C3TxG contends that since the Conrpanies have not provided any support for the autornatic annual increases, which could result in total rate increases over the three-year period of $87 million for CSI' and $262 million for OP, the annual increases should be disaIlowed (OEG a. 3 at 18-19); Sirnilar7y, TCroger argues that AF.z"'-{7hio did not appropriately account for costs associated with the non-PAC ccxinponent of the proposed generation rates (Kroger Sr. at 14). Staff opposes C5P's and QP's recorainended annual, non-FAC increases of 3 and 7 percent, respectively (Staff Ex. 10 at 4). Instead, Staff stated that it believes a anore appropriate escalation of the non-FAC. generation component would be half of the proposed amottnts, therefore, recoirunending annual inereases of 1.5 percent for CSP and 3.5 percent for QP (Td.). Staff witness Cahaan rationalized the proposed reduction by stating lhat "an average of 5% for the two companies xnay have been a reasonable expectation of cost increases at the time that the ESP was contenrpiated, but not now. With the recent financial crises, we are entering a recessionary, and possibly a defYationary, per-iod and any expectations of price increases need to be revised downward" (Id.). Furthermore, while recogn{zing that the ultimate balancing of interests lies with the Conunission, Staff witness Cabaan testified that Staff's recommended reduclian in the proposed increases was a reasonable balance between the Companies' obligation and costs to serve cnstomers and the current economic conditions (Tr. V'ol. Xtl at 211). The Companies rejected Staff's rationalization for the reduction in their proposed non-FAC increases (Cos. Reply Br. at 49). FEEU also rejected StafYs rationalization for the xeduction, arguing that no automatic inereases are warranted (fF.U Br. at 24). Stating that it is in the public interest for the Companies to continue investing in environmental equipment and to be in compliance with current and future envirorkrnental requirements, Staff witness Soliman also recommended that AFiI'-Ohio be permi.tted to recover carrying costs for anticipated environmental investments made during the E9P period (Staff Ex. 6 at 5). Staff recommended tlu.3t this recovery occur through a future proceeding upon the request of the Companies for recovery of additional carrying costs associated with actual environmental investn'tent after the investments have been made (Staff Br. at 6-7). Specifica]ly, Staff suggested that the Gommission require the Companies to file an application in 2010 for rocovery of 2009 actual envirorirnental investment cost . and annually thereafter for each succeeding year to reflect actual expenditures (Tr. Vol. XII at 132; Stafl Ex. 10 at 7). OCEA sc.ems to agree with Staff's recommendat3on (OCEA Br. at 71). The Coinpanies further respond that Section 4928.143, Revised Code, does not require that the SSC? price be cost-based and, instead, Section 4928.143(B)(2)(e), Revised Code, authorizes electric utilities to include in their ESP provisions for automatic increases in any component of the 9St} price (Cos. Reply Br. at 48-49). 60 o8-9T7-EL-SSC) and 08-918-EL-S!3O 'I'he Commission finds Staff's approach with re$u'd to the recovery of the carrying costs for an.ticipated environmental investnients made during the k'SP to be reasonabie, artd, therefore, we direct the Companies to request, through an annaal filing, recovery of additional carrying costs after the investments have been nnade. We also agree with Staff that the econorn.ic conditions must be balanced against the Companies provision of electric service under an ESI'. In balancing these two interests, as well as considering all components of the ESI', we believe that it is appropriate to modify this provision of the Companies' PSP and remove the indusion of any automatic non-FAC increases. As recognized by several irttervenors, the record is void of sufficient support to rationaliEe automatic, annuaI generation increases that are not cost-based, but that are significant, equaling approximately $87 nullzon for C.9P and $262 million for OP (see, i.e., OCEA Br. at 29-30, citing Tr. VoI. XIV at 208-209). We also befieve the moctification is warranted in light of the fact that we have removed one of the Cornpanies' significant costs factored into establishing the proposed automatic increases. Accordingly, we find that the F',SP should be modified to elimitiate any automatic increases in the non-1^AC portion of the Companies' generation rates. IV. DIS'TTtCBUTION A. Annual I?istribution Increases To support initiatives.to improve the Companies' distribution system and service to customers, the Companies proposed the foIlowing two plans, which wiil result in annual distribution rate increases of 7 pereent for CSP and 6•5 percent for OP: 1. hnfiancecl Servira Reliability Plan fESRI'] The Companies proposed to implement a new, three-year ESRP pursuant to 4928.143(B)(2)(h), ftevised Code,19 which includes an enhanced vegetation initiative, an enhanced underground cable initiative, a distribution automation initiative, and an enhanced overhead inspection and rnitigation initiative (Cos. Ex. 11 at 3). While noting that they are providing adequate and reliable electric service, the Cotnpanies Jastify the need for the 1;SRP by stating that customers` service reliability expectations are in+u'easing, and in order to maintain and enhance reliability, the ESRP is -equired (Id, at 3, 8,10-14). consisting of the four reliability ASI'-Ohio further states that the three-year ESRP, tW sirppark their 19 On page 72 of its brief, the Companies rely on Section 4928.154(B)(2)(h), Revised Code, for the incrementat casts of the incrementat ESRP atltvities• We are request to receive cost recovery error and that the Companies inlYnded to cite to as.su¢ting that the reference wfls a typographiral Section 4928.143(B)(2)(h), Revised Code (sea Cos. RepSy Br. at 50-51). 61 -31- 0$-917-SL-S50 and 08-418 EL-SSO distribution progranrs, is designed to moderniae and improve the Companirs' infrastructure (ld.). (a) Fnhanred veatatlozr initiative The Coinpanies state that the purpose of this new initiative is tr, im.prove the customer's overall service experience by reducing and/or eliminatini; momentary interruptions and/or sn..stained outages caused by vegetation. The Companies proposed to accomplish this goa! by balancing its performance-based approach to reflect a greater consideration of cycle-based factors (id, at 26-28). The Companies state that under their proposed vegetation initiative, they will employ additional a'esources (approxhI3ately , greater emphasis on cycle- double the current number of tree crews in t3hto), ennploy based planning and scheduling, increase the level of vegetation management work performed so that aIl distribution rights-of-way caa be inspected and znain^ end, and utiii.7.e improved technoiogies to collect tree inventory data to opiirnize p g and scheduling by predicting problemareas before outages occur (Id. at 28-29). (b) Eniranced ucjderpround cable irlitiative The Companies state that the purpose of this initiative is to reduce momentary interruptions and sustained outages due to failures of aging under'gro'zud cable. The CornpanieW plan to target underground cables manufactured prior to 1992 to replace and/or restore the integrity of the cable insulation (Id. at 31). (c) T^' bri.bution automation (DA) initiative The Compan.ies explain that t).A is a, critical component of their proposed l,rridSMART distribution initiative that is described below. DA is an advanced technology that improves service reliability by minimiaiag, quickly identifying and rsolaftg faulted distribution line sections, and remotely restoring service interruptions (ld. at 34-35). (d) Enhanced overhead ins ection and miti *ation iniiiative The C.ompanies state that the purpose of this initiative is to improve the customer's overall service experience by reducing equipment-related mowentary interruptions and sustained outages. "I'1'.e : ompanies iritend to accompiish this goal through a coniprehensive overhead inspection pxocess that wilt proactively identify equipment thadfi is prone to fail (Id. at 18). ':Che Companies also state that the new program w^ go bey the current inspection program required by the electric service and safety (F^) rules, is a basic visual assessment of the general condition of the distribution facilittes, by whfch conducting a comprehensive inspection of the eyuiprnent on each structure via walking the circuit lines and physically climbing or using a bucket track to inspect (Td.. at 19). Irt conjunction with this program, AEP-Ohio proposes to focus on five targebed overhead 62 -32- tl$-917-EL-SS© and 08-918-EL-SSt3 asset initiatives, including cutout replacement, arre.ster replacement, rectoser replacement, 34.5 k.V protection, and fauit indicatar (id. at 2(1-22). Generally, nuxnerous i.ntexvenors and Staff opposed the distributian?nitiatives and cost recovery of such initiatives tiuough this proceeding. Many parties advocated for deferral of these distribution initiatives, and the ESRP as a whole, for consideration in a future distribution base rate case (Staff Br. at 7; Staff Ex.1 at 6-7; OPAEJAPAC at 1,9; IEU Br. at 25-26; Kroger Br. at 18; 01-IA Br, at 17; OMA Br. at 6). Further, OCEA argued that the Comparues have not demonstrated that the 'ESRI' is incremental to what the Companies are required to do and spend under the current ESSS rules and current distribution, rates (OCEA Br. at 44; CK:C Ex. 13 at $-11). t/V1tile supporting several aspects of the Companies' ESRP programs, Staff lviiaiess Roberts also questioned the incremental 70-77). nature of the proposed ts,SRP programs (Staff Ex. 2 at 46,13,17,18; Tr. Vol. ULEi at The Conunission agrees, iii part, with Staff and the inten+enors, The Conunission recognizes that Seckion 4928.143(I3}(2)(h), Revised Code, authorizes the Companies to include in its ESP provisions regarding single-issue ratemaking for di.etribtttion infrastructure and modernization incentives. However, wlule SB 221 may have allowed Companies to itulude such provisions in its ESP, the zntent could not have been to provide a'blank check' to electric utitities. In deciding whether to approve an. ESP that contains provisions for distribution in.frastructare and modexnization incentives, Section I 4928.143(B)(2)(h), Revised Code, specificaliy requires the Comnission to examine the reliabiJity of the electric utility's distribution system and ensiue that customers' and the electric utilities' expectations are aligned, and to ensure that the electric utility is emphasizing and dedicating sufficient resources to the reTiability of its distribution system, Given AEP-Ohio's proposed ESRP, the only way to examine the full distribution system, the reliability of such systetn, and custorners' expectations, as well as whether the programs proposed by AEP-Ohio are "enhanced" inifiiatives (truly incremental), is through a di.stribution rate case where aI1 components of distribution rates axe subject to xeview. Therefore, at this time, the Cot'sunission denies the Companies' reques-t to impternent, as well as recover costs associated therewith, the enhanced underground cable initiative, the distribution automation initiative; and the enhanced overhead inspection and mitigation initiative. Witli regard to these issues, we coricur wi'th OHAt "The recard in thfs case reflects the fact that the distribution prong of AEI''s electric service deserves further Comrnission scrutiny - but not in tlLe context of this accelerated ESI' proceeding" (OHA Br. at 17). Nonetheless, the Comnmission finds that AEP-Ohio has demonstrated in the record of this proceeding that it faces increased costs for vegetation management and that a specif.ic need exists for the imp2ementation of the enhanced vegetation initiative, as pxoposed as part of the three-year ESRI', to support an incremental level of reliability ac^ivities in order to maintain and improve service levels. 'tlre Companies' current 63 48-417 CL-5SC1 and flB-918-E1rsSMM approach to its vegetation management program is mostly reactive (Staff Ex. 2 at 10). Wlule we recognize the difficulties that recent events have caused, we believe that it is important to havc a balanced approach that not onJy reacts to certain incidents and problems, but that also proactively limits or reduces the impact of weather events or incidents. In addition to reacting to problems Ihat occur, it is imperative that A8P-Olu.o implem.e,nts a cycle-based approach to maintain the overall system. To tlvs end, the Companies &ave demonstrated in the record that inc-reased spending earmarked for specific vegetation initiatives can reduce tree-caused outages, resulting in bettet'relia'bility (Cos. px. 21 at 27-31). UCC witness Cleaver also recognized a problem with the cu-rrent vegetation management program, and supported the adoption of a new, llybrid approach that incorporates a cycle-based tree-trimming program with a performance-based program ((3CC Ex. 13 at 30, 35). Staff witness Roberts further suppor°ted the move to a new, four-year cycle-based approach and reeonunen.ded that the enhanced vegetation initiative include the foIlowing: end-to-end circuit rights-of-way inspections and maintenance; mid-point circuit inspections to review vegetation clearance from conductors, equipment, and facilities; greater clearance of all overhang above three•plrase pr3rnary lines and single-phase lines; removal of danger trees located outside of rights-of- ways where property owner's peimission can be secured, and using technology to collect tree inventory ciata to optirnize planning and scheduling (Staff Ex. 2 at 13). The Cammission is satisfied that the Comparues have demonstrafied in the record that the costs associated with the proposed vegetation initiative, irncluded as part of the proposed three-year ESRP, are incrementai to the current D3stribution lregetation Management program and the costs embedded in distribution rates (Cos. b'ac. 73. aE 26-31). SpecificaIly, the Companies proposed to employ additional resources in Ohio, place a greater emphasis on cycle-based plaruung and 5chedu}ing, and increase the level of vegetation management work performed (Fd. at 28-29), Although OCCs witness questions the incremental nature of the costs proposed to be included in the enhalueed vegetation initiative, t3C;C offered no evidence that the proposed initiative is already included in the cnirent vegetation management program, and thus, is not incremental (t3CC Lx.13 at 30-36). Rather, CCC seems to quibble with the definition of "enhanced." OCC witness Cleaver stated: "I recommend that the Commission rule that the Company's proposed Vegetation Management Programs, while an improvement over its curmit addifional tree performance based program, is not an eniamurmerzf but rather a reflection of trinuning needed as a result of their prior program" (Id. at 35 (etatiphasis added)). Furthermore, we believe that the. record clearly reflects customers' expectations as to tree- caused outages, service interruptions, and reliability of customers` service.20 We also believe that, presently, those custotner expectations are not aligned with the Companies' expectations. However, as required by Section 4928.143(B)(2)(h), Revised. Code, we believe that the Compardes' proposal for a new vegetation initiative mare closely ali,gns 20 A common theme front the customers throughout the locai public hearings was that outetges due to vebetation have been problemaHc. 64 08-917-EL-SSO and 08-918-1ri.-S50 the customers' expectations with the Companies' expectations as it relates to tree-caused outages, irnportaru:e of reliability, and the increasing frctstration sun•ounding momenkary outages with the emergence of new technol.ogy. Accordingly, in balancing the customers' expectations and needs with the issues raised by several intervenoxs, the Commission finds that the enhanced vegetation initiative proposed by the Companies, with Staff's additional recommendations, is a reasonable program that will advance the state policy. To this end, the Commission approves the establishment of an FSRP rider as the appropriate meehanism pursuant to Section 4928.143(B)(2)(h), Revised Code, to recover such costs. The ESRP rider initially wIll include os-dy the incremental costs associated with the Gompanies proposed ^c.11 at 91, Chart 7) as set forth herein. Consiatent enhanced vegetation initiative (Cos. E. with prior decisions,21 the Conunission a4so believes that, pursuant to the sound policy goals of Section 4928.02, Revised Code, a distribution rider established pursuant to 8ection 4928.143(B)(2)(h), Revised Code, should be based upon the electric utility's prudently incurred costs. Therefore, the E9RP rider will be subject to Commission review and reconciliation on an anmual basis, As for the recovery of any costs associated with the Companies' remaining initiatives (i.e., enhaticed underground cable initiative, distribution automation initiative, and entianced overhead 'uvspection and ntitigation initiative), the ESRP rider wiIl not include costs for any of these programs iintil sneh time as the Commission has reviewed the programs, and associated costs, in conjunction wlth the current distribution system in the context of a distribution rate case as explained above. If the Commission, in a sub.sequent proceeding, detennines that the programs regarding the rernaining initiatives should be implemented, and thns, the associabed costs should be recovered, those costs ntay, at that tiine, be included in the PSI21' rider for future recovery, subject to reconciliation as di,scussed above. 2. Grid9MART The Companies propose, as part of their Fa"P, to initiate Phase 1 of gridSMAItT, a three-year pilot, in northeast central Ohia. GridSMART will include three main cocnponents, AMI, DA, and Home Area Network (HAN). The AMI system features inclu.de smart meters, two-way communicatians networks, and the infdz•rnation technology systeuls to support system interaction. AEP-Ohio contends that AMl rvill use iateznal commurdcations systems to convey real-tiane c:nergy usage and load irsfornaation to both the customer and the company. Acarrding to the Companies, AMI will provide the capability to rnonitor equipment and convey information about certain cnalfunctions and operating conditions. DA will provide real-time control and rnonitorlttg of seler-t 711uminating Co., Toledo Edieon Co., Case No. 08-935-GtrSSO, 21 Sn re Ohia Edisan Gn., 77 e Ckcreinn t Fleefrr•c Opinion and Order at 41 (llecember 19, 2008). 65 08-427-EI.-SSC) aztid 08-418-EI.-55C7 electrical components with the distribution system, hiduding capacitor banks, voltage regulators, reclosers, and automated line switches. HAN will be installed in the customer's home or business and wi]I provide the customer with uiforntation to allow the customer to conserve energy. I-IAN inclerdes providing residential and business custome.rs who have centraf air conditioning with a programmable cornmunicating thermostat (PCT) and a load control switch (LCS), which is installed ahead of a major electrical appTiance and wiil tu.rn the appliance on and off or cycle the appliance on and off. AEP-Ohio reasorw that centrai air conditioners are typically the largest piece of electrical equipment in the home and w'sll yield the most significant demand response benefit (Tr. Vol. III at 304). LCS will provide customers who have a direct load control or interruptible tariff the ability to receive cornmands from the meter and the option to respond and signat the appropriate action to the meter for confirination. The Companies propose a phased-in implementation of Phase 1 gridSMAR`.C to approximately 110,000 meters and 70 distribution circuits in an approximately 100 square mile area within CSI"''s eS further service territory (Cos. :Ex. 4 at 5,12-13; Tr. Vol. IlI at 9{I3-304)• '1'he Compan► propose to extend the inatallation of I)A to 20 zircuits in ar'eas beyond the gridSMART Phase 1 program. 'I'he Companies propose a phased-in approach to fiztly implement gridS[v1AF.T throughout their service area over the next 7 to 10 years, if granted appropriate regulatory treatment. The Companies estimate the net cost of gridSMAItT of $2.7 Phase 1 to be approximately $109 million (including the projected net savings million) over the three-year period (Cos. Ex. 4 at 15-16, KLS-1). The rate design for .ric1SMART includes the projected cost of the program over the life of the exluipment. The Companies ltave requested recovery during the ESP of only the costs to be incurred the three-year term of the E5P (Cos. F.x. l at DNIIt-4). Thus, AEI'-Ohio asserts that during it is inappropriate to consider the long-term operational cost savings when the long-term costs of gridSMAR'r have not been included in the ESI' for recovery. Although Staff generally supports the Companies' implementation of gridSlvIART, particularly the AMI and DA components, Staff raises a few concerns with this aspect of the Conipanies' fiSI7 application. Staff is concerned that the overhead costs for meter purchasing is overstated and recommends that the overhead costs be reviewed before approval to ensure that the costs are not duplicativez of the overhead meter purchasing costs currently recovered in the Coiiipanies' rates (Staff Ex. 3 at 3). Staff argues that there is no reason for the Companies to restrict the PCTs to customers with air conditioning to any customer that desires to own this only, and recommends that the device be offered type of thernlostat to control air conditioning or otl3er electricad appliances (_^taff Z3r, at 12). Staff and C)CC also argue that customers who have invested in advanced technological equipment for gridSrirIART will not benefit from dynamic pricing and time differentiated rates if the Companies do not sirnultaneously file tariffs for such services (Staff Ex. 3 at 5; OCEA Br. at 82). Staff reeoznmenda that the Companies offer some form of a critical peak pricing rebate for residential customers, and some form of hedged price for cotnmercial customers for a fixed amount of the custvmers demand (Staff Ex. 3 at 5). 66 0&-917-EL-SSO and 08-918-EL-SSO Further, Staff argues that the Companies' gridSMART' proposal does not contain sufficient infortnation regarding any risk-sharing between the ratepayers and shareholders, operational savings, or a cost/benefit analysis, and states that AEP-OJltio did not quantify any customer or societal benefits of the proposed gridSMART irritiative Br. at 12-13). Staff notes fhat accord'vng to the Companies, DA wilt. not be (Staff implemented until 2011, the third year of the ESP, and that the F.9P proposes to install DA beyond the Phase I gridSMART area ('I'r. Vol. III at 246). Staff opposes DA outside of the I'liase I area because the Companies` cannot estimate the expected reliability improvements associated with the installation of DA. Staff also argues that L7A costs should be recovered through a DA rider. The cost of gridSMART, per AEP-Oh.io's proposal, is to be recovered by adjusting distributiorr rates. Staff is opposed to incre.asing distribution rates in this proceeding (Staff Ex. 5 at 6). Instead, Staff recommends that a rider be established and set at zero. The Staff argues that a rider has several bmefits over the proposed increase to distribution rates, including separate accounting for gr3cISIvIART costs, an opportunity to approve and update the pTan annualty, assurance that expenditures are made before cost recovery oceurs, and an opportunity to audit expenditures prior to recovery. Finally, Staff also advocates that the Companies share the financiai risk of gridSMART between ratepayeis and sfiareholders, as there is a benefit to the Companies. Additioru7l.ly, Staff questions whether gridSMART will meet utistitnum reliabiRty standarcls. Lastly, Staff assexts that AFP•Ohio shoald cortduct a study that quantifies both custotner and societal benefits of its gridSMART plan (Staff Sr. at 14). C7CC, Sierra, and OPAE/APAC argue that the Companies ESP fails to denlonstrate that its gridSMAl2'f program is cost-effective as required by Sections 4928.02(I7) and 4928.64(E), Revised Code, and state that AEP-Ohio's assurrtption that the societal and customer benefits are self-evidettt is mispllced (OCBA Br. at 77-80; QPAE/APAC Br: at 17-18). OCC, Sierra, and OPAE/APAC note that there are a number of factors about the program that the Companies have not deterntined or evaiuated, which are essential to the Cornmission's comideration of the plan. OCC, Sierra, and OPAE/APAC state that the Companies have failed to include any fuil gridSIv1ART impletnentation plan or costs, the anticipated life cycle of various components of gridSMAl2T, a rnethodolog,y for evaluating perfonnance of Oc1SMART Phase T, an estimate of a customer s bill savings, or the positive impact to the environrnestt or job creation (OCirA Br. at 79-80; OPAE\APAC Br. at 17-18). Further, CICC's vaihu:ss states that the ESP fails to acknowledge that full systea-t implementation is required before many of the benefits of gridSMART can actually be realized (OCC Bx. 12 at 6). OCC reco.trunends that i'ltase I have its own set of perfortnance measures, a more detailed project plan, inc3uding budget, resottrce allocation, and life cycle operating cost projections for the ful17-70 year implementation period of gridSMA1.2T and beyond, and performance measures for the Comnussion's approval (OCC Sx.12 at 18). 67 0$-917-RI^ SSO and 08-918-EL-SS0 ^7- AEP-Chio regards the Staffs proposal to offer PC"I`s to any customer as overly generous, particularly given that Staff is recommending that the rider be set initiaUy at zero (Cos. Br, at 68-69). AEP-Ohio also submits that it has committed to offering new service tariffs associated witli Phase I of gridSMART once the technology is instaIled and the billing funcrionalities available (Cos. Ex. 1 at 6; Tr. Vol. III at 304-305; Cos. Br. at 68- 69). Further, regarding Staff`s policy of risk-sharing, the Compani.es contend that the assertion that the gridSMA1tT investment benefits CSP just as much as it does customers is not true and, given that the operational savings do not equal or exceed the cost of the argues that program, is without any basis presented in the record. `I'hus, :ATcP-0hio discounting the net cost to be recovered by CSP is unfair and inappropriate (Cos. Reply Br. at 63-64). The Cornpanies are unclear how the Staff expects to determine whether gridSlvIART meets the min.imum reliability standards and contend that this issue was first raised in the 5taff's brief. Nonetheless, the Companies argue that imposing reliability standards as to gridSMART Phase 1 is inappropriate, priniarily because sttict accountability for achieving the expected reiiability impacts does not take into account the many dynamic factors that impact service reliability index performance. Moreover, accurate measurement and verification of the discrete impact of gridS'IVIAR.'C deployment on a particular reliability index would be difficult. The Campanies also explain that the expected reIiability impacts provided to the Staff were based on good faith esfimates of the full implementation of gridSMART Phase 1 as proposed by the Colnpanies. Thus, the Companies would prefer the establishm.ent of deployment project milestones as opposed to specific reliability impact standards. Although the Coinpanies anaintain that their percentage of distribution increase is reasonable and an appropriate part of the EaP package, in recognition of 5taft's prefer.'erue for a distribution ridex and to address various parties' conce,rns regarding the acLurracy of .ABP-Ohio's cost estinlates for gridSMART Phase I, the Companies would agree to a gridSMART Phase I rider set at the 2009 revenue requirement subject to aiuiual true-up and reconciliation based on CSp's prudently incurred net costs (Cos. Reply Br. at 70; Cos. Bx.1, Hxlubit DIvIR-4). The Cotnrnission believes it is important that steps be taken by the electric utilities to explore and implement techntdogies, such as AMI, that will potentially provide long- term benefits to customers and the electric utility. GridSIVIART Phase I wiil provide CSP with beneficial inE'ormation as to ittnplementation, equipment prefaretzces, custoiner expectations, and customer education requirements. A properly desil;ned ^`'tv'Il systes^ and DA can decrease the scope and duration of electric outages. More reliable service is clearly beneficial to CSP's customers. The Commission strongly supports the implementation of AIvfl and DA, with HAN, as we believe these advanced technologies are the foundaflon for AkP-Ohio providing its customers the, ability to bettex manage their energy usage and reduce their energy costs. Thus, we encourage CSP to be more expedient in its efforts to implement these components of gridSMART. While we agree 68 -W 08-917-&L,-SSO and 08-918-EL„SSO informatian is necessary to implement a successful Phase I program, we that additional do not believe that all infonnation is required before the Cornnussion can conclade that the program is beneficial to ratepayers and should be implemented. Therefare, we will rider, as we agree with the Staff that a rider development of a g,xidSMAT(T approve the ates, including has several benefits over the proposed annual increase to distribution r separate accounting for gridSMART, an opportunity to approve and update the plazt each year, assnrance that expenditures are made before cost recovery occurs, and an to audit expenditures prior to recovery. The Cornrrussion notes that recent opportunity federal legislation makes matching funds available to smart grid projects. Accordingly, proposal contained in its proposed. PSi' to recover $109 the Companies' gridSMART million over the tersn of FSP, should be revised to $54.5 million, which is half of the Companies' requested amount. Additionally, we direct CSf to make the necessary filing for federal matching funds under the American Recovery and Reinvestment Act of 20D9 The gridSMAIZT rider shalI for the balance of the projected costs of gridSMA11T Phase 1. established at $33.6 million for the 2009 projected expenses subject to annual be itv.tialiy incurred costs. true-up and teconciliation based on the company's prudently the creation of the EfiRP rider and the gridSMAR'I.' rider, the Cornmission With finds that annual distribution rate increases in the amounts of 7 percent for CSP and 6.5 percent for QP to recover the costs for the FSR.I' and gridSMART programs are utulecessary and should be rejected. Accordingly, the Commis5ion finds that A.kd'-tJhio's rider and the gridSMART rider, as ESP should be modified to include theMRP proposed increases. approved hercin, and to eliminate the aiulual distrihution rate 6. Riders 2. Provider of Last Resort (POLR Rider - 'I'he Companies proposed to include in, their BST' a distribution non-bypassabie POLR rider (Cos. App. at 6-8). The PQLR charge was proposed to collect a POLR revenue reqixirement of $108.2 miilion for CSP and $60.9 million for OP (Cos, Ex, 2-A at 34; Cos. Ex. 1, Fxhibit DMR-5). The Companies stated that they have a statutory obligation to be the POLR,22 and thus, the proposed POLR charge is based on a quantitative artalysis of to the Companies to provide to customers the optionality associated with POLR the cost serv+.ce (Cos. Ex. 2-A at 25-26), AEP-Ohio argued that this charge covers the cost of allowing a customer to remain with the Compasties, or to switch to a Corcipefiitive Petail Electric Service (CRES) provider and then return to the Companies' 990 after shopping (Id.). To further support the proposed increase, the Companies added that their current POLR charge is sigzv.ficantIy below other Ohio electric utilities' POLR charges (Cos• Ex. 2 at 8). The Cnmpanies utilized the Black-Scholes Model to calculate their cost of fulfilling 72 See Section 4428.14I (A) and 4918.14, RevisecI Code. 69 08-917-EL-S.SO and (&91$-i:L-SS0 -39- the POLR obligation, comparing the customers rights to "a series of options on powee (Cos. Br. at 43; Cos. Ex. 2-A at 31). f+EP-C3Iuo listed the five quantitative inputs used in the Black-Scholes Model:1) the market price of the underlying asset; 2) the strike price; 3) the time frame that the option covers; 4) the risk free interest rate; and 5) the volatility of the underlying asset (Id.). The Companies assert that the resultit.ig POLR charge is conserv atively low (Cos. '6r. at 44). The numerous intervenors and Staff opposed the level of POLR charge proposed by the Coinpaaies, as well as the use of the Black-Scholes Model to calculate the I'CfLR charge (OPAE/APAC Br. at 14-17; OCC Ex. 11 at 5-14). 5pecifically, OCC and others questioned the use of the LIBOR rate as the input for the risk-free interest rate (Tr. Vol. X XI at 166-182). Staff questioned the risk that the I'^LR charge at 165-182,188-I89,1'r. Vol. was intended to compensate the Companies for, explaining that there are or,ly two risks involved: one risk is the risk of customers returning to the SvSO and the other risk is that the customers leave and take service fmm a CRES providet' (migration risk) (Staff Ex. 10 at 6). Staff witness Catiaan testified that the risk associated with customers retarning to the SSO could be avoided by requiring the customer ta return at a market price, instead of the SuO rate, which would either be paid directly by the returrning customer or any ir The Companies responded that their risk is not nSleviated by customers agreeing to return aE market price, argusng that future circumstances or policy considerations may require them to retieve customers of their promises to pay market price when circumstances eYrange (Cos. Ex. 2-A at 27-30). AEP-Ohio's witness expressed skepticism as to a fatare Commission upholding such promises (Id). AEp-Ohio also opposed recovering any costs for market purchases incrured for returning customers through the FAC as an improper subsidization of those customers who chose to shop, and then return to the electric utility, by non shopping customere (Cos. Ex. 2-£s at 14-16). Furthermore,'the Companies claim that their risk of being the POL1t exists, regardless of historic or current shopping levels ([d.). Nonetheless, A,EP'writriess Baker testified that, even adopting Staff witness Cahaan's theory that the Companies are only at risk for migration (the right of customers to leave the S50), migratioa risk equals approxinaately 90 pexcent of the Companies' POLR costs pursuant to the Blactk-Scholes model ('Tr. Vol. XIV at 204-205; Cos. Ex. 2-E at15-16). 70 08-917-EL-SSO and 08-918-1iG-S5C} As the POLR, the Commission believes that the Companies do have some risks associated with customers switthing to CRES providers and returning to the electric utility`s SSO rate at the conclusion of CRI;S contracts or during times of rising prices. However, we agree with the intervenors and Staff that tlte POLR charge as proposed by the Coinpanies is too Iligh, but we do not agree that there is no risk or a very minimal risk as suggested by some. As noted by several intervenois and 5taff., the risk of retunung customers may be mitigated, not eliminaled, by requiring customers that switch to an alternative sitpplier (either through a governmental aggregation or individuaI C12ES and pay masket price, if they return to the providers) to agree to return to market price, electric utility after taking service from a CR> S provider, for the remaining period of the ESP term or until the customer switches to another alternative supplier. In exchange for this coannutment, those customers shall avoid paying the POLR charge, We believe that this outcome is consistent with the xequirement in Section 4928.20(J), Revised Code, which allows governmental aggregations to elect not to pay standby service charges, in exchange for agreeing to pay market price for power if they return to the electric utility. Therefore, based on the record before us, we conclude that the Compaaies' proposed BSP should be nlodified such that the POLR xider wfIl be based on the cost to the Companies to be the POI.R and carry the risks associated thexewith, including the migration risk. The Commission accepts the Conrpanies' witxuess' quantification of that risk to ecjua190 percent of the estimated POLR costs,23 and thus, finds that the POLR rider shall be established to collect a I'OLR revenue requirement of $97.4 mitlion for C.SP and $54.8 million for OP. Additionally, the POLR rider shall be avoidable for those customers who shop and agree to return at a market price and pay the market price of power i.ncurred by the Companies to serve the returning customers. Accordingly, the Commission finds that the POLR ride,r, which is avoidable, should be approved as modified herein. 2. Re^ultor,yAssetR3der The Companies proposed to begin the recovery of a variety of regulatory assets that were authorized in various Commission proceedings regarding the Companies' electric transition plan: (L'Tl'), rate stabilizafion plan (RSP), line extension program, green pricing power program, and the transfer of the R4onPower's service territory to CSF. In their application, the Cumpanies proposed to begin the amortization of tlrese regulatory assets in 2011 and complete the arnoiitizat3on over an eight-year periocl. The projected balances at tlie end of 2010 to amortize are $120.5 million for CSP and $80.3 million for OP. AFP-Ohio asserts tbat these projected balances, or the value on June 30, 20f1t3, were not challenged by any party. To recover these regulatory assets, the Companies created a RAC rider to be collected from customers in 2011 through 2018. The rider revenues will be reconciled on an annual basis for any over- or under-recoveries, 23 6ee C:os. );x.1, Exhibit DMR-5. 71 08-917-EL-SSO and 48-91$-EL-SSt? 41 Staff proposed that the eight-year amortization perzod proposal be deferred until the Companies' next distribution rate case where all components of distribution ratEt4 ar.e subject to review (Staff Ex. 1 at 4). AEP-t)hio responded tliat 58 221 authorizes single- issue ratemaking related to distribution service, which is what it is proposing. AET'-Ohio also iYotcs that the only opposition to the Companies proposal is with regard to the collection of the historic regulatory assets, which was by Staff (Cos. Reply Br. at 94). The Companies submit that Staff's preference to deal with this isaue in a distribution rate case is irrelevant and inconsistent with the statute. The Commission finds that the Companies have not demonstrated that the creation of the IUC rider in its proposed ESP, as a single-issue ratemaking item for distribution infrastructure and modeinization incentives, fulfills the requiremettts of SB 221 or advances the state policy. Therefore, the Cotxnrtission finds that the RAC rider should not be approved in this proceeding. We note, however, that we agree with Staff that the consideration of the requested amortiaation of regulatory assets is more appropriate within the context ©f a distribution rate case where all distribution related costs and issues can be exainined collectively. Accordingly, the Commission finds that P.EP-Ohio`s proposed ESI' should be modified to eliminate the RAC ri.der. 3. Energy k.fficiency, Peak Demand ReducHn^^ I7 erna7.ld Response, and TnterruUtible Capabilities (a) n r F.Eficiencyand Peak Demand lieduction Section 4928.66, Revised Code, requlres the electric ntilities to implement energy efficiency programs that will achieve energy savings aad peak demand programs designed to reduce the electric utility's peak deniand. Specifically, an electric utdity must aclu.eve energy savings in 2009, 2010, and 2011 of .3 perGent, .5 percent, and .7 percent, respectively, of the normalized annual kWh sales of the electric utility during the preceding three calendar years. This savings continues to rise unfiil the cumulative savings reach 22 percent by 2025. Peak demand must be reduced by one percent iri 2009 and by .75 percent annuaU.y unti12018. CS? and 01' include, as part of their E.SP, an unavoidable Energy Efficiency and Peak Demand Reduction Cost Recovery Rider (EE/PDR rider). The estimatect annual DSM program cost (including both BE and PDR) is to be trued-up annually to actual cost and compared to the antortization of the actual deferral on an annual basis via the EE/PDR rider (Cos. Ex. 6 at 47-95). (b) 13aselines and Benchmarks In the E.9P, the Compuues have established the baselines for meeting the benchmarks for statutory coinpliance by weather norrrializing retail sales, excluding 72 Os-917-F.7r5.5fJ and 08-913-Efr..SSt3 economic development load, accountzng for the load of former MonPower service territory and the C3rmetJHaazuiibal Real Estate load, accounting for future load growth due to the Companies economic development efforts, and accounting for increased load associated tivith the funds for econornic development purposes pursuant to the order in Case No: O4-169-Et,-C7ItD (RSP Order)24 (Cos. Eac. 8 at 4; Cos. Ex. 2A at 46-51). The 'tions 4928.64(li) and Companies contend that its process is consistent with Sei. 4928,66(A)(2)(a), Revised Code. The Companies request that the methodology be adopted in this proceeding so as to provide the Companies lear guidance with statutory compliance mandates. Further, the Companies reserve their right to request additional adjustrnents due to regulatory, economic, or technological reasons beyond the reasonable control of the Coznp`mies. As to the calculation of the Companies' base3ine, Staff asserts that the former MonPower load was acquired prior to the three-year period (2006 to 2008) and is not truly economic development. Therefore, Staff contends that the MonPow'er load is not a reasonable adjusirnent to the baseline. Staff suggests that the Companies' savings and peak demand reductions for 2009 be as set forth by Staff witness Scheck (Staff Ex. 3 at 6-8, Ex. GC5-1 and Ex. GCS-2). Staff recommends that CSP and OP niake a case-by-tase filing with the Con>znission to receive credit for the energy savings and peak demand reduction efforts of the electric utility's mercantile customers. Staff argues that because programs like PJM's demand response programs are not committed for in.begra8on into the electric efficiency and peak reduction programs, such credits should not count utilities energy towards AEP-Ohio's annual benclunarks and retail customers who have such agreements should not receive an exemption from AEP-Ohi.o's energy efficiency cost recovery mechanism (5taff Br. at 17-19; Staff Ex. 3 at 6-11). Kroger recornmends an opt-out provision of the rider for non-residential customers tha[ are above a threshold aggregate load (10 MW at a sirigle site or aggregated at multiple sites) within the AEP-Ohio service territories. ICroger proposes that, at the time of the opt-out request, the customer would be required to self-certify or attest to AEP- Ohio that for each facility, or aggregated facilities, the customer has conducted an energy aiidit or analysis within the past three years and has implemented or plans to implement the cost-effective measures identified in the audit or analysis. TKroger argues that the unavoidable rider penalizes customers who have implemented cost efficient DSM nteasures. Kroger contends that this is consistent with the intent of Section 4928.66(A)(2)(c), Revised Code (Kroget Ex.1 at 13-14). IEU riotes that the Convnission has previously rejected a proposal similar to Kroger s opt-out proposal with a demand tlueshold for mercantile customers in IIuke's Case No. 04-169-EGORD, Opinion snd 24 In re Colun+btrs 5ou1juxrz Pamacr Company and Ohio Pauvr Compnny, Order (Ianuary 26, 2005) (RSP Order). 73 OS-917-E3LrSSO and 05-918-EL-SSO ESP case.25 IEU urges the Comrnission, consistent with Section 4928.66, Revised Code, (IEU Reply Br. at and its determination in the Duke IsSP case, to reject ICroger's rc.^yuest 22). The Commission concludes that the acquisition of the former MonPower load shoutd not be excluded from baseline. The MonPower load was not a load that CSP served and would have lost, but for some action by C^S?. Therefore, we find that the CoYnpanies' exclusion of the MonPower load in the energy efficiency baseline is inappropriate. The Commission does not believe that all economic development should automatically result in an exclusion frorn baseline. On the otherhand, we agree with the Companies adjustment to the baseline for the Ormet load. We note that the Companies and Staff agree that the impact of customer-sited specific DSM resources will be included in the Companies' compliance benchrnarles and adjusted for any existing resources that had historic implication during the years 2006-2006. The Commission also recagnizes that Staff and ttie Compani<-, agree that the appropriate approach would be for the Cornpanies to make case-by-case filings with the Comrnission to receive credit for contributions by ntercantile customers. In regards to Kroges's recommendatian, for an opt-out process for certain commerclal or fndustrial custorners, the Commission finds Kroger's proposal, as advocated by tCroger witness Higgins, too speculative. It is best that the Commission deter;nine the inclusion or exemption of a mercantile customer's tJSM on a case-by-case basis. We note that Section 492$.66(A)(2){c), Revised Code, provides, in pertinent part, the following: Any mechanism design.ed to recover the cost of energy efficiency and peak dema.n.d reduction programs under divisions {A)(1)(a) and (b) of this sr.'ction may exempt mercantile customers tttat commit their demand response or other customer-sited capabilities, whether existing or new, for integration into the electric distribution utility's demand-response, energy efficiency, or peak dentartd reduction progxam.F, if the contznission detezmines that that exemption reasonably encourages such customer to commit those capabilities to those programs. This provision of the statute permits the Commission to approve a ri.der that exempts Tnercanti2e customers who commit their capabilities to the e7r.ctric utility. However, the statute does not dictate a minimum consumption level. For these reasons, Uhe Cominission rejects Kroger's proposal. +30, et al., Opinion and OrEter (Decemta 17, 2008) 75 tn +e Bukr Energy Ohio, Inc., Case hTO. 08-920-EL,. (Duke FSP Order). 74 08-917-EIrSSCT and 08-918-EI fSSO (c) En gZy Efficieqcy and I'eak Demand I+eduction Prot^rams The Companies proper3e ten energy efficiency and peak demand reduction prograrns that will be refined and supplemented at the completion of the Market Potential Study ttirough the creation of a workiuig collaborative grottp of stakeholders. As part of the Compardes' energy efficiency and peak demand reduction plan, the Companies propose to spend $178 million on the following programs: (1) Residential Standard Offer Prograczt, Small Conunercial and Industrial Standard Offer Progratn, Ffficient Commercial and Industrial Standard Offer Prograna; (2) Targeted Energy Weatherization Program; (3) Low Income Weather.ization Program; (4) Residential and Small Commercial Compact F"luorescent Lighting Program (5) Comm.ercial and Industrial I.ighting I'rograin; (6) 5tate and Municipal Light Emitting Diode Program; (7) Energy StarO New I-Ion-Les Program (8) Energy StarM Home Appliance Program, (9) Renewable Energy `I'echnology I'rogram; (10) Industrial Process Partners Prog;ram (Cos. Ex. 4 at 20- 22). OEG supports the Companies EPs/PDR rider as a reasonable propnsal (ORG Ex- 2 at 13). OPAE generally supports the Conipanies proposed programs as reasonable for low- income and moderate income custamers. However, OPAE requests that the Companies be required to empower the collaborative to design appropriate programs, provide funding for existing programs that can rapidly provide energy efficiency and demand response reductions, and to retain a tturd-party administrator to tnanage program implementation (OPAE Ex_ 1 at 16-17; OPAI:/APAC Br. at 21-22). Staff also generally approves of the Companies' demand-side management and energy efficiency programs. However, Staff notes that certain of .AEP-Ohio's progr'ams are expensive and should. be required to comply with the Total Resources Cast Test (Staff Br. at 17-19; Staff Ex, 3 at 6-11). OCC makes five specific recommeiidations (t7CC Ex. 5 at 9). Fitst, OCC contends that the Companies DSM programs for low-income residential customers are adequate but should be available to all residential customers in Ohio. Second, OC:C recommends that AEP-Ohio work with Columbia Gas of Ohio, Inc., to develop a one-stop horne of the ESP. "i'hird, OCC recommends that programs for perforinance program in year two consumers above 175 percent of the federal poverty level should be competitively bid and castoiners charged for services according to a sliding fee scale based on income. Fourth, like Staff, OCC contend,s that a1l programs should be evaluated for cost-effectiveness pursuant to the Total Resource Cost Test. FinaIIy, OCc expresses concern regarding the administrative costs of the programs, in conlparison to energy efficiency programs offered by other Ohio utilities and recommends that the adtninistrative cost of ti-te DSM program (administrative, educational, and marketing expenst=s) be detemuned by the collaborative, and limited to 25 percent of the program costs to evsure that the majority of the program dollars reach the customers (Id.). 75 08-917-EL-SSU and 08-918-EL-SSO -45- The Commissioat directs, as the Companies submit in their ESP, that the collaborative process be used to contain adniinistrative cost of the BE/ FDR prograrns and to etr.sure, with the possible exception of low-income weatherization programs, that all programs comply with the Total Resource Cost Test We do not agree with OPAE/APAC that a third-party administrator is necessaty to act as a liaison between the Companies and the collaborative, Thus, the Companies should proceed with the proposed EE/PDR programs proposed in its ESP as justified by the market project study and as refined by the collaborative. (d) Interrui?tible (_aoacitv The Complnies count their interruptible setvice towards their peak demand reduction requirements in accordance with Section 4928.66(A)(2)(b), Revised Code. More specifically, the C.'ompanies propose to increase the limit of C1P's Interruptible Foisrer- Diseretionarv Schedu.le (Schedule IRP-D) to 450 Megawatts (MW) from the current limit of 256 MW and to modify CSP's Emergency Curtailable Service (EC'S) and Pxi.ce Curtailable 9eiroice (PCS) to make the services more attractive to custosners. The Compani.es request that the Commission recognize the Companies' ability to curtail custozner usage as part of the peak demand reductions (Cos. Ex.1 at 5-6). Staff advocates that any credits awarded for the annnal peak demand reduction targets for the Companies' interruptible programs should only apply when actual rcductions occur (Staff Ex. 3 at 11). OCEA argues that interraptible load should not be counted toward ALP-C)hio s peak demand reduction as it is contrary to the intent of SB 221 to improve grid reliability and would be based on load under the control of the customer rather than AEP-Ohio. Further, OCEA argues that the Companies would reap an inequitable benefit from interruptible load (possibly in the form of off-system sales) that is not reduced at peak which would allow the Compmues bo sell the load or avoid buying additional power. OCEA contends that any such benefit is not passed on to customers (t)CEA Br. at 102-103; Tr. Vol.1X at 68-69). 7"he Companies argue that capacity associated with interruptible custom.ers shouid be counted toward coinpliance with the requirements of Section 4928.66, Revased Code, as the ability to interrupt is a significant demand reduction resource to AEP-Ohio. Further, the Companies state that interrttptions have a real impact on customers and the Companies do not want to interrupt service when there is no system or market requiretnent to do so (Cos. 'Ex. l ae 6). T 4ie Cornpanies note that Section 492$.66(A;(1)(b); Revised Code, requires the electric utility to implement programs "designed to achieve" a specified peak demand reduction level as opposcd to "achieve" a specified level of energy savings as required by Section 492$.66(A)(1)(a), Revised Code. Staff witness Scheck admits that the plain meaning of "desig,zted to achieve" and "achieve" are different ('i'r. Vol. VlTI at 208). The Companies argue that the different language in the statutory requirements is intended to recognize the differences between energy efficiency programs 76 08-917-EL-SS0 and 0$-928-EL-5S0 46- and peak denzand reduction programs. As such, the Companies contend that Staffs position is not snpported by the language of the statute and it does not overcome the policy rationale presented by the Companies. The Companies also note that, in the context of integrated resource planning, interruptible capabilities are counted as capacity and evaluated iri the need to plan for pew power facilities. Finally, the Comparries note that the Conm-assion defines native load as internal load nninus interruptible loadA For these reasons, the Companies contend that their interruptible capacity should be counted toward their compliance with the peak de.nzand reduction benchmarks (Cos. Br.114-1.15; Cos, Reply Br. at 90-93). Purtlier, the Companfes claim that interruptible customers receive a benefit in the fortn of a reduced rate for tatcing intrrruptible service irrespective of whether their service is actually curtailed. AEP-C)hio notes that it includes such interruptible service as a part of its supply portfolio, unlike tlie PjM demand response prog,rams, which is based on PJM's zonal load, T'herefore, AEP-Ohio asserts there iv no disparate treatment between counting interruptible capabilities as part of peak demand reduction compliance requirexnents and prohibiting retail part'tcipation in wholesale Fj1vI demand reduction prograins (Cos. Reply Br. at 90-91). Further, as to OCEA's claims regarding interruptible custoiner load, the Companies argue that the assertions are without merit or basis in the statnte. The Com.panies argue that counting interntptible load fits squarely within the stated intent of the statute that programs be "designed to achieve" peak demand reduction and facilitates the ability to avoid the construction of new power planta. As to the customer's control of interruptible load argument, the Companies note that the customer has a choice to "buy tlanugh" to obtain replacement power at market prices to avoid curtailment and in such situations the Companies' supply portfolio is not affected. Regarding OC:EA's assertion that the Cornpariies might benefit from the associated interruptioii, AEP-Ohio acknowledges that off-system sales are indircctly possible, as are other circun-^,stances, based on the market price. Nonetheless, A&1'-Ohio argues that such does not altcr the fact that AEP-Ohio's retail supply obligation is reduced and the supply portfolio is not accessed to serve the retail customer. Accordingly, ApI'-C3hio asserts that interntptibie tariff capabilities should count toward the Cozmpanies' peak demand reduction compliance requirements. The Comniission agrees with the Staff and OCEA that iriterruptible load should not be counted in the Companies' determination of its EE/PDR compliance requirements unless and until the load is actaally interrupted. As the Companies recogxtize, it is imperative, with regard to the PJM demartd response progratiis, that the Companies 1=.ave 26 Sec proposed Rule 4901:5-5-01(Q), O.A.C., Tn the Matter of the Adoption of Ruies fos Atternatiae and Reneux!ble Er:ergy 7echHOiog9es and kesm rces, and Etnrssian Confra77ic7roriing ReRre rertrenM ara! fimeicdurent Cnde, Pursumet to C7rapter of C'.7utprcrs 2901:5-1, 4902:5-3, 49015-5, and 49015-7 of the Ohio Administrative 4928, Reaiscd Code, to hnpteunent Sermfe Aiti Nv. 221, Case Nn. 08-888-F,TrORT3 (Green Ritleq). 77 -47- O8-917-EL-SSO and a8-91t3-]3In55O AT.P'Qhio's soxne control or commitment from the customer to be included as a part of Section 4928.66, Revised Code, compl"tance requirements. Further, the Connnission emphasizes that we expect that applications filed pursuant to Section 9928.66(t1)(2)(b), Revised Code, to be initiated by the electric utility only when the circumstances are justified. At the time of'such filing by an electric utility, electric utility's continued compliance is the Comnussion will determine whether the possible under the circun-otances. 4. Economic Developtnenr Cost Recovery Ricler and the Partnershin with 0Iu.o Fund The Companies' ESP application includes an unavoidable Economic Development Rider as a mecltanism to recover costs, incentives and foregone revenue associated with new or expandirnf; Commission•approved special arrangements for economic development and job retention. The Companies propose quarterly filings to establish rates based on a percentage of base distribution revemie subject to a true-up of any under- or over-collection in subsequent quarterly filings, ht addition, the Companies propose the fund from sbareholders. The fand would development of a"Partnership with Ohio" conaist of a $75 million commitment, $25 m.iIlion per year of the ESP, from shareholders. The Companies' goal is for approximately half of the fund to be used to provide assistance to low-income . custorners, including tmergy efficiency programs for such custorners, and the balance to be used to attract and retain business developinent within the AEP•Oluo service area (Cos. Ex.1 at 12; Cos. Ex. 3 at 15-16; Cos. Ex. 6 at 49; Tr. Vol. III at 115-119). dividing the recovesy of taCC proposes that the Cominission continue its policy of forgone mvenue subsidies equally froni ABP-Ohio's shareholders and customers or require shareholders to pay a larger percentage. Further, CJCC expresses some concern that the rider may be used in an anti-cornrnpetitive manner as it is not likely that incentives andJor discounts will be offered to shopping cust.ocners. To address OCC's anticompetitive concerns, OCC proposes that the Commission make the econoniie development rider avoidable or establish the charge as a percentage of the customer's entire bill ratlier than a percentage of distribution charges. C7CC also recommends that all parties participate in the initial and annual review of the economic development contracts and that, at the annual review, if the customer has not fulfilled its obligation, the arrangement be cancelied, the subsidy paid back, and the Companies directed to credit the rider for the discounts (OCC Ex. 14 at 4-8; OCEA Br. at 104-706). The Companies contend that Section 4905.31, Revised Code, as amended by SB 221, explicitiy provides for the recovery of foregone revenues for entering into reasonable arrangements for economic development and, thus, OCC's recommendation to continue the Comniission's previous policy is misplaced. Further, the Companies note fliat the 78 {39-917-EL-S5C7 and 08-918-8[., SSO Conunission's approval of any special arrangement will include a public interest determination. '1'hus, the Companies argue that OCC's recommendation for all parties to initially ancl annually review economic development arrangements is unnecessary, bureaucratic and burdensoine, and should be rejected. The Companies contend that economic development and fiill recovery of the foregone revenue for economic development is consistent with SB 221 and a significant feature of the Companies' ESP, which should not be modified by the Commission (Cos. Br. at 132). The Conunissionlinds that C7CC's concerns are unfounded and unnecessary at this stage. The Commission is vested with the authority to review and deternzirte wbether or not economic development arrangements are in flie public interest. QCC's request is denied. OPAE and APAC argue that the Companies have not provided any assurances that the $75 mfllion will be spent from the parmtership with Ohio fund if the Cornmission modifies the ESP and fails to state how much of the fund will be spent on low-income, at- risk populations (C?PAE/.APAC Br. at 19-20). The Companies submit that, if the ESP is SY in its entirety to detera-dne whether modified, they can then evaluate the modified ES this fund proposal contained in the ESP requires eiinv.nation or modification (Tr.. Vol. Ifi at 137-138; Tr. Vol. X at 232-233). While the Partnership with Dhio fund is a key component of thc econontic development proposal, in light of the modifications made to the ESP pursuant to this opinion and order, we find that the Companies' shareholders should fund the Partnership with Ohio fund, at a minimum of $15 m'sllion, over tlre three-year ESP period, with all of the funds going to low-income, at-risk customer programs. Accordingly, we direct AE[ = Ohio to consult with Staff to administer the prograrn established hereiui. C. Li.ne Extensiorvs In its ESP, AEP-OhiO proposes to modify certain existing line extensi"n policies and charges included in its schedules (Cos. Ex,10 at 5-14). Specifically, the Companies requested a modification to tlieir definition of line extension and system improvements, a continuation of the up-front payment concept established in Case No. 01-2708-ELrCOlF an increase in the up-front residential line extension charges, implementation of a uniform, up-front line extension charge for all nonresidenfiial projects, the eIimination of the end cise customerrs monthly surcharge, and the elimination of the alternative construction option (Id. at 3-4, b-7,10-12). of Poever ComFarqb the Commission' s Invesfigation into tlte PWiciss and Procedrtres Ohio 27 lrt the Maftr.r of Ohio F.ddson Company, The Power Cvrrpar,y, T7ae Cievelarul Electric Illurninafing Comparay, ( nlumbu.s Sont3urn Installaflon of New Line LxEenaions, Company mul Monongahela Porner C'orttFany Reganting the Toledo Edison 2002). Case No. f77 2708-HI,COI, et al. Opinion nnd Order (November 7, 79 49- 08-917-PT.-SSO and 0&918-131.-550 Staff testified that distribution-related issues and costs, such as those related to line F'ix.13 at 4). IEU extensions, be examined in the context of a distribution rate case (Staff concurred with Staff's position (IEU Br. at 25). OCC also agreed and added that ABR Ohio shou3.d be retluired to deinonstrate in that rate proceeding that its costs related to line extensions have substantially increased, thereby justifying AEP-Ohlo's proposed increase to the up-front residential line extension charges (OC=.SA Br. at 87). i'er SB 221, the Commission is required to adopt uniforrn, statewide Iine extension rules for nonresidential customers within six months of the effective date of the law. The Commission adopted such rules for nonresidential and residential casf'omers on is still November 5, 2008?8 Applications for rehearing were filed, which the Commission con.sidering. Accordingly, the neiv line extension rules are not yet effective. The Conmiission finds that AEP-Ohio has not dem:orlstrated that its proposal to cvntinue, in its TiSP, its existing line extension policies regarding up-front payments, with modifications, is consistent with SB 221 or advances the policy of the state. Therefore, in light of the SB 221 mandate that the Commission adopt statewide line extension rules that will apply to .AFP-fJhio, we do not believe that it makes sense to adopt a unique poHcy for the Companics' ESP should be modified to eluninate the AEP-Ohio at this tisne, As such, provision regarding line extensions, which would have the effect of also eliminating the atternative construction option as requested by the Companies. A'pP-f)hio is, however, directed to account for all line extension expenditures, excluding prentium services, in plant in service until the new line extension rules become effective, where the recovery of such will be reviewed in the context of a distribution rate case. The Companies may corttinue to charge customers for premium services pursuant to their existing practices. . V. TRANShritS.510N In its FSP, the Cornpanies requested to retain the current TCRli, exCept the rnargiu7al loss fuel credit will now be reflected in the FAC instead of the TCRIt. We concur with the Cornpanies' request. We find the Companies' request to be consistent with our determination in the Companies' recent TCRR Case,211 and thus, approve the TCiZR rider as proposed by the Cortrpanies. Additionally, as contemplated by our prior order in ehe TCRR Case, any overrecovery of trati,smission loss-related costs, which has 4901:1-9, 4901:1-10, 8901:1-22, 4901.1-22, 4901:1-23, of tlu Cummissian's neureza of Chupters 26 See In tlzc A9atter Case No. 06-653-HL-ORD, Ninding and Order 4901:1-24, und 4901:2-25 of the Ohin Ad ninistratPue Cmte, (November 5, 200s), Entry on Rehearing (Decemier 17, 2(108) (06r653 Case). Ohio Pomer C-ornpuny to Adjust Appifca3iori of CotunrLus Soathernt Pawer Company and 21 In the Matier of tFw Case No. 08-1202-E1,CTNC, Finding and Order Encti Company's Trnnsrnission Cost Recovery Ridsr, (Decr.rnbes 17, 2008) (FCRR Cise). 80 0$-917-EL-SSEl and 03-918-EL-SSU `50- occurred due to the timing of our approval of t:he Companies' ESP and proposed FAC, shall be reconciled in the overJunderrecovery process in the Companies' nextTCRR rider update filing. VI. OTf-IER ISSUEE A, Corporate Separation 1. Functional Senaration In its E.sl' application, AF-p-Chio recluested to remain functianafly sefrarated for the term of the ESP, as was previously authorized by the Commission in the Companies^ rate stabilization plan. proceeding,3a pursuant to Section 4928.27(C), Revised Code (Cos. App. at'14; Cos, pr- at 86). the Cornpanies also requested to modify their corporate separation plan to allow each cornpany to retain its distribution and, for now, transmission assets and tliat, upon the expiration of functional separation, the Companies would sell or transfer their generation assets to an affiliate (Id.). Staff testified that the Companies' generating assets have not been structm'ally cted that, separated from the operating companies (Staff I^a c. 7 at 2-3). Staff also recominend iut accordance with the recently adopted corporate separation rules issued by the Commission in the SSO Rules Case,31 the Companies should file for approval of their corporate separations plan within 60 days after the rules become effective. Furthermore, Staff proposes that the Companies' corporate separation pian should be audited by an independent au(iitor withai the first year of approval of the F.SP, the audit should be funded by the Companies, but managed by Staff, and the audit should cover compliance with the Contrni.sslon's rules on corporate separation (Staff Ex. 7 at 3-4). No party opposed AEP-t7hio`s request to remain functionally separate. Accordingly, the Commission finds that, while the ESP may move forward for approval, as noted by Staff, in accordance -writh our recently adopted rules in the SSO Itules Case, the Companies must ffle for approval of their corporate separation plan wikhin 60 days after the rules become effective. Company, Case No. 04-169-RLd3NC, Opinion aud 30 In re Colum6us Southern Power Cnmpany and Ohio I'oa+er Order at 35 (january 26, 2005). Ofjcr, Corporate Sepm'atfon, Reasonabla 31 In tbe Mattsr of the Adoption of Rutes for SMndard Service Uk'lities Pursuant to Sections 4928.14, 4928.I7, and Arrangernents, and Transmission Riders fm-^tertrie 8ubstlttete Senate Bift No. 221, Case No. 08-777-SL-C>RD, 390537, ttevised Code, as amended by Ameuded Pincting and Order (3eptesnber I7, 2001f), and Entry on Rehearing (Februury 11, 2tXt9) (SS(7 Rnles Ca+se). 81 -51- 08-917-EL-SSO and 08-918-EL-SSO 2. Transfer of GeneratingAssets The Companies request authorization for C5p to sell or trarisfer two recently acquired generating faciliti(t Through its application, the Conipanies also notify the Conunission of their cantractual entitlements/arrangements to the output from the Oluo Valley Electric Corporation generating facilities and the Lawrenceburg Generation 5tation that the Cotnpanies intend to sell or traitisfer in the future, but argue that any sale or transfer of those entittements do not requfre Coinrni.ssion authorization hecause the entitlements do not represent generating assets wholly or partly owned by the Companies pursuant to Section 4928.17(F.), Revised Code (Id.). The Cooniparnies argue that, if the Commission does not grant authorization to transfer these plants or entitlements, then any expense related to the plants or entitlements not recovered In the FAC should be recovered in the non-FAC portion of the generation rate (C.os. Br. at 89; Cos. Ex. 2-E-at 20-21). ABp-Ohio states that this rate rmovery would include approximately $50 rnilli(n of carryiug costs and expenses related to the Waterford Energy Center and the Darby Electric Generating Station annualfy, and $70 million annually for the contract entitlements (ld.). Staff witness Buckley testified that, wltile Staff does not rtecessarily disagree with the propsal to transfer the Waterford Energy Center and the 1)arby Electric Genesatin.g Station facilities, Staff believes that the transfers could have a potential financial and policy impact at the time of the transfer (Staff Ex. 7 at 3). Tnus, Staff recosnsnended that the Companies file a separation application, in accordance with the Commission's SSO rules, at the time that the transfer will occur (Id). Several other parties agree that, in the absence of a current plan to seU or transfer, the Cornnlission should not approve a future sale or transfer. Rather, the parties argue that the Companies should seek approval, 82 08-917-EL-SBO and 08-418-EI^SSO -52- pursuant to Section 4928.17(E), Revised Cod.e, at the time of the actual sale or trattsfer (OCEA Br: at 100; tET1 Br. at 26-27; OEG Br. at 16). The Comxnission agxees with Staff and the intervenors that the request to transfer well the Waterford Energy Center and the Darby Electric Generating Station facilities, at+ as any contractual entitlementsJarrangeznents to the output of certain facilities, is preinature. AEP-OFiio should file a separate application, in accordance with the Commission's rules, at the time that it wishes to sell or transfer these generation fac'tlities, 11ie Cornuiission, however, recognizes that these generating assets have not and are not included in rate base and, thus, the Companies cannot collect any expenses related thereto, even if the facilities or contractual outputs have been used for the benefit of Ohio customers. If the Comrnission is goizig to require tfjat the electric utilities retain these generating assets, then the Coinmission shouid also allow the CompanieS to recover Ohio customers' jurisdictional share of any costs associated with mstintaiuuirtg and operatiuig such facilities. Accorclistgly, we find that while the Companies stiil own the generating facilities, they should be alloqved to obtain recovery for the Ohio customers' jurisdictional share of any costs associated therewith. Thus, we believe that any expense related to these generating facilities and contract eltitlements that are not recovered in the FAC shall be recoverable in the non-FAC portion of the generation rate as proposed by the Companies. The Commission, therefore, directs Afii'-Ohio to modif5' its ESP consistent with our determination herein. B. Possible Early Plant Closures The Companies include as a part of their application in these cases a request for authority to establish a regulatory asset to defer any unanticipated net cost assoclated with the early closure of a gencrating unit or unlts. The Conipanies assert that, during the ESP period, generating units may experience failures or safety issues that would prevent the Companiea from continuing to cost-effectively operate the generation unit prior to the end of the depreciation accrual (unanticipated shut down) (Cos. App. at 18•14; Cos. Ex. 2- A at 51-52). The Companies request authority to indude net early closure cost in Account 182.3, Other Regulatory Assets. ]n the event of an unanticipated shut down, the Companies state they will timefy file a request w-iHi the Commission for recovery of such prudent early closure costs via a non-bypassable rider over a.rzlatively short period of time. The Companies are requesting that the rider include carrying cost at the WACC ratc (Cos. App. at 18-19; Cos. Ex 6 at 25-26). The Companies also request authority to come bcfore the Conunission to deternrine the appropriate treatment for accelerated depreciation and other net early closure costs in the event that the Companies find it necessary to close a generation plant earlier that otherwise expected (earlier than anticipated shut down) tCos. Ex. 6 at 28). 83 08-917-EL-SSO and 08-418-EL-SSO -53- ()CEA posils that the Companies' request for accounting treatment far early plant closure is wxong and should be rejected. C3C'6A reasons that the plant was included In rate base under tz•aditional ratemaking regulation to give the Compatues the opportunity to earn a relurn on the investment and the Cotnpanies accepted the risk that the plant might not be fully depreciated when it was removed from service. OCEA asserts it is not appropriate to guarantee the Companies recovery of their utvestment. If the Commiission determines to allow the Companies to establish the requested accounting treatment, C)CEA asks that the Commission adopt the Staff's "offset" recommendation (OCEA Br. at 102). Staff argues that the value of the generation fleet was determined in the Compailies' BTl' cases,32 wherein, pursuant ta the stipulation AEP-C)hso agreed rGat ta itnpose any lost generation cost on-switching customers during the market develapment period. Staff notes that, although the economic value of the generation plants was never specifically addressed by the Co.nunission, it is reasonablle to assume that the net value of the Companies' fleet was not stranded. Accordingly, Staff opposes the Cotnpanies' requests to impose on customers the cost or risk of uneconomic plants without accounting for the offset of the positive economic value of the rest of the Companies' generatian plants (Staff Ex.1 at 8). Based on the record in. tliius proceeding, the Commission is not convinced that it is appropriate to approve the Companies request for recovcxy of net cost associated with an unanticipated shut down. Despite the arguments of the Companies to the contcary, we are persuaded by the arguments of the Staff that there may be offsetting positive value associated with the Companies generatian fleet. Accordingly, while we wili grant the Companies the authority to establish the accounting mechanism to separate net early closure cost, the Companies must file an application before the Commissxon for recovery of such costs. Accordinglly, this aspect of the Companies ESP application is denied.. As to the Companies' request for authority to file with the Comrnission to detennine the appropriate treatment associated with an eaxlier-than-anticipated shut down, the Commission finds i:his aspect of the application to be reasonable and, accordingly, the request should be granted. C. PrM Deman.d l?esponse Programs Through the ESP, the Com.panies propose to revise certain tariff provisions to prohibit customers receiving SSO froni participating in the demand response programs offered by PJM, cither directly or indirectly through a third-party. Under the PJM programs retaiI customei,s can receive payment for being available to curtail even if the Motter of the Applica#orrs of Colur9ibus Srnithem Power Companyand Ohio Pmner CansF"ut'JJar RPt'rO°at 12 In the a/'Transitfon Rmanues, Case Nos. 99-1729-F1-E1I' and 99- of The{r Eiectnc Transitior: Pir+ns atid for Iteceipt 1730-F^.C ,EIP, Opyninn and Order at 15-18 (September 28, 2000). 84 08-917-E1..-SSQ and 08-91$-EL-SSO -54- customer's service is not actually curtailed. AEl'-()hio argues that alIowing its retail customers receiving SSC7 to also paxticipate in PJM demand respoBse programs is a no- win situation for AEP-C7hio and its other customers and `utconsistent with the requiretnents of SB 221. The Companies contend that PJM dernand response programs are intended to ensure the proper price signal to wholesale castomers, not to address retail rate issues (Cos. Fx. 1 at 5-7). AEP-Ohio argues that retail customers should participate through AEP-©hio-sponsore.d and Commission-appproved programs. The Companies conterid that FBRC has granted state conznussions, or- more precisely, the '•relevant f:lectric retail regalatory authority," the authority to preclude retail customer participation in wholesale demand response programs. W1wlesale CompQtzti°n in Regions witFi Organised EIeetric Markets (Docket Nos. I2ikI07-19-000 and AD07-7-000),125 FERC ¶ 61,071 at 1$ CPR Part 35 (October 17, 200$) (Final Rule) (Cos. Br. at 119) AEP-Ohio notes that it has consistently challenged retail custopners' ability to participate in such programs and argued that the terms and conditions of its tariff prohibited such and, therefore, demand response retail parti.cipants should not be surprised by the Companies' position in this proceeding (Tr. Vol. IX at 212). AEP-Ohio argues that dhio businesses participatutg in PJM`s demand response progratrts have not invested their ohm capital or assets, taken any financial risk, or added any value to the services for which they are being compensated through PJM. The Companies assert, as stated by Staff witness Sc:heck, that the PJM demand response grograms cost AEP-C7hia's other. customers as the load of such PJM program participants contirtues to count toward the Coinpanies' Fixed Resource Requirements (PRR) option and such cost is reflected in ABP-Ohio's retail rates (Tr. Vol. VIII at 165466). Further, the PjM program participant/customer's ability to interrupt is of no use to AEP-Ohio, as the Companies claiin that PJM's curtailment request is based on PJIV^`s zonal load and not AEP-C)luo's peak load (Cos. Br. at 122-123). The Companies reason that SB 221 uicludes a process whereby mercantile customer-sited resources can be conunitted to the utility to comply with the peak demand reduction bcnchznarks as set fortlx in Section 4928.66(A)(2)(d), Revised Code. Further, AEP-Dhio argues that it is unclear how the interruptible capacity of a customer participating in PJM's demand response program can count toward the Companies' benchmarks without being under the control of the Companies and "designed to achieve" peak demand reductions as required by the statue. As such, the Companies argue that, if participation in the PjM demand response program is allowed, PJM wi31 be in direct competition with the electric distribution companies efforts to com,ply with energy efficiency and peak demand reduction benchmarks and thus, render the mercantile custonier commitment provisions largely ineffective. For these reasons, P.EP-Ohio states that it should incorporate participation in PJM's demand response programs th.rough AEP-phio and AEP-©hio would then be in a position to pass so:ne of the economie benefits associated with participation in PJM programs on to retail customers through 85 0$-917-E1-SSO and 08-91$-EL-SS0 complementary retafl tariff programs and to pursue mercantile customer-sited arrangemenis to aclueve benchmark compliance, thvs a3lowiiV the Companies to avoid duplicate supply costs (Cos. Er. at 124126). This aspect of the Companies' ESP proposal is opposed 'by Integrys, OMA, Commercial Group, OEG, and IEU. Most of the intervenors contend that AET-C7hia, in essence, considers retail eustonier participation in PJM programs the reselling of power provided to them by AEP-t]hio, Integrys ma.k.es the most comprehensive arguments opposing AEP-OIuU s request for approval to prohibit customer participation in the PJM deinand response programs. hitegrys argues that 18 C.F.R. 35.28(g) only permits this Commission to prohibit a retail custonier's particlpation in dentand response pa'ograms at the wholesale level t.hrough law or regutat-ion. Section 18 C.F.R 35.2$(g) sta tes: Each Comrnission-approved independent system operator and xegion.al transmission organixation must permit a qualified aggregator of retail customers to bid deman.d respornse on behalf of retail customers directly into the Conunission-approved independent system operator's or regional transmission organization's organ.ized markets, untess f3ze lnws and 7egulations of the relevant etectrtr retail regulatory authority exptessly do not lmrmit a retail customer to participate. [F.mphasis added.l Thus, Integrys reasons that a ban on participation in wholesale demand response programs through A.F.P-Ohio's tariff is not equivalent to an act of the General Assembly or rule of the C:ommission. Accordingly, Integrys reasons that any attempt by the Comntission to prohibit participation in this proceeding is beyond the authority granted by FERC and will be preempted. Further, Integrys and Coustel_Iation argue that AEP- Ohio has failed to state under what authority the Comntiission could bar customer participation in PJM's demand response and reliabiTity prograrns. Constellation and Integrys posit that it is not in the public interest for the Comrnission to approve the prohibition from participation in such programs (Constellation Sr. at 20-23; ConSteltatlon Lx. 2 at 18; Integrys Ex. 2 at 15; Tntegrys Br, at 2). Even if the Commission concludes that it has the authority to grant AEP-Ohio's request to revise the tariff as requested, Integrys asserts that the Companies have not met their burden to justify prohibiting participation in PJM demand response programs. lntegrys asserts that the request is not properly a part of the ESl' applications and should have been part of an application not for an increase in rates pursuant to Section 4909.18, Revised Code. Nonetlteless, Integrys concludes that under Section 4928.143 or Section 4909.18, Revised Code, the burden of proof is on the etectric utility company to show that its proposal is just and reasonable, 86 08-917-I;L-SSO and 08-918-EL-SSO -56- The Coinpanies, according to Integrys and the Commercial Group; have failed to present any demonstration that the Conzpanies' programs are more beneficial to custoiners than the P)It4 programs. On the other hand, Integrys asserts that the PJN! programs are more favorable to customers tlva.i the programs offered by AEP-Ohio as to notification, the number of curtaibnents per year, the hours of curtailmerits, payments and payment options, and penalties for non-compliance (Integrys Ex. 2 at 10-12; Commercial Group Br. at 9). In addition, oertain interveners note, and the Companies agree, that PJM has rtot curtailed any customers since AEI'-t)hio joined PJM ('I'r. Vol. IX at 48). Fuxtherniore, the intervenors contend that participation in the demand response prugrams provides improved grid reliability and improved efficiency of the market due to competition (Integrys Tac. 2 at 8). lntegrys also notes that the Ohio castomers receive significant financial benefits from load serving entities beyond OMo (Tr. Vol. IX at 52-52, 118). Integrys argues that AEP-Ohio wishes to ban customer participation in wholesale demand response programs to facilitate the increase in 0S5 of capacity to the benefit of the Companies' shareholders. Integrys reasons that because AEI'-Ohio can count load enrolled In its interruptibl.e service offerings as a part of the PJM ILR demand response prngrarn, the Companies wiu receive credit against its F1tR cornmitment, The Companies, according to Integrys, hope that additional load will come from the custozners currently parlicipating in PjM's demand response programs in Ohio (Tr, Vol.. IX at 53-58; Integrys Br. at 20-22). Integrys proposes, as an alternative to prohibiting customex participation in wholesale demand response programs, that the Commission count participation in the programs towards AEP-Ohio's peak demand reduction goals in accordance with the requirements of Section 4928.66, Revised Code. Integrys argues that the load can be certif3ed, as it is today with the PJM demand response programs, or the electric services company could be required to register the conunitted load with the Coinmission. . Furthennore, Integrys reasons that the Commission can not retroactively interfere witlt existing contracts between customers and the customer's electric service provider in relation to the conrenitment contracts with PJM. With that in rnind and if the Commission decides to grant AEP-Ohio's request to prohibit participation in wholesale demand response programs, Integrys requests that customers currently committed to participate in t'JM programs for the 2008-2009 planning period and the 2009-2010 plantting period be permitted to honor their comznitments (Integrys 13r. at 27-28). Integrys argues that the Companies' claim that taking SSO and participating in a wholesale dem.and response prograrn is a resale of power and a violation of the tertns and conditions of their tariffs is nvsplaced. Integrys opines that there is no actual resale of energy, but, instead, there is a reduction i,n the customer's consumption of energy upon a call from the regional transmission operator (in this case, PJNI). The exastomer is n.ot purchasing energy from AEP-Ohio, so any energy purchased by AEP-Ghio can be 87 08-917-EL-SSO and 08-918-EL-SSO `57" transferred to another purchaser. Thus, Integiys asserts that AEP-Ohio`s argument regarding participation in a whoiesale demand resportse program is fiction and not based on FERC's interpretation of participation in such programs. Finally, integrys contends that AEEP-C)hio's proposal is a violation of Section 4928.40(D), Revised Code, as such prohibits electric utilities from prohibiting the resale of electric generation sea'vice. The Comniercial Group asserts, that because AEP=Ohio has not performed any studies or analyses, the Companies' assertion that wholesale demands response programs must be different froni a demattd response program offered by AHP-Ohio is unsupported by the record (Tr. Vol. IX at 47). The Commercial Group requests that the Companies be directed to design energy efficiency and demand response prograzns that incorporate all available prop ams (Coaunercial Group at Br. 9). OEG argues that, to the extent there are real benefits to the Companies as well as to thei.x 'retail customers in the form of improved grid reliability, AEP-Ohio should be required to offer PjM demand response programs to its large industrial customers by way of a tariff rider or through a third-party supplier (C)EG Ex. 2 at 13). IEU adds that the Companies currently use the capabilities of their interruptible custoiners to assist the Ccampanies in satisfying their generation capacity requirements to PJM. According to IEU, SB 221 gives mercantiie customers the option of whether or not to dedicate their customer-sited capabilities to the Companies for integration into the Companies' portfolio (IEU Ex. 1 at 12). Constellation argues that AII'-Ohio's proposal violates Section 4928.20, Revised Code, and the clear intent of SB 221. Further, ConsteIlation argues that approving AEP- C3ktio's request to prohi.bit Ohio businesses from conservation programs during this pexiod of economic hardship is ill-advised, especially considering that other busin.esses with which Ohio businesses' must compete are able to participate in the PJM programs. As such, consistent with the Coni,niission's decision in C}uke's FSP case (Case No. 08-920- EL-SSO, et al), Constellation encourages the Con-anission to reject AEP-Ohia s request to prohibit SSO customers from participating in PJM demand response programs and give Ohio's business customers all available opportunities to reduce deniand, conserve energy, and invest in conservation equipment (ConstelIation Br. at 23). OMA supports the claims of Constellaticut (OMA Br. at 10). First, we will address the claims regarding the Comuussion's authority, or as cIaimed by rntegrys, the lack of authority, for the Cotrunission to deterrnine whether or not Ohio's retail customers are permitted to participate in wholesale demand xesponse^ prograxns. The Commission finds that the General Assembly has vested the Cornmission with broad authority to address the rate, charges, and service issues of Ohia s public utilities as evidenced in '1'itle 49 of the Revised Code, Accordingly, we eonsider this Connnission the entity to which FERC was referring in the Final Rule when it referred to 88 08-917-EL-S.SO and 08-918-BL,5SO -58- the "relevant electric retail regulatory authority." We are not convinced by Integryf( arguments that a specific act of the General Assembly is necessary to grant the Commission the authority to determine whether or not Oh4o's retail customers are permitted to partlc'ipate in the RTO's deinand response programs. Next, the Conunission aclaiowledges that the PJM programs offer benefits to program participants. VJe are, however, concerned that the record indicaws that t'j1vl demand response programs cost AF,P-Ohio's other customers as the load of AEP-Ohio's FRR and thc cost of ineeting tliat requirement is reflected in AEP-Ohio's reW rates. Finally, we are not convinced, as AEP-Ohio argues that a cctstornez's participation in deniand respoit,se prograrns is the resale of energy provided by AEPd]hio. For these reasons, we find that we do not have sufficient information to consider both the potential benefits to program participants and the costs to Ohio ratepayers to determine whether this provision of the E.SP wiA produce a significant net benefit to F1Ef'-Ohio consumers. The Commission, therefore, concludes that this issue must be deferred and addressed in a separate proceeding, w2uch will be established pursuant to a subsequent entry. Although we are not making a determination at this time as to the appropriateness of such a provision, we direct A13P to modi,fy its .p.SP to eliminate the provision that prohibits participation in PJM demand response programs. U. Inte ated Gasification Conibined Cvcle (IGCC In Case No. CI&-376-EIrUNC, the Conunission concluded that it was vested with the authority to establish a mechanism for recovery of the costs related to the design, construction, and operation of an IGCC generating plant where that plant fulfills AEP- Ohio's POLR oblip,ation and, therefore, approved the Phase I cost recovery mechawsm included in the Companies` application.33 Applications for rehearing of th.e Commission's IGCC Order were tiinely filed and by entry on rehearing issued June 28, 2006, the ComnRission denied each of the applications for rehearing (IGCC IZehearing Entry). Further, the IGCC Rehearing Entry conditioned the Cotnmission's approval of the application, stating that: (a) all Phase I costs would be subject to subsequent audit(s) to determine whether such expenditures were reasonable and prudently ancvned to construct the proposed IGCC facility; and (b) if the propased IGCC facifity was not constructed and in operation within five years after the date of the entry on rehearing, all Phase I charges collected must be refunded to Ohio ratepayers with interest. In this ESP proceeciing, AEP-Ohio witnei+s Baker testified that, a9though the Companies have not abandoned their interest in constructing and operating an IGCC facility in Meigs County, Ohio, certain provisions of SB 221 are a barrier to construction and operation of an IGCC facility. As AEP-Ohio interprets 5B 221, the Companies may be C'orupany, Case No. 05-376-Et.-L3NC, qpinbn and In re ColumbuF Saufhern Poxosr Coralrany axd Ohrn Pmucr Order (Apri110, 2006) (IGCC Order). 89 08-917-EL-SSfl and 08-918-EL-SSC) -59- required to remain in an ESP to assure an opportunity for cost recovery for an IGCC facility; the construction work in process (CWIP) provision which requires the facility to be at least 75 percent complete before it can be included in rate base; the' ^lnnit on CWIP as a percentage of tcrtal rate base which the witness contends causes particular aneerhainties since the concept of a generation rate base has no applicability unde.r SB 221; and the effect of "n7irror CWIP" (Cos. Ex. 2-A at 52-56). 'rhe C4mpanies assert that not ortly are these barriers to the construction of an IGCC facility but also to any base load generation facility in Ohio. Nonetheless, the Compantes state that they are encouraged by the fact that SB 221 recognizes the need for advanced energy resources and clean coal technology, such as an TGCC. Finally, the Companies' witness notes that, since the time the Companies proposed the IGCC facility, CSP has acquired additionaI generating capacity. According to Company witness Baker, the Companies hope to work with the Governoi'a administration, the General Assernbly, and other interested parties to enact legislation that will make an IGCC facility in. Meigs County a reality (Cos. Ex. 2-A at 55-56). OCEA ophles that SB 221 did not eliminate the existing requirement that electric utilities must satisfy to eam a return on CWIP and, since the Companies do not ask for the Commission to inake any determination in flus proceeditig or at any definite time in the fuhtre as to the IGCC faciIity, the Commission should take no action on this issue (OCEA Br. at 98-99), The Commission notes that the Ohio Supreme Court rentanded, in part, tlie Conunission's IGCC Order, for further proceedings and, accordingly, the matter is currently pending beforc the Commission. Further, as QCEA asserts, there does not appear to be any requeat from the Companies as to the IGCC facility in this proceeding. Accordingly, we find it inappropriate to rule, at this time, on any matter regarding the Meigs County IGCC facility in this proceeding. We will address the matter as part of the pending IGCC proceeding. E. Alternate Feed Service As part of the ESP, the Companies propose a new altem.ate feed service (AFS) schedute. For customers who desire a higher 1c:vel of reliability, a second distribution feed, in addition to the customer's basic service, wiil be offered. Existing AEPdahio customers that are currently paying for AFS wiIl continue to receive the service at the sarne cost under tlze proposed tariff. Existing customers who have AFS and are not paying for the service will continue to receive suc:n service uwntit AEP Jhio upgrades or otherwise makes a new investrrtent in the facilities that provide AFS to that customer. At such time, the customer will have 6 nionths to decide to discontinue AFS, take partial AFS, or carttinue AiS and pay for the service in accordance with the effective tariff schedule (Cos. Ex. 1 at £i). While c.9FIA supports the impTementat3on of an AFS schedule offering with clcarly defined terms and conditions, OHA takes issue with two aspects of the APS proposal. OI-IA witness Solganick testified that it is his understanding that the 90 08-917-Eir.`7St7 and 08-918-EL-550 customer will have six months after the custome,r is notified by the cornpany to make a decision (OHA Ex. 4 at 15). However, OHA witness Solganick advocated that s'4x months or lead was insufficient because criticat-use customers, like hospitals, require me time to24 evalvate their electric supply infrastructure and needpurposes .)jdAB Moreover, OHA argueded months would be more appropriate for planni^.tg l^'pd cost of operating AEP^ that, because this issue involves the overall management and distribution system, the Commission should defer consideration of the proposed atc AFS until AEP-Uhio's next distribution rate case where there (OHA Bmait'c29}h t}rHA treatment of the lssue as opposed to thisf15t3-dady^Yproceeding ^t the ^^ly^g rate believes that a distribution rate proceedinl, structure for AFS is correct, siun.ilar to the argument for deferring decision on other distribution rate issues presented in this FSP proceeding (Id.). Staff and 7.EU also agxee that the issue should be addxessed in a di.stribution rate case (Staff Ex. l at 4; IEU Ex. 10 at 11). Idowever, IEU further reconvnends that the Comn-assion deny the Companies' request because it is not based on prudently incurred costs (IEIJ Hr. at 75-26). The Companies retort that, while they may have some flexibility as th^^on for provided customers, such notice is limited by the Companies pl.annht$ distribution facilities and the lead time required to complete construction of upgraded APS facilities (Cos. Reply Br. at 122). The Companies reason that, while more than. 6 months may be feasible, anything more than 12 rnanths wouid not be prudent and, in certain rare eircucnstances, would not facilitate the construction of complex facilities (Id.). Nonetheless, the Companies stated that they will commit to 12 znonths notice to existing APS customers for the need to make an election of service (id.). However, the Companies vehemently opposed deferring approval of their proposed AFS sractiCes currentiy be^g proceeding, stating that the proposed AFS tariff codifies existing p addressed on a customer-by-customer contract addendum basis (Id.). Further, the Companies argue that IEU has nat presented any basis to support the implication that the AFS schedule will recover isnprudently incurred costs (Id. at 12,',). Thus, AEP-C)hio cantends there is no good reason to delay intplementation of the AFS schedule with the understanding that the Companies will provide up to 12 months notice to existing customers (Id. at 122-123). AS previously noted in this order in regards to other distribution rate issuea, the Commission believes that the establishment of various distribution riders and rates, including the proposed new AFS schedule, is best reviewed in a distribution rate case where all components of distribution rates are subject to review. F. l{eLE-nar^^_N_IetcrineService The Companies' ESP application includes several tariff revisfors. More specifically, the Companies propose toeliminate the one percent Iunrutation on the total rated generation capacity for customer-generators on the Companies' Net Energy 91 (}8-917-EL-SSO and 08-918-EL-SSL? -61- Metering Service (NEMS) and add a new Net Energy Metering Serv'a.ce for' Hospitals (NEMS..gI), The Companies note that, at the time the ESP application was filed, they had filed a proposed tariff modification to the NEMS and Minimum Requiiements for Distribution System Tnterconnection and Standby Service in Case No. 05-1500-FiL -...-'C)I.M The Companies state that upon approval of the modifcatlons filed in 05-1500, the approved modifications will be incorporated into the tariffs filed in the FiSP case (Cos. Ex. 1 at 8-9). OHA identifies two issues with the Companies' proposed NEM6-H schedule. First, OHA asserts the conditions of service are unduly restrictive to the extent that NEMS-H requires the hospital customer-generator's facility must be o'svned and operated by the custcrmer and located on the customer-generator's preniises. OHA asserts that this requirement prevents hospitals from benefiting from economies of scale by utiliz9ng the expertise of distributed generation or cogeneration companies, centralized operation and maintenance of such facilities, and shared expertise and expenses. Further, OHA asserts that the requirement that the faeility be .locatecl on the hospital's premises is a barrier because space limitations and legai and/or financing requirements may suggest that a generation facility be located on property not owned by the hospital. Of3A argues that the Cbmpaniea do notcite any regutatory, operational, financial, or other reason why the ownership reciuirement is necesuary. Therefore, OHA requests that the Commission delete this condition of service and require only that the hospital contract for service and comply wittr the Compan.ies' interconnection requirements (OHA Ex. 4 at 8-10). AEPd7hio responds that the requirernent that the generation facility be on-site and owned and ciperated by the customer is a provision of the currently effective NF.,MS schedule. Further, the Companies argue that economies of scale may be accompiished with multiple hospitals contracting with a third-party to operate and maintain the ge.neration facilities of each hospital. Further, AII'-Ohio argues that there is no support for the claim that efficiencies can not be had if the hospital, rather fhan a thi.rd-party developer, is the ultimate owner of such fac.ilities (Cos. Br. at 128). As to OFIt1's opposition to the requirement that the hospital own and operate the generation facility on its premises, AEP-Ohio contends that such is required based on the language in the definitions of a customer-generator, net metering system, and self-generator at Section 4928.02(A)(29) to (32), Revised Code (Cos. Reply Br. at 124-125). Second, OI-iA argues that the payment for net deliveries of energy should include credits for transmission costs that are avoided and energy losses on the su$trarisadssjcu`` and distribution systerres that are avoided or reduced. Further, OHA requests that such payments for net deliveries should be made monthly without a requirement for the ^!n t7te MatfGr nf the AypLi nl on af tJr Cvnrmrssior['s Re-vierv to Prrnlfsiotu,^ of the ferYeral Ert°.rgy Policy Act of Resjwnse, Cogeaerativn, and ?onri r Product'°r<. Case 200512egardiag Nef Ivteferin& Smrtrt Meferirrg; Aemarrd No. 05-1500-EL-COI (05-1500). 92 -62- 08-917-EL-SSO atzd 08-918-ELr5SO customer-generator to request any net payment. The Companies propose to naake such paymettit annually upon the customer's request (OHA Ex. 4 at 11-12). The Companies assert that OI-IA assurnes that the customer-generator s activities will reduce transmission, subtransmission, and distribution line losses and there is no support for OI-TA's contention. Further, AEP-C7hio argues that annual payment is in compliance with Rule 4901:1-10-28(I:)(3), Ohio Administrative Code (O.A.C.) (Cos. Reply Br. at 124). OHA witness 5oiganick conceded that the annual payment requirement is in compflance with the Commission's rule (Fr. Vol. X at 118-119). Staff submits that the Companies' proposed NEM5-H tariff is premature given that requirenients for hospital net metering are currently pending rehearing before the Comrnission in the 06-653 Case. Thus, Staff proposes, and OHA "supports, that the Companies withdraw their proposed NEiviS-1i and refile the tariff once the new rcqnirements are effective or with the Companies' next base rate proceeding, whichever occurs first (Staff Ex. 5 at 9; 0I-IA Reply Br. at 9). AEP-Ohio argues that the statas of the 06-653 Case should not postpone the implementation of one of the objectives of SB 221 and notes that, if the final requirements adopted in the 06-653 Case impact the Companies' NEiviS-13, the adopted requirements can be incorporated into the NEMS-H scheduIe at that tirne. As the C,onunission is in the process of deterntining the net energy meter service requireinents pursuan.t to SB 221 in the 06-653 Case, the Commission finds AEP-Ohia`s revisions tn its net energy metering service schedules prematuxe. Therefore, the Corrtmission finds, as proposed by Staff and supported by OI-IA, the Companies should ref9le their net metering tariffs to be consistent with the requirements adopted by the Commission in the 06-653 Case or with the Companies' nerct base rate proceeding. G. Green Pricin and Renew bte e Credit Purchase Pro ams OCEA proposes that the Commission order AEP-Ohio to continue, with the input of the D5M coIlaborative, the Companies' Green Pricing Program and to require the Companies to develop a separate residential and smali commercial net metering customer reriewable energy credit (REC) purchase program. OCC witness Gonzalez reconcmended a rnarket-based pricing for RECs. On brief, OCEA proposes an Ohio mandatory market hased rate for in-state solar electric application and a diffexent rate for in-state wind and other renewable resources. OCEA asserts that the prrograms will assist custamers with the cost of owning and using renewable energy and assist the Companies in meelfng the renewablc energy requirements (CJCC Ex. 5 at 10-11; Tr. Vol. IV at 232-234; OCEA (3r. at 97-98). 93 -b3- 0B-917-EL-SS{7 and O8-918-EL-5S0 The Companies argue ttlat, pnrsuant tp the stipulation agreement approved by the Commission in Case 1`Io. 06-1153-EL-LJNC,35 the Green Pricing Program expired December 31, 2006. Further, the Compardea note that the Cornmission approved the expiration of the Green f'ricing Program by the Pinding and Order issued in Case No. 08- 1302-EL-.ATA.36 However, the Companies state that they intend to offer a new green tariff option dnring the EBP term (Cos. Ex. 3 at 13). Accordingl.y, the Companies request that the Conlanission OCEA's request to defail. or adopt a new green tariff option at this time. In regards to 0CEA'9 RFC propn.gal, the Coinpanies assert that the prescriptive piicing recommendation presented on brief is at odds with the testimony of tJCCs witxiess. Further, the Companies note that OCC's witness acknowledged the adrniriistrative and cost-effective issues associated with the proposat. Thus, the Companies note that, as OCC's witness acknowledged, the proposal requires further study before being implemented. CNhile the. Commission believes there is merit to green pricing and REC programg and, therefore, ericourages the Companies to evaluate the feasibility and benefits to implementing such programs as soon as practicable, we decline to order the Covnpanies to initiate such prop,mns as part of this ESP proceeding, as it is not necessary that these optional requests be pursued by the Companies at this time. Accordingly, we find that it is unnecessary to modify AEP-f3hio's FSP to include any green pricing alid Si,EC programs, and we decline to do such modification at this time. H. Gavin qcrnbber Lease The Companies note that in the Gavin Scrubber Case,37 the Contmission authorized OP to enter into a lease agreement with JMG Iznding, L.P. QMG) for a scrubber/solid waste disposal facilities (scrubber) at the Gavin Power Plant. Under the terrns of the lease agreement, the agreement may not be cancelled for the initia115-year tertn. After the initial 15-year period, under the Gavin lease agreement, OP has the option io renew or extend the lease for an additional 19 years. OP entered into the lease on January 25,1995. Therefore, the initial lease period ends in 2010, and at that time, OP wiII have the option of renewing the Gavin scrubber lease for an additional 19 years, until 2024. On Apri14, 2009, OP filed an application for authority to assume the obligations of JMG and restructure the financing for certain JMG obligations ut the dI' and JMG caseA In the OP and JMG case, the Corrunission approved QI''s request subject to two conditions: OP must seek Comrnission approval to exercise the option to purchase the Pozver Conipany, Case No. 06-1153-EGT3NC (May 2, 35 In re Coiunibus Soirtlunn Fower Conipany and Ohio 2007). Ohio Power Campany, Case No. 0£5-1342 EI`ATA 36 ln re Co[umlrus Southern Pomer Conrpuny and (December 19, 2008). 37 In re O16 Power Coinpany, Cuse No. 93-793-EL-A1S, Opinion and C3rdex (December 4,1993). Case No. 08-498-EI.rNS, Finding and Orde= (June'!. 2W8). 38 In re Ohio PGnver Company, 94 08-97.7-T3i.-S.SO and 08-916-EL-SSO -64- Gavin scruhbers or terminate the lease ageeement; and OP must provide the Commission u*ith details of how the company intends to i.ncorporRte the project into its ESP (Cos. Ex. 2-A at 56-58). As part of the Companies' ESP application, OP requests authority to return to the Commission to recover any increased costs associated with the Gavin lease (Cos. Ex. 2-A at 56-58). The Companies state that a decision on the Gavin scrubber lease has not been made becluse the market vaiue of the scrabbers and the analysis to detertnine the least cost option is not available at this time. The Commission recognizes that additinnal information is necessary for the Companies to evaluate the options of the Gavin lease agreement and, to that end, we heiieve that AIiP-Ohio should be permitted to file an application to request xecognition of the Gavin lease at the time that it makes it6 decision as to purchasing or terminating the lease. Once the Com.panie.s have niade their eleCt'son, they should conduct a cost benefit analysis and file it with the Comntission prior to seeking recovery of any incremental costs associated with the Gavin scrubber lease. 1. Section V.E (fnterim Plan) The Companies assert that this provision is part of the total ESP package and should be adopteci. The Companies reqnested that the Corroniseion authorize a rider to collect the difference between the ESP approved rates and the rates under the Companies' current SSCf for the length of tin-te between the end of the December 2008 billing month and the cffective date of the new ESP rates. dv`order. We find 9ection I.ti of the proposed ESP to be moot ^^'this opiniony 2. The Commission issued finding and orders on Iaecember 19, ] and Februar, 20i?9, interpreting the statutory provision in Section 4928.7.4(C)(1, Revised Code, and approving rates for an in.terim period until such tizne as the Commission issues its order on AEP's proposed ESP 39 Those rates have been in effect with the first billing cycle in January 2009. Consistent with Section 4928.141, Revised Code, wlyich requires an electic utility to provide consumers, beonning on January 1, 2009, a SSO established in accordance with Section 4928.142 or 4928.143, Revised Code, and given that AEP-Uhia's proposed ESP term begins on January 1, 2009, and continues thraugh December 31, 2011, we are authorizing the approval of Alsi''s ESI', as modified herein, effective january 1, 2009. However, any revenucs collected from customess during the interin period rnust be recognized and offset by tttc new rates and charges approved by this opinion and order. ated Ohio Power Coarpany, Cese No. 08-1302-11-. ATA, Pinding 39 tn rc Cafumbus Sou[herrt pou rr Crnnpang mid Order nt 2-3 (17ecember 19, 2008) and Finding nru'i Order at 2(Febrnary 25, 2009). 95 08-917-EL-SSO and 08-91$-EL-SSO VII. SIGNIFICANTLY EXCE^-aSIVE EARNINC Section 4928.1A^'1(P), Revised Code, requires that, at the end of each year of the ESP, the Commission shall consider if any adjushnents provided for in the ESP: ...resulted in excessive eannings as measured by whether the earned return on common equity of the electric distribution utility is sigcvficantly in excess of the return on common equity that was earned during the same period by publicly traded comparnies, including utilities, that face comparable business and financial risk, with such adjustments for capital structure as may be appropriate. AEP--Ohio's proposed ESP SEET process may be sunnrnariaed as follaws: The book rneasure of earnings for C.SF and OF is determined by calculating net income divided by beginning book equity. 'The Companies then propose that the ROE, for CSSP and OP should be blended as the book equity an-kounts for AEP Ohio is more meaningful since CSP and OP are supported by AEP Corporation. To develop a comparable risk peer group, i.rticluding public utilities, with similar business and financial risk, AEP-Ohio'a process includes evaluating alt publicly traded U,S. fu'tns, By using data from both Value 1 ine and Compustat, AEP-Ohio applies the standard decile portfolio technique, to divide the firms into 10 different busniess risk groups and 10 different financial risk groups (loivest to highest). AEP-Ohio would then select the cell which includes AEP Corporation, To account for the fact that the business and financial risks of CSP and OP may differ frozn AEP Corporation, this aspect of the process is repeated for CSI' and OP and taken into consideration in deterntining whether CSP's or OP's ROlis are excessive. The ESP evaluate9 business risk by using unlevered Capital Asset Pricing Mod.el betas (or asset betas) and the financial risk by evaluating the book equity ratio. The Conipanies assert that the book equity ratio is more stable fxom year to year and, therefore, is considered by fixed-income investors and credit rating agencies. The F9P utllized two standard deviations (which is equivalent to the traditional 95 percent confidence level) about the mean ROEs of the comparable risk peer group and the utility peer g'roup to deterrnine the starting point for which CSF's or OF's ROE may be considered excessive (Cos. Ex. 5 at 13-42). Pinally, AEP-Ohio advocates that the earnings for each year the SEET is applied should be adjusted to exclude the margins associated with OSS and accounting earnings for fuel adjustment clause deferrals for wlucit tl-te Companies v1i1l nct have collected revenues (Cos. Ex. 2-A at 37-38; Cos. Ex. 6 at 16-17; Cos. Ex. 2 at 39140). OCC, OEG, and the Commercial Group each take issue with the development of the comparable firms and the threshold of significantly excessive earnings. Kroger and OCEA argue_ that the Companies' statist'scal process for deter,ni„i„g when CSF and OP 96 08-917-EL-SSQ and 08-918-EI.-SS47 -66- have eamed significantlyexcessive earnings improperly shifts the burden of proof set forth in the statute from the company to other parties. OCC witness Wootridge devetoped a proxy group of electric utfliti.es to establish the business and financial risk indicators, then uses Value Line to develop a data base of compatues witli business and financial risk indicators within the range of the electric- utility proxy group. Woolridge suggests computing the benchmark ROE for the comparable companies and adjusting the benchniark ROE for the capital structure of Ohio's electric utility conipanies and adjusting the benchmark by the FERC 150 basis points ROL adder to determine significantly excessive earnings (OCC Fac. 2 at 5•6, 20). AEP-Ohlo argues that OCC's process is contrary to the language and spirit of Sec.l:ion 4928.143(P), Revised Code, as the statute requires the comparable fixzxis include non- utility firms. The SEEP proposed by OCC witness Woolridge results in the sayne cornparable list af firnis for each Ohio electric utility evaluated (Cos. Ex.B-A at 5-6). OEG proposes a method to establish the comparable group of finns by utilizing the entire list of publicly traded electric utilities in Value Line's Jlatafile,40 artd one group of non-uti.lity firrns. The comparable non-utility group is compased of Compames' with gross plant to revenue between 1.2 and 5.0, gross plant in excess of $1 billion and companies for which Value Line has a beta (QEG Ex. 4 at 4-6). OEG then calculates the difference 9n the average beta of electxic utility group and the non-utility group and adjust it by the average historica[ risk premiutn for the perlod 1926 to 2008, which equals 7.0 percent to deterrrtine the adjustment to account for the reduced risk associated with utilities. Thus, for example, for the year 2007 OEG determined that the average non- utility earned return of 14.14 percent yields a risk-adjusted return of 12.82 percent. OEG then applies an adjustment to recognize the financial risk differences of AEP-Ohio to the utility and non-utility comparison groups. Finatty, to determine the level at which eaxztings are "significantly excessive," OEG suggests an adder of the 200 basis points to encourage investments (OEG Ex. 4 at 7-9). OEG argues that the use of statistkal confidence ranges as proposed by AEP-Ohio would severely limit any finding of sxcessive earnings as a two-tailed 95 percent confidertce interval would mean that orily 2.5 percent of all observations of all the sample company groups would be deemed to have excessive earnings. Further, OEG argues that as a statistical analysis the AEP-Ohio- proposed method elirninates most, if not all, of the Commdssion's flexibility to adjust to econonzic circumstances and detertnine whether the utility company's eart>utgs are sigiuficantly excessive (OEG Ex. 4 at 9-10). AEP-Ohio contends ttlat OEG's SfiET method fails to comply cvith the stitutory requirements for the SEET, fails to control for financial risk of the comparable sample gcroups, fails to account for business risk and wilt, like the process proposed by OCC, 40 OZ:G would etiminate one company wittl a signiticantnegative return on equity far 2W7. 97 08-917-E1 rS80 and 08-918-EI.cSO . -67- produce the same comparable non-utility and utility group for each of the Ohio electric utilities (Cos. Ex. 5-A at 8-9). The Commercial Group asserts that AEP-Ohia's proposed SEET inethodology will produce volatile earned retarn on equity thresholds and, therefore, does not meet the prirnaxy objective of an F5P' wluch is to stabilize rates and support the econom-fc development of the state. Further, ABP-Ohio s SEET ntethod, according to the Commercial Group, fails to compost a comparable proxy group with business rzsk sinuiar to C'SP and C1I', including urtregulated nuclear subsdiaries and deregulated generation subsidiaries. 'I'hus, Commercial Group recommends a comparable group consist of publicly traded regulated utility companfes as detertnined by the Edison Electric Institute (FiEI}. Commercial Groixp witrtess Gorman notes that using EEI's dmignated group of regulated entities and Value Lines earned return on common equity shows that the regulated companies had an average return on equity of approximately 9 percent for the period 2005 ihrnugh 2008. Witness Gornaan contends that over the period 2005 through 2008 and projected over the next 3 to 5 years, approximately 85 percent of the earned return on equity observations for the designated regulated electric utility companies will be at 12.5 percent return on equity or less. Therefore, Coinniercial Group recommends that the SEET test be based on the Commission-approved return on equity plus a spread of 200 basis points. Commt`rcial Group witness Gorrnan reasons that the average risk, extremc risk and beta spread over AEP-Ohi.o`s proxy group suggest that a 2 percent/200 basis points is a conservative determination of the excessive eaniings threshold (Commercial Group Ex. 1 at 3,12-17). t1.&P-()hio argues that the Commercial Group's proposed SEET fails to develop a comparable group as required by the SEET and ignores the fact that the rate of return is a forward-looking analysis and the SEE.T is retrospective. Thus, AEP Ohio concludes that this method does not address the measurement of financial and business risk (Cos. Ex. 5-A at 9-10). OCC opposes the exclusion of accounting earnings for fuel adjustment clause deferrals and the deduction of revenues associated withOSSS, as OSS are not one-time write-offs or non-recurring items (OCC Ex. 2 at 21). OCC contends that revenues associated with the deferrals are reported during the same period with the Companies fuel-related expenses and to eliminate the deferrals, as AEP-Ohio proposes, would reduce the revenues fc;r the period without deducting for the underlying expense (OCC Reply &r. 69-70). Similarly,lCroger proposes that A.EI'-Dhio credit the fuel adjustment clause for the margin generated by OSS and notes that AEP Corporation's West Virginia and Virginia electric distribution subsidiaries currently do so despite AEP-Ohio's assertion that such is in violation of federal law (Kroger Ex.1 at 9). 98 O9-917-Ef_-.5:50 and 08-91$-EL-SSO Staff advocates a single SEET methodology for all electric distribution utilities as to the selection of comparable firms and, further, proposes a workshop or technical conference to develop the process to detctmine the "comparable group earnings" for the SEET. Staff witness Cahaan reasons that the SEST proposed by AEP-Ohio as a technical, statistical analysis, if incorrect3y forinulated shifts the burden of proof from the company to the other parties. Staff also contends that the Companies' SEET proposal is based upon a de.#inition of significance which would create intermal inconsistencies if applied to the statute. Further, Staff believes the "zone of reasonable" earnizgs can be framed by a return on equity with an adder in the range of 200 to 400 basis poinis. rurther, Staff recogni.zes that if, as AEP-Ohio suggests, revenues from 05S are excluded from SEET, other adjustments would be required. Staff believes it would be unreasonable to predetermn2e those other adjustnients as this t'une. Thtis, Staff proposes that this proceeding determine the Xnetltod of establishing the comparable group and specify the basis points that will be used to determine "significantly excessive earnings." Staff clairns . that under its proposed process, at the end of the year, the ROE of the comparable group could be compared to the electric utility`s 10-K or FER.C-1 and, if the electric utility's ROE is less than that of the sum of the coinparable group's ROE plus the adder, it wilf be presumed that the electric utility's earnings were not significantly excessive. Further, Staff asserts that any party that wislies to challenge the presumption would be required to demonstrate otherwise, ff, however, the electric utility's earned ROE is greater than the average of the con-iparable group plus the adder, the e7ectric rrtility would be required to demonstrate that its earnings are not sign3ficantly excessive (Staff Ex. 10 at $,16,19, 21-24, 26-27; Staff lir, at 27). OCEA, ONfA, and the Commercial Group recommend that the comparable firm process for the SEET be detertnined, as Staff proposes, as part of a workshop (aCEA Br. at 110; OMA Br. at 13; Commercial Group Hr. at 9). I'he Conunission believes that the deterntination of the appropriate methodology for the SEET is extremely important. As evidenced by the extensive testimony in this case concerning the test, there are many diffei.'ent views concerning what is intended by the statute and what methodology should be utilized. However, as pointed out by several parties, whatever the ultimate determination of what the niethodology should be for the test, the test itself will not be actually applied until 2010 and, as proposed by the Comparues, will not commence until August 2010, after Compustat information is n-ade publidy available (Cos. Ex. 5 at 11-12). Therefore, consistent with our opinion and order issued in the FirstEnergy ESP Case,41 the Comrnission agrees with Staff that it -would be wise to examine the rnethodolof,ry for the excessive earnings test set forth in the statute within the framework of a workshop. This is consistent with the Cornniissiosfs finding that the goal of the workshop will be for Staff to develop a common methodology for the C.ampazLy,, and tFza TalEdo Ertison Cozrtpany, 41 in re Ohio Edisozz Company, The Cletietand Elechxc Itiumiraatbzg Case No. 0$-935-ELfSSO, Opumion and Order (December 19, 2008). 99 08-917-EL,SSO and 08-918-E1.-pn.SO excessive earnings test that should be adopted for all of the electric utilities and then for Seaff to report back to the Comniission on its find2ngs. Despite A.SP-Ohxo's assertions that FirstEnergy's ESP is no longer applicable since the FirstEnergy companies rejected the rnodified ESP, the Contmission finds that a common methodology for significantly excessive earnings continues to be appropriate given that other FiSP applications are currently pending and, even nnder AEP-Ohio's ESP appl€cation, the SEET information is not available until the July of the following year. A.ccordingiy, the C:omxntssron finds that Staff should convene a workshop consistent with this determniation. However, notwithstanding the Commission's conclusion that a worlsshop process is the method by zvhich the SEBT wiIl be developed, we recognir.e that AEP-O2v.o must evaluate and fleternune whether to accept the ESP as modified herein or reject the modified ESP and, ihere€ore, require clarification of our decisiun as to C?aS and deferrals (Cos. Reply Br. at 134). We find that a determination of the Companies' earnings as "significantly excessive,, in accordance with Section 4928.143(F), Revised Code, necessarily excludes OSS and deferrals, as well as the related expenses associated with the deferrals, consistent with our decisian regarding an offset to fuel costs for any OS5 marglns in Section III.A.1.b of this order. The Commission believes that deferrals should not have an impact on the SfifiT until the revenues associated with deferrals are received. Further, although we conclude that it is appropriate to exclude off-system sales from the SEET calculation, we do not wish to discourage the efficient use of C)P'a generation facilities and, to the extent that the Companies' earnings result from wlwlesaie sources, they should not be considered in the SEET calculation. Vill. IvIItO V. ESP The Companies argue that "[t]he public interest is served if the ESP is more favorabie in the aggregate than the expected results of an MRO" (Cos. Br. at 15), 7'he Companies' further argue that the state policy set forth in Section 4928.02{A), Revised Code, is satisfied if the price for electric service, as part of the FSP as a whole, is n-Lore favorable than the expected results of an MRO (Id.). The Contpanies aver that not only is the S.SO proposed under the ESP more attractive than the SSO resulting froman MRO, other non-S5O factors exist adding to the favorability of the ESP over the MItO (Cos. Ex, 2-A at 4,8; Cos. Ex. 3 at 14-19). Specifically, AEP calculated the market prlce competitive benclunark for the expected cost of electricity supply for retail electric generation ScaO custorners iti the Companies' service territories for ttre next three years as $88.15 per IvlWl'i for CSP and $85.32 per Ivn^H for C5P for full requirements service (C--,,-.. Ex. 2-A at 5). These conlpetitive benchniark prices were calculated by AEP using market data frorn the first five days of each af the first three quarters of 2008, and averaging the data (Id. at 15}. AEP-Ohio witness Baker then compared the ESP-based SSO with the IvIItO-based SSC), analyzing the following components: market prices for 2009 tiuough 2011; the 100 0g-917-EL-SSO and 08-918-EL-SSO -70- phase-in of the MRO over a period of time pursuant to Section 4928•142, Revised Code, at 10 percent, 20 percent, and 30 pereent; the full requirements pricing components of the states of Delaware and Maryland; PJM costs; incremental environmental costs, POT.T{ costs, and other non-market portions of an MRO-based 850 (Cos. Ex. 2-A at 3-17). AEP- Ohio witness Baker also considered nonSSO costs in the comparison, such as the distribution-relateci costs of $150 million for CSP and $133 nvllion for ClP (Id. at 16-17). AEP-Ohio concluded that the cost of the ESP is $1.2 billion and the cost of the MRO is $1.5 billion for CSP, white the cost of the ESP is $1.4 billion and the cost of the MRO is $1.7 billion fcar OP (Cos_ Ex. 2-B, Revised Exhibit JCB-2). Therefore, AEP-Ohio states that the ESP far the Companies in the aggregate and for each individual company is rlearly more favorable for castomers, and would result in a net benefit to the customers under the RSP a.s cornpared to the MRO of $ 292 million for CS? and $262 million for OP (id.; Cos. Br. at 135). The Companies state that, in addition to the generation component, the FSP has other elements that, when taken in the aggregate, make the ESP considerably more favorable to customers than an MRO alternative (Cos. Ex. 2-A at 17-18). AFiP-C)hio explains that the benefits in the ESP that axe not available izt an MRO, include; a shareholder-funded conunitment focused on economic development and low-income customer assistance programs; price certainty and stability for generation service for a specified three-year period; and gridSMART and enhanced disiz9bution reliabitity initiatives (Cos. Ex. 2-A at 17-18; Cos, Ex. 3 at 16-18, Cos. Br. at 135-137). The Companies contend that once the Conunission deterntines that the ESP is more favorable in the aggregate, then the Commission is required to approve the ESP. If the Coinxnission determines that the ESP is not more favorable in the aggregate, then the Commission may modify the E.SP to make it more favorable or it may disapprove the TiSP application. Staff states that, as a general principle, Staff believes that the Companies' proposed ESP is n;ore favorable than what would be expected under an MRO (Staff Br, at 2). 1-Iowever, Staff explains that modifications to the proposed FSP are necessary to make the ESP reasonable (Id.). With Staff's proposed adjustments to the 73SP rates, Staff witness bless testified that the Companies' proposed ESP "results in very reasonable rates" (Staff Ex. I at 10). Purthermore, Staff witness Hess demonstrated, utilizing Staff v+itnwEs johnson's estimated market rates, that the ESP is rnore favorable in the aggregate as compare.^d to the expected results of an MRO (Staff Ex. 1-A, Revised. Exhibit fEH-1; Staff Br, at 26). Several intervenors are critical of various components of AEP-Ohio's proposed ESP and thus conclude that the E51", as proposed, is not more favorable in the aggregate and should be rejected or substantially modified, or that AEP-Ohio has failed to meet its 101 -71- 0$-917-EL-SSa and 08-918-EL-SSO burden of proof under the statute that the proposed ESP, in the aggregate, is more favorable than an MRO (OPAE Br. at 3, 22-23; OMA Br. at 3; Ksoger Br. at 4; OI-IA Sr. at 11; Commercial Group Br. at 23; OEG Br. at 2-3; Constellation Br. at 16•1$). More specifically, OHA contends that the Commission must take into account all ternis and conditions of the proposecl ESP, not just pricing (OHA Br. at 8-9). OI3A further explains that the Commission must weigh the totality of the circtanstances presellted in the proposed ESP with the totality of the expected results of an MRL) (Id. at 9). OH.A also states that the proposed ESP fails to rnftigate the har.n-tfizl effects of new regulatory assets, peoposed deferrgs, and rate increases on hospitaZs and, therefore, the E5P does not provide benefits that make it more favorable than a simple MRO (1cd. at 11). IEU asserts that both the Conlpanies` and StafPs comparison of the bSP to an MRO are flawed becauscy the comparisons fail to reflect the projected costs of deferrals, assume the ma;imum blending percentages allowed under 4928.142, Revised Code, and fail to desnonstrate the incrernental effects of the maxizmmm, blending percentages on the FAC costs (IEU 13r. at 33, citing Cos. Ex. 2-A, Staff Ex.1, Exhibit jF.I-I-1, Tr. Vol. XI at 78-$2, and Tr. Vol. XIII at 87-86). OCEA dispntes the Companies coniparison of the ESP to the MR(?, stating that the Conlpanies liave overstated the competitive bencltmark prices (QCC Eu.10 at 15; OCrA Br. at 19-24). Based on data from the fourth quarter 2008, and taking in consideration adjusttnents for load shaping and distribution losses, t7CC calculates that the updated competitive benchrnark prices should be $73.94 for CSP and $71.07 for OP (C?CC Ex. 10 at 15-24). (7CEA also questioned other underlying components of AEP witness Baker's comparison of the MRO to the ESP regarding the proposed ESP, as well as the exdusion of certain costs in the MRO caleulation (fd. at 37-40). Nonetheless, OCF-A ultimately concludes that AEP's ESP, if appropriately modified, is more favorable than an MRO (C}CEA Br, at 19-24; OCC Ex. 10 at 39). Constellation also submits that the forwaid market prices for energy have fallen significantly since the Companies' filed their application and submi.tted their supporting testimony (Cbnstellation Ex. 2 at 16). Contrary to the position taken by ConsteIlation and OCEA,42 AEl'-Ohio contends that the market price analysis supplied in support of the ESP does not need to be updated in order for the Commission to detennine whether the FSP is rnore favorable that the expected result of the 2vIRO. Furthermore, AEP-Ohio responds that the appropriate method is to look over a longer period of time, and not just focus on the recent decJlne in forward market prices. (Cos. Reply Br. at 130-131). Contrary to argtrments raised by various intervenors, AFiP-Ohio avers that the legal standard to approve the E9P is not whether the Commission can make the FSP even more favorable, whether the rates are just and reasonable, whether the costs are prudently 42 Constellation Br. at 17; OCEA Br. at19-24. 102 -72- OS-917-Et.-SSCI and 06-918-EL-SSO incurred, krhether the plan pravisions are cost-based, or whether each provision of the plan is more favorable than an MRO (Cos. Reply Br. at 1-6). The Companies contend that the Commission only has authority to modify a proposed ESP if the CommiSsion determines that the ESP is not more favorable than the expected results of an MRO (Id. at 4). As some intervenorr have recogitized,43 the Conunission does not agree that our authority to make modificaiions is Iimited to an after-the-fact determination of whether the proposed E.SP is more favorable in the aggregate. Rather, the Commission finds that our statutnry authority includes the authority to make modificafions aupported by the evidence in the record in this case. Based upon our opinion and order and using Staff witness Hes,a methodology of the quantification of the ESP v. MRO comparisori, as znod`zfied herein, we believe that the cost of the ESP is $673 million for CSP and $747 miIlion for OP, and the cost of the MRO is $1.3 bilIion for CSP and $1.6 billion for C1P. Accordingiy, upon consideration of the application in this case and the provisions of Section 4928.143(C)(1), Revised Code, the Commission finds that the ESP, irxluding its pricing and all other terms and conditions, including deferrals and future recoveYy of deferrals, as modified by this order, is more favorable in the aggregate as compared to the expected results that would otherwise apply under 5ection 492E3.142, Revised Code. IX. CC7NCLUSION The Coirunission believes that it is essential that the plan we approve be one that provides rate stability for the Companies, provides future revenue certainty for the Com.panies, and affords rate predictability for the customers. Upon consideration of the application in this case and the provisions of 5ection 4928.123(C)(1), Revised Code, the Commission finds that the E,ST', including its pricing and all other terms and conditions, including deferrals and future recovery of deferrals, as modified by.this order, is niore favorable in the aggregate as compared to the expected results that would otherwise apply under Section 4928.142, Revised Code. Therefore, the Commissian finds that the prciposed tttree-year ESP should be approved with the ntodifications set forth in this I order. To the extent that intervenors have propos^-' d modifications to the Companies' ESP that 11ave not been addressed by this opinion and order, the Commission concludes that the requests for such modifications are denied. Furtherrnore, the Commission finds that the Cornpanies should file revised tariffs consistent with this order, to be effective with bills rendered januazyy 1, 2!7t?9. In light of the timing of the effective date of the tariffs, the Conunission finds that the revised tarif#s upon filing, effective January 1, 2009, as set forth herein, and contingent shall be approved upon final review by the Commission. 43 OEG Br. at 3. 103 -73- 08-917-EL-SSO and 06-918-EL-SSO FINDINGS OF FACT AND CONCLCISIONS OF LANf: (1) CSP and OP are public utilities as defined in Se.'ction 4905.02, Revised Code, and, as such, the companies are-flubject to the jurisdiction of this Commission. (2) On July 31, 2008, C.SP and OP fi]ed applications for an S9C7 in accordance with Sectioti 4928.191, Revised Code. (3) On August 19, 2008, a technical conference was held regarding AEP-Ohio's applications and on November 10, 2008, a prehearing conference was held in these niatters. (4) On Septeinber 19, 2008, and October 29, 2008, intervention was granted to: OEG; OC:C; Krogex; C)EC; IEU-()hio; OPAE; APAC; OHA; Constellation; Dominion; NRDC; Sierra; NEMA; Intey,rys; Direct Energy; OMA; OFBF; Wind Patergy; OASBOjOSBAJB.ASA; Clnnet; Consumer Powerline; Morgaxt Staziley Capital Group lnc.; Commercial Group; EnerNoc, Inc., and A.ICC3O. (5) The hearing in these proceedings conunenced on November 17, 2008, and concluded on December 10, 2008. Eleven witnesses testified on behalf of AEP-Ohio, 22 witnesses testified on behalf of various intervenors, and 10 witnesses testitied on behalf of the Commisslon Staff. (6) Five local heati.ngs were held in these matters at which a botal of 124 witnesses testified. (7) Briefs and reply briefs were filed on December 30, 2008, and January 14,2009, respectively. (8) AEP-Ohio's applications were filed pursuant to Section 4928.143, Revised Code, which authorizes the electric utilities to file anESP as their SSO. (9) 'Phe proposed ESP, as modified by this opinion and order, including its pricing and all other terms and conditions, including deferrals and future recovery of deferrals, is more favorable in the aggregate as compared to the expected results that would otherwise apply under Section 4928.142, Revised Code. 104 08-917-EL-SSO and 08-918-EL-SSO -74- ORDER: It is, therefore, ORDERED, TTiat the Companies' application for approval of an ESP, pursuant to Sections 4928.141 and 4928.143, Revised Code, he modified and approved, to the extent set forth herein. It is, further, ORDERED, That the Contpanies file their revised tartiffs consistent with this opinioii and order and that the rc:vised tariffs be approved effective January 1, 2004, on a bills-rendered basis, contingent upon final review and approval by the Commissiors. It is further, ORL7pS12ED, That each company is authorized to file in final form four complete, printed copies of its tariffs consistent with this opinion and order, and to cancel and withdraw its superseded tariffs. The Companies shall file one copy in this case docket and one copy in each Company's TRF docket (or may make such filing electronically, as directed in Case No_ 05-90(I-AU-WVR). The remairring two copies shall be designated for distribution to Staff. It is, further, ORDERED, That the Companies notify alf affected customers of the cliazWs to the tariff via bill message or bill insert within 45 days of the effective date of the tariffs. A copy of this customer notice slzall be submitted to the Cominission's Service Monitoring and Enforcement Department, Reli.abiiity and Service Anatysis Division at ]east 10 days prior to its distribution to customers. It is, further, 105 68-917-RT. SSC? and 08-418-&7rSSO of this opinion and order be served on all parties of recox'd., ORDERED, "Fhat a copy THE PUBLIC,14'I'tLITIES C4MMISSIC?N OF 013I© A CWeryl L. Roberto Valerie A. Lemmie TCWB/GI\TS.vrm,/ct Entered in thejournal h1AR 1 S 2w9 ,(" 9,-^^Z-:' RenO 1. jenkins Secretary 106 BEFC?RH THE PUBLIC LtTILi7TES COMMTSSIt?N OF flHZO In the Ivlatter of the Application of Columbus Southern Power Coinpanyfor Approval of its blectric Security Plan; an Case No. QS-919-BL-SSJ Amendment to its Corporate Separation Plan; and the Sale or Transfer of Certain Generating Assets. In the Matter of the Application of C)hio Power Company for Approval of Case No. 08-418-BL-SSO its Electric Security Plan; and an Amendment to its Corporate Separation I'lan. C t?NCURRANG OI'LNK>1~It7F Cl•IIILMAN ALAN R.SCHRIBER AN'C) COMmrsSiC)Nl"sg. PALTL A CENTC3LELL.A We agree with the Comm.'i.ssion`s decision and write this concurring opinion to expreas additional rationales supporting the Commission s decision in two areas. g_ridSMA--R'I' Rider The Order sets the initial amount to be recovered through the gridSlvlAitT rider based on the availability of federal ntatclung funds for smart grid demonstraiions and. deployments under the Arrrericaxt Recovery and Reirltvestment Act of 2009. AEP-Mo should proinptly take the necessary steps to apply for available federal funding. Additionall.y, AEP-Ohio should work writh staff and the collaborative established under the Order to refine its Phase I plan and initiate deployments in a timeiy and reasonable manner. The foundation of a smart grid is an open-arch.itecture communications system which, first, provides a commori platfortn for implementing distribution automation, advanced inetering, titne-dif€erentiated and dynamic pricing, home area networks, and other applications and, second, integrates these applications with existing systems to improve reliability, reduce costs, and enable consumers to better control their clectric bills. These capabilities can provide significant consumer and saeletal benefits. In the near term, participatzng cwnsumers will have new capabilities for managing their energy usage to take advantage of lower power costs and reduce their electric bills. .AET'-Ohio wflt be able to provide consumers feedback regarding their electric usage patterns and improved customer service. And, the combination of distribution automation and advanced metering should enable ATr.P-Oluo to rapidly locate damaged and degraded 107 08-917-EL^SSO and 08-918-EL-SSO 2 distribufion equipment, reduce outages, and minimize the duration of any service interruptions. We expect that consumers will experience a material iraprovement in service and reliability. SB 221 made it state policy to encourage tirne-differentiated pricing, iinpleanentation of advanced metering infrastructure, development of performance standards and targets for service quality for all consumers, and implementation of distributed generation. Section 4928.02 of the Revised Code. The Comtnission's Order advances these policies. .AF'P-Ohio and its custornei•s are likely to face significant challenges over the next decade from rising costs, requirements for improved reliability, and environmental constraints. Our Order will enable AEP-Ohio to take a first step in developing a modem grid capable of providing affordable, reliable, and environmentally sustainable electric service into the future. I']M Demanci Res^onse program First, we wish to emphasize that the Comrnission suppor.'ts demand response initiatives. Second, it is essential that consumers benefit from demand response in terms of a reduction in the capacity for which ATiP-Ohio customers are responsible. We encourage AEI'-Ohio to work with I'jM, the Commission, and interested stakeholders to ensure that predictable consumer demand response is recognized as a reduction in capacity that it must carry under PJM market rulE.w. Finally, consumers should have the opportunity to see and respond to changes in the cost of the power that they uae. While an ESP may set the overall level of prices, consumers should have additional opportunities to benefit by reducing consumption whe.n wholesale power prices are ltigh. We would encourage the companies to work with staff to develop additional dynamic pricing options for commerci.al and industrial SSC3 customers who have the inierval metering needed to support such rates. Such options should enablgqigible copsumys to directly manage risk and optiniize their energy usagc. ^^^.^ Alan R. Schriber Paul A. Centoletla 108 ATTACHMEN-T B ATTACI-xMENT B BIsWORE THE PUI3h1C UTILITIE.S COMMISSION OF UHIC) In the Matter of the Application of Columbus Southern T'ower Coxnparty for,Approvai of. an Electric Security Plan; an Amendnfent to Case No. 08-917-EL-SSO its Coiporate Separation Plan; ancl the Sale ox T ransfer of Certain Geneiating Assets. In the Matter of the Application of Ohio . Pwer Company.Cnr Approval of its Blectric Case No. 08-918-EL-SSO Security Pian; and an Amendment to its Corporate Separation l'lati. ENTRY NUItIC I'l2O'I'UNC The Commissioil finds: (1) Section 4928.141, Revised. Code, provides that electric utilities • shall provide consnmers a standard servzce offer (SSO) of all competitive retail electric senrices in accordance with Section 4928.242 or 4928_143, Revised Code. (2) Qn, Jtily 31, 2005, Columbus Southern Power Company and Ohio Power Company (jointly, the Companies) filed an application for an S50, in the forln of an eFeceric security p3an (ESP) in accordance witti Sectioii 4978.143, Revised Code. (3) On March 18, 20[19, the Coinmission i.ssued an opinfon and order tltat approved the Compaiiies' proposed three-year ESP (Januai•y 1, 2009, throngh December 31, 2009) with certain modifications, and directed each company to file rev4sed tariffs consistent with the opinion and order and subject to finaI review anci approval by the Commission. (4) Upon review of the opinion a-nd order, the Commission finds that inadvertent inconsistencies • exist and must be corrected. The second paragraph, under section IX oti page 72 incorrectly references Jaziuary 1, 2009, as the effective date of the tariffs. As stated on page 62, the reference to the Januaryy 1, 2009, date should be to the ESP term; not to the tariffs. It was not the Coinmission's intent to allow the Companies to re-bill cu rtomers at a higher rate for their ;[irst quarter usage. The new This is to cert.ify that tho 4magee ar.nettrinii a.r.e an accur,ate afld completa reprodcsch.a.on ox, a ua.r>:a .Z3.la docsaznzxt del•zvearod in ihl!! re.c,las.ta.r ao=w-l-Ba of buaiaesa. Taeahnioian -' ^ate FroeESee 3 3 D ^^-- 110 -2- 08-917-iil: 554, ei al. rates established pursuant to the B..SP were not to go into effect until final review and approval by the Comrnission of the Companies' compliance tariffs. Given that our order was issued an March 18, 2009, and that the Coinpanies existing tariffs appf'oved by the Cornmission were scheduled to expire no iater than the iast billing cycle of March 2009, it was anticipated that the new rates would not become effective until the first billing cycle of April. Accordingly, the second paragraph should state: Iiurthermore, the Con rnission finds that the Companies' should file revis.ed taritfs consistent with this order, to be effective on a date not earlier than both the commencement of the Companies' April 2009 billing cycle, and the date upon which f.inat tariffs are filed with the Commission. In light of the timing of the effective date of the new tariffs, the Commission finds that the tariffs shali be effctive for bills rendered on or after the effective date, and contingent upon final review by the Comi.nission. (5) Similarly, the second ordering paragraph on page 74 should state: ORDERED, '1'hat the Companies file their revised tariffs consiatent with this opinion and Order and that the effective date of the new tariffs be a date not earlier than both the coinmencement of the Coinpanies' April 2009 billinb cycle, and the date upon which four complete copies of final tariffs are filed with the Commission. The new tariffs shall be effective for bills rendered ori or after the effectPvc date. (6) Lastly, the secon.d paragraph under section I on page 64 incorrectly refcrences Section I.E of the proposed ESP and Section 4928.14(C)(i) of the Revised Code. Instead, the first two sentences should state: "We find Section V.E of the proposed ESP to be nioot with this opinion and order. The Coinrnission issued finding and orders on December 19, 2008, and February 25, 2009, iuiterpreting the statutory provision in Section 4928.141(A), Revised Code, and approving rates for an interim period until such time as the Comrnission issucs its order on AEP's proposed BSI'." 111 -3- ()6-917-EL-raSO, et aI. It is, therefore, ORDERED, That the opinion and arder dated Mas'ch 1°v, 2009, be amended, nidnc pro iunc, as set forth above. It is, further, ORDERED, That a copy of this entry be seived on all parties of record. I"IIE PIJBLIQ!JCILI'i'IES f:OIvfMISSIOhI Ot= OHIO ~--^^^nndfl I-IaThTtari ^^^ ^^^•^ Valerie A. Leinnue Cheryl L,IZoberto itWl3:ct Entered in ttie Jowrtia) MAR 302009 )ieile^ ^_ jCll)(ins Srcretary 112 ATTACHMENT C ATTACHME NT C B ORE T f-IA T'UI3LIC UTTLTTIF?S COMM[SSION OF OHIO In the Matter of the Application of Columbus ^ Sorithern Power Cozitpany fox ApprovaT of an Electric Security Plan; an Amendinent to ) Case No. 08-917EL-SSO its Corporate Separation Plau; and the Sale or Transfer of Certain Generaking Assets. ) )- In the Matter of the Application of Ohio Power Company for Approval of its I:lectric ) Case No. 08-918-E7rSSO Security Plan; ancl an Amendment to its ) Corporate Separation Plan. ) ENTRY ON T2fiT-3J;A[tTNG The Cornnussion finds: (1) On July 31, 200$, The Columbtis Southern Power Company {tST) and Ohio Power Company (OI') {jointly, AEP-Ohio or the Companies) filed an applicatlon for a standard service offer (SSfj) .pursuant to Section 492$.141, Revised Code, The apptication is for anelectric security plan (FSP) in accordance wifh Section 4928.143, Revzsed Code. (2) On March 18, 2009, the Corrunission issued its opinion and ordec (Otrier) in these nzatters approving, with moc3ifications, AEP-Ohio's proposed LSP. On ivlarch 30, 2009, the Commission amended, nunc pro tune, its Order. (3) 5ection 4903.10, Revised Code, states that any party to a Conunission proceeding may apply fox rehearing with re.spect to any matters determined by the Conunissioit, within 30 days of the entry of the arder upon the Coinmisszon's j,ournal. (4) On ts.pril 16, 2009, Ohio v;nergy Croi:p (OEG)'exzd L^?dustcial Energy Users-Ohio (IEi3) each filed applications for rehearing. Applications for reliearing were aTso 'filed by the OFtice of the Ohio Consumees' Counsel (OCC); Ohio Associatfon of Schbol Business Officials, . Ohio School Boards Association, and Buckeye Association of School Administrators {colTectivety, SchooTs}; Oluo Hospital Association (OHA); Ohio 114 -2- , q8-917-EL-SSC7, et al. Manufacturers' Association (OMA); ICroger Company (IGroger); and ALP-01-io on April 17, 2009. Meinoranda conkra the various applications for rehear.mg wcre filed by Kroger, OCC, AEP-Ohio, lliCl, OIC3, Integrys Energy Service, Inc. (Integrys), and Ohio Partners for Affordable Rnergy (OPAE). In their applications for rehearing, the various intervenors raised a nuniber of assigrunents of error, alleging that thc: Order is uiireasonable and unlawful. (5) 13y entry datc:d May 13, 2009, the Commission granted rehearing for further consideration of the inatters specified in the applications for rehcaring. In tltis entry, the Comn-dssion will address the assignments of error by subject matter as set forth below. (6) T'he Contmissiort has reviewed and considered all of the arguments on rehearing. Any arguments on rehearing not specifically discussed herein have been thoroughly and adequatety considered by the Conunission and are being denied. (7) IEU filed a motion for immediate relief froin electric rate increases on Apri120, 2009, and AGT'-(Jhio filed a menzorandum contra on April 23, 2009. 11;U filed a reply on April 24, 2009. Further, on June 5, 2009, OCC, OMA, Kroger, and OEG filed a motion f.or a refurid to AEP-Ohio's customers and a motion for AEP-Ohio to cease and desist future collections related to its arrangement with Ormet Primary Aluminunl Corporation (Ormct) from its customers. AEP-Ohio and th'cnet filed memoranda contra the nFotions on June 12, 2009, and June 23, 2009, respectively, and the movants replied on June 17, 2009, and June 30, 2009. OCC also indicates in its application for rehearing that it is seeking rehearing on the two March30, 2009, orders issued by the Commission, which includes the Entry Nunc Pro Tunc that amended the Order in this proceeding, as well as the order issued denying a motion for a stay. The Commiasion will address the substance of all of the n'totions, and all responsive plead'uigs, within aur discussion of and decision on the merits of the applications for rehearing as set forth below. Accord'uigly, with the consideration herein of the issues raised in the motinns, the motions are granted or denied as discusseci hereiat 115 08-917-ET,SSO, et al. -3- 1. C TsNB12A'IION A. Luel A djustment L:lause {FAC) (8) AEP-Ohio asserts that limiting the FAC to only three years (the term of tl,e ESP) is unreasonably restrictive (Cos. App. at 37-38). AI;t'-Ohio argues that it is um'easonable to allow the FAC to expire given that a FAC may be required in a futrire 550 established in accordarue with 5ecNon 4928.141, Revised Code. (9) IEU anci OCC disagree with AEP-Ohio and submit that there is na valid rcason for the FAC mechanism to extend beyond the life of the I:SP (ILU Memo Contra at 13; OCC Memo Contra at 6- 7). (10) `f71e Commission finds that AHP-Lahio's argunient lacks merit, ai-kci therefore AEP-Ohio:s rehearing request on this gtound should be denzed. The Commission Iimited the authorized FAC mechanism, established as part of the proposed ESP, to the terrn of the ESP approved by the Commission. If a FAC inechanism is proposed in a suhsequent SSO application filed pursuant to Section 4928.141, Revised Code, Lhe Conunission -will determine the appxopriateness of the SSO proposal, including all of its terms, at that tune. It is unnecessary, at this time, to extend this provislon of the PSP beyond the terin of ihe approved ESP. 1, FAC Costs (a) C)ff-Svstem Sales !C}SS} (11) dCC contends that the Commission erred by not crediting c.ustonvers for revenues from OSS and for not following its own precedent (OCC App. at ]6). OCC relies on past Commiission decisions concerning electric fuel clause (EFC) proceedings. (12) IEU also disagrees with the exclusion of an offset to Lhe FAC costs for revenues associated with OSS, claiming that the Corlunission did not explain the basis for its decision (IEU App. at il). 116 08-917-EL: SSO, et al, -4- (13) ABP-Ohio notes that OCC's arguments were already rejected by the Conlmission in its Order, and that the Corninission's decision is not inconsistent with any of its precedents regarding the sharing of profits from flSS between a utility and its custorncrs (Cos. Memo Contra at 40). AEP-Ohio distinguishes previous rF'C proceedings from proceedings filed pursuant to SB 221. (14) The Coinmission first explains that this is not an EFC proceeding. While some aspects of the autontatic recoveiy mechanism contained in Section 4928.143(B)(2).(a), Revised Ccx3e, snay be analogous to the EFC mechanisni, the statutory provisions regarding the EFC were repealed many years ago. 'Phus, OCCs cited precedent is irrelevant to our ruling in this case with respect to the OSS. Secondly, contrary to IEI.1's assertion, fhe Commission has already fully considered and addressed, in the Order at pages 16-17, all of the arguments raised, on rchearing by OCC, as well as those raised by other intervenors in the proceeding. The Commission explained that Section 4928.143(I3)(2)(a), Revised Code, specifically provides for the automatic recovery, without litnitation, of certain prudently incurred costs: the cost of fuel used to generate the electricity supplieci under the SSO; the cost of purchased power supplied uncler the SSO, including the cost of energy and capacity and power acquired from an affiliate; the cost of emission allowances; and the cost of federally mandated carbon or enEagy taxes. Given that OCC and IEU have failed to raise any new argunlents regarding this issue, rehearing on these grounds should be denied. However, we emphasize that FAC costs are to continue to be allocated on a least cost basis to POLR customers and then to other types of sale customers. Allocating the lowest fuel cost to POLR service customers is consistent with the electric utilities' obligation to POTaR customers and wilt minimize the burden on most ratepayers. 2, PAC Basehne (15) OCC's first assigrmtent of error is that the Commission's adoption of the FAC baseline was not based on actual data in the record, and that the Company bears the burden of creating such a record in order to collect fuel costs pursuant to Section 4928:143(B)(2)(a), Revised Code (OCC App. at 12). C7CC 117 08 917-EIUSSO, et al, -5- rccognites that an ESP may recover the costs of fuel, but argues titat these costs must be °prudently izceut.-red" (Id,). OCC adds that [t]he clear language [of SB 221] must be read to include recovery of only actual costs as anything more would not be prudent to recover fxom customcrs" (7d.). Nonethcless, OCC then admits that the actual 2008 fuel costs were not known at the time of the hearing,l but requests that the Commission order the Companies to produce actaal fuel costs for 2008, after the recordof the case has been closed, for purposes of estabTishing the baseline. Thus, OCC would have the Commission do exactly what its first assignment of error is criticizing the Commission's order for doing, whicl-t is use data that is not in the record. (16) Siinilarly, I3:U argues that, based on information and reports that have been subsequenEly developed and filed `ut .other jurisdictions, Staff's methodology was nlcorrect. Tlxereforc, IEU requests that the CoizuYUssion adopt a ntethodology that sets the baseline based on 2008 actual costs (TEIJ App. at 12-13). (17) AIiP-Ohio responds that the Cotnmission's decision mtlst be based on the record before it and it is not feasible to do what OCC and Il;l.7 request (Cos. Memo Contra at 39). Nonethciess, AEP-Ohio states that, even if the 2008 data was available in the record, it would be inappropriate to use absent substantial adjustments due to the volatility of fuel costs in 200$ and the extraordinaty procurcment activities that occurred (Id., citing Cos. rx. 7l3 at 2-3; Tr. XIV at 74-75). AEP-Oltio further argues that the Conunission's modification of the Companies' baseline car-Ltained in its proposed E.SF was tuireasonable. AEI'-Oliio argues that its methodology xvas the appropriate 2nethodology because its metTiodology identifies the portion of the 2008 SSO rate that corrclates to the new PAC rate, and is not a proxy for 2008 fuel costs (Cos. App, at 38-39). OCC disagrees and urges the Commission to xeject AEP-(Ohio's methodology, as well as 6taffs, and adopt the actual 2008 fuel costs (C7CC Menio Contra at 8). t We wiii assume that OCCs reference eo 2009 actual data was a typograpliical e.rror and the reference sliould be to 2008 (see OCC App. at 13). 118 08-917-EL-SSO, et ai -6- ("18) As explained in the Order, the actual 2008 fuel costs wexe not known at the time of the hearh;g (Order at 19, citing C1CC L;x,10 at 14). Therefore, based on the evidence presented iri the record, the Commission deterznined that a proxy should be used to calculate the appropriate baseline. After making this determination, the Corntnission reviewed all evidence 'v1 the record and all parties' arguments, and adopted Staff's methodology and resulting value as the appropriate PAC baseline_ AEP-Ohio, OCC., and IGU have raised no new arguments regarding this issue. Accordingly, rehearing on this ground is denied. 3. FAC I?eferrals (19) OCC argues that the Commission erred by not requiring deferrals and carrying costs to be calculated on a net-of-tax basis, and the Conunissiori s reliance on Section 4928.144, Revised Code, was misplaced because the FAC deferral approved by the C'omm'xssion is not a phase-in of rates autltorized by SB 221 (OCC App. at 14). T21e Schools, however, conclude that the Comnussion exercised its authority pursuant to Section 4928.144, Revised Code, when it found that AEP-Ohio should phase-in any authorized increases, and that those ainounts ovet the allowable inerease percentage Icvels would be deferred pursuant to Section 4928.144, Revised Code, with carrying costs (Schools App. at 4). Notwithstanding the Commission's statutory authority to phase--in increases through deferrals, the Schools assert that School Pool participants who buy generation service from cornpetitive reta4l electric service (CRES) providers shottld receive a credit on their bills during the FSP equal ta the fuel that is being deferred (even though NAC deferrals will not be recovered via ari unavoidable sux-charge until 2012, if necessary) (Id. at 5), The Schools rationalize that aaiy other outcome would violate the policy of the state, specifically Section 4928,02(H), Revised Code (Id. at 6). (20) OCC also arglies that the Comntission failed to follow its own precedent and that deferrals arc incompatible with Section 4928.143(B)(2)(d), Revised Code, inasmuch as the deferrals destabilize custon2er prices, introduce uncertainty, aiid are unfair and unreasonable (OCC App, at 14, 42-44). OCC recognizes that SB 221 allows deferrals under an ESP, but .states 119 -7- 08-917-EL-SSO, et al. that those deferrals are liunited to those that stabilize or provide certainty (Id. at 42). OCC expIahls that deferrals will cause future rate increases and add carrying costs to the total amount that customers will pay. OCC adds that the record is void of any projection that electric rates will decrease following the ESP period, attd, therefore, concludes that the (21) OCC. further contends that the use of a weighted average cost o.E capital (WACC) to calculate the carrying costs associated with the PAC deferrals is unreasonable and will result in excessive payznents by customers. OCC asserts that the carrying charges should instead be based on the actual financing required to carry the deferrals during the short-term period (Id. at 45). (22) 1FU sutnnits that the Commission failed to require AfiP-Qhio to Iiniit the total bill increases to the percentage amounts specified in the Order (IHU App. at 40). (23) AElP-Ohio supports the Commission's decision authorizing PAC deferrals, with carrying costs, and contends that the authorized phase-in of ratc increases, atid associated BAC dc.fercals, comply with Section 4928.144, Revised Code, and are compatible with Section 4928343(B)(2)(d), Revised Code (Cos. Memo Coiitra at 42). AFS'-flhio also supports the use of WACC, rather than a short-term debt interest rate, given that the period of cost deferrals and their subsequenfi recovery will take place over the next ten years (Id. at 43). (24) AI3I'-Ohio, however, a.rgues that the Coinsnissiori s adjustxnent to its phase_in proposal and 15 percent cap on the ESP rate increases were unreasonable, disrupting the balance between up-front revenue recovery and subsequent recovery of deferrals (Cos. App. at 12). To this end, AEP-Ohio contends that tlte Cornmission's authority under Section 4928.144, Revised Code, "ntust be exercised in tlie total context of Chapter 4928, Ohio 120 -8- O8-91%-EL-S9O, et al. Rev. Code, particularly in the context af the standard for approval of an >3Sl' without modification" (ld., n,6), AEP-Ohio adds that the Commission's modification of its 15 percent cap wa:, "too severe," and requests that the Corxunission rebalance the amount of the authorized increases and the size of the deferrals to reflect, at a minimunt, annual 10 percent increases during the LSP term (Id. at 12-13). While agreeing with AEl'- Oltio that the Order is unjust and unreasonable, IELJ disagrees that the balance favors custozners. TEU argues that the Commissioii s imposition of lirnits on the total percentage increases on customers' bills has not been followed (IEtJ Memo Contra at 8A). (25) Furehexmore, AEP-Oh4o requests that, if the Conitnission does not modify the total percentage increases allowed, the Comcnission should claxify the intended scope of the lixnitations that it has imposed, and specify ttiat the 15 petxent cap does not include reveitue increases associated with a distribution base rate case or the revenues associated with the Energy Efficiency and Peak Demand Reduction Cost Recovery (EE/PLlR) Rider (Cos. App. at 13). OEG supports AEP-Ohio's clarification, v,rlule IEIJ urges tlie Conunission to reject AF,P-Oldo's requested clarification, and find that the Iimitations on the percentage increases nnposed by the Comnisszon in the Order apply on a total bill basis (OFsG Memo Contra at 3; IIiO Memo Contra at 9). (26) Section 4928.144, Revised Code, authorizes the Commission to order any just and reasonable phase-in of any clectric utility rate or price established pursuant to an ESP, with carrying charges, and requires that any deferrals associated with the authorized phase-in be collected through an unavoidable surcharge. The Commission continues to believe thlt a phase-in of the E5P increases, as authorized by Section 4928.144, Revised Code, is necessary to ensure rate or price stability and to mit4gate the impact on customers. We furtlier believe that our established limits on the total percentage increases on customers' bills in cach year were just and reasonrcbie and remain appropriate. Nonetheless, upon fitrther review of the workpapers filed with the tariffs and the conunents received from paxties concerning the practical application of the total percentage increases on custonters' bills, it has come to the Commission's attention that the Companies included in the total allowable revenue increase 121 -9- US-9'1'7-EIrSSO, et ai, an amount ihat equals the x•evenue shortfall associated with their joint service territory customer, Ch'rnee. In their calcuCat'ron, the Companies assumed that the joint service territory custotner would continue paying the amount that it was paying on Ilecentber 31, 2008 (established puxsuan.t to a prior settlement), which was above the approved tariff rate for that rate schedule. Instead, the Companies shouid have calculated the allowable total revenue increase based on that cusf:omer paying the December 31, 2008, approved tariff rate for its rate schedule, Additionally, the Compatties' calculation should have been Ievelized and not reflected any variations in cnstomers' bills for tariff/voltage adjustments. Accordingly, we direct the Companies to recalculate ehe total allowable revenue inca'ease approved by otir Order issued on March 18, 2009, as clarified by tlie Fntry Nunc Pro Tunc issued on March 30, 2009, and as modified herein, and file revised tariffs consistent with such calcutation, (27) Adclitionally, the Commission clarifies that the Transmission Cost Recovery (TCR) rider should not impact the allowable total percentage increase. As approved in the Order, the TCR rider will cotitinuc to be a pass-through of actual transmission costs incurred by the Companies that is reconciled qaarterly. Similarly, any future adjustments to the EE/PDR Ricler are excluded f-roin the allowable total percentage increases. As explained in the Order, the EE/PDR Rider was designed to recover costs associated with the Coinpanies' implementation of energy efficiency prograrns that will achieve energy savings and peak demand programs designed to reduce the Contpanies' peak demand pursuant to Section 4928.66, Revised Code (Order at 41). '£he costs included in the'tiE/T'DR Ricier will be trued-up annually to reflect actual costs, (28) We further clarify that the phase-in/deferral structure does nat include revenue uicreases associated with any distribution basc rate case that may occur in the future. Any distribution -rates establislted pursuant to a separate proceeding, outside of an S'SQ proceeding, will be considered separately. Section 4928.144, Revised Code, authorizes phase-in of rates or prices established pur4uant to Sections 4928.141 to 4928.143, Revised Code, not distribution rates established pursuant to Section 4909,18, itevised Code, 122 -10- 08-91.7-ELr-SSO, et al. (29) With respect to C3CC's and the Schools' issues regarding the. FAC deferrals and carrying charges, we find that those issues were thoroughly addressed in our Order at pages 20-24, and that the parties have raised no new arguments rel;arding those issues. Accordingly, the Connnission finds that rehearing on those assignm.ents of error are denied. (30) Sitnilarly, the Commission finds that AEP-Ohio's argiiments regarding its proposed 15 percent cap were fully addressed in our Order, and AEP-Qhio has. raised no new arguments to support its position. Additionally, AEl'-Ohio's alternative proposal of an annual 10 percent cap fails on similar grounds. The Compani.es have offered no justification or support for its adjusted proposal. As such, the Commission finds that rehearing on this ground is denied. (31) With respect to the other assignments of error rai.sed, the Commission emphasizes that it was the intent of our Order to phase-in the aut.horiaed increases and to limit the total percentage nlcreases on customers' bills to an increase of 7 percent for CSP and 8 pere:ent for OP for 2009, an iutcrease of 6 percent for CSP and 7 percent for OP for 20'10, and an increase of 6 percent for CSP and 8 percent for OP for 2011, as explained herein, `1'o the extent that the Coxxunissiozi s intent was not memorialized in the Companies' tariffs, or the application of those tariffs, we grant rehearing to correct the errors or cJarify otir Order as dclineated above. R. Ineremental Carrvine Cost for 2001-2008 Environmeital lnvestinent and the Carrving Coat Rate (32) In the Order, the Convnission concluded that AEP-dhio should he allowed to recover the iitcremental capital carrying cost.s that will be incurred after January 1, 2009, on past environmental investrnents (2001-2008) that are not presently reflected in the Companies•' existing rates, as contemplated in Abl' ^hio's iZSP Case. Turther, the Commission found that the recovery of continuing carrying costs on environtnental investments, based 123 08-917-FL-SSO, et al. "11" on W ACC, is consistent with our decision in the 07-63 Case2 and the RSP 4 Percent C.ases 3'I'he Conunission agreed with the ratianale presented by the Compaiues fhat the levelized carrying cost rates were reasonable and should be approved. (33) First, IRU argues that the Comrnission's decision fails to comply with the requireaients of Section 4903.09, Revised Code, to sufficientiy set forth the reasons prontpring the Comtnission's decision based upon the findings of fact in regards to carrying costs and several other issues (IEU App. at 4-26). (34) I£sU and C2CC argue that Section 4928.243(S)(2)(b), Revised Code, limits any allowance for ali enviroiunent-a^ expenditure or c:ost to those incurred on or after January 1, 2009. IEU and OCC interpret Section 4928.143(B)(2)(b), Revised Code, to only allow the electric utility to recover a reasonable allowance for construction work in progress for any of the electric utility's costs for envirorunental expenditures for any electric generating facility, provided the costs are incurred or the expenditures occur on or after )anuary 7, 2009 (IbU App. at 14; OCC App. at 38-39). OCC argues, as it did in its brief,`t that both divisions (B)(2)(a) and (13)(2)(b) of Section 4928.14.'^, Revised Code, require an after-the-fact determination that the expenditures were pradent and are, therefore, inappropriate for the Conunissiozi s consideration in this E5P proceeding (C}CC App. at 38), OCC contends that the Order failed to address whether it was proper under tlie statute to collect carrying costs on the environinental investment as the Conunission rnerely accepted Staff's position (OCC App. at 38-39). OCC concludes that the prudence of the environmental investmelit should be examined in a subsequent proceeding. (35) Further, IRU and OCC also claim that the Comrnission failed to calculate the carrying chaxges on the various types of special financing available to finance envirolunental or pollution control ctssets, including the cost of short-term debt, consistent Company, Case No. 07-53-31,UNC, Opin{nn and a In ra Coturwbus Snut7iern Power Conrpany and O7 io Power prder (Oetober 3,2007) (07-63 Case). Nos. 07-1132-E1. [7NC, 07-1191- In re Colunnbus 5outhern Power Company nnd Ohio Power Company, Case HL-UNC, euut 07-1278-BI^UIVC (RSP 4 Percent Cases). 4 OCC and the Sierra CIaU-Ohio Chapter joined togelhec to file its brief in this matter and referred to themse(ves jointly as thc Ohio Consumer and Environmental Advocates (OCEA). 124 08-917-EL-SSO, et al, -12- with the Commission`s rulings in other proceedings (IEU App. at 15; fJCC App. at 46).5 (36) A1iP-Dluo argues that to comply with the reSuirements of Section 4903.09, Revised Code, the Order must show, in r:ufficient detail, the facts in the record upon which the order is based, and the reasoning followed by the Conunission in reachhig its conclusion.6 Thus, AEP-Ohio concludes that as long as there is a basic rationale and record evidence supporting the Order, no violation of Section 4903.09, Revised Code, exists (Cos. Memo Contra at 8-9)? (37) Further, AEP-Ohio argues that OCC is mischaracterizing the Companies' request fc>r environmental carrying costs pursuant to Section 4928.143(B)(2)(b), Revised Code. AEP-Ohio argues tliat its requests for envirorunental carrying costs iztcurred during the ESP period are based on the broader language of Section 4928.143(B)(2), Revised Code. AEP-Ohio notes that Sec.tion 4928,143(B)(2), Revised Code, states that a company's RSP may provide for or include, tiYithout lnnitation, any of the provisions itetnized in paragraphs (a) through (i) of Section 4928.143(13)(2), Revised Code (Cos. Memo Contra at 45-46). (38) 'C'he Conun.ission affirms its decision to permit AEP-Ohio to recover the carrying costs to be incurred after ]annasy 1, 2009, on environinenfal investments made prior to 2008. The Cotr¢nission interprets Scction 4928,143(B)(2), Revised Code, like the Companies, to permft AFP•Qhia to include as a part of its ESP the carrying costs on environmental investments that are ineurred January 1, 2009, through December 31, 2011, the ESP period. The carrying costs on the environinental investments fall within the E'SP period and, therefore, may be included in the ESP pursuant to the broad language of Section 4928.143(B)(2), Revised Code, permitting recovery for unenurnerated expenses. Conrpany and Olaio Pawer Company fo Adjust S.;e 1x tl e Matter cf tfre Ataylicrtion of Columbus Southern Power Each Comprrny's Transmission Cost Recoven,/ Rider, Case No. 08-1202-0.,UNC, Pinding and Order at 4 Compan,y forAuthority to (peceniber 17, 2U0k3);1n tke Mntler of #rc Apptiarlxon of T7u Dayton Potoernnd LiSht Restoration Cosfs, Case No. 08-3332-EL. Modrfi,f-iEs Accouufiug Procedure for- Certritt Storn[-Related Services AAM, Pinding and Order at 1 Qaztuary 14,2009). (2008), 117 Ohto St.3d 486, 493, quo8ng MCI t ertrrs. L'trergf Users-Olrio o. PerSlic LttPd, Cotrutr. Telecomnnmicafions Corp. v. Pub. Utit, Cotnur. (1987), 32. Ohia St3d 306, 312. Tangren v. Pub. i.Ttii. Cornm. (1999), 85 Ohio St.3d 87, 9D. 125 -13- 08-917-ET.-aSO, et al, As noted in the Order, approval of the continuing enclironmental carrying costs is consistent with the Com2nission s decisions in the 07-63 and the RSP 4 percent cases. Given our prior orders, we find that inclusion of these expenses is reasonable. IEU and OCC havc not raised airy new clainrs that the Coinmission have not previously considered regarding the carrying costs on AEP-t7hio's environmental irtvest-inents. Accordingly, IIIU's and oCC's rea,uests for rehearing on this issue are denied. C. Annual Non-I;AC Increases (39) AEP-Ohio asserts that the Commission's rejection of the proposed aiutomatic annlxal increases to the non-FAC portion of the generation rates is untawftii and unreasonable (Cos. App. at 14=17). AEP-Ohio claims that the proposed annual increases of 3 percent for CSP and 7 percent for OP were intended to recover costs during the ESP period associated with environmental investments made during that period, as well as cost increases related to iznanticipated, non-mandated, generation-related cost increases (Id. at 74). AEP-Ohio notes that, although the Order adopted 5taff's proposal regard'uig recovery of carrying charges on nc:w envirnnrnental itivestments, the Corntnission's failure to adopt any automatic, annual increases was unreasonable and, unlawfixl pursuant to Section 4928.143(B)(2)(e), Revised Code (Id. at 15). The Companues specifically request that the Coniinission authorize the 3 and 7 percent automatic, annual increases, offset by whatever revenue increase is granted in relation to the recovery of carrying costs related to new environmental investrnent (Id. at 15-16). At one point, however, AEP-C)hio seems to be arguing that the Commission should adopt any automatic, aruiual Increases, regardless as to whether it is the atnount of increases proposed by AEP-Ohio or the amoutnt recomnlended by Staff (id. at 15). (40) As noted by IEU and flCC, the Companies do not raise any new arguments tivith regard to allowin.g autoniatic, azuiual increases (tEU Ivleino Contra at 9-10; OCC Memo Contra at 20), just as we concluded in the Order, the Companies have failed to sufficiently support the inclusion of such automatic increases, and the record is void of any justification for the increases, 126 08-9"17-BL-SSO, et al. AEP-Ohio has raised no new arguments, and thus, its request for reliearing on this ground is denied. (41) Ytirith regard to the recovery of carrying charges on new environmental investments, A8P-Ohio questions the timing of urhen it may seek recovery of the carrying costs associated with the new investinents made during the FSP (Cos. App. at 16). (42) In our Order, we adopted Staff's approach regarding the recovery of the carrying costs for environmental investments nlade during the FSI' period, and found that the Companies could request, through an annual filing, recovery, of carrying costs after the investcnerits have been made to ,refIect actual expenditures (Order at 29-30). The Commission cited StafE's exatnple, which envisioned an appIication in 2010 for recovery of 2009 actual environmental investment costs and arvuially thereafter for each succeeding year to ret7ect the actual expenditures (Id., citing Tr. Vol. XII at 132; Staff I;x.10 at 7). To clarify, we conclude that Staff's approach, requiring an application to request recovery of actual environmental invesh.nent expenditures after those expenditures have been incurred, is reasonable, fi. DI5'fRI Bll116N A. Annual Distribution Increases (13) 'l'he Companies proposed two plans, an Fnhanced Service Reliability Plan (ESRP) and gridSMART, to support initiatives tcr improve APP-Ohio's distribution systern and service to its customers. The Companies requested annual distribution rate increases of 7 percent for C5P and 6.5 percent for OP to implement the two plans. In the Order, the Commission considered the two plans separately culd found tliat the annual distribution rate increases were unnecessary in light of the Commission s findings on the 13S1ZP and gridSMAP3' plans, and consequently elfminated the annual distribution rate increases fi•om the ESP (Order at 30=3$). (44) Kroger maintains that the Coixunission properly rejected AEP- Ohio's annual distribution rate increases (Kroger Memo Contra at7). 127 08-917-FL-S6O, et aI. 1. ESRP (45) AEP-Ohio asserts that the Commission's deferment of certain aspects of its FSRP to a distribution rate case where all components of distribution rates trrottld be subject to review is un.reasonable and unlawful in violation of Section 4928.143(B)(2)(h), Revised Code (Cos. App, at 27). AFP-C1hio posits that the Coznmissiori s conclusion conflicts with the express provisions of 513 221, which permit single-issue ratemaking proposals for distribution infrastructure and moderni7ation initiatives within ESP proposals (Id. at 27-28). AEP-Obio further claims that it "merely sought incremental fanding to support an incremental level of reliability activities designed to maintain and enhance service reliability levels" (Id. at'2'7). (46) AEP-Ohio argues that the Cozrutiission erred by failing to find that three of the faur PSRP initiatives met the statutory requirements of Sectian 4928.143(I3)(2)(h), Revised Code (Id. at 28). While f1EP-Ohio commends the Commission on its finding that the enhanced vegetation ntanagement program did mect the statutory requirements, it believes that the Commission ehonld have reacliod similar conclusions on the other EST{P programs (Id.). (47) Conversely, Kroger and OPAB contend that the Cornmission lawfully ancl reasonably deferred the decisfon to implement all but one of the ESRI' initiatives to a distribution rate case (Kroger lvfeino Cotttra at 7-8; OPAfi Memo Contra at 5). Kroger explains that, while Section 4928.143(8)(2)(h), Revised Code, allows an ESP to include provisions regarding siitgle-issue rateniaking, it does not mandate that the Conlmission approve such provisions, and it especia[ly does not require the Commission to authorize all distr.ibution proposals included in an ESP (Id.). (48) QCC opines that, al.tl-ougli it agrees with the decision to defer ruling on the three ESRP initiatives, it believes that the Companies failed to meet their burden of proof in ilemonstrating that the vegetation management progra n complies with Ohio law and is in the public interest (OCC App. at 57-59). OCC also disputes th.e Conunission s application of Section 4928.143(&)(2)(h), Revised Code, and states that the Conunission erred in finding that the vegetation manageinent 128 08-917-FL-SSO, et al. -16" initiatives met the statutory requireinents. OCC also subznits that the Commission exTed when it characterized tlie proposed vegetation initiative as "cycle-base.d" (C?CC App, at 6:1). (49) Moreover, CCC alleges that the Cortunission acted unlawfully when it approved an ESRP rider without specifying an id.entified amount and without receiving testimony on the need for the riders (id, at 55). (50) As stated in the Order, the Commission recognizes that Section 4928.M(13)(2)(h), Revised Code, authorizes the Contparv.es to include in its proposed ESI' provisions regarding single-issue ratemaking for distribution infrastructure and modernization incentives. However, the statute also dictates what the Conunission must do as part of its determinatioa as to whether to allow an ESP to include such provisions. Section 4928,143(Tf)(2){h), Revised Code, states, in pertinent part: As part of its determination as to whelher to allow in an electric distribution utitity's electric security plan inclusion of any provision described in division (B)(2)(h) of this section, the comrnission 'shali exanrdne the reliability of the electric distribution utility's distributlon system and ensure that customer.s' and the eleclxic distribution utility's expectations are aligned and that the electric distribution utility is placing sufficiesrt einphasis on and dedicating sufficient resources to the reliability of its distributian system. Section 492$.143(B)(2)(h), Revised Code (emphasis added). The Comixission examined the four initiatives included as part of the Companies' ESRP and determined that only one, the enhanced vegetation initiative, met these criteria. Contrary to AEP-Ohio's assertion,s the Commission did consider and evaluate each initiative and found that the errhanced vegetation niitiative was the only initiative that was supported by the record in this proceeding (see Order at 30-32). The Commission conc(udect that, at the time of the Order, the record did not s Cos. r1pp. nC3o. 129 08-917-EL-SS0, et al. -17- contain sufficient evidence to support the oilier three initiatives and, tltus, the Commission declined to impleinent the programs witlun the context of the ESP; however, the Coinnrission stated that it would consider the initiatives furthcr in the context of a distribution rate case, (51) The Cotnnaission contiu2ues to believe that the appropriate vehicle to review, consider, and make a deterinination on the remaining initiatives, as well as the recovery of any costs assoclated with those initiatives, is through a distribution base rate case, Accordingly, AEP-Oh9o s request for rehearing on this issue is denied, (52) '1'he Comniissioil agrees wfth OCC wi.th regard to the three initiatives referenced above. 'the Cointni.ssion did not believe that the record supported the need for those progranms and, thus, the Conunission declined to include those programs in the ESRP, and declined to include any recovery for such programs in the FSRP rider, The Comcnission disagrees, however, that the record was void of any evidence regarding the vegetation. management program and costs associated therewith. Several individuals, including an OCC witness, testified on the proposed plan, as well as the Companies' currentpracttces (Cos. Ex. 11; OCC. Ex, 13; Staff Ex. 2; Tr. Vol, VII 64-65, 84, 87-88; Tr. Vol. VIII at 60-62). Testimony was also heard on the expenditures associated with the proposed vegetation initiative and the recovery of those costs (Staff Ex. 2 at 9-13). The Commission created the FSttT' Rider as a mechanism to recover the actual costs incttrred so that the expenditures could be h'acked, reviewed to determnte that they were prudent and incrementaI to costs included in base rates, and reconciled annually, As fully discussed in the Order at pages 30-34, the Commission finds that the Crnnpanies did meet their burden of proof to demonstrate that the vegetation inanagensent program, with StafPs addilional recoxrunendations, was reasonable, in tlte public interest, and in compliance with the statutory requirements. OCC raises no new arguments on rehearing and, therefore, rehearing on this ground is denied. (53) AEP-Ohio seeks clarification on tlte additional Staff recommendations that the Coznmission approved as part of the enhanced vegetation initiative (Cos. App. at 34). 130 08-917-FL-SSO, et al. -18 (54) The Comsnission found that the enltanced vegetation initiative, with Staff's additional recommendations, was a reasonable prohn-an7 that will advance the state policy. The, Conunission emphasized the importance of a balanced approach that not only reacts to problems that occur, but that also maintains the overall system. To achieve this goal, the Commission ftilly expects the Companies to -sa=ork with Staff to strike the correct balance within the cost level established by our Order, whicli is based on the Companies' proposed ESRP program. (55) ABP-Ohio also seeks clarification on the final paragraph in the Order that discusses cost recovery associated with the three remaining initiatives proposed through the FSRP (Cos. App. at 32). (56) The Conunission further clarifies that the langaage regarding cost recovery and the inclusion of costs associated with the reinairiing initiatives in the ESRP rider is permissive and conditioned on subsequent Commtssion approvall fcw including suclt costs. Specifically, the Commission stated: "If the Corrunisslon, in a subsequent proceeding, deterxnines that the programs regarding the remaining initiatives should be implemented, and thus, the associated costs should be recovered, those costs tnay, at that time, be included in the FSRP rider for future recovery, subject to reconciliation as discussed above " (Order at 34 (emphasis added)). 2. GridSMART (57) 'l'1ie Order recognized that federal matching funds under the American Recovery and Reinvestment Act of 2009 (ARR Act) are availalile for the installation of gridSMART Phase I and directed AF..P-Ohio to make the necessary filing to request the federal funds. Given the availability of federal funds, the Commission reduced the Comparues' request for gridSMAR1' Phase 1 from $109 niillion (over the term of the F5P) by half to $54.5 inillion for the term of the FSP. Furthet; the Order established the gridSMART rider for 2009 at $33.6 million based on projectecl expenses, subject to an annual true-up and reconciliation of CSP's prudently incurred costs. 131 -19- 08-917-FsI.-tiSC}, et al. (58) In its application for rehearing, AEP-Ohio notes that CSP developed an incremental revenue requirement for gridSMART Phase I of approxiinately $64 tniflion during the ESP term (Cos. rx. 1 DMR-4) and, therefore, CSP's compliance tariffs reflect, consistent with the intent of the Order, half of the increme.ntaI revenue requirement. According to A13P-C7hio; as reflected in ilie Coinpanies" cornpliance tariff filing, the initial gridSMAItT rider rate is designed to recover approximately $32 miIIion or half of the gridSMART Phase I incremental revenue requircment (Cos. App, at 35, n.13). (59) However; AEP-Ohio argues that the C;ouirnission's cliscussion of the ARR Act and the likelihood of AEP-Ohio obtaining such futtds are beyond the scope of the record. Furtlter, AEP-lJhio asserts that the details for federal funding of smart grid projects have not been fully developed. The Companies argue that, to the extent that the Order conclusively presumes that AEP-Ohio will secare federal matching funds for each dollar invesked by the Coinpanies and their custoiners, the Order is unreasonable and unlawful: AEP-Ohio states that the Commission's decision as to grid8MART places CSP in an unfunded mandate situation to the extent that CSP receives less thati 50 pereent for its gridBMART project or the U.S.1?epartrnent of Energy institutes a cap of $20 n-dllion on each gridS.NIART project. For this reason, AEP-Ohio requests that the Coinrnission clarify that it intends to fully fund the gridSMART Phase I project through rates. Otherwise, AEP-Ohio reasons that the Commission lacks the auth.ority to order enhancement prograazns without recovery for t-be utility as to improvements ordered. Forest Hidis Utitity Co. v. Pub. LHil. Canttrt. (1972), 31 Ohio St.2d 46, 57 (Cos. App. at 35-37). (60) OCC contends that AEP-Ohio's assertion that the directive to proceed with gridSlvIA.RT Phase I without commensurate rate relief contradicts Forest Hills and will be subject to reversal by the Supreme Court of Ohio is iilappropriate at this time and unfounded. OC.'C reminds tlte Companies that, pursuant to the Order, the initial rider is established to provide AEP-C)hio $33.6 million f.or its 2009 gridSMART expenditures. AccnrdingIy, OCC states that NL:P-Ohio has not been denied funding and there has been no determ3nation that AEP-C)hio s prudently incurred gridSMART costs will not be fuliy covered in the 132 118-917-5?L-SSO, et al. -20- future. Thus, OCC reasozvs that the Companies' claim of an nnfunded rnaiidate situation is premature, and the request for rehearing should be denied (OCC Memo Contra at 23-25), {61) First, the Commission acknowledges that the Order inadvertently based the grid3MART component of the Companies' F.SP on $109 million, which is the total projected investinent costs, including operations and maintelance expenses, for the Coznpanies' proposed gridSMAILT Phase I project. tls the Companics explain, CSVs 16SI' application included a request for the incremental revenue requirement for gridSMART duriuig the FSP of approximately $64 million (Cos. Ex.1 DMR 4). As recognized by AfiT'-Ohio and irnplemented in its tariff fi.Iing, it was our intent to approve recovery of half of the gridSMART Phase I incremental revuene requirement, $32 millioit. Accordingly, rehearing is granted to correct this error in our Order, (62) Next, the situation before the Supreme Court in Foresf Hills, is factually different from the situation for CSI' a.s to gridSMAR'1' Phase 1. In Forest Hills, the court held that the utility had not been awarded fnnding to adequately rstaintain utility service mucli less th.e iron renloval ecluipnlent and water storage tanks ordered by the Cornmi5sion. In this instatZce, the initial gridSMART rider is,set at $32 rnillion for 2009 projected expenses, subject to annual true-up and reconciliation based on CSI''s prudently incurred costs and application for federal funding. Based on the information presentcd at Cos. Ex. l. DMR-4, $32 million represents sufficient revenues for CSP to commence its gridSMAR'I' program. As noted in the Order, the Conunission wishes to encourage the expedient implementatton of gridSMART. However, the Commission will not let the clesire for the expedient iniplementation of gridSMART cloud the financial soundness of the costs to ultimately be incurred by Ohio`s ratepayers. Consistent with our decision to approve the gridSMAttT Phase I project, we clarify that, once CSP properly applies for and otherwise meets its obligations to receive federal funds to offset the total costs of gridSMART Phase l, the Commission will review its gridSMART Phase I expenditures and, once the Commission concludes that such expenditures were prudently incunvd by CSP, the Conrmission intends to approve recovery of CSP's griduMART Phase I costs. 133 -21- 08-917-ELSSO, et al. (63) IEU, C7CC, and OPAE argue that the Order approved, in part, the Compan?es' request for grLdSMART without addressing the intervenors' arguments thai the gridSMART proposal was not cost-effective as required by Secfions 4928.02(B) and 4928.64(F), Revised Code (IEU App. at 22, 39-40; OPAE Memo Contra at 6; OCC App. at 49-51). According to OCC, because Alil'-t]hio faifed to present a detailed cost/benefit analysis of gridSMART Phase 1, the full deployment of costs of gridSMAR'I', a risk sharing plan between ratepayers and shareholders, or the expected operational savings associated with the implementation of gridSMART, AEP-Ohio failed to nleet its burden of proof that grirISMART is cost-effective (OCC App. at 49-51). OCC also argues that AFP-Ohio failed to present any evidence that grid5MART will benefit AEP-Ohio customers or society (OCC App. at 51-52). IEU and OCC argue that the Order fails to set forth the Commissiori s reasorw.kg for its approval of the Companies` gridSMART proposai (IEU App, at 22, 39-40; OCC App. at 48-49), Further, OCC argues that the Order does not include in the findings of fact or conclusions of law any support for the Coznrnission's adoption of gridSMART I'hase 1, in violation of SectSon 4903.09, Revised Code (OCC App, at 48-49). IEU axgues that the Commission's approval of thcse aspects of the ESP can not be reconciled with the goal of keeping rate ulcreases "as close to zero as possible" (IEU App. at 22, 3940). For these reasons, IEU and OCC argue that the Order is unreasonable and unlawful. (64) Regarding fEU's and OCC's ciaims that the Order fails to ccxinply with Section 4903.09, Revised Code, AEP-Ohio retorts that IBU's and OCC's disagree.ment with the Conumission s decision is not equivalent to a violation of Section 4903.09, Revised Code. T"he Companies note that the Order specifically recognized the features aid benefits of proposed gridSMART Phase I, based on the record, Accordingly, AEP-Ohio argues that the Order presents the Comnassion's basic rationale and record support for gridSMART Phase I and, therefore, the Order rneets the i.•equiremenis of Section 4903.09, Revised Code (Cos. Memo Contra at 25-27), (65) As to OCC`s and IE[Ps claims that gridSMART has not been shown to be cost-effective in accordance with Sections 134 -22_ 08-91'1-ELrS.SO, et al. 4928.02(D) and 4928.64(E), Revised Code, AFsP-Ohio answers that these code provisions are pplicy arguments that are not binding on the Commission and, therefore, the arguments of OCC and IEY.T on the basis of Sections 4928.04(E) and 4928.64(E), Revised Code, are misguided- The Companies note that several statutes of the Ohio Revised Code promote the deployxnent of advanccd metering irtfrastruclure (ANII). Notably, ..AEP-Ohio points out that Section 4928.02(D), Revised Code, encourages the deployment of AMI as an example of cost-effective, demand-side, retail electric service; that Section 4945.31(E), Revised Code, In the context of an ESP, creates a specific cost recovery mechanism opportunity for the cleployment of advanced meters; and that the General Assembly included a long-term energy delivery infrastructure modernization plan as an item that can be included in an ESP under Section 4928.148(B)(2)(h), Revised Code. Based on the potential of gridSMAItT technologies to significantly enhance customers' energy managemeazt capabilities, AEP-Ohio reasons that the legislature tnandated the requirements in Section 4928.66, Revised Code, for energy efficiency and peak demand reductioitis (Cos. Memo Contra at 27-29). The Coinpanies argue that, while OCC and IEU focus exclusively on one aspect of the stated policy, cost-effectiveness, the Comrnission has a responsibility to consider all of the policies presented in Section 4928.02, Revised Codc. Cost-effective, as defined by AEP-Ohio, does not mean that a network component (or group of camponents like gridSMART) pays for itself but, rather that it is a reasonable and prudent approach to deploying needed functionalities and features, (Cos. Memo Contra at 27). (66) In the Order, the Commission summarized the key components of CSP's gxid9MAKT proposal and emphasized its support of smart grid technologies. The Commission noted the potential for a wcll-designed smart gTid system to provide customers and the electric utility long-term benefits, including decreasing the scope and duration of electric outages, irinprovesnents in electric service reliability, and the ability to provide customers the opportunity to better inanage their energy consumption and reduce their energy costs (Order at 34-35, 37). The Commission's endorsement of grldSmart Phase I is based on the projects ability to drive a broad range of potential econoinic 135 -23- 08-917-FIrSSC), et al. benefits bath to consumers and the utilities. While con.sumers are given the capabilities to reduce their bills, utilities earn the capability to manage their systetns. For customers, the ability to have real-time psice inforsnation and the ability to respond to such prices means that they may devel.op consumption patterns that both save them dollars while hel.ping the utilities shave their peaks. '1'his price-responsive demand not only rediices the need for high-cost generation capacity, but also reduces the need to contipually expand the costly transmission and disi.ribution components. The essence of this project is an infrastructure that embraces the following elements: advanced metering, dynarnic pricing, information feedback to consuiners, automation hardware, education, and energy efficiency programs. If executed appropriately, customers will receive the benefits of demand reduction across all seasons. From the utility infrastructure side, gridSmart may lead to inuch-n.eeded improvements in reliability. In the digital world that presently exists, and in the tecluzology-driven world iuto which we are moving, the demand for precise and reliable power delivery systems is imperative. As we move forward, there will be new demands placed upon the grid to accommodate variable and intermittent Inputs, such as the various forms of alternative energy generators. One can hardly imagine what the technologies of the future will bring us; we understand, however, that they must be adaptable to our needs. This is the essence of the amart grid. (67) Further, the statutes referenced by AEP-Ohio in its memorandum contra indicate the iegislature's endorsement of AMI. Furthermore, to the extent that SBB 221 encourages the deployment of AMI and clarifies the legislature's policy directives at Section 4928,02, Revised Code, and in light of the Commission's desire to implement infrastructure and technologicaf advancements to enhance service effi.ciencies and improve electric usage, the Commission modified and adopted the Companies' gridSMART proposal. The Commission specificalty directed AEP-C7hio to pursue federal funds, in an effort to reduce the gridSMART Phase I cost that could be passed on to Ohio ratepayers. tNe also, as suggested by Staff, 136 -24_ 08-917-EL-SSO, et al. implemented a rider as opposed to the automatic increase proposeci by the Companies. In keeping with the enunciated state policies for reasonable electric rates and the requirements of SB 221 that cncourage the implenientation of AMI, the Commission approved the adoption of a gridSMART rider. Our Order requires separate accouiiting for gridSMART, an opportunity for the gridSMAR'T plan to be reviewed and updated aiuiually and an opportunity for the Co»urussion to review the gridSMART expenditures to ensure that they were prudently made prior to the Companies' recovery of any gridSMART costs. For these reasons, the Commission concludes that the adopted gridSMART component of AFP-t7hio's ESP best meets the requireinents of SB 221, and meets the Connmissfon's.obligation to the citizens of Ohio to encourage the implementation of AMI and ensure the avaitahilityof adequate, reliable, safe, efficient and reasonably priced electric service. As noted in the Order, we believe it is impottant that electric utilities take the necessary steps "to explore and implement technologies such as AMI that will potentialiy provide long-terin benefits to customers and the electric utility:" Thns, tlie Coanmmission denies IEU's, QCCs, and OPAE's applications for rehearing as to the gridSMAI2T coniponent of the Companies' ordered ESP. Because of the compelling need to aiter the paradigm tliat has traditionally governed the relationsitip between the customer and the utility, we are ordering AEP to implement no later than June 30, 2010 a transition to an integrated smart grid within its Phase t project area. Ttic. goal shouid be to maximize benefits to consumers consistent with the aforementioned objectives. B. Riders 1. rovider of Last Resort (PQLR Rider (68) ©CC and Kro;er allege that the Comrnission's approval of the POLR charge to allow AEP-t3hio to collect 90 percent of ahe revenues that AEP-Ohio proposed in its POLR rider was unreasonable and unlawful given that the charge was calculated incozTectiy and was established unreasonably lugh (C1CC App. at 29-34; Kroger App, at 3-6), Kroger submits that reducing the 137 -25- 08-917-1;L-SS(), et al. requested POT..R amount by 1Q percent to account for the rrduction in risk by requiring shopping customers to pay market rates if they retu.in to the Companies is insufficient. ICroger agxees that the POLR risk is reduced if returning customers are required to pay market prices, but ICrogcr believes that the reduction in the POLR risk to the Companies is greater than 10 percent (Kroger App. at 4-5). Kroger also opposes the use of the. Black-Scholes model to calculate the amount of the POLR tisk, stating that the Black-Scholes model exaggerates the Companies' POLR risk (Id.). (69) OHA afid OMA raise similar argumeilts; adding that fhe limited shopping that has occurred and the unlikelihood that it will occur in the future further reduces A1:P-Ohio's risk and the need to compensate for that risk (OI-3A App. at 6-8; OMA App, at 5-6). (70) OEG states that the Commission properly found that the 1'OLR rider should be avoidable for those customers who shop and agree to return at a market price; hvwever, OEG believes that the Commission did not go far enouglt. OEG requests that the Coinmission grant rehearing to allow the POLR rider to be avoidable by those customers who agree not to shop duxing the PSl' through a legally binding corruniUnent (OEG App. at 6). (71) OCC further contends that the Conunission's actions authorizing the collection of POLR charge reveriues for January tlu•ough March 2009 at the higher rates authorized by the Order, even though the new `;.50 rates were not in effect at that time, and customers were already paying a POLR charge, violated Section 4905.22, TLcvised Code, and case precedent (OCC App, at 34-36). (72) Additionally, OCC alleges that the Commission violated Section 4928.200), Revised Code, when it required residential customers of governmental aggregators to pay a stand-by charge. OCC explains that the statute permits govertun.ental aggregators to elect not to receive standby service on behalf of their residential customers, in exchange for electing to pay the market price for power if the resideizt#al customers return to the electric utility (OCC App. at 36-37). 138 -26- 05-917-13L-S,SO, et al. (73) AEP-Ohio disagrees with the hltervenors and argues that the POI.R rider approved by the Commission was lawful and reasonable (Cos. Memo Contra at 3-8). AFP-Ohio asserts that th.e parties are raising issues tha.t were fully litigated in thc proceeding and have not raised any new argtnnents and thus the grounds for rehearing on the POLR-related issues shou]d be denied. (74) AEP-O1uo also explains that OCC misperceives the risk associated with the POLR obligation and argues that, as with other rate components that are part of the ESP, there is no double-recovery (Cos. Merno Contra at 24). Rather, the Companies' increased all charges enibedded in the FSP, including the POLR charge, to reflect the 2009 revenue levels authorized by the Conu-rlission, and then offset the revenues that had been collected already in the first quartcr (Id,). (75) First, as explained by AEP and recognized by others,9 we explicitly stated in our Order that customers in governmental aggregation programs and those who switch to an individual CIiES provider can avoid paying the POLR charge if the customers agree to pay the market price upon return to the electric utility after taking service from a CRES provider (see Order at 40). As such, OCCs xequest for rehearing on this nvatter is denied. (76) With regard to the amotrnt of the POLR charge, the Cominission carefully considered all of the argoments, testimony, and evidence in the proceeding and determined that the Companies shonld be compensated for the cost of carrying the risk associated with being the POLR provider, i.ncluding the migration risk. Based on the evideitce presented, the Conlmission adopted the Companies' witness' testimony who quantified that risk at 90 percent of the estimated POLR costs, using the Biack-Scholes model (see Tr. Vol, XIV at 254-205; Cos, F.x, 2-E at 15-16; Cos. Ex. 1, Exhibit DMR-5). The parties have not raised a:.y i:ew issuteG for the Commission's consideration, 'Therefore, we deny rehearing regarding the various l'OLR issues that have been raised. 9 See Cos, tvtenlo Contra at 2-3; OFG App. at 6. 139 -27- 08-917-F,T: SSt7, et al. (77) As for the argument of double-recovery of POLR charges or retroactive ratemaking, the Commission finds that this argument is comparable to OCC's argunients concerning all of the FSP charges and finds snnilarly. As discussed in subsequent section III.C: (Effective Date of the I3SP), our C7rder authorired the Companies' to increase all charges embedded in the ESP, including the POLR charge, to reflect the 2009 revenue Ievels approved by the Commission. However, our Order also directed the Contparries to offset any revenues that had been collected fronl customers in the first quarter to specificalty prevent any double recovery. As such, rehearing on this issue is also (ienied. 2. Enerfry Effic4ency Peeik Demand Iteduction, Demand T'titupo-nse, and Intera^uptible Cauabilities '(a) Baselhles azld Benclamarks (78) The Companies proposed that the load of the former Monongahela Power Coinpany's (MonPower) custainers be excluded from the calculation of CSP's BI3 baseline to be established prxrsuant to Sections 4928.64 and 4928.66, Revised Code?u In the Order, the Commi.ssion concluded that. the MonPower customer load shall be included in the Companies' EE baseline, because the MonPower load was not a load that CSP served and would have lost, but for some action by CSP (Order at 43). (79) AEP-Ohin reyuests rehearing on this aspect of the Order. AHP- Ohio, in its sixth assignment of error, argues thaf the Order crroneously failed to address the Companies' demonstration that the record in the MonPower Transfer Case reflected the Commission's concerns for MonPower's custoiners if they were not served under a rate stabilization plan (1ZSP), CSP notes that Staff witncss Scheck acicaowledged that MonPower customers were facing electricity prices directly based on wholesale market prices that far exceeded the level of retail prices offered by MonPower (Tr. Val. VII at 201-202). 0511 retininds the Cornrnission that, in thfs proceeding, Staff recognized that there ,/ Co&tmh14s la 7n fl e Matter of the Transfer of Mottungahela Pomer Cnnapony's Certified Territor+ in Oiiio to the Southern Pmnr.r Company, Case No. 05-765-0.-TINC, Opinion and Order (November 9, 2005) (MonPower 1Yansfer Case). 140 08-917-EI rS.SO, et al. -28- were important "economic developxnent" issues in the MonPower Transfer Case (Cos. Ex. 2A at 48). Further, CSP notes that, in the MonPower Transfer Case, the Conunission concluded that "economic benefits will inure to all citizens and busitnesses in both regions by helping to sustain economic development in southeastern Ohio."11 The Companies argue that it is not fair or reasonabie for the Commission to now take such a natrow and teclutieal view of economic development and request that the Comznission exclude the MonPower load from the Ela baseline. In the alternative, CSP requests that, should the Commission affirni its decision titat the MotiPower l.oad was not economic development, the EE and T'DR baselines be adjusted to ensure that the compliance measurement is not unduly influenced by other factors beyond ChSP's control as requested in the Companies Brief (See Cos. Br. at 103; Cos. App. at 17-20). (80) The Commission affirms its decision to include the former MonPower custoiner load in the calculation of CSP's RE baseline to be established pursuant to Sections 4928.64 and 4928.66, Revised Code. While the Couiniission appreciates that CSI' entered into an agreement to serve the foriner seivice territory of MonPower, as discussed in the Order, the transfer of such customer load was not economic development given that it was not a load CSP served aiid would liave otherwise lost but for some action by CSP. We acknowledge tliat puzsuant to Section 4928.66(A)(2)(b), Revised Code, the Comrnission may amend an elecfric utility's BE and PDR bP.nclnnarks if the Conunission determin.es that an aniendment is nccessary because the electric utility cannot reasonably achieve the benchtnarks due to regulatory, economic, or tecimologicai reasons beyond its reasonabte control. We also acknowledge that Section 4928.66(A)(2)(c), Revised Code, requires the basc-line to be normalized for certain changes including appropriate factors to ensure that the compliance measurement is not unduly influenced by factors outside the control of the electric utility. The Conunission will con.sider such request for adjustments to the baseline by AEP-Ohio and other electric utility companies when appropriate. 31 MonPower Tran9fer Case, Opinion nr.d Order at 11. 141 -2q.. 0$-917-E,t.-5S0, et at. (b) Inten•uptible Cauacitv (81) As a part of the ESI', the Companies reclnested that their interruptible service load be counted towards their PDR requirements to comply with Section 4928.66(A)(2)(b), Revised Code. The Cotnpanies also proposed to increase the, timit of OP's Interruptible Power-DiscretionarY SchecluIe (Schedule IRP- D) to 450 Megawatts (MW) from the current lirnit of 256 MW and to modify CSP's Ernergency Curtailable Service (ECS) and Price Curtailable Service (PC5) to snake the services more attractive tri customers. The Companies reqttest that the Coiniruission recognize the Companies' ability to curtail customer usage as part of the PDR compliance (Cos. Ex. I at 5- 6). (82) In the Order, the Commission agxeed with Staff and OC);A that interruptible load should not be counted in the Cornpanies' determination of its EB/PDR compliazice requirements uriFess and until the load is actually ulterrapted. IpU argues tltat the Conunission failed to present sufficient reasoning to support this position. IEU states that the Commissiori s reliance on khe testimony of Staff and OCEA's discussion of the issue is Ii.tnited (IEIJ App. at 51), (83) As noted iin the Order, OCEA argued that counting interruptible load is contrary to the objectives of SB 221 and, because the customer controls part af ehe load when non-mandatory reductions are requested, interruptible load should not be counted (Order at 46). IIiU proffers that OCEA's arguments are contrary to the record evidence and common sense (IEU App, at 52). The Compazues and IEU reason that Section 4928•66(A)(1)(b), Revised Code, dictates that the peak demand reduction probrams me,rely be °designed to achieve" a reduction in peak demand (Cos. App. at 21; IF,U App. at 52). The applicants for rehearing note that Staff witness Scheck acknowledged thaL °designed to achieve" is fundamentally different from a requirement to "achieve" as is required in Section 4928.66(A)(1)(a), Revised Code, xegarding EE programs (Cas. App. at 21; IEU App. at 52). fliU agrees with the Companies' arguments on brief that interruptible service arrat gentents provide an on-system capability to satisfy reliability and efficiency objectives as part of a Iarger plarutiing process (Cos, Brief at 112-115), and cites the regional 142 0- 08--917 EI,-SSO, et ai. transmission organizations (RT(:)) programs as an example (IEtJ App, at 52). The Companies contend that, unlike unused energy savings capabilities, I'DT2 prograins create a capability to reduce peak dernand that can either be exercised or reserved for future >.tse as needed and, if the PDR resource or capability is not nceded for operatiotial reasons or because weathex i.s mild, I'DR capability is fully reservedfor tuture use without depletioin or diminishing its value as a resource (Cos. App. at 22). IEU also contends that an ittterruptible customer's buy-through of a non-manclatory inten-zptible event is not a reason to reject it as a part of an electric utitity PDR program under Section 4928.66(A)(2)(c), Revised Code, and the Comnvssion should reverse its decision. IECJ stAtes that excluding interruptible capacity will require the Companies to offer a program inferior to the programs available from the RTO (IEU App. at 52-53). Finally, ARP-Ohio emphasizes, as noted in the Comp (84) OCC states that the Commission previously considered and rejected certain of the Compaz.v.es' arguinents on this issue. In light of the fact that the Cormnission has previously given tlus issue due conaideration and rejected the Cotnpanies' arguments, OCC argues that the Companies' application for rehearing of this issued should be denied (OCC Memo Contra at 22-23). (85) Upon further consideration of the issues raised, the Conunission has determined that it is inore appropriate to address interruptible capacity issues in A&1'-Oluo's PDR portfolio plan proceeding docketed at Caye Nos. 09-578-EL-EEC and 09-579- tsl.-LiGC. 12 See adopted Rule 4901:5-5-03 (R), O.A.C:, In the A2atter of theArloption of Rulesfnr Alternative urtd Ren zaa6tc Ettetgy Techitologies, Re.sntsrres, attd Clizxate Regutaflotis, at:d Reuiew of Chapters 490I,5-2, 4902:5-3, 490I :5-5, ,/ and 4902:5-7 of fhe Ohio Adnzinistrat-ive C'.otfe, 2'ursuant ¢o Section 4928.66, Reoieed Code, as Amended tn ArrientIed Sub:titute Senate Bill No. 221, Case No. 08-888-EL-ORD (Greeti Rufes) (Apri215, 2009). 143 -31- o8-917-EI..-SSO, et al. (c) EflIPDR Rider (86) In its fourth assig.unent of error, AFP-Ohio requests, among other things, that the Convnission clarify that the phase-in of the approved rate inerease and deferral of total bill increases over the established cap do not include revenue increases associated with a distribution base rate case or the revenue associated with the energy efficiency and peak detuand reduction cost recovery (1 E/pDR) rider (Cos. App. at 13-14). (87) As discussed in findings (27) and (28) above in regard to the TCR, we clarify that the perccntage cap increase on total custozner bills does not include the EF/PDR rider or futirre distribution base rates established pursuant to a separate proceeding. 3. Econonuc 1?evelopment Cost Recoyery Rider (a) Shared recovery of forgone. economic developnent revenue (88) In its application for rehearing, OCC argues that the Commission Order is unreasonable to the exterrt that the Order fails to require the Companies to share a portion of the revenues forogone due to economic development progr•ams (OCC App, at 39-41), OCC recognizes that Section 4928.143(B)(2)(i), Revised Code, pertnits an electric utility to file an ESP with provisions to implement economic development programs and to request that program costs be recovered from, and allocated to, all customer classes. OCC repeats the statements made in its briefs and rejected by the Comtnission in the Order that it has been the Commission's long-standing policy to equally divide t[le cost of the foregane revenue subsidies between the utility's shareholders and custorners, OCC clainvs the Commission's ru[ing on this issue coinsfiitutes an unreasonable shift in established regulatory policy to the prejudice of AEP-Ohio's residential customers and a rejection of OCC's request to annually review each approved economic development arrangement. OCC interprets the Order to foreclose any sucli annual review and, except for the Companies and the Cosmnission, to bar any other parties an opportunity to review 144 08-917-fiL-SSO,'et at. -32- econoznic development contracts initially and periodically thereafter (OCC App. at 39-41). (89) AFsP-Ohio opposes OCC's request for rehearing on this matter. AFP-Ohio argues that, althougli OCC acknowledges that it is witl-cin the Commission's discretion to deterntine "the arnaunt and allocation of the costs to be recovered" for foregone econornic development.reve.nue, at the same time, OCC claims that revenue sharing is within the Conunission's disc.retion, AEP-Oliio asserts that despite OCC's claim that revenue sharing is an established Commission policy, the practice is not reflected in anv of its special arrangements prior to the implementation of S8 221, Tlte Companies proffer that, to the ektent the alleged change in policy requires a reason, in SB 221, the General Assembly explicitty included recove:ty of foregone revenue as a part of economic development contracts in the arxiendrnents to Section 4905.31(E), Revised Code (Cos. Memo Contra at 36-37). (90) The Conunission finds that OCC has failed to present any new axguments for the Commission's consideration on this issue. We do not find it necessary or appropriate to require all parties to initially review andJor to annually review the econ.omic development arrangenents. Consistent with the cmrent practice, the Commission will review economic development arrangetnenta on a case-by-case basis which will afford interested parties an opportunity to be heard in individual econonuc arrangement cases. Accordingly, we deny OCC's requestforrehearing. (b) Econonnic develoument contl'act custonter comvliance review (91) OCC also argaes that the Econoanic Developxr.ent Rider (.PDR) is urifair, lacks accountability and fails to evaluate the Coxnpantes' or the customer's conipliance with their respective obligations. OCC states that the EDR approved in the Order does- i:ot require that recovery be linzi.ted to AEP-Ohio's costa net of benefits of the economic development pxogram.. Further, OCC claims that, without any review or accountability of the customers receiving the economic development benefits of such approved arrangements, costs cannot be detertnined. OCC argues that the Corxunission failed to make any provisions for 145 -33- 08-917-11L-SSO, et al. recipients of economic developnient contracts to be held accountable for their obligations imder the economic development arrangements. Further, OCC asserts that this absence of accountability of the customer-recipient is unreasonable because it allows anyone to receive an economic developntent discount with nothzng more than representations that it will ntake investinents in the state of Ohio, C]CC contends that the Commisaion should only approv"e discounted econoznic development rates, recovery by the electric utility and EDRs if investment in dhio actualty occurs (OCC App, at 65-66). (92) OCC also argues that the non-bypassable EDR is also unreasonable and unlawful because it is abusive, anticompetitive, and not proper. OCC states that AEP-C7hfo does not intend to offer economic development rates td shopping customers; but wilt impose the EDR charges on shopping ccistomcrs. OCC asserts that tlie lack of symmetry between the availability of the benefit, and who pays for the benefit, renders the EDR unlawful and unreasonable, as approved by the Commission (OCC App. at 66). (93) The Companies state that OCC's arguments are premature. In defense of the Commission s decision, the Companies remind OCC that the Comznission wiIl review and address the specific cireunistances of eaclt econoanie development arrangement as it is presented for approval and, that if there are any enforcement issues in the future, the Comrnission's continuing jurisdiction over economic development arrangements can be used to address any issues that arise. Regarding OCCs claims that the non-bypassable nature of theEDR is turIawful, abusive, and anticompetitive, the Companies reason that the fact that the EI?lt is non-bypassable ensures that it is competitively neutral. AEP-Ohio explains that a bypassable FDR would give CIZGS providers an undue advantage and emphasizes tkult CRES provider rates do not reflect recovery of °public ntterest" discounts in comparison to the electric utility's regulated SSO rates, which refleq forgone ec.onomic development discounts. Fnrtller, the Conipanies reasoxi that all custoniers an.d. the coznmunity benefit fronl econoiriic development (Cos. Memo Contra at 37-38). 146 -34- U8-917-EL-S,.SO, et al. (94) The Cnnunission finds that OCC has not presentad any new arguments that the Commission has not previoualy considered regard'uig review of economic development arrangements or the sharing of forcgone reventies for econoinic dcvclopment. We agree witlt the Companies that all customers and the cornmunity benefit frorn economic development and, therefore, find it is reasonable for the EDR to be non-bypassable as peimitted by law. The Commission finds that its current procedure to review and aitalyze each proposed economic development arrangeinent is sufficient ta address OCC's concerns regarding accountability and the electxic utllity's and economic development customer's contract compliance aliligat-Ions. For these reasons, we deny OCC's request for rehearing. C. I^ine Nxtensions (95) AEP-Ohio avers that the Commission's rejection of its proposed line extension provisions is unlawful and unreasonable, and states that the Convtussion should authoriLe ACsP-Oitio to implement up-front payments contemplated sn the Conun'rssiori s November 5, 2008, Finding and Order issued in Case No, 06-653-EL-ORD (Cos. App. at 6-9)13 (96) Recognizing that the line extension policies were still being considered at the time of the rehearing applications, OCC argues that AEP-Ohio's rehearing request is without support and should be denied (OCC Memo Contra at 19-20). (97) As stated in our Order, the Commission is required to adopt uniform, statewide Iine exfension rules for nonresidential customers pursuant to S13 221, wlvch it has done in Case No. 06- 653-EIs ORD. Although the rules are not yet effective, the Commission adopted modified line extension rules in its Entry ra 'Ltre ()hio Home Builder's Associ.ation (OHT3A) requested leave to file a limited memoraurdum contra AEP-Ohia s application for rehearing on April 27, 2009, AEP-Ohio responded to the request on May 5, 2009, and moveci to strike the pleading. t^le find OHBA's motion to be improper and wilt not be considered bceause OFIBA is not a party to these cases and becaune OHBA has not shown that its failure to unter a prior appearance is due to just cause and that iLs interests were not already adequately coruidered by the Commission. However, even if we were to consider the request and permit OHBA's memorandum contra, OTIt3A's argumen+s would not niodify our derision regarding the line extension issue. 147 -35- 08 •917-.E G-SSO, et al. on Rehearing issued on May 6, 2009. AEI'-O1uo was an active participant hi the adTninistrative rulemaking and concerns that it has regarding the matters inctuded. in that rulenraking process are not appropriate for these proceedings. AEl'-Ohio has failed to raise any new arguinents regarding this issue. Accordingly, rehearing on this ground is denied. III. 0713EId ISSUES A. Cort1nra te 5eparation 1. Transfer of Generating A ssets (98) IEU alleges that the Cmnmission eired by allowing AEP-Ohio to recover, through the noxrFAC portion of ifte generation rate, the Ohio customers' jurisdictional share of any costs associated with maintaining and operating the Waterford Energy Center and the Darby Electric Generating Station (lEU App, at 19-21). IEU states that tlle Conunissioii s detennination was without record evidence and a deinonstr.ation of need (Id.). (99) AEP-Ohio responds that the Convnission`s actions were reasonable in liglrt of SB 221 and the requireanent that the Commission placed on ABP-Ohio to retain the generating facilities. AEP-Oliio also submits that the Coxnmission's decision was lawful pursuant to Sectioxi 4925.14% Revised Code, wluch allows such flexibility in approving an ESP (AEP Memo Contra at 11-12). (100) After further consideration, the Cornrnissi.on finds IEU's arguments persuasive and grants rehearing on the issue of recovery of costs associated with maintaining and operating the Waterford Energy Center and the Darby Electric Generating Station facilities.throLrgh the non-FAC portion of the generation rate. The Companies have not demonstrated that their current revenue is inadequate to cover the costs associated with the gcncrathig facilities, and that those costs should be recoverable through the non-FAC portion of the generation rate from Ohio customers. We, therefore, direct AEP-Ohio to modify its ESI' and reinove tlte annual recovery of $51 million of expenses 148 08-917-61, SSO, et aI. -36 including associated carrying charges related to these generation facilities. B. T'JM Demand R^onse. Progranis (101) As a part of the 1:3P, the Cornpanies proposed to revise certain tariff provisiotls to prohibit S9O customers from participating in the deinand response programs (1?RP) offered by PJNh, both directly and indirectly through a third-party. The Commission concluded that, despite lntegrys' argunients to the con[Tary, the Cotnmission was vested with the broad authority to address the rate, cllarges, and servlce issues of Ohio`s public utilities as evidenced in Title 49 of the Revised Code and, tlterefore, reasoned that this Cotxurtission is the entity ta which ttie Federal Energy Regulatary Commfs.sion (FFRC) was referring in the Final Rule,t' 7-lowever, the Cotrunission uItimately determined that the record lacked sufficient informatiatt for the Cotnxn4ssion to consider both the potential benefits to program participants and the costs to Ohio ratepayers to determine whether this provision of the ESP will produce a significant net benefit to AEP-Oltia consumei•s, As a result, tlie Comrnission deferred the issue to be addressed in a separate proceeding and requested that AEP•.Ohio modify its ESI' to eliminate the provision that prohibits participation in PJM DRP. (102) The Companies request rehearing of the Commissicm`s decision, arguing that deferring this matter to a subsequent proceeding and allowing continued participation in DRP is nntvasonable and against the manifest weight of the evidence in the record. AI;P-Ohio points to what it calls "exhaustive treatment" of the issue by the parties in their briefs, motions, memoranda, written testimony anti hearing transcripts. AEP-Ohio subtnits that the Order allows current DRP participants to continue participation in such programs t'hrough niid-2010, halfway through the term of the BSP; but also perrruts other customers to register to participate since FERC has re-apened registration until May 1, 2009.15 The Companies view the re-opening of registration by FERC as an opportuzuty for ihe Coinmission to prolubit current id Whalesnle Competifiurt irc ftcyions zoith Orgartizcd Elech'ic• Markcts (Docket Alos. Rtvi07-14-000 and AD07-7- 000),1251'GRC ^ 61,071 at 18 CFR Part 35 (October 17, 2008) (Final Rule). is PJM Inierconnec ion,126 PERC ¶61,275, Otnler at ¶89 (Ivfarch 26, 2009) . 149 08-917-Lil: SSO, et al. registrants' participation in DRP, without prejudice, by way of a timely decision to restrict retail participation. (203) The Companies also argue tllat the Indiana Utility Regulatory Commission (TJi2C).recentty granted a request by an AEP-Ohio affiliate to continite the Commission's default prohibition agai.nst retail participation in the PJM DRP 'while that Commission continues to consider a more pezmanent resolution to this isstze. However, the Tndiana LJRC will consider individual eustoincr requests to participate in DRP on a case-by- case basis.xb AEP-Ohio advocates the Indianx URC's approach, which the C.ompanies assert will facilitate the use of dernand resources within Ohio and allow AF3P-Ohio to refine its retail DRP to meet the mandates for PDR. AEP-Ohio contends that the Order creates uncertainty for the Companies and additional costs for ratepayers in two respects: (a) AEP-Ohio's i'DR cornpliance costs increase witlt the exportation of Ohio's demand response resources through retail participation in the PJM prograrns; and.(b) nonparticipating customers will incur additional long-term capacity costs due to ANP-Ohio's obligation to continuc to provide firin service even though the participatin.g customers are using their load in a manner that is akin to interruptible service. APP-CJhio states that it is the Companies' goal to emulate the PJM DRP at the retail level to the extent possible. Further, AEP Ohio proposes that, if the Commission restricts retail participation on rehearing and ordcrs the C:oinpanies to niodi.fy their programs to the inaximum extent possible, AEP-Ohio's customers would benefit from demand response in terms of a reductioil in the capacity for wliich AEl'-Oliio customers are responsible. According to AEP-Oiiio, such a decision would also siuourage A)iP-Ohio to work with stakeholders to ensure that predictable consumer demand response is recognizeci as a reduction in capacity that CSP and OP carry under PJM market rules and support APP- Ohio's PDR obligations (Cos. App. at 23-26). (t p2) IEU, OCC. and Integrys each filed a memorandtim corttra this aspect of the Compmlics' request for rclioaring. Like AEP-Ohio, tEU agrees that the Commission had suffic.ient fnformation to Related to Dernand Sespon`se Progran s 16 In the Matier of the Cornntissrort'4 Ins ehtigalion fnto Any and Att Matters OfJered lry ttre Midwest fSO and Pfh4 tnferconnection, Cause No. 43566 (Pehruary 25,2009 Order). 150 -38- 08-917-EL-56O, et al. decide this issue, but supports the Commission s conclusion to allow retail paxticipafion in DRP until a decision is ultimately inade_ Further, IBU asserts that the bases .ACP-Ohio cites for support of its xequest for rehearing are inaecurate and(or misleading (IrU Memo Contra at 10-11). IEU and OCC state that Alsl'-Ohio ha.s mischaracterized the Indiana URC's ruling. IEU contends 4hat the Indiana URC's position is irrelevant as Inc3iana operates under a cost-based ratemaking regime unlike Ohio (I13U Meino Contra at 11). Further, OCC cites and IEIJ quotes the Indiana URC's order to state, in part: . The initiation of the Comrnission`s investigation in this Cause did not alter the Commission's exisflng regulatory practice of requiring approval prior to direct participation by a retail customer in an [regional transmission organivation demand response program]. Nor did the Commdssion's investigation prohibit Indipnu end-use customers desiring to participate in PJNi's D.PRI's from ffling a petition seekxrog approval fronr the Cortimission. histead, the Coxtunission commenced this investigation to determine whether, and in what martner, the Cozzunissioxi s regulatory proceduxe should be modified or streamiined to address requests by end-use customers based on the iraportance of dernand response and the increased iarterest in participation in RTO DRPs. [F.mpYwsis udded.]17 IFsU and OCC note that of the five Indiana customers that requested approval to participate in the RTC? DRP, as of the filing of the memoranda, three requests had been approved and two were pending (ISU Merao Contra at 12, n.5; OCC Memo Contra at 13). In other words, IPU concludes that there is in facE no prohibition on customer participation in RTO I)RP in Indiana (IEU Memo Contra at 11-12). (105) Integrys and OCC state that there is no evidetu e in the record to support AFP-Ohio's daims that continued participation in RTO DRP will increase the Companies' compliance cost to meet its PDR requirements under Section 4928.66, Revised Code (Integrys Mema Contra at 8; OCC Memo Contra at 12). Integrys 17 Id, at 5. 151 -39- 08-917-BC.-SSO, et al. expla'vw that the statute does not require the use of in-state demand response resources, prohibit participation in RTO DRP or require the mercantile customer to integrate or commit their DrPs to AEP-Ohio. Gonunit7nent is at the mercantile customer's option. Further, Integrys interprets the Comanission's decision in the Duke Energy of Ohio ESP case to affirm its ini:erpretationla (Inte{,nys Memo Contra at 5-6, $; OCC Memo ContA•a at 12). OCC also argues that ilzere is no evidencc in the record to support the representation that customer participation in DRP will not benefit AEP-Ohio's customers by decreasing A1;T'-Ohio's Ioad. OCC reasons, and Integrys agrees, that DRP improve grid reliability ancl make markets more efficient by avoiding the cost associated with new generation to service load and, as such, the intervenors reason that DRP are a benefit to all custoincTs participating in the RTO's markct (OCC Memo Contra at 12; Integrys Memo Contra at 9). Integrys rationalizes that customers participating in the PJM DTtP under AEP-Ohio Scliedutes GS-2, GS-3 and GS-4 pay demand charges for firm capacity irrespective of whether the customer takes service or service is curtailed (Integrys Memc) Contra at 9). IF"iJ claims that ALI'-Ohio's arguments implicitly concede that PJM's DRP are niore valnable to customers than the interruptible service offered by CSP and OP, and IELJ empllasizes that it is the mercantile customer's choice to dedicate customer-sited capabilities under SB 221. Also, IELJ asserts that the Companies' assertion that the Order witl cause additional long-term capacity cosfs for nonparticipating customers is misleading at best. IEU explains that, should any additional long-term capacity costs be incuxred, it would not be the result of customers participating in RTO DRP, but AEP-Ohio's convnitment to nieet the generation resource adequacy requirement of aIl retail suppliers within its ].'JIvI zone for a period of five years through PjM's fixed resource requirement program (IE'U Memo Contra at 12-13). Pinally, OCC asks that the Commission retain an 5S0 customer's option to participate in a variety of competitive DRP as sucit is supported by the goals of SB 221(OCC Memo Contra at 11). of an EtectTic SecuritY Pian, Case No. i9 1n the Iutatfer o( tlre Appitcatton of Duke Pnergy Ohio, Inc., for Apprvvai 08-920-FL-SSO, et al., Opinion and Order at 35 (December 17, 2008). 152 -40- 08-917-EL-SSO, et aI. (106) Integrys and IBU assert that any failure of AI3P-Ohio to comply with the PDI; requirements of Section 4928.66, Revised Code, are not because of customer participation in PjM's DRP but the Iack of attractive prograins offered by AEP-Ohio (IEU Memo Contra at 13; Integrys Memo Contra at 7). Purther, Integrys notes that the Compauies' three interruptibie service offerings (Schedute IRP-D, LCS Rider and YCS Rider) have only 8 AEP- Oluo customers (intel,Trys Memo Contra at 7). Further, Integrys suggests that, if the Companies believe that the DRP are affecting the Companies' PDR compliance piaiis, Section 4928.66(A)(2)(b), Ttevised Code, permits AEP-Ohio to request that its PDR goals be xevised (Integrys Memo Contra at 7-8). (107) As to the Companies' alleged desire to emulate RTO DRP, OCC argues that the Companies conld have developed and filed C3RP that rnirrored PJM's programs as a part of their PSI' application (OCC Memo Contra at 12). For these reasons, IEU, Integrys, and OCC request that the Commission deny AEP-Ohio's application for rehearing as to the PJM DRPs. (108) The Commission rejects AEP-Ohio's proposal to direct DRP partxcipants to withdraw from. PJM programs at this iime. The registration deadline of May 1, 2009, has passed and we consider this request to be moot. Furthermore, the Corrunission is not convitlced by AEP-Ohia s claims that an abrupt change in the Commissiori s decision would not harm customers already registered to participate in PJM's DRP, given that customers may have entered into contractuat arrangements, invested in new eguipmettt, and agreed to operational commitments in reliance ori the Commission`s Order. Thus, we affirm our decision not to prohibit AEP-Ohio's SSO customers' from parLicipating in PJM's DIZP at this time and will reconsider our decision in a subsequent proceeding. Finally, the Conuiission rtotes that AEP-Ohio, IEL3, tntegrys nor OCC presented, in their respective briefs or memoranda, quantification of record evidence to address the Commission's primary concern with this provision of the FSP. The Commission requires additional information to consider the costs incurred by various customers to balance the interest of AEP-Ohio customers participating in PTivi's DRI' and the cost AEP-(7hio's other customers incur via the Cornpanies retail rates. Moreover, none of the arguments presented in the applications for rehearing or the memoranda 153 -41.- 08-917-EL-SSO, et al. contra sufficiently address this aspect of the PJM DRI' and, therefore, fail to persuade the Commission to reconsider its decision regarding PJM DRP participation. In further consideration of the need to balance the potential benefits to PJIF41aRI' participants and the costs to ATs"i'-Ohio ratepayers, the Commission clarifies that AEP-flhio customers turder reasonable arrangements with l1EP-Ohi.a, ineluding, but not liimited to, FE/BDR, economic development arrangements, unique arrangements, and other special tariff schedriles that offer service discounts froin the applicable tariff rates, are prohibited from also participating in PJM D72P, unless and until the Convnission decides otherwise in a subsequent proceeding. `l'he remaining issues in the applications for rehearing on PJM DRP participation are dcnied, C. Effective I?ate of the FSP (109) OCC claims that the Coinmission erred by permitting AEP-flhio to apply their amended tariff schednles to services rendered prior to the entry of the Corrunission approving such schedules, in violation of Sectioas 4905.22, 4905.32, and 4905.30, Revised CodF, and the Ohio and United States Constitutions (OCC App. at 18_19, 24-25). CjCC recognizes that the effective date of the tariffs, as corrected by the Entry Nunc i'ro Tune issued on Ivlarch 30, 2009, was "not earlier than both the cornrnencement of the Cornpanies' April 2009 billing cycle and the date upon which the fuzal tariffs arc filed with the Commission" (Id.). However, QCC asserts that permitihig the increased rates to be effective on a"bilis-rendered" basis, instead of a"services- rendered" basis, authorizes increased rates prior to the approval of the ncw rates, whicli includes charges for electric energy already consumed. OCC opines fhat applying aznended tariff schedules to services rendered prior to the Commission's entry that approves such schedu7es violates Sections 4905.22 and 4905.32, Revised Code (Id.). (110) OCC also asserts that the Conitnission erred by establishing the term of the ESP beginning January 1, 2009, which equates to the Companies collecting retroactive rates for the period January 2009 through March 2009, in violation of Ohio law and case precedent (Id. at 20-24). 154 08-99 7-CC.-SSO, et aI, -42- (111) C7CC further alleges that the Order violates Section 4929.141(A), Revised Code, which OCC interprets to require an electric utility's rates in effect January 1, 2009, to continue if an S5SO has not been approved by the Commission, OCC argues that, to the extent that, the Order replaced the rates in effect at January 1, 2009 without an apprpved SSO, it violates Section 4928.141(A), Revised Code (Id. at 25-26). (7.12) Sitnilar argumc:nts were raised by several other intcrvenors (OMA App. at 3-4; OI-iA App, at 2-6; Kroger App, at 8-9). (113) AEP-Ohio opposes the intervenors cl.aims regarding retroactive ratemaking, stating that the various claims are without merit and should be rejected (Cos. Memo Contra at I4-25), AEP-Ohio explairs, that the Commission's Order, as clarified by the Entry Nunc Pro Tunc, approved a modified ESI' with a term commenci-ng January 1, 2009, and ending Decetnber 31, 2011 (Id. at 14). AEP-Ohio £iled coinpliance tariffs implementing the new rates adopted in the ESI', conunencing with the first billing cycle of Apri12tJ09, wliich included an offset of the reve.lues collected from custoiners dnring the interim period (Id). The Companies argue that Sections 4905.22 and 4905.32, Revised Code, require public utilities to charge rates that are authorized by the Commission, as reflected in approved tariffs at the time of the billing, which AIrP-Ohio properly did, and OCC's general disagreement with adopting rate increases on a bills-rendered- basis is not an issue unique to this proceeding (Id. at 16). (114) ALP-Ohio further responds that the Coztunission authorized a three-year. ESP with a term of January 1, 2009, through December 31, 2011, and required that the revenues that were collected duxing the interian period, pursuant to Case No. 08- 1302-EL-ATA, be offset by the new rates (Id. at 17). AEP-Ohio states that the Commission did not establish retroactive rates but, instead, nsed a prospective rate mechanism to implement the full term of the PSP. The Cornpanies also note that the Commisszon's decision did not provide for new rates during the first quarter of 2009 and did not require tha Companies to baclcbill individual customers for service already provided aitd paid for. 155 08-917-EL-SSO, et al. (115) It has been a long standing Commission policy to approve the effective date of tariffs on either a bills-rendered or seivices- rendered basis depeiiding on the specific facts of each case. As noted by the Compataes, "jo]rderillg rate increases effective on a bi11s-rendered basis is a widely used and established practice in various types of rate cases' (Cos. Memo Contra at 16). (116) We also agree with AEP-nhio that our decision does not constitute retroactive ratemaking in violation of Keco Irtdusfrie,s, Inc. v. Cincinnati & Suburban Betd Tel. Cn. (1957),166 Ohio St. 254 (Cos. Memo Contra at 1€3). During the interim period (first quarter of 2009), the Co.nnrussion approved rates pursuant to Sectioci 4928.141(A), Revised Code,19 artd, subsequently, tlwough our Order in this proceeding, we authorized the revenues collected during the interim period to be offset against ttte total allowable revenues that the Companies are auttiorized .to receive pursuant to their, 1;SP, as modified by the Cornrnission (Order at 64, corrected bry Entry Nunc Pro Tunc at 2). The Cornmission did not permit the Companies to go back to j'anuary 1, 2009,.and re-bill customers for the consumption that tIiey used during the first quarter of 2009 at the.higher rate estabiished by our Order. F-Iad our Orcler allowed the Companies to re-bill customers at the higher rate based on actual consurnption froni Janttary 1, 2009, through Mmd1 31, 2009, which it did not, ive would agree that an order anthoriying such rebil.liztg would constitute retroact-ive ratetnaking. (117) As explained previously, our Order remains consistent with Section 492$.9.41, Revised Code, which requires an electric utility to provide consumers, begiiuiing on 7anuary 1, 2009, a SSO established in accordance with Section 4928.142 or 4928.143, Revised Code (Order at 64, corrected by Fntry Nunc I'ro Tune at 2). The Commission approved APSP-Ohio's three- year FSP, with modifications, but did not allow AEP to collect higher rates associated with that approved ESP until the first billing cycle of Anri12009. We clarified our intent to this effect in our Lntry Nunc Pro Tune, pages 1- 2: " In re Cotwubr.is Sothern Pcnuer Co. mrd Olrirr Power Co., Case No. 08-1302-PirATA, finding and Order at 2-3 (D¢cember 19, 2008) and nindhig and (hder at 2(Pebmary 25,2009). 156 08-917-EI.SSO, et aL It was not the Conunissi.on's intent to allow the Companies to re-bill customers at a higller rate for their first quaiter usage. The new rates established pursuant to the ESP were not to go Into effect untdl final review and approval by the Cornmissioit of the Conlpanies' cosnpliance tariffs. Given that our order was issued on March 18, 2009, and that the Coinpanies' existing tariffs approved by the Conunission were scheduled to expire no later than the last bi31i.ng cycle of March 2009, it was anticipated that the new rates would not become effective until the first billing cycle of ApYil. (Iig) We further addressed these issnes in our entry issued on It9arch30, 2009, when we denied the request for a stay (March 30 Fntry). In that March 30 hntry, we specifically stated that we disagree with the characterization that our action, alIowed AEP-Ohio to retroactively collect ratea (March 30 Entry at 3). In that saine March 30 Entry, we also addressed the claim that ttte Order violated Section 4928.141(A), Revised Code. We explained that in, our finding and order issued on December 19, 2008, in Case No. 08-1302-ETrATA, the Commission established rates for the interini period, stating that "the rates in effect on July 31, 2008, would continue until an 5Sd is approved in accordance with Section 4928.342 or 4928.143, Revised Code" (March 30 Entry at 3). Moreover, we agree with Alsi'-Ohio's undex'standing of the offset required by our Order (C:os. Meino Contra' at 22), The offset was an adjustcnent that the Comniission believed to be fair in calculating the incrementally higher revenue autliorized for 2009, in light of the tin-ing of the Canunission's decision on the ESP and the need for an interim plan. Tlie Commission lras considered atl of the axguznents raised surrounding these issues several t-imes in multiple proceedings and has specifically addressed the arguments in its previous decisions. The parties have raised nothing new for the Comniission's coit.sideration. Accordingly, the Coaxunission finds that its Order does not constitute retroactive ratemaking, and does not violate any statute or constitutional provision. Therefore, we deny rehearing on all grounds associated with the effective date of the new ESP rates. 157 -45- 08-917-EL-SSO, et al. (119) Furthermore, the Commission finds that the Companies' should file revised tariffs consistent with this eltry, to be effective on a d.ate not earlier than both the conrmencement of the Companies' August 2009 billing cycle, and the date upon wl-ach final tariffs are filed with the Commission. In light of the timing of the effective date of the ltetv tariffs, the Coininission finds that the tariffs shall be effective for bills rendered on or after the effective date, and contingent upon final review by the Conunission, IV. SIGNIFICANTLY E^CESSIVS EARNINGS TEST (5ELi11 (120) In the Order, the Commission concluded that the SEET would be established withai the framework of a workshop to develop a coi7mzon rnethodology for all Ohio electric utilities. The Commission reasoned that, pursuant to Section 4928.143(P), Revised Code, there is time to develop a comrnon methodology for all Ohio electric utilities because the SEET will not actually be applied until 2010 for the year 2009, consistent with the Conunission's decision in the TirstEnergy ESP Case?o However, the Coznmission recognized that AEP-Oluo required certain information to evaluate the xnodified ESP. The . Coirunissitn noted that the Companies' earnings from off- system sales would be excluded from fuel costs and, consistent with that decision, also excluded off-system sales margins from any SEET. A. AE1'-Qltio as n sinff1e-entit4 for SEET (121) AFP-Ohio, in its tlvrteenth assigiunent of error, requests that the Commission provide further clarification of the SEEiT and the scope of the issues to be addressed at the SEET workshop. AEP-Ohio requests that the SEET apply to CSP ancl OP as a single entity because investments in the electric utilities are made aiui their operations are conducted on a com6ined basis. The C'ompanies tirgue that the "single entity" approach was supported by Staff (Staff Flx. 10 at 25). The Companies also argtze that a common SEET methodology does not require an and the Tofedo Edtson Conipany, ^ In re c3Jrio t:dtson Conipanx The CievoJand Elechic I11uFnfnating Company, Case No. 08-935.-FiL-SSO, Opinioii wLd Order (December 79, 2008). 158 08-917-0^SSt7, et al. -46- ide.nticalSEET methodology for each Ohio electric utility (Cos. App. at 40-41). (1,22) While IBU does not take a position, at this time, on the merits of AEP-(]liio's request, IBtJ argues that the clarification need not be addressed as a part of the entry on rehearing and the issue is more appropriately deferred to the workshop (IEU Memo at 15). O.n the other hand, OCC opposes AEP-Ohio's request. OCC proffers that despite Staff's belief that the consolidated evaluation of the Companies' earnnngs for purposes of the SEET would help mitigate "asynunetrical" risk, Staff was reluctant to address the issue of whether such practice was permilted pursuant to SB 221.. OCC argues that combining CSP and OP for SEET pzrposes is prohibited by the statute. OCC notes that paragraphs (C) and (E) of Section 4928.143,1Zevised Code, each refcr to "ttle electric distribution utility" and that Section 4828.01(A)(6), Revised Code, defines electric distribution utility as "an eleetric utility that sapplies at least retail electric distribution sea.vice." As such, C?CC contends that the statute clear.ly expresses the legislative intent and the statute must be applied accordingly.=1 Thus, OCC reasons that the earnings of CSP and OP cannot be combined for calculatioti of the SEET pursuant to the statute (OCC Memo at 14-15). (123) 'I'he Coz'n.n'Lission concludes that consideration of whether CSl' and OP should be considered a single-entity, AEP-Ohio, far purposes of the SEE'I' is an issue more appropriately addressed as a part of the SET"r workshop. B. OS5 (124) Kroger reasons that the Order is unreasonable and unlawful to the extent iliat the Order excluded OSS ntargins from the SEET and did not share OSS margins with custozi2ers as an offset to TAC. IU•oger claims that the Order does not explain why OSS zztargins are excluded from the SEET (Kroger App, at ff), Further, Kroger clarifies that its request as to OSS was in the alternative. More precisely, Kroger requested that should tire Wood (1973), 36 23 1 inie Warner v. Pub, Utit. Comm. (1996), 75 Ohio SY0d 229, 237, citing Prozrident 8ank v. Ohio St,2d 101. 159 08-917-SL-550, et aI. • -47- Commission exclude OSS margins as an offset to the FAC, then the Commission should then include 055 margirrs in the SEET. Kroger argues that the {7rder uiappropriately allows AEP-Ohio to retain all of the benefits of OSS Tnargins and AEP-Ohio's distinction between SB 221's focus on retail sales as opposed to wholesale transactions is unsupported by legal authority and contrary to Ohio law. Kroger reasons that AEP-Oluo's generating assets, which produce electricity for C?SS, are included in the calculation of the Companies common equity and, therefore, OSS should be includeci in the SEET. Further, according to Kroger, neither Section 4928.143(F), Revised Code, nor any other provision of the I2etrised Code excludes OSS fiolu the calculation of the reiurn on conunon equity. Tllus, Kroger requests that the Commission reconsider the Order to at least share OSS margir-v5 with AF.P-Ohio's custonlers (Kroger App. at 6-B). (125) OCC argues tlcat recogctizing OSS profits and sharing the profits between custoiners and the electric utility is consistent with the Comznisston s decision in a prior CEI Rate Case22 Further, OCC asserts tttat the Comrnission has previously determined that providing OSS xevenue to jurisdictional customers can assist in achieving the goal of providing reliable aicd safe service a.ud is consistent with the state policy set forth in Section 4928.02(A), Revised Code.23 OCC argues that, although the law does nat explicitly require an allocation of OSS to custontezs, the law also does not explicitly prohibit it, Thus, OCC reasons that the Commission has failed to follow it own precedenV4 (C.aCC App. at 16-17). Further, CCC reasons that the order fails to offer any justification for changing its position on tlus issue or to demonstrate why its prior decision.5 were in ermr. For this reason, OCC alleges that the Contrriission s Order yields an unreasonable and unlawful result as to the SEET (OCC App. at 18). Matter of the Application of the Cleveland Electrir litunrinatirrg Compnny for Authority to Amend and to 22 In the Etsctric Service, Case No. 83-'188-EL-AIIt, Irrcrerise Certuitt of it Fited Sc•hedtcies Fixtng Rates and Cliarges for Opinion and Order at 21 (March 7,1985). Company for aa Lnr.rease 6r its Rates for Gas 2-3 frt the Matter of tke. Application of the Cincinnati Gas & Elecirio Cnstonters, Case No. 95-656-UA-FSIi, Entry on Rehearing at 6-7 (February 12, Service to Ait JurisdicG'o>wl 1997). 24 Cleoetand Elec. IJluminatirtg (1975), 42 ORio St.2d 403 at 431. 160 -4&- 08-917,1:L-,S5O, et al. (126) OEG and OMA argue that the exclusion of OSS creates a fundainental asymtnetry by comparing only part of the eanvngs of AEl'-Qhio with the full earnings of the corztparable companies (OEG App. at 24; DMA App, at 4-5). OEG argues that the "return on cosmnon eqtsity that was earned° by the Companies includes profits from M. OEG contends there is no statutory basis for comparing oi-dy part of the earnings of AEI'-Oh[o with basis full earnings of the comparable cornpanies and such a comparison distorts the analysis. As a key consumer protection provision of SB 221, OEG asserts that failing to include aIl of the Companies' earnings undermines the intentions of and the plain meaning of the statue. OEiG notes that the record reveals that, during the term of the ESP, projected OS5 S profits are $431 million for OP and $360 nullion for C.SP and ignoring such earnings misconstrues the statue aYUi fails to provide meaningful consumer piptection as intended by 513 221. On such basis, OEG and t)MA argue that the SEET set forth in the Order is un(awful (OEG App. at 2-4; OMA App. at 4-5). (127) As interpreted by OCC, Section 4428.148(F), Revised Code, requires the Com.mission to determine whethex AEP-Ohio's ESP results in excessive earnings and includes all provisions of the E..SI', including deferrals. OCC believes that eliminating deferrals from the SEET is an unauthorized adjustment and opines that the elimiztation of the deferrals is unlawful as it is not aathnrised by the statue. OCC argues that eliminating deferrals from the SEET wi]I rnisstate the Companies' earnings, distorting the match between expenses and revenues and distorting the SEET. OCC asserts that the exclusion of the deferrals unlawfully gives AEP-Ohio a inargin and virtually ensures that the Comparnies will not violate the SEE'3.' (OC.'C App, at 67-68). (128) OEG agrees with the Commission's decision to exclude deferrals and the related expezises from the 3EET so that deferrals are matched with revenues when revenues are received by the Companies. However, OEC; seeks clarification of the Order to the exteiit that the Companics' annual eaznings for purposes of the SET:T will exclude all defcsral of expenses and, once recovery of the deferral actually begins, all amortization expenses associated with amounts previously deferred (OEG App. at 4-6). 161 et al. -49- (129) We grant the intervenors' requests to reconsider the exclusion of pSS margins fxom the SEET calculation. We have decided that Iilce our coiisideration of whether to treat AEP-OIuo as a single-entit} for purposes of the SF..ET, flSS is an issue more appropriately addressed. in the SEET workshop. Similarly, the Commission concludes that to furthex explore the issues of deferrals and related expetvses, in regarda to the SEET, we will also address these components of the BEET as part of the workshop. V, MARKET-RATE OFFER (MRO} v. ESP ( l3tl) AFt'-Ohio argues that the t]rder is unlawful and unreasonable because Section 4926.143(C)(1), Revised Code, does not permit the Commission to niodify the ESP if the proposed ESP is rnore favorable than the MRO (Cos. App, at. 4-5). OCC disagrees and states that the Commission properly applied the seatutory test when it compared the modified ESP to the results that would otherwise apply under a MRO (OCC Memo Contra at 9). Similarly, Kroger, OPAE, IEU, and OEG assert that the Comrnission properly exercised its statutory authority to modify the proposcd ESP to nlake it more favorable than the expected results nf a MRO (Kroger Memo Contra at 4; OPAE Meino Contra at 4-5; IBU Memo Contra at 7; OEG Memo Contra at 3). (I3-1) We agree with the intervenors, The statute contemplates modification of a proposed 1;SI' by the Commission, and then a comparison of the zrtodified ESP, as approved, to the results that would otherwise apply under a MRO. As explained in our Order, our statutory authority is not limited to an after-the-fact determination, but rather, includes the authority to make modifications to a proposed ESP that are supported by the record. Therefore, AI;P Ohio's rehearing request fs denied on this ground. (132) IEU argues that the costs associated with the POLR obligation should not be included in the MRO portion of the ESP versus MRO coinparison (IEU App, at 43-44), IEt7 contends that the Comcnission lacks the authority to approve a POLR charge in a Section 492$_142, Revised Code, proceeding (Id. at 44). 162 -50- 08-917-EC.-..SSO, et al. (133) Tkle Companies interpret IEU's argulnent as an erroneous belief that the Coxnpanies' I'OI12 obligation tertnfnates in the MRO context (Cos. Melno Contra at 13). P.EP-Ohio contencis that its risk associated with the POLR obligation under SS 221 continues regarding the non-market portion of tlie MRO, and that it is unreal"sstic to evaluate the cost of an MRO without including the POLR obligation (Id.). (134) IBU also appears to be r-equesting rehearittg claiming that the Order does not pr.ovide adequate justification or offer even the "s]ightest clue" for its decision as required by Section 4903.09, I:evised Code (IF.U App. at 22-26). However, IEU then argues that the market price that the Contmission used in its comparison is too high an.d that, since testimony was filed in the proceedizig, market prices have declined. IEU is suggesting that the Conu-nission do on rehearing exactly what it criticizes the Cornrnission's Order for doing, w.hich is base its opinion on information and data that is not in the record of the proceeding. AEP-Ohio objects to IEU's approach of using extra-reeord iAiformation to state that hhe Coinmissiou s analysis was flawed (Cos. Memo Contra at 12). (135) Tltere was no need for IE[7 to 5earch for clues in the workpapers, The Conunission weighed the evidence in the record and adopted Staff's estimated markct prices, as well as Staff's methodology, in the Order. At page 72, the Conunission stated its basis: "Based upon our opinion and order ancT using Staff7uitness Hess' methndotogy of the qumstification of the F.SP v. MRO compari.son ,.,° (emphasis added). Prior to explicitly stating which quantification analysis that it used, the Coxnmission explained that Staff witness Hess' methodology included the utilization of Staff witness Johnson's estimated market rates to demonstrate that the ESP is more favoxable in the aggregate as conzpared to the expected results of an MRO (Order at 70). The Order also explained that the Companies calclalatecl the estimated market prices to be $8$15 per M{'VI-I for CSP and $85.32 per MtNH for OP. OCC provided testimony of estlnlated market prices of $73.94 per MwI3 and $71.07 per MWI-I for CSP and OP, respectively (OCC Ex. 10 at 15-24), while Staff offered testimony of estimated nrarket prices of $74.71 per MWH and $73.59 per MWH for CSP and OP, respectively, 163 08-917-EL-S6O, et a.l. -51- which were then utilized by Staff in an MRO v. ESP comparison (Staff iix.1-A, Revised Exhibit )EH-1). Utilizing tbeir respective estiinated market prices, both OCEA (which includes OCC) and Staff concluded that the IaSP, if lnodi.fied, was niore favorabie in the aggregate than an M1ZO (see Order at 70-71). Based on the record before it, it was reasonable for the Convnisssion to adopt Staf£'s estimated market rates and Staff's methodology to yuantify the ESP v. MPiC1 cornparison. IEU's argument to the contrary lacks merit and, thus, is rejected. (136) With regard to the M1t0 versus ESP comparison, our analysis did not end with the rehearing requests. Upon review of the record in this case and all arguments raised on rehearing, the Commission does in fact find that the ESP, including deferrals and future recovery of deferrais, as modified by the Order and as further inodified by this entry, is more favorable in the aggregate as compared to the expected results that would otherwise apply under Section 4928.142, Revised Code. (137) The Commission notes that, with this entry, it is further modifying AEP-Ohio's 1?SP to reduce the rate impacts on custoiners. '1'he Contlnissioii believes that the niofli.fications made in this e-ntry increase the value of the Companies' ISP. Nonetheless, even if we do not include the POLR obligation in the calcLilation of the MRO versus ESP comparison, the Coni.mission finds that the ESP is still more favorable in the aggregate as compared to the expected results that would otherwise appiy under Section 4928.142, Revised Code. VI. StCTTON 4963.U9 REVISL'-DCODE (138) IBU generally argues that the Convnission's decision fails to comply with the requirements of Section 4903,09, Revised Code, to sufficiently set forth the reasons proinpting the Commission's decision based upon the findings of fact in regards to carrying costs, FAC, the rate increase Iinlitatlon, POLR, the tiaiisfer of generation assets, gridSMART and other distribution rate increases, and the coinparison of the ESP to the MRO (IEU App. at 4-26). 164 08-917-EhS5O, et al. -52. (139) Similarly, OCC argued that the Cornrnission failed to meet the sufficiency requiremcnts of Section 4903.09, Rev9sed Code, when it denied OCC`s mo6an for stay in its Marcli 30, 2009, Entry Nunc Pro '1'une, and failed to mafce the Companies' collection of rates subject to refund, and when it approved the ESRP rider (OCC:11pp. at 27-29,55-57). (140) AEP disagrees, stating that the Commission explained the bases for its determination of the issues raised in this proceeding in a manner that satisfies Section 4903.09, Revised Code, as well as Supreme Court precedent (AEP Memo Contra at 5-10). (141) As discussed.znore fully in the individual sections deal'uig with each subject matter, the Coinmission finds that it fully and adequately set forth its decisions in its Order, consistent with Section 4903.09, Revised Code, and long standing precedent, See Industrial Energy LTsers-Olaao v. I?u.b. iXtfl. Con2nz. (2008), 117 Ohio St.3d 486, 493, 2008 Ohio 990; MCI Telecom. Corp: v. Pub, tlfit. Cotnm. (7.987), 32 Ohio St.3d 306, 513 N.E.2d 337; Tongreit v. Pub. lttil. Com. (1999), 85 Ohio St.3d 87,1999 Ohio 206. it is, therefore, O1tDHRBD,1'hat the applications for rehearing be granted, in part, and denied, in part, as set forth hereui. It is, further, ORDERED, That the Companies file, for Commission review and approval, their revised tariffs consisten[ with tlus entry. It is, further, 165 -53- ©8-9I7-EL-SSO, et aI. OIZDBRFD, That a copy of this enta•y on rehearing be served upon all parties and otlier interested persons of record, •p13E PUBLICVILPi'IF,S COMMJSSION OF OHIO Ronda Hartman Fergus ^ papl A. Crezttolella Cheryl L. Robezto Valerie A. KWB JGNS:ct Entered in the jonrnat aUL h 3 2099. Reize6 J. jenkins Secretary 166 SEFORE Ti-IE PUBLIC UTILI'I'IES COMMISSION OF OIJIO In the Matter of the Application of Columbus Southern r'ower Cornpanv for Approval of an Electric Security Plan; an Amendment to Case No. 0$ 917-EL.SSO its Corporate Separation Plan; and the Sale or Transfer of Certain Generating Assets. In the Matter of the Application of Ohio Power Company for Approval of its Electric Case No. 08-918-EIrSSO Security Plan; anct an Amendment to its Corporate Separation Plan, Ct3IVCURRII^tGOPJ^IION OF CC7MIVIISSIONEIZ CIZERYL L. At^BEP.TO rt is the Comnaissioii s responsibility to proinote the policy of this state to "ensure the availability to consumers of .., reasonably priced retail electric service." R.C. 4928.02(A)- We are mandated to approve or ntodify and approve an electric security plan (ESP) whert we find that the plan or modified plan, including its pricing and all otlier terms and conditions, including any deferrals and future recovery of deferrals, is more favorable in the aggregate as compared to the expected results that would otlierwise apply under R.C. 4928.142. R.C. 4928.143(C)(1). While an ESI' may include components described in R.C. 4928.1430)(2), nothing in S.B. 221 requires that it be built on a component by component basis. In fact, given that the ESP is not cost based, focusing on any component in which a cost iturease is expected or demonstrated obscures the failure to conduct the corollary examination of components of the base rate in wlrich savings have occurred or in which revenue lias increased. T'hus, we are practically timited in our examination of an ESP or modified E.SI' to the aggregate impact. While I concur tllat the xnodified ESP is more favorable in the aggregate than what would be expected under an MRO, I do not agree with tlte underlying policy decisions expressed in paragraphs 18, 38, and 76 of the order and write separately to highlight that, while I do not agree as to these policy decisions.l do concur in, the result. As to tlie FAC baseline, in a cost-based matter it would be unacceptable to sacrifice accuracy when, alternatively, the Commission could order the record to be reopened for the sole purpose of receiving updated testimony as is appropriate for information that could not have been known at the time of the hearing pursuant to Rule 4901=1-34 of the Ohio Administrative Code, or order that the baseline be trued-up to account for actual 2008 fuel costs during annual reconciliation. Further, I specifically do not agree that R.C. 167 -2- 08-917-L?L-S.SO, et al. 4H28.143(B)(2) contemplates recovery for pre-January 1, 2009 environmental expenditures or that carrying costs for envirorimental expenditure.v should be aecrued at tlie weighted average cost of capital when there has been no finding that the debt has been prudently .tncurred taking into account the availability of pollution control funds. Nor can I find, as to the incremental increase in the provider of last resort cost, that the Black Scholes model is an appropriate tool to determine an appropxiate POLR charge, or that an inrseased risk of migration exists which resluires an incremental increase in POLR, as a POLR conaponent was already included within the Companies' existing base rates. The iiltimate resiil.t of these policy deeisions, however, is to increase the Companies' authori7ed revenue which, when combined with revenue realized from results in a particular price for retail electric service. It is other components of the Fa.P, this price, together with all the terms and conditions of tlle modified ESP, that must be more lavorablc in the aggrEgate than the results otherwise to be expected pursuant to R.C. 4928.142 in order for the modified E,SP to be approved. pvaluating the °expected" results that would otherwise apply under R.C. 4928:142 when compared to this price is of necessity speculative. The calculation must include a projected market cost. Within the existing record, I concur that the projected market cost has been appropriately defined.' I do, however, fmd that, as argued by Il?U and as summarized in paragraph 132, such a calculation may not properly include ait 137, even when incrententat POLR increase. However, as stated in paragraph correcting for this error by eliminating the incremental POLR increase from the MRO cost, I specifically concur that the modified ESP is still more favorable in the aggregate as compared to the expected results of an MRO. Cherylj< Roberto, Comndssioner i Given the signiHcantly.differeut econontic condidons which existed between ihe time of the record tastirnony and the time at which the Commission considered this matter (both as to flie origina! entry and upon rehearing), I would, however, have supported reopening the record for the limited purpose o£ refreshing the market price projections as this liiformation ivas not avaflable at the tinte of the hearing. 168 ATTACHMENT D A'l.'TACTITFNT D BEFORE '1'H1; PLIBLIC LPI'fL1TIBB COMIvJJSSTt}N OF OE3IO In the Matter of the Application of Columbus 5outhern I'o{ver C.otnpany for Approval of an Electric Security Plan; an Amendment to se No. 0S-917 Ei -SsO its Corporate Separation P]a n; and the Sale or 'I'ransfer of Certain Generating Assets. I'n the Nfatter of the Application of C7Yc'co Power Company for Approval of its Electric Case Na. 08-918-ELSSC) Secnritp Plan; and an Amenndment to its Corporate Separation Plan. HN'T'Rl! ON 1i13i tHARING The Commission f3nds: (1) . On Jal.y 31, 2008; Columbus Southern Power Company (CSP) and Ohio Power Company (OP) (jointly, AP,I'-Qhio or the ['..ompanies) ffled an application for a standard service offer (S50) pursuant to Section 4928.141, Revised Code. The application was for an e[ectric security plan (ESP) in accordance with Sectiott 4928.143, Revised Code. (2) On March 18, 2CK19, the Cotramission issaed its op3nion and order (Merch 18 £)rder) in these matters approvizeg, vri.tA moaifications, AEP-(?Iilo's proposed ESP. The Csammission amerided, nunc pro tunc, its Ivtarrli 18 Oxder on 1vTarch 30; 2.009. On April 16, 2009, and April 17, 200% several applications for rehearing of the March 18 t)rder wer'e €iled by numerous parties. By entry ozi rehearing issued May 13, . 2009, the CoanrrLission granted rehearing for further consideration of the inatters specified in the applications for rehearing. Oii July 23, 2009, the Com..i;aQion granted, in part, and den.ied, in part, the various applications for reheuring of the MaaYh 18 Order as set forth in the entry (july.23 Entry). . (4) Pursuant ta sewon 4403.10, Revised Code, any party who has entered an appearance in a C`.nmmission proceeding may apply for reheariuig with respect to any matters detem-ined by the Comraissioiy within 30 days of the entry of the order upon the Comrnission's jonnull. 170 -2- 08-917-EL-5Sa and 4$-918-EL-SSO (5) The Companies and the Industrial Energy Usars-0hio (IHU) fited applications for relwaring of the Conunission`s July 23 Entry on July 31, 2009, and August 17, 2009, respectively. IEU and the Office of the Ohio Consumera' Counsel filed memoranda contra the Companies' rehearing request on August 10, 2009. The time for filing memoranda contra IEU's rehearing request has not yet expired, (6) In order to address all of the applications concurrently, the Continlission finds that the applications for rehearirtg filed by AII''-Ohio and IEU should be granted. Furthermore, we believe that sufficient reasons have been set forth in the applications for rehearing to.ivarrant further consideration of the matters specified in the applications for rehearing. It is, tlterefore, ORDERED, "fhat the applications for rehearug be granted for further consideration of the matters specifieci in the applications for rehearing. It is, ftu'ther, 171 -3- 08-917-EL-SSCI and 08-918-E1rSSC7 ()RDERED, That a copy of this entry on rehearing be served upon all parties and other interest:ed persons of record. THE PUBLIC U'TII.iTIFS Co1vMSSIaN ar oHla 7 ^ Valerie A. Lernul3,e eryl L. Rot>ertv KWB/vrm Entered in the Journal At3 ° $ ZEB Rene6 J. Jenkins Secretary 172 ATTACHMENT E ATTACHMEN"x E - BEI"ORE THE PUBLIC UTILITIES COMMISSTON OF OHIO In the Matter of the Application of Columbus Southern Power Company for:Approval of an BIectric Security I'lan; an Ainendment to Case No. 08-917-EI.-SSO its Corporate Separation Plan; and the Sale or Transfer of Certain Generating Assets. in ttte Matter of the Application of Ohio Pov,er Company for Approval of its Electric Case No. 08-918-EI: SSO Secazity Plan; and an Amendrnent to its Corporate Sepaz'ation Plan. SECOND PNT12Y ON RPSHFsA3ZING 1 he Cominission finds: (1) On July 31, 2008, CoIutnbus Southern Power Company (CSP) and Ohio Power Company (Oh3.o Power) (jointly, AEP-OMo or the Companies) filed an application for a standard seryice offer (SSO) pursuant to Section 4928.142, Revised Code. 'L'he application was for an eleciric security plan (PSP) in accordance with Section 4928.143, ReviSed Code. (2) On March 18, 2009, the Cocnmission issued its opinion and order (lvfarch Order) in tltese matters approving, with mod'zfications, AEP-Ohio s proposed ESP. Tlle Cominission amended, nunc pro tunc, its March Order on March 30, 2009. (3) I'uxsuant to Section 4903.10, Revised Code, any party who has entered an appearance in a Commission proceeding may apply for rehearing with respect to any matters determined by the Conunissior^ withiui 30 days of the entry of the order upon the Comrnzssion`s journal. (4) On April 16, 2009, and April 17, 2009, appiications for i rehearing of the March Order were filed uy nur.erous parties. On May 13, 2009, t[ie Comrxcission granted rehearing for further consideration of the matters specified in the applications for rehearing. By entry on rehearing issued July 23, 2009, the Con'imission granted, in part, and denied, in part, the various appIications for rehearing of the March Order (July Entry). 174 -2- 08-917-EL-SSO 08-91$-EL-SSO (5) The Coinpanies and Industrial. Energy Users-Ohio (fEU) filed applications for rehearing of the Commission`a July Entry on July 31, 2009, and August 17, 2009, respectively. IBU and the Ohia Consumers' C:ounsel (OCC) filed memorailda contra ttle Companies' request for rehearing on August 10, 2009. The Companies filed a mentorandunt contra IEU's application for rehearing on Aiu.gust 27, 2009. (6) By entry issued August 26, 2009, the Commission determined that the applications for rehearing prescnted sufficient reason to warrant furthcr consideration of the issues raised therein. Pruthermore, to faciiitate the concurrent. consideration of the applications for rehearing filed by AEP-Ohio and CEU, the Commission granted the applications f.or rehearing. In this entty on rehearing, the Commission addresses the merits of the issues raised by AEP-Ohio and IEU. Watcrford and Darby Generatin^ Assets (7) In its Marcit Order, the Cominission found AEP-Ohio's request to transfer the Waterford Energy Center (Wate.rford) and the Darby Electrie Generating Station (Darby) facilities premature and directed CSP to' file a separate application for authority to seli or transfer the generating assets. However, the Coiiurussion concluded that CSS' should be allowed to recover Ohio customers' jurisdictional share of costs associated with the maintenance and operation of Waterford and Darby (March Order at 51-52). IfiU argued on rehearing that the C.omnission's decision to allow CSP to recover costs for the Waterford and Darby facilities lacked record evidence and the record lacked any dernonstration of need. Upon further review of the issue, the Coinrriission conciuded that the Cnrnpanies had not demoatstrated that their revenue is inadequate to cover the costs associated with ti-ie Darby and Waterford facilities and directed the Comp'rnics to reduce the artmual recovery of expenses in the RSP by $51 million including associated carrying charges related to the facilities (July Entry at 35-36). (8) AEP-Ohio argues that the July Entry is uirlawful and unreasonable to the extent that the Conimission revoked the Companies' ability to recover the costs associated with the Waterford and Darby pfants without reconsidering the 175 -3- 08-917-FT,Sa50 08-918-EL-SSO Companies' authority to sell or transfer the planta pursuant to Section 4928.17(E), Revised Code. I'tae Companies note that the facilities were purchased in anticipation of generation rates being market-based under Amended Substitute Senate Bill No. 3 (SB 3) and have never been included in CSP's rate base. Fnrther,% the Companies offered testirnony which states that Ohio customers' generation rates do not reElect CSP's investment in the plants or the expense of operating and tnaintaining the plants. The Companies argue that in light of the Commission's revocation of CSP's authority to recover Ohio custoniers' jurisclictional share of the costs associated with the Darby and Waterford facilities, the Commission should authorize CSP to sell or transfer the facilities in accordance with Section 4928.17(E), [2evised Code. Further, the Companies claim that the Coinrn.ission is legally required to authorize the sale or transfer of the generating assets if the Coirunission will not allow cost recovery for the generating assets (Cos. App. 2-4). (9) In response, [EU argues that, as the party seelcing an utcrease in the total a*nount of allowable revenue, AEP-Ohio has the burden of proof to demonstrate that the existing rates fail to produce adequate invenue. IEU adds tliat a mere demonstration that a particular cost fs not currently reflected in the electric utility's existing rates may suggest, but is not evidence, that the revenues do not provide adequate compensation. Purthermore, [EU argues that Arnended Substittrte Senate Bill No. 221 (SB 221) does not establish or maintain a cost-of-setvice, least cost service, or just and reasonable service standard as was done with traditional ratemaking or bundled rate regulation pursuant to SB 3. 11:TJ reasons, therefore, that AEP-Ohio's claim that it is entitled to some sort of cost-based xecovery for the generating assets is contrary to Ohio law and other clainvs made by the Companies (IEU Memo Contra at 3-6). OCC, in its memorandum contra, argues that the July Bntry mereiy recognizcd that under Section 4928,143(C)(1), Revised Code, the Companies bear the burden of proof in this case and have failed to meet that burden of proof. OCC argues the Coinpanies request for authorization to sell or transfer the 176 -4- 08-917-EL-SSO 0$-918-EL -S..SO Waterford and Darby facilities at some futLile date, without filing or complying with the applicable rules that govern such a transfer, is inappropriate. OCC reasons that, if and when the Companies have developed a plan to sell or transfer, rather th.an just a request for pre-approval, it should file the plan pursuant to ttte rules adopted by the Commission. OCC conEends that following the rules enacted on this very issue will give interested parties the opportunity to fully explore the implications of the sale oe trarusfer (OCC Menio Contra at 1-3). Accordingly, IEU and OCC argue that the Companies' application for rehearing should be denied. (10) b%1i1e the Corn.mission ultimately concluded that the Companies failed to demonstrate that the revenue to be received was inadequate to cover the costs associated with the Darby and Waterford facilities and, therefore, the ESP was modified, the Corrunission did not prohibit the Companies from selling or transferring the facilities. The Coimnission directed the Companies to make a separate application for approval to sell or transfer the facilities, consistent with the requirements of Section 492$.27(E), Revised Code. Our decision in the March Order and the July Entry was based on the Companies' testimony that there was not a°present plan to exercise" the authoriiy to sell or transfcr the Darby or Waterford plants and the Staff's observation that the transfer or sale of the facilities could have a potential financial and policy impact at the tiaue of the transfer (Cos. Ex. 2-A at 42; Staff Ex. 7 at 3). AF..l'-Ohio has not presented any reasoii in its request for rehearing that convinces the Con.lmission to reverse its March Order or the July 13ntxy to the extent that the Commission concludcd that the Coanpanies' request for authority to transfer or sell the facilities is premature. When the Companies have established a plan to exercise their authority to sell or transfer the facilities, they sl-oald file such plan with the Commi.ssion for our corvsideration as required by Section 4928.17(E), Revised Code. Accordingly, AEI'-0hia s application for rehearing is denied. I'TIVI Dernand Ttesponse Pxoarain (11) In its application for rehearing, IEU asserts that the July Entry urdawfully and unreasonably prohibits AES'-Ohio customers, 177 -5- 08-977-EL-SS0 08-918-hIrS50 taking service pursuant to reasonable arrangements, from participating in the PJM demand response program (DizP). IEU argues that it is unreasonable for the Commission to prohibit customers under reasonable arrangements from participat-ing in the PJM '171iP until the Cormnission coivsiders the issue, as a whole, in a separate proceeding, because the Comnlission believes that it lacks sufficient informatian or a reasonable basis to make such a determination. Furtiier, IEU recominends that the Comrission address any concen.ls that it has about customers . with reasonable arrangements participating in the PJM DIRP on a case-by-case basis, pursuant to the Cosrunission's authority under Section 4905,31, Revised Code (IEl7 App. at 5-7). IEU also argues that the Comniissioxi s July Entry violates Section 4903.09, Revised Code, to the extent that it fails to provide any citation to record evidence or to provide an explanation for the Commission's decision to prohibit custonters with reasonable at7angements from participating in the PJM DRP (Id, at 7-9). (12) AEP-Ohio notes that.the July Entry expl.ains the Comrnission's rationale regarding PJM DRP participation as a need to further balance the potential benefits to PJM DRP participants and the costs to AEP-Ohio's ratepayers, In the context of the numerous pages of testimony, the sununation of the arguments, and rationale included in the July Entry at 36-41, AEP-Ohio posits that the explanatfon is adequate. to support the temporary, partial restrictioat on retail participation in the PJM L1RI' in light of the multitude of concerns raised in this matter. Further, AEP-Ohio rei.terates, as Staff testified, that the Companies and AEP-Ohiis's customers incur costs associated with retail custoiner participation in the PJM DRP, as the Companies count the customer's load as firm ttnder the C:ompanies' Fixed Resource Requireinents (FRR) that is reflected in AI3P-Ohio's .retail rates. Thus, AEP-Ohio requests that IEt7's application for rehearing of this issue be derved (Cos. Memo Contia at 2-6). (13) The March Order relies on Staff's testimony, which states that the PJM DRP cost AEP-Ohio's other customers as the load of such PJM prograin participants continues to count toward the Companies' FRR option and such cost is reflected in ArP- 178 -6- 08-917-E1-SSO 08-918-h1 SSO Ohio`s retail rates (Tr. Vol. VIII at 165-166; March Order at 54). The March Order and the July Entry explain the factors that the Comznission relied upou to reach its decision on this issue, as well as to support the refinement of the decision in the July Entry. Itecogiiizing that the FJM DRP offers a benefit to Ohio prograrn participants, in the March Order, the Commission also recognized •that the record indicated that the PJM DRP costs AEP-C3hio s other customers. It is indeed reasonable, upon recognition of these facts that, upon further consideration of the issue, tlte Cormnission extended its directive to prohibit AEP= Oliio's custotneis taking service pursuant to reasonable arrangements, which reflect a discount of the retail tariffed rate, frozrt also participating iur and receiving additional benefits from the PJM DRP at the expense of AEP-Ohio's other cti.stoniers. Although the Commission cannot, at this tirne, ciuantify the costs and benefits of the PJM DRl' to AF.i'-Ohio's customers, until the Corrunission furtlzer evaluates and addresses the issue, we cannot ignore the fact that reasonable arrangement custot-LLers, who already receive service at a discounted rate, arc also securing benefits from the PjM DRI' at the expense of other customers. As lEU acknowledges, the Cominission is vested with the authority to approve such reasonable arrangements pursuant to 5ection 4905.31, Revised Code. It is pursuacrt to such authority, and based on certain evidence cited in this entry, that the Commission finds it necessary and appropriate, at this time, to continue to limit reasonable arrangement custorners from participating in the PJM DRP, until the Commission further evaluates the issue. For fllese reasons the Cbmnussion finds that the March Order and the July Entry satisfy the requiremerits of Section 4903.09, Revised Code, and, thus, we affirm our decision in the July Entry and deny IELt's request for rehearing on, this issue. "A^c,-Ttance° of Modified FS7? Rates (I4) In its last assignment of error, IEU contends that the July Entry unlawfully failed to prohibit AFiP-Ohlo from accepting the benefits of the rates approved in the FSI' while simultaneously preserving its right to withdraw the ESP. On April 20, 2009, IELl filed an application for iinmecliate rate relief on the basis th,nt l:ER-Ohio had filed an applicaticu7 for rehearing asserting thaL various aspects of the March Order were unreasonable and 179 08-917-RI.,-SSO 05-918-EI.z'S0 unlawful and had began billing custotners, in accordance with the Commission's March 30, 2009 entry approving revised tariffs, while reserving judgment on H'hether to withdraw or accept the BSl' as modified by the Commission. IBU asserts that Section 492$.141, Revised Code, requires the prior rate platt to continue until a MRO or ESP is approved by the' Commi;,sion and accepted by the electric utility (IEU App, at 9- 12). (I5) A13P-Ohio responds that nothing in' Chapter 4928, Revised Cocle, dictates that an electric utility must forego its right to file an application for rehearing of an order modifying its ESP and continue to charge its pre-RSP rates while the Commission considers the argunrents raised by the other applications for rehearing. By entry issued March 30, 2009, the Commission authorized AEP-Ohio to charge (16) Given that AEP-Ohio has not filed notice with. the Commission tllat it wishes to withdraw its ESP, as modified and approved, it is unnecessary to address this issue on rehearing. Accordingly, IEU's request for rehearing on th4s issne is denied. it is, therefore, fu-rther, ORDHIZED, That the applications for rehearing are deued. it is, 180 -8- 08-917-EL-.%0 08-918-1:1-550 ORDERED, That a copy of this entry on rehearing be served txpon all parties and other interested persons of record. TFIB Pi3BLTC I.7TII.,ITIES COMIvIISSION OF OHIO Alan R. Schriher, Chairman 1'Aul A. Centolella L. Robezto CyNS/vrm Entered in the jotn-iial #iaV D 4 -1GaA 9: ,c^gy- Renec J. ]enlcins Secretary t81 REtEI Vyrg^00c BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO 7Ud9dPR 1,5 In the Matter of the Application of ) Columbus Southern Power Company for ) 0 Approval of its Electric Security Pian; an ) Case No. 08-917-EL-SSO Amendment to its Corporate Separation ) Plan; and the Safe or Transfer of ) Certain Generating Assets. ) In the Matter of the Application of ) Ohio Power Company for Approval of its ) Case No. 08-918-EL-SSO Electric Security Plan; and an Amendment ) to its Corporate Separation Plan. ) APPLICATION FOR REHEARING AND MEMORANDUM IN SUPPORT OF INDUSTRIAL ENERGY USERS-OHIO Samuel C. Randazzo (Counsel of Record) Lisa G. McAlister Joseph M. Clark MCNEES VVALLACE & NURICK LLC 21 East State Street, 17^m Floor Columbus, OH 43215 Telephone: (614) 469-8000 Telecopier: (614) 469-4653 [email protected] [email protected] [email protected] April 18, 2009 Attorneys for Industrial Energy Users-Ohia Thia is to certify tlzat the images appearing are aa accurate and complete r®prodr:ction of a case file dcaument de.live---x)-ed in the regnalar course of ba[aiae^; Techuieiaii. J rn Date Proceased yWa-P62 182 BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO 4n the Matter of the Application of Columbus Southern Power Company for Approval of its Electric Security Plan; an Case No. 08-917-EL-SSO Amendment to its Corporate Separation Plan; and the Sale or Transfer of Certain Generating Assets. In the Matter of the Application of Ohio Power Company for Approval of its Case No. 08-918-EL-SSO Electric Security Plan; and an Amendment to its Corporate Separation Plan. APPLICATION FOR REHEARING AND MEMORANDUM IN SUPPORT OF INDUSTRIAL ENERGY USERS-OHIO TABLE OF CONTENTS Pa eNo APPLICATION FOR REHEARING I MEMORANDUM IN SUPPORT 1. The Commission erred by granting stunning rate Increases while failing to issue a written decision in this contested proceeding that sets forth, in sufficient detail and baaed on the facts and law, the reasons prompting the decision. 4 A. The Fuel Adjustment Clause ("FAC") 9 B. The Missing Rate Increase Cap 13 C. Carrying Costs 14 D. Provider of Last Resort ("POLR") 1s E. Transformed Request for Generation Asset Transfer Approval 18 F. gridSMART and Other Disttibution Increases 21 G. ESP and MRO Comparison 22 II. The Commission's rate increase for ninety percent of AEP-Ohio's requested POLR revenue requirement is unjust, unreasonable and 26 unlawful. 183 Ill. The Commission's authorization of a rate increase for recovery of costs of ownership and other interests In generating assets Is unjust, unreasonable, unlawful and unsupported by the evidence. 35 IV. The Commission's selective distribution rate increases, for gridSMART and a service reliability plan are unjust, unreasonable and unlawful. 38 V. The Commission's failure to require AEP-Ohio to limit the total bill increases to the percentage amounts specifled in the Order Is unjust, unlawful and unreasonable and the Commission must immediately require AEP-Ohio to comply with the Order and to refund amounts billed and collected In excess of such caps. 40 VI. The Commission's conclusion that the ESP is more beneficial in the aggregate than the alternative under Section 4928.142, Revised Code, is unjust, unreasonable, unlawful and unsupported by the evidence. 41 VII. The Commission's unbundling of the non-fuel and fuel component of the generation rate based on something other than 2008 actual fuel costs is unjust and unreasonable. 44 Viii. The scope of the fuel and other cost recovery mechanism authorized by the Commission is unreasonable, unlawful and unjust both because of the types of costs that are subject to recovery through the mechanism and the substantial negative effect that the kWh-based mechanism has upon larger, high load factor customers. 47 IX. The Commission's determination that interruptible load may not be counted towards OP's and CSP's determination of their peak demand respvnse compliance requirements is unjust, unreasonable and unlawful. 80 X. The combined effect of the unexplained conclusions in the Commission's Order is unreasonable, unjust and unlawful because the Commission arbitrarily and capriciously exerciaed its discretion to allow CSP and OP to bill and collect excessive rates. 83 XI. Conclusion 54 ATTACHMENT A ATTACHMENT B CERTIFICATE OF SERVICE 11 184 BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO In the Matter of the Application of Columbus Southern Power Company for Approvai of its Electric Security Plan; an Case No. 08-917-EL-SSO Amendment to its Corporate Separation Plan; and the Sale or Transfer of Certain Generating Assets. In the Matter of the Application of Ohio Power Company for Approval of its Case No. 08-918-EL-SSO Electric Security Plan; and an Amendment to its Corporate Separation Plan. APPLICATION FOR REHEARING OF INDUSTRIAL ENERGY USERS-0HIO Pursuant to Section 4903.10, Revised Code, and Rule 4901-1-35, Ohio Administrative Code ("O.A.C.1, Industrial Energy Users-Ohio ("lEU-Ohio") respectfully submits this Application for Rehearing of the Opinion and Order ("Order") issued by the Public Utiiities Commission of Ohio ("PUCO" or "Commission") on March 18, 2009 on the electric security plan ("ESP") of Columbus Southern Power Company and Ohio Power Company (individually °CSP" and "OP", respectively, and collectively "Companies" or `AEP-Ohio"). As explained in more detail in the attached Memorandum in Support, the Commission's Order in this case is unreasonable and unlawful for the following reasons: The Commission erred by granting stunning rate increases while failing to issue a written decision in this contested proceeding that sets forth, in sufficient detail and based on the facts and law, the reasons prompting the decision. 185 II, The Commission's rate increase for ninety percent of AEP-Ohio's requested POLR revenue requirement is unjust, unreasonable and unlawful. iil. The Commission's authorization of a rate increase for recovery of costs of ownership and other interests in generating assets is unjust, unreasonable, unlawful and unsupported by the evidence. IV. The Commission's selective distribution rate increases, for gridSMART and a service reliability plan areunjust, unreasonable and unlawful. V. The Commission's failure to require AEP-Ohio to limit the total bill increases to the percentage amounts specified in the Order is unjust, unlawful and unreasonable and the Commission must immediately require AEP-Ohio to comply with the Order and to refund amounts billed and collected in excess of such caps. VI. The Commission's conclusion that the ESP is more beneficial in the aggregate than the aitemative under Section 4928.942, Revised Code, is unjust, unreasonable, unlawful and unsupported by the evidence. Vil. The Commission's unbundling of the non-fuel and fuel component of the generation rate based on something other than 2008 actual fuel costs is unjust and unreasonable. VIII. The scope of the fuel and other cost recovery mechanism authorized by the Commission is unreasonable, unlawful and unjust both because of the types of costs that are subject to recovery through the mechanism and the substantial negative effect that the kWh-based mechanism has upon larger, high load factor customers. IX. The Commission's determination that interruptible load may not be counted towards OP's and CSP's determination of their peak demand response compliance requirements is unjust, unreasonable and unlawful. X. The combined effect of the unexplained conclusions in the Commission's Order is unreasonable, unjust and unlawful because the Commission arbitrarily and capriciously exercised its discretion to allow CSP and OP to bill and collect excessive rates. For these reasons, discussed in greater detail below, IEU-Ohio requests that the Commission grant this Application for Rehearing and modify AEP-Ohio's ESP as 2 186 described herein and in the attached Memorandum in Support. This is not a situatfon that wil( permit the public interest to be protected or served by the Commission granting rehearing and then letting the large increases produced by the Order continue to grind on customers and Ohio's economy until the Commission gets around to issues on rehearing. If the Commission does not have serious intentions to right the wrongs that were embedded in the Order and do it quickly, !EU-Ohio urges the Commission to not erect procedural barriers to an appeal to the Ohio Supreme Court by granting rehearing for the purpose of allowing the Commission more time. Justice delayed in this situation is surely justice denied at a time when Ohio's electric customers can least afford it. Respectfully submitted, Samu)A C. Randazzo Lisa G. McAlister Joseph M. Clark MCNEES WALLACE & NURICK LLC 21 East State Street, 17TH Floor Columbus, OH 43215 Telephone: (814} 469-800t) Telecopier: (614} 489-4653 [email protected] [email protected] [email protected] Attorneys for Industrial Energy Users-Ohio 3 187 BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO In the Matter of the Application of Columbus Southern Power Company for Approval of its Electric Security Plan; an Case No. 08-917-EL-SSO Amendment to its Corporate Separation Plan; and the Sale or Transfer of Certain Generating Assets. In the Matter of the Application of Ohio Power Company for Approval of its Case No. 08-918-EL-SSO Electric Security Plan; and an Amendment to its Corporate Separation Plan. MEMORAPIDUM IN StJPPORT 1. The Commission erred by granting stunning rate increases while faiting to issue a written decision in this contested proceeding that sets forth, In sufficient detail and based on the facts and law, the reasons prompting the decision. Ohio's electricity consumers (big and small) are struggling on many fronts. Residential consumers that still have jobs are worried about a trend line that seems to bring more bad news by the day. C)hio's businesses are unable to make both ends meet and are trying to cope with the trauma that comes from large and sudden reductions in their sales. Ohio's leaders can often be heard these days talking about what Ohio should do to make things better. Even the Commission has been, in some cases, mindful of the present difficulties.' Quring the course of his testimony before the Finance and ' in the Matter of the Application of Ohio Edison Company, The Cfeveland Electric !ltuminating Company Sectton and the Toledo Edison Company for Authority fo Establish a Standard Servtoe Offer Pursuant to 4 188 Appropriations Committee on the Commission's budget, Chairman Alan Schriber recently specifically addressed the current difficulties customers are having. In response to an observation made by Representative Yates that "The ordinary citizen feels like they're taking it on the chin," Chairman Schriber stated, 'We are very intsnt, in this day and age, to mitigate rate increases," adding that the Commission's goal is to have "virtuaiiy no increase in utility rates"2 Chaimnan Schriber went on to say, "I think we're doing a pretty decent job this year of doing that. This is not the year when you want to increase rates. There is no question that, over time, rates are going to go up °3 IEU-Ohio does not mention the significant stress that customers are under because it wants or needs the PUCO to provide customers with an unfair or unlawful advantage. On the contrary, the Commission must fairly balance the interests of customers and the utiiities subject to the PUCO's regulatory jurisdiction. The purpose of mentioning Ohio's hard times here is to highlight how important ft is in times like these for the PUCO to clearly and carefully explain why it chooses to resolve contested issues in ways that produce large electric rate increases that add to already difficult consumers' burdens or how the actions taken to increase rates now will make things better in the future. Clear communications from the Commission through 4928.143, Revised Code, in the Form of an Electric Security Plan, Case No. 08-935-EL-ESP, Opinion and Order at 17 (December 19, 2008) (hereinafter cited as the FirstEnergy ESP Case). 2 Gongwer News Service, Gongwer House Activity Report (March 5, 2009) (Attachment A). 3 W. Regardless of what Chairman Schriber may have said in his recent testimony before the General Assembly, the Order is a clear blow to the chin of customers. As discussed below, each opportunity that the Commission had to exercise its discretion about the magnitude of the increase was accompanied by a selection that made the Increase as high as possible. This Is not an outcome that can be reconciied with doing a"pretty decentjob" of ineeBng the goal of virtually no increase. 5 189 its orders also provide consumers with information they want and need to predict where rates are likely to go in the future and how they might engage in self-help. Clearly reasoned decision-making and clear communications by the PUCO are also important from a legal perspective. Section 4903.09, Revised Code, requires the PUCO to issue written decisions in contested proceedings "...setting forth the reasons prompting the decisions...". This obligation must be satisfied by the PUCO to permit the Ohio Supreme Court to properly discharge its duties on appeal4 To meet the requirements of Section 4903.09, Revised Code, the PUCO's orders must show, in sufficient detaii, the facts in the record upon which the order is based and the reasoning followed by the Commission to get to the conclusion.5 Unfortunately, the Commission's Order omits a merit-based examination and reasoned disposition of the contested issues based on the evidence, the law and conceals its real effect. Despite the heading at page 73 of the Opinion and Order, there are no findings of fact or conclusions of law in the Opinion and Order that relate to any substantive Issue. On the way to authorizing excessive increases, the Order effectively treats the hard E'digation work undertaken by customer representatives and the commands of the General Assembly as little more than background noise. The conclusions that are contained in the Order suggest that the PUCO resolved contested issues in ways that produce significant rate increases for Ohio consumers. i administrative agency's explanation of the 4 MC7 Gorp. v. Pub. Util. Com., 38 OS3rd 266, 270 (1988). An reasons for its decision is required not only for appellate review but also to assure the parties that their fadual allegations and legal arguments have been fully considered. See Riverside General Hospital v. Howarcf Savings Institution of N.J. Hospitat Rate Sefting Comn, 98 N.J. 458, 468 (1985); Application of Newark, 32 N.J. 29, 52 (1960). 5 MCI Telecommunications Corp. v. Pub. Util. Comm., 32 083rd 306 (1987). 6 190 Adding insult to injury (from a consumer's perspective)6 the PUCO a[so acted to make sure that the electric distribution utilities (°EDUs") get a full year's value out of the PUCO-sanctioned increases in the balance of 2009 that remains. By cramming 12 months of revenue increase into the remainder of 2009, the PUCO permitted AEP-Ohio to go deeper into customers' empty pockets. Regardless of words creatively used by the Commission to describe the retroactive effect of the large rate increases, the numbers that are now appearing an customers' bills make the consequences unmistakable. The PUCO's Order seems inclined to diminish the signiflcance of these regulator- sanctioned increases by characterizing (perhaps as part of the PUCO's public relations spin) the rates resulting from the Order as the lowest in Ohio. However, this comparison is without any basis in the record evidence (particulariy since the future rates of other Ohio electric utilities are presently unknown). And, the low-rates-spin appears to be built on assumptions about AEP-Ohio rate levels that will ultimately depend on variables (such as the cost of fuel, carbon taxes and carrying costs) that are likely to accelerate the upward movement of AEP's electric rates when compared to the ESPs that have been approved by or submitted to the PUCO. Contrary to the PUCO's spin, the record evidence shows that CSP and OP are generating the highest level of margin per MWH (gross revenue less fuel costs) within the entire American Electric Power ("AEP") system, including the operatfng companies 6 In the testimony referenced above, Representative Yates stated that it was his sense that consumers feel their positions are not considered and Representative Goodwin stated that there is a perception that the Commfssion is "run by utiiities." Chairman Schriber responded that the Commission tries to baiance the needs of consumers and utiiities and that It is difficult to convince Ohioans that the Commission's actions are in the best interest of the State. Gongwer News Service, Gongwer House Activity Report (March 5, 2009) (Attachment A). 7 191 just across the Ohio border in Michigan, Kentucky, Indiana and West Virginia. Even if AEP-Ohio's rapidly escalating rates might be the lowest in Ohio (a comparison that seems to suggest that the PUCO is only interested in eliminating this condition by making AEP-Ohio's rates even higher), AEP-Ohio's rates appear to put Ohio at a relative disadvantage when compared to the other areas served by nearby affiliates. The gross revenue margin (revenue l®ss fuel and purchased power expense)7 per MWH of AEP-Ohio° suggests that its Ohio customers are and have been carrying their weight (and perhaps more) when it comes to fairly compensating OP and CSP. As IEU-Ohio demonstrated 9 the gross margin per MWH reported for AEP-Ohio for the third quarter of 2008 was $43.9 per MWH compared to $46.8 per MWH for the corresponding quarter in 2007. In both quarters, the next highest gross margin per MWH contribution to earnings per share by any AEP business unit came from Off System Sales (at between $32 and $33 per MWH). And, in case the relationship between the gross margin achieved by AEP-Ohio and the gross margin from Off System Sales was lost on the Commission the first time that IEU-Ohio pointed out these figures, the lower gross margin from Off System Sales indicates that the go-to-market opportunity lusted after by AEP-Ohio is less compensatory than retail rate revenue collected by AEP-Ohio.'0 ' Tr. Vol. IV at 285. The " East Integrated Utilities" line includes Appalachian Power Company, Kentucky Power Company, IRM [Indiana Michigan Power], Wheeling Power and Kingsport Power Company. Tr. Vol. IV at 287. e The term "Ohio Companies" refers to CSP and OP. Tr. Vol. IX at 112. e IEU-flhio Exhibit 2 at 11, which is the 2008 earnings release presentation for the third quarter that was issued by AEP on October 31, 2008. See also, Tr. Vol. tV at 285. 10 The evidence on the relative rate levels in Ohio and the balance of the AEP system includes more than gross margin comparisons discussed above. For example, IEU-Ohio Exhibit 7, at pages 20 through 39, shows that the average per-k11Vh historical prioes of CSP and OP have been well above retail prices of their affiliates operating in other states, $ 192 uMnaeeRana+s: GNSII.4>mi¢ 1B,9fi0 GR!Ao $x79 f.AYT/' : 7 EanitaB^nNn9ramtl4^in +QBT1 f3Wlfe $Y&6 149 i}dA?r' ^ 2 0lioGcmF rves 13,144 GWhQ SA0.8 RAWk=. 1712T GMfio 6KTt *°[9AWh:c 341 9 WesiRyJMMtrtb^r^'LMrnare, tR,/^ Gwh^ 528.9 ^MY^W; ^ ..i,9pf GribG.f192 169 4 TwnN7w r-n1 ovr,^ t,te amvt^ = 9'tft G'Bic *33.o ^MN7r = ^ Sks 5 o169ysiem33ks t0,7N G4rt+® $ffi.V,Mvw 6 rravtt^Re.rme-20PMw 7 anaoperatNrrcwnua a wk'IyGmxUraio Rather than making its reasoned review and resolution of the contested issues transparent, the Commission's Order contains a discussion of the various positions of the parties followed by a naked conclusion. There is a beginning and end in the text, but the Order omits the required documentation of the Commission's reasoning from the facts and law to the conclusions reached on the contested issues. In the context of customers who are under siege by very difficuR circumstances, the Commission's inability or unwillingness to document its reasoning and explain its choices constitutes a stunning disregard for its legal and practical responsibilities as an arbiter, an agent of the General Assembly and communicator that appreciates, particuiariy now, the need for all govemment agencies to inspire the public's confidence. The discussion below highlights the absence of reasoned decision-making and the flip-flopping conclusions that dominate the Order. A. The Fuel Adjustment Clause ("FAC") CSP and OP proposed an ESP pursuant to Section 4928,143, Revised Code, that included the establishment of an automatic adjustment mechanism (referred to as 9 193 the fuel adjustment clause or "FAC") to recover the cost of fuel, non-fuel items, fixed costs and variable costs. Despite its significance, AEP-Ohio's proposal was accompanied by little detail. The parties to the proceeding raised issues and presented evidence that required the Commission to, among other things, address questions about the scope of the FAC, the baseline value that should be used to initiate the FAC mechanism and set the non-FAG portion of the rate, the lack of substantive detail, the lack of process detail, the unfaimess of the mismatch between costs and benefits, whether forecasted or actual prudently incurred costs were subject to recovery through the FAC and the reasonableness of effectivety allocating fixed costs on a volumetric or kWh basis through the FAC mechanism. The Order does not disclose how these issues were resolved by the Commission. The Order states that the Commission believes that the establishment of an FAC mechanism as part of an ESP is authorized pursuant to Section 4928.143(B)(2)(a), Revised Code, to recover prudently incurred costs associated with fuel, Including consumables related to environmental compliance [consumables are nowhere mentioned in the law], purchased power costs, emission allowances, and costs associated with carbon-based taxes and other carbon-based regulations [regulations are nowhere mentioned in the iaw]." The Commission held that purchased power is not a prerequisite for adequately serving additional load requirements assumed by AEP-Ohio because there is no rational basis to approve recovery of such purchased power in the absence of a " Order at 14. 10 194 demonstrated need.j2 But wfthout any requirement that need be first demonstrated, the Commission authorized AEP-Ohio to increase rates (FAC and non-FAC) to include costs of generating units in which AEP has an ownership or other interest.93 The Commission rejected a recommendation that revenue from off-system sales be used as a credit to costs recovered through the FAG mechanism saying that it was not "persuaded" by the intervenors' arguments and that it did not believe that off-system sales should be a component of the ESP. The Commission did not explain the basis of this belief or explain what its betiefs have to do with its statutory duties to resolve contested issues based on the record evidence and the law. The Order states that intervenors cannot have both an off-system sales offset to the FAC and inclusion of off-system sales revenue for purposes of the significantly excessive earnings test ("SEET").'" But, the Order states that off-system sales revenue will also not be considered for purposes of the SEET.15 Thus, it appears that what the Commission actually did (contrasted with what it suggested it was doing) was to hold that the costs absorbed by customers will not be mitigated by either an FAC offset or any consideration of the benefits of off-system sales In the SEET context. Additionally, the Commission's SEET determinations specific to AEP-Ohio followed a PUCO holding 12 1d. at 16. ")d. at 52, 14 !d. at 17. 'b 1d at 69. 11 195 that the subject matter should not be addressed on a case-by-case or utiiity-specffic basis16 Heads, AEP-Ohio wins. Tails, consumers lose. The Order rejected the use of 2008 actual fuel costs as a basis for setting a baseline to separate the FAG and non-FAC components of current rates. The recommendation to use the 2008 actual costs was designed to make sure that the FAC baseline value was not too low and the non-FAC rate set too high.17 The Commiasion elected to not use actual 2008 costs, saying that actual costs were not known at the time of the hearing. Instead, it adopted a Staff-sponsored proxy for 2008 costs perhaps believing that a wrong number was close enough. Regardless of what was known at the time of the hearing, the Commission could have nonetheless found in favor of the methodology that set the baseline based on 2008 actual costs and required AEP-Ohio to observe this requirement for purposes of developing rates. Since 2008 actual fuel costs are now known, since they are significantly higher than the "proxy" adopted by the Commission, and since the "proxy° is, by definition, not the prudently incurred costs authorized in Section 4928.143(B)(2)(a), Revised Code, the Order results in the non-FAC portion of rates being too high and the risk of increases in the FAC portion as well as the amount of deferrals too great. In fact, in public presentations during 2008 and 2009, AEP Indicated that its average price of coal delivered in 2007 was $36.58/ton, while its 2008 cost was reported to be $46.61lEon; a 27.4 percent increase over 2007. These data indicate that the Staff proxy for '@ id. at 68. "1d.at19. 12 196 determining the 2008 baseline FAC costs produced a baseline FAC cost that was too low. Similarly, actual results for 2008, as reported in the SEC 10K Report, indicate that OP had a$148 million increase in fuel and consumables compared to 2007, and that CSP had a $65 million increase in fuel, allowance, and consumables expenses in 2008. Based on the 3 percent escalation that Staff applied to CSP's 2007 FAC costs and the 7 percent escalation applied to OP's 2007 FAG costs to arrive at its 2008 proxy, the proxy baseline FAC costs are understated by tens of millions of dollars, whether the 2008 SEC actual data are used or the Commission uses the 2008 actual data otherwise publicaBy reported by AEP. Now that AEP's books have been closed for 2008 and the actual fuel costs are known, it would have been straightforward to require AEP-Ohio to develop fts rates based on these actual costs as was recommended during the litigation phase of this proceeding. There is no good reason for the PUCO to unbundle the FAC and non-FAC rate components based on a proxy when the actual costs are readily available. B. The Missing Rate Increase Cap The Commission's Order states that an Increase in excess of 15 percent would, during this difficult economic climate, impose a severe hardship on customers and that a 15 percent cap is too high.'$ The Order states that AEP-Ohio must observe a limit on increases during 2009 of 7 percent of the total bill for CSP customers and 8 percent of the total bill for OP customers.19 Yet, and as the Commission well knows, the rates 'a fd. at 22. 113 197 that the Commission has now authorized AEf'-Ohio to charge customers in 2009 produce actual total bill increases substantially in excess of the total bill caps established by the Commission. In some cases, the actual total bill increases in 2009 will be above the 15 percent level that the Commission said would cause severe hardship. In all cases, the actual increases are well above the "virtually no increase° expectation which Chairman Schriber created in his recent testimony before the General Assembly. Despite being informed of this problem (the mismatch between the total bill cap established by the Commission and actual, much larger, increases), the Commission did nothing to correct this problem before the Commission allowed AEP-Ohio's rates to go into effect. C. Carrying Costs AEP-Ohio's ESP proposal included a provision to increase rates for carrying costs (about $110 million annually) on environmental expenditures made during the period 2001 through 2008. Over the three-year term of the ESP, it appears that thls aspect of the Order will cost customers some $330 million. The intervenors opposed this proposal on several grounds. They cited Section 4928.143(B)(2)(b), Revised Code, that limits any allowance for an environmental expenditure or cost to those incurred on or after January 1, 2009. The intervenors pointed to the requirement in Section 4,928.143(l3)(2)(b), Revised Ccxfe, for any allowance authorized under this Section to be related to construction work in progress and the fact that the requested canying charges were unrelated to any construction work in progress. The Commission's Order does not address the Intervenors' legal 14 198 claim that a pre-2009 environmental expenditure cannot be used to increase rates as part of an ESP. Also related to this pre-2009 carrying charge proposal, the Commission disregarded the uncontested facts that show that carrying charges associated with environmental assets are not properly based on a weighted average cost of capital and must reflect the favorable cost of capital that is made available as a result of various types of special financing available to environmental or pollution control assets. The Commission's bent-over-backwards accommodation of a carrying cost rate based on the overall weighted cost of capital and the use of a hypothetical capital structure that pushed the weighted cost of capital calculation result even higher are circumstantial but nonetheless clear indications of the Commission's unwiitingness to keep the magnitude of any rate increases as low as reasonably possible. It is also worthwhile to note that the Commission has often approved the use of a debt cost rate, not the weighted cost of total capital, for purposes of establishing carrying costs.20 The Commission's choice of a carrying cost rate computed based on the weighted cost of capital is a choice that unreasonably and unjustly favors higher electric prices. D. Provider of Last Resort ("POLR") There is not one bit of evidence In the record that suggests that any AEP-Ohio customers have switched and if, as the Order asserts, AEP-Ohio's rates will be the 20 Sea, for example, In the Matter of the Application of Columbus Southem Power Company and Ohio Case No. 08-1202-EL- Power Company to Adjust Each Company's Transmission Cost Recovery Rtder, UNC, Finding and Order at 4 (December 17, 2008); see also, In the Matter of the Applicadon of The Dayton Power and Light Company for Authority to Modify its Accounting Procedure for Certain Storm- Retated Services Restoration Costs, Case No. 08-1332-EL-AAM, Flnding and Order at 1 (January 14, 2009). 15 199 lowest in Ohio, there is little reason to expect this condition will change. Nonetheless, CSP and OP proposed a non-cost-based distribution POLR rider claiming that it was required to cover the cost of providing customers with the ability to remain with AEP- Ohio, switch and then return to CSP or OP 2t Since the AEP-Ohio POLR proposal is a distribution-related and non-competitive service element, one might expect that the Commission's determination, at page 32 of the Order, would apply to defeat this rate increasing proposai. At page 32 of the Order, the Commission found that AEP-Ohio should file a full distribution rate case so that all components of distribution rates can be examined prior to authorizing AEP-Ohio to incrementally increase distribution charges. But this expectation is undone by the PUCO's response on the incremental distribution rate increase for POLR. And, contrary to the impressions conveyed by the Order that customers may avoid the POLR rate increase by agreeing to stay with AEP during the term of the ESP, AEP's administration of the Order is leaving no opportunity for customers to avoid the POLR increase by agreeing to stay with AEP during the term of the ESP. AEP-Ohio used the Black-Scholes Model to develop a POLR price tag (revenue requirement) and this approach was criticized by every other party (including the Staff), with the other parties citing facts and the law to support their objections to AEP's POLR proposal z2 After a summary recital of some (but no analysis) of the opposing parties' Z' ta at 3a_ 2Z Yes, it is true. The PUCO relied on the same Black-Scholes Model that was used to value mortgaged backed securities that now have the distinetion of sending the Nation's and the World's economy inbo an Ball, William abyss. Onstaught. Crists of the World Financia! System: The Financial Predators Had A Engdalf, Global Research, February 23, 2009 (available via the Intemet at http7ttwww globa€research ca)index ohr>?context=va&aid=8156y. The devastation from Main Street to Wall Street has caused even Myron Scholes, one of the developers of the Black-Schoies Modai, to 16 200 posftions on the POLR proposal, the Commission awarded AEP-Ohio a POLR revenue requirement of $152.2 million per year, ninety percent of the $169.1 million AEP proposed. The Order ignores the opposing parties' demonstration that the Black- Scholes Model (as applied by AEP-Ohio) was invalid, did not include any actual costs of providing POLR, was tied to ridiculous assumptions about shopping and relied on a market price (about $88 to $85 per MWH) which was rejected (implicitly) by the Commission for purposes of comparing the ESP and market rate option ("MRO°) options. The Order's treatment of AEP-Ohio's POLR proposal also ignores the significance of AEP-Ohio's participation in PJM LLC. OP and CSP currently participate in PJM LLC, a regional transmission organization ("RTO") subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"). All of OP's and CSP's available generating capacity is bid into the PJM market (it is not dispatched to serve retail customers in Ohio). In other words, AEP, acting on behaff of each of its operating companies, offers the output of available generating units to PJM. It is up to PJM to determine what to do in response to these offers .23 On any given day, the actual retail load presented by the OP and CSP customers could, in accordance with PJM's determinations, be served by generators other than those owned or operated by the Companies 24 Regardless of who actually owns the generation capacity, PJM will suggest that the model's assumptions may not reflect the real world. Myron SchWes Says Regulat'are Need to 'Blow Up or 8urn' OTC Derivatives Markets, Ces Quirijns, March 9, 2009 (available via the Intemet at http:llgulri'ns. especialreports .com/2QO9/03109/myron-shol es savs reaulators-need-to-blow-un- gr-bu rn-otc-derivati ves-markets/. 23 Tr. Vol, XI at 56-57, 65. 2" Tr. Vol. XI at 58. 17 201 zs dispatch available generation capacity to serve load and maintain real-time reliability. Under the PJM rules, all suppliers with load serving responsibilities (including OP and CSP) must maintain adequate resources to reliably meet their customers' needs -26 The Order acknowledges that the cost of meeting the PJM generating resource adequacy requirement (Fixed Resource Requirement or'"FRR" in AEP's case) is already reflected in rates?' And prior to these proceedings, AEP entered into a commitment to meet the generation resource adequacy requirement of all retalt suppliers within its PJM zone for a period of five years (ending after the ESP period).28 Under PJM's rules, the cost of a default by a load serving entity is "socfalized" throughout the PJM footprint z9 As discussed below, IEU-Ohio believes that authorizing OP and CSP to collect $152.2 million annually for POLR risk is unwarranted based on the facts and law. But if the Commission elects to rule against 1EU-ohio's position, it is obligated to explain the basis for the ruling. During the three-year ESP period, the Order will give AEP the opportunity to collect some $456 million in POLR revenue. z5 Tr. Vol. XI at 59-60. z8 Tr. Vol. XI at 60-61. 27 Order at 58. zB Tr. Vol. Xi at 61. '9 Tr. Vol. XI at 70. According to the April 6, 2009 edition of Energy Daily, PJM has recently socialized some $80 million associated with a default by one market participant. 18 202 E. Transformed Request for Generation Asset Transfer Approval Amended Substitute Senate Bill 221 ("SB 221") modified Section 492$.17, Revised Code, so that no EDU could transfer any generating asset without the PUCO's prior approval. Although AEP-Ohio had no plans to do so, it included requests in its ESP application for PUCO approvals of potential transfers of certain generating units or it gave the PUCO a "heads up" that it might someday transfer interests in generating units. Because AEP-Ohio had no plans to transfer any of these interests or assets, the intervening parties and the Staff asserted that AEP's request was premature30 Even though AEP-Ohio acknowledged that it had no current plans to transfer any interest in ( such assets, it pushed for authority to do so claiming on rebuttal) that if the PUCO did not approve the plan-deficient transfer request, that the oosts of such assets should be included in rates. AEP-Ohio's litigation posifion - that the costs of such assets are not in current rates - suffered from the obvious problem that AEP-Ohio's rates are not based on costs and the PUCO has steadfastly precluded any cost-based examination of AEP-Ohia's generation rates. In the end, the Order selectively transfomred AEP-Ohio's open- ended, plan-deficient request to transfer certain interests in generating assets and current rates that are not cost-based to begin with into a conclusion that current rate revenue is inadequate to cover the costs of such generating interests and that the non- ° Order at 51. 19 203 FAC and FAC31 revenue produced by current electric rates must be increased by $120 million per year. During the three-year ESP period, the total extra burden that AEP- Ohio customers will carry as a result of this transformative and rate-increasing determination amounts to about $360 million. The Order makes no reference to any provision of Ohio law that authorizes the PUCO to establish cost-based generating rates for some of AEP's generating assets and there is nothing in the evidence of record that would allow a determination of what revenues might be warranted based on the cost of providing generating service.32 The information that is in the record shows that AEP-Ohio is futly recovering all of its costs and is collecting a very "healthy" return on equity (using balance sheet equity values that include all interests in generating assets).33 There is nothing in the Order or the evidence that suggests that these assets are needed to serve AEP-Ohio's customers. And, there is a substantial amount of record evidence that shows that AEP is making large amounts of wholesale or off-system sales, the benefit of which the Order withhoids 37 By increasing the non-FAC and FAG rate components (which are not based on a total cost of service evaluation) to include costs related to the operation of the generating assets that AEP-phio may transfer at some point, the Order boosts the total rate revenue that will be collected by AEP-Ohio during the ESP period and increases the size of the deferrals that the Opinion and Order permds AEP-Ohio to amorUze through a non-bypassable charge during the 2012-2018 period. Another blow to the chin of customers. 32 AEP-Ohio has strongly opposed cost-based ratemaking for purposes of developing standard service offer ("SSO") electric generation supply prices. Yet, AEP-Ohio selectively invited cost-based ratemaking during this proceeding. AEP-Ohio's selective applicatlon of a cost-based methodology is no doubt influenced by its opinion about how its rates would look It Its total revenue were determined on a cost basis. "AEP's power pool's cnmpetitive, largely coal-based production costs are among the lowest in the nation." IEt1•Ohio Exhibit 7 at 12. The Order's selective applicatlon of cost-based ratemaking produces a result for customers that is the worst of both worlds. The actual cost of providing service is ignored unless its consideration allows for an upward adjustment to rates. This is not a ratemaking approach that can be reconciled with the goal of keeping rate increases as low as possible. 33 As Mr. Cahaan testified, the Companies were obviously recovering their fuel costs (which he defined to include purchased power) in 2007 or their earnings would have been insufficient Staff Exhibit 10 at 3. 20 204 from AEP-Ohio's retail customers. If AEP-Ohio's retail customers are required by the Order (and not anything in Ohio law) to pay even higher rates to cover costs of generating assets for which no need has been demonstrated, why is it that the same customers are not entitled the benefits of the revenue generated through the use of these assets? This result cannot be reconciled with the goal of keeping rate increases as close to zero as possible. The Order's authorizaUon of a $120 million increase in AEP-Ohio's annual retaii revenues (and rates paid by customers) to cover the costs of the above-described generating assets is also remarkable based on the PUCO's response to AEP's request for a rider to recover costs associated vrith earty closure of generating plants. Again, AEP-Ohio identified no plans to prematurely close any generating plants as part af promoting this portion of its ESP proposal. Numerous parties, including the Commission's Staff, opposed the proposed early-closure-cost rider -- demonstrating that the rider was unlawful and that it would not take into account the positive economic value of the rest of AEP-Ohio's generating fleet. The Commission agreed that the positive economic value of the fleet must be recognized. F. gridSMART and Other Distribution Increases Despite other conclusions that distribution rates should not be increased incrementally and must await a full examination of distribution revenues and expenses, the Order awards a 20{}0 distribution rate increase of $17.6 million for CSP and $17.3 million for OP that is now being charged and collected through the rates which the PUCO allowed to go into effect. This component of the extra rate burden placed on customers contrasts wfth StafPs recommended increase of $0 for distribution oosts and 21 205 i this extra burden was approved by the PUCO with no regard for any cost-effectiveness requirements.34 Additionally, the Order did not address the intervenors' legal argument that the gridSMART proposal was not shown to satisfy the cost-effectiveness requirements of Sections 4928.02(D) and 4928.64(E), Revised Code. Instead, the Order resorts to a discussion of what the Commission believes might be the case if there is a properly designed and implemented program (something that was not put forward in evidence). The Order indicates that the Commission is a strong supporter of elements of the gridSMART proposal35 while acknowiedging that additional information is required before successful implementation is possibie.36 Yet, the Order commands full speed ahead by increasing 2009 distribution rates by $17.5 million for CSP and $17.3 million for OP. This resutt cannot be reconciled with the goal of keeping rate increases as close to zero as possible. G. ESP and MRO Comparison The Order concludes that the ESP manufactured in the Order is more favorable than the alternative under Section 4928.142, Revised Code (MRO) 37 The conclusion appears after a discussion of the issues raised by the parties, including the Staff. As with the rest of the Order, there is no exptanation of how the Commission resolved the issues raised by the parties to reach the conclusion. 'd Order at 36. 35 Order at 37. !d at 38. 37 Id. at 72. 22 206 While the Order itself offers not the slightest clue, the Order work paper (summary sheet attached hereto as Attachment B) indicates that the "market price" information relied upon by the Commission is the same information that was included with Staff witness Johnson's testimony. Staff witness Johnson testified that his market price estimate (about $74 per MWH) was at the high end of the rangese which he developed when he prepared his testimony. He agreed that market prices continued to fall after he prepared his testimony.39 Since the close of the record in this proceeding, it is common knowledge that the wholesale price of electricity has continued to plunge; a condition that would likely be of interest to a regulator working hard to keep rate increases as small as possible.Ao If there is any doubt about the unreasonably high market price that was embedded in the ESP v. MRO comparison, the Commission need look no further than its decision in another recent ESP case. More specifically, the market price the Commission appears to have used for the MRO v. ESP comparison in the AEP-Ohio case is almost identical to the average generation price of $75 per MWH which the 3e Staff witness Johnson revealed on crossexamination that he had developed a market price range after starting with AEP-Ohio's ridiculously high $88 and $85 per MWH market prices for CSP and OP. During his cross examination, Mr. Johnson's answers indicated that he was not inclined to proactively share information that would allow his analysis to be more fully understood or evaluated. 39 Tr. Vol, Xli at 182, 187; Staff Exhibit 9 at 6. 40 For example, on April 8, 2009, the New York independent Sysiem Operator ONYISO"j reported that wholesale electricity prices In New York State dropped to their lowest level since 2003. It reported that the average cost of wholesale electricity In the state was $45.63 per MWH In March, and that the last time wholesale electricity prices were this iow was in November 2003 when the average cost was $43.40 per MWH. It stated that the March prices were down sharply from $73.28 in January of this year. See the NYISO Press Release at http://www.nyisa comlpublic/wetxtocslnewsroomlpress releasest20091NYISO Wholesale Power P rices Drop to Lowest Level 04082009 ndf. 23 207 Commission found to be excessive (by almost $8 per MWH) in the December 19, 2008 Opinion and Order modifying the ESP proposed in the FirstEnergy ESP Case.qt If there is any doubt about the unreasonably high market price that was embedded in the PUCO's ESP v. MRO comparison, the information which AEP presented to the public and the financial community shows that the doubt must be resolved against the PUCO. Page 6 of IEU-Ohio Exhibit 6, AEP presentation slides from a conference that took place in November 2008, shows the sharp decline in electricity market prices (for 2009 delivery). zweE:ses,ea+^, zooaemnomd Mernuc ^zx.^sa G CE61dkC1WlCM61a4NChVNYMIX[YpP GC The Order work paper (attached hereto as Attachment B4?) shows that the MRO scenario included a generation-related revenue requirement based on the maximum blending percentages allowed by Section 4928.142, Revised Code, thereby using a 41 FirstEnergy ESP Case at 89. 42 It should be noted that the total MRO costflgures on the work paper agree with the Opinion and Order figures at p. 72 but for some reason the ESP cost figures on the work paper do not agree with the Opinion and Order. 24 208 worst case MRO assumption to show an ESP advantage. The Commission did this even after the General Assembly amended Section 4928.143, Revised Code, to make it absolutely, unmistakably clear that the blending percentages that were used for purposes of the Order were n®t required. The same work paper shows that the MRO scenario relied upon by the Commission included $366 million in "cost" for POLR even though POLR as proposed by AEP-Ohio and approved by the PUCO is a distribution charge and even though there is nothing in Section 4928.142, Revised Code, that even hints that the PUCO has authority to approve a POLR charge in a Section 4928.142, Revised Code, proceeding. Rather than reasoned decision-making on the MRO v. ESP comparison issues, the Order contains a naked conclusion that appears to be based on the highest market price the Staff could come up with when the Staff prepared its testimony and a market price that is nearly $8 per MWH higher than the Commission found to be appropriate for purposes of conducting the same test in the FirstEnergy ESP Case. In other words, the Order suggests that the Commission's decision was not reasonably balanced but tilted to produce an outcome that unreasonably favors AEP-Ohio, prejudices customers and ignores the commands of the General Assembly. Among other things, and as the contested issues demand of the Commission, customers deserve to be told by the Commission just how and why: 1. The Commission picked the high end of the StafFs market price range when the record evidende shows that the generation price trend line was decidedly downward not upward (as discussed in the FirsfEnergy ESP Case); 2. $74 per MWH is just-right for AEP-Ohio and $8 per MWH too high in the FirstEnergy ESP Case; 25 209 3. The MRO v. ESP comparison was based on the maximum blending percentage allowed by Section 4928.142, Revised Code; 4. The Commission included costs in the MRO scenario that are not legally wfthin the MRO authority of the PUCO; 5. The Commission included a phantom POLR revenue requirement estimate using an economic model that contributed to the largest financial collapse since the Great Depression and a market price that is even higher than the market price used for the MRO v. ESP comparison itself; 6. The gridSMART costs were excluded from the ESP costs used in the ESP v. MRO comparison; and, 7. Customers must resort to forensic analysis to try to figure out how the Commission could have possibly come to such a conciusion while the Commission is teiting elected officials that it is working hard to keep rate increases as low as possible. Whatever the legal consequences of the Commission's faiiure to explain how it got from A to B to resolve the contested issues, the Commission owes customers a clear and auditable explanation of how and why the Commission's choices were made so decidedly in favor of outcomes that sequentiaily and excessively raise AEP-Ohio's electric prices. 11_ The Commission's rate increase for ninety percent of AEP-Ohio's requested POLR revenue requirement is unjust, unreasonable and uniai+vful. The Order states that the Commission believes that AEP-Ohio has some risks associated with customers switching to CRES providers and retuming to the EDU's SSO rate. With this belief as its foundation, the Order then embraced AEP-Ohio's witness' quantification of risk to equal ninety percent of AEP-Ohio's hypothetical POLR costs. The Order states that AEP-Ohio may establish a rider to collect a POLR revenue requirement of $97.4 million for CSP and $54.8 million for OP (or ninety percent of the 26 210 POLR revenue requirement requested by AEP}.43 The Commission's authorization of AEP-Ohio to collect the POLR revenue requirement is unjust, unreasonable and unlawful for the following reasons. 1. AEP-Ohio did not demonstrate that it has any POLR risk. I 2. Assuming for argument sake that AEP-Ohio does have POLR risk, AEP- Ohio did not demonstrate that it could not mitigate the risk through options. 3. Assuming for argument sake that AEP-Ohio does have POLR risk that cannot be mitigated, AEP-Ohfo did not demonstrate that there is a change in its risk profile that merits substantially increasing rates for POLR. 4. Assuming for argument sake that AEP-Ohio has POLR risk that cannot be mitigated and there has been a change in the risk profile, there has been no demonstration that AEP-Ohio's estimate of the POLR revenue requirement is based on the prudently incurred cost of POLR or is otherwise reasonable and lawful. 5. The Commission has not provided any reasoning for its holding 44 As IEU-Ohio noted in ifs Reply Brief, AEP-Ohio currently participates in PJM 4s Under the PJM rules, all suppliers with load serving responsibilities (including AEP- Ohio) must maintain adequate resources to reliably meet their customers' needs:46 AEP-Ohio has elected to meet the capacity requirements as an FRR entity under the reliability pricing model {"RPM"} or the capacity market inside of PJM 47 AEP-Ohia has 43 Order at 40. 40 As discussed above, Section 4903.09, Revised Code, requires the Commission to make a complete record in all contested cases heard by the Commission, inciuding a eritten opinion seiting forth ttre reasons prompting the decisions arrived at, based upon findings of fact. 45 IEU-Qhio Reply Brief at 16. 48 Tr. Vol. XI at 60-61. °' Tr. Vol. IX at 52; Tr. Vol. X at 61. 27 211 elected the FRR option for five years.48 PJM's resouroe adequacy requirements and generating resource dispatch responsibilities have significance relative to AEP-Ohio's claims regarding risks associated with any default supplier obligations. Specifically, all of AEP's available generating capacity is bid into the PJM market. In other words, AEP, acting on behaff of each of its operating companies including OP and CSP, offers the output of available generating units to PJM and it is up to PJM to determine what to do in response to these offers.49 On any given day, the actual load presented by AEP-Ohio's customers could, in accordance with PJM's determinations, be seived by generators other than those owned or operated by AEP 5D Regard4ess of who actually owns the generation capacity, PJM will dispatch available generation capacity to serve load and maintain real-time reliability.51 Moreover, even if AEP-Ohio did not own any generation at all, PJM would still dispatch generation in order to meet the needs of AEP-Ohio's customers 52 By electing the FRR option for five years, AEP committed to being the sole load-serving entity for retail load wkhin the AEP zone to meet the resource adequacy requirements specified by PJM. That means that AEP has committed to being responsible for meeting the reserve requirements even for retail 48 Tr. Vol. X at 61. "s Tr. Vol. XI at 55-57, 65. 56 Tr. Vol. XI at 58. 51 Tr. Vol. XI at 59-50. 52 Tr. Vol. XI at 59-60. 28 212 customers that elect to take service from a competitive retail electric service ("CRES") provider as if that customer remained a retail customer of AEP.53 Moreover, AEP receives benefits associated with its FRR election as opposed to participating in PJM's RPM auction process. For example, Staff witness Johnson indicated that there is a significantly large cost advantage as a resuft of the difference between RPM and FRR that could be as much as the difference between RPM and the depreciated book value of AEP's generating capacity.64 Additionally, AEP has the opportunity to sell and has sold generating capacity into the other capacity market (RPM).55 Once AEP has met the PJM requirements of its load times 1.155 to meet the PJM dictated reserve margin plus 450 megawatts, if AEP has capacity in excess of that amount, it may sell the next 1,300 megawatts into the RPM market.sa When AEP has a capacity surplus within that bandwidth, it has sold the excess capacity into the market for a profit.57 In other words. AEP voluntarily assumed the risk of customer switching through its FRR election in PJM and is being adequately compensated through the PJM process with the option to do better through sales opportunities in the PJM markets. The Order allows AEP-Ohia to retain the full benefit of these safes even when the Order increases rates for costs associated with additional generating assets. Allowing AEP-Ohio to '3 Tr. Vol. Xi at 61. 54 Tr. Voi. XII at 186. 5s Tr. Vol. Xi at 63-64. 'e Tr. Vol. XI at 63-65. 57 Tr. Vol. Xi at 64. 29 213 collect a POLR charge from customers provides AEP-Ohio and its parent with a windfall that is inconsistent with any definition of the type of regulatory action that might be motivated by the goal of keeping increases to the lowest amount possible. For the sake of argument, even assuming that AEP-Ohio did have some POLR risk of customers migrating which it has not already voluntarily taken on and for which it is not already being compensated, AEP-Ohio did not demonstrate that it cannot mifgate the risk through various options, including obtaining agreements from customers to not switch during the ESP period. Throughout the hearing, AEP-Ohio referred to the POLR risk as a put (the risk of customers leaving AEP-Ohio's SSO) and a call (the risk of customers returning).58 Further, based on the discredited Black-Scholes Model, AEP- Ohio indicated that "the majority of the value comes about as a resutt of the put part of the series of options; less of it is related to the call"59 Despite this acknowledgment, AEP-Ohio said it has not determined whether it will actually purchase any options to cover the risk.60 In fact, AEP-Ohio witness Baker did not even believe that its decision to cover the put risk through an option was relevant to the ESP - most likely because the proposed POLR charge more than covered any risk that AEP-Ohio could conceive.61 AEP-Ohia has the burden of proof. The Commission has said that it wants to keep rate increases as small as possible. Requesting a revenue requirement of nearty See, for example, Tr. Vol. X at 211. safd fio Id. at 211-212. et !d at 212. 30 214 $170 million based on the costs of an option that AEP-Ohio might never exercise without even requiring an examination of lower cost alternatives to cost-effective risk management is unjust and unreasonable. The Commission decision to give AEP-Ohio a revenue collection opportunity equal to ninety percent of AEP-Ohio's request has no redeeming quaiities and is entirely inconsistent with any serious regulatory effort to keep rate increases as low as possible. Even assuming for argument sake that AEP-Ohio has POLR risk that cannot be mitigated, AEP-Ohio did not demonstrate that there has been a change in its risk profile that necessitates a rate increase to compensate it for its actual POLR cost beyond what might already be embedded in current SSO rates. The Commission authorized a POLR rider in AEP's rate stabilization plan ("RSP") case sZ While SB 221 was enacted between the approval of AEP-Ohio's RSP and the time when AEP-Ohio filed its ESP application, nothing else has changed. AEP's witness Baker indicated wrongly that SB 221 enhanced AEP's POLR risk in two ways: 1) Mr. Baker incorrectly asserted that, without SB 221, AEP could have gone to market and would no longer have had the POLR obligation,eg and, 2) SB 221 promoted governmental aggregation. OP and CSP, as Ohio EQUs, had the obligation to provide defauft generation service prior to the enactment of SB 221, they would have carried the same legal obligation even had they gone to market-generation supply pricing under Amended °' tn the Matter of the Application of Columbus Southern Power Company and Ohio Power Company for Approval of a Post-Market Development Period Rate Stebitization Plan, Case No. 04-168-EL-UNC, Opinion and Order at 27 (January 26, 2005). es Tr: Vol. X at 219-220. 31 215 Substitute Senate Bill 3 ("SB 3"), and they continue to have the obiigation post-SB 221 enactment. Moreover, govemmentai aggregation was created under SB 3, not SB 221. Whiie Section 4928.20(K), Revised Code, now states: 'The Commission shaA adopt rules to encourage and promote iarge-scaie government aggregation in the state;' there are no specific provisions that enhance the legal authority of municipaifties to aggregate as compared to those available prior to the enactment of SB 221. Moreover, the Companies did not conduct any studies to assess that risk and AEP-Ohio's witness Baker conceded that whether there will be any governmental aggregation is "very dependent on the future price of power in the wholesale market."s4 Despite the facts, the record evidence, and the law, the Commission authorized AEP-Ohio to collect ninety percent of the POLR revenue requirement it requested. And remarkably, the Commission sanctioned the use of market price estimates of $88.15/MWH for CSP and $85.32/MWH for OP ($86.74 on average) to quantify the POLR-related revenue requirement for AEP-Ohio thereby picking an even higher market price than the excessively high market price that the Commission used for purposes of the ESP and MRO comparisons. For purposes of the ESP v. MRO comparison, the PUCO used excessively high market price values of $74.711MWH for CSP and $73.59/MWH for C}P.65 The Commission has provided no explanation for why the unwarranted rate increase for POLR should be inflated even further by using an estimated market price that the Commission determined was too high. The Order's selective and inconsistent use of excessively high estimates of market prices cannot be ^ Tr.Vol.Xat221. B5 Order at 72. 32 216 reconciled with an outcome that indicates that the Commission is working hard to keep rate increases as low as possible. Finally, as discussed above, the Commission failed to provide reasons setting forth the decision to authorize AEP-Ohio to increase rates by over $100 million for a POLR obligation for risks that AEP-Ohio does not have except by its own choices and, in any event, for which it is already being compensated. The Commission's entire discussion of this issue88 consists of the observation that "the Companies do have some risks associated with customers switching to CRES providers and retuming to the electric utility's SSO rate at the conclusion of CRES contracts or during times of rising prices"67 and an acceptance of the Companies' witness' "quantification of that risk to equal 90 percent of the estimated POLR costs."68 There are no findings of fact connected to any conclusions of law. Perhaps equally bad, the Order misapplies the few citations to record evidence it does offer while summarizing the parties' positions. For example, in describing AEP- Ohio's arguments for its proposed POLR revenue requirement level, the Commission indicates that, "Companies added that their current POLR charge is significantly below other Ohio electric utilities' POLR charges... ."09 First, this reference is confusing at 06 The Comrnission devotes one paragraph to its discussion of its "consideration" of the reasonabteness of this issue. Moreover, as noted above, the "Findings of Fact and Conclusions of t.cW section of the Order, other than a list of procedural events, fails to include a single finding of fact and includes only that the "proposed ESP, as modified by this opinion and order, inctilding its pricing and all other terms and conditions, includVng deferrals and future recovery of defettals, is more favorable in the aggregate as compared to the expected results that would otherwise appty under Section 4928.142, Revised Code." Order at 73. 67 0rder a t 40. e' Order at 40. 69 Order at 38 (cidng Cos. Ex. 2 at 8). 33 217 best, particularly since the Commission has approved an ESP for FirstEnergy that does not have a POLR charge. In fact, the stipulation and recommendation approved by the Commission in FirstEnergy's case states, "There shall be no minimum default service rider or standby charges as proposed by the Companies in their ESP filed on Juty 31, 2008 in Case N. 08-935-EL-SSO. There will be no rate stabilization charges {'RSC'} starting June 1, 2009. Unless otherwise noted, all generation rates for the Stipulated ESP period are bypassable and there are no shopping credit caps."70 Second, while the Commission seems to be using the claim of a relatively low POLR charge argument to justify its authorization, the reference cited in the Order does not support the conclusion. The PUCO reference is to AEP witness 6aker's rebuttal testimony, which was limited to issues related to AEP's proposal for the interim period between January 1, 2009 and the time the Commission issued an Order - not the ESP period. Moreover, had the Commission read and applied the meaning of the very next sentence of the testimony, it would have realized that AEP conceded that °[i]n light of the very low level of the Companies' current POLR charges, both on an absolute basis and relative to Ohio's other electric distribution utilities, I believe that, as part of the interim ESP rate, the Companies' POLR charge should be increased to reflect haff of the increase in POLR rates proposed by the Companies in their application." If haff of what AEP-Ohio sought in its application would suffice, the Commission authorization of ninety percent of AEP- Ohio's request is even more unreasonable. Neither outcome can, of course, be reconciled with the goal of keeping increases as low as possible. 70 FirstEnergyESP Case, Stipulation and Recommendation at 10 (February 19. 2009). 34 218 The unreasonableness of the Commission's authorization of the POLR charge becomes more clear when the impact of the increased POLR rider alone on customer bills is examined. For example, an industrial customer on rate schedule G8-4 using 6 million kWh per month paid a POLR charge of $2,827 per month to CSP prior to the implementation of the Commission's March 18, 2009 Order. As a result of the PUCO's effort to keep rate increases as low as possible, the same customer will now pay $26,757 or about 10 times more per month for the POLR charge alone. Similarly, a GS-4 customer of OP using 6 million kWh per month will see its POLR charge increase from $6,601 to $12,913 per month. In other words, the rates approved by the Commission (and according to simple typical bill analysis for an individual customer) allow for over $320,000 per year in POLR revenue to be collected by CSP and nearly $155,000 per year by OP based on hypothetical risks, a market price input variable that is laughably high and application of an economic model that has brought financial markets to their knees because of its unwarranted assumptions and manipulation potential. This is not the type of regulatory scrutiny that can be reconciled with the goal of keeping rate increases as low as possible. III. The Commission's authorization of a rate Increase for recovery of costs of ownership and other interests In generating assets is unjust, unreasonable, unlawful and unsupported by the evidence. AEP-Ohio's ESP proposal requested authority to sell or transfer two recentiy- acquired qenerating facilities (Waterford Energy Center and the Darby Electric Generating Station). AEP-Ohio also stated that both Companies might sell or transfer their portion of the output entitlement in certain generating facilities of the Ohio Valley Electric Corporation ("OVEC°) and that CSP's affiliate, AEP Generating Company, might 35 219 sell or transfer its ownership in the Lawrenceburg Generation Station (CSP has a contract for the entire output of this combined-cycle natural gas-powered plant). 1EU-Ohio and all other parties opposed AEP's request for authority to sell or transfer these assets until the Companies provide sufficient detail to permit evaluation on how the sale/transfer might serve to advance state policy.7t The Commission agreed and held that AEP's requests are premature and AEP should file a separate application when it wishes to sell or transfer the generation facilities.72 However, without any reference to the law, the Commission hetd that AEP-Ohio may obtain recovery for the Ohio customers' jurisdictional share of any costs associated therewith, through the FAC and, to the extent not recovered in the FAC, through the non-FAC portion of the generation rate.73 The Commission's authorization to recover costs from Ohio customers runs afoul of the Commission's SB 221 authority and traditional ratemaking concepts. First and most importantly, as AEP-Ohio asserted throughout this proceeding, generation rates are no longer cost-based.74 SB 221 provides the Commission with the alternative authority to establish pricing for competitive services and this alternative authority has been described as a hybrid. But SB 221 does not require the Commission to selectively " Moreover, IEU-Ohio pointed out that because the output of OVEC's generating units is priced based on a tradit+onal cost of service model rather then market-based pricing (with average expected costs of $40 per MWH for 2008), it would be prudent for the Companies to use OVEC entitlement to meet Ohio customers' needs prior to resorting to market-based purchases. 72 Order at 52. " Order at 52. While the PUCO directed AEP-Ohlo to adjust its ESP accordingly, it did not provide any procedural direction or indication of whether ft would determine that AEP-Ohio's calculation of the jurisdictionat share of the associated costs is reasonable or accurate. '" See AEP-Ohio Initial Brief at 15 (December 30, 2008). See also Tr. Vol. Xi at 86-87. 36 220 increase rates (which are not based on costs) because the non-cost-based rates do not reflect a particular category of costs. The Commission cannot use traditional cost- based ratemaking selectively to increase rates where it believes particufar categories of generation costs are not currently reflected in rates. Even if legally permissible to do so, once an analysis starts with non-cost-based rates, it is not possible to say what particular costs are adequately covered or not covered by the revenue available from the non-cost-based rates. Even if default generation supply service was priced pursuant to traditional ratemaking concepts, as IEU-Ohio explained in its briefs, the traditional ratemaking process does not track costs by individual category; it produces a regulatory authorization to collect revenue through the application of rates and charges to the service provided by the utility. Once the ratemaking process has produced authority to bill and collect revenue for service, the rates and resulting revenue are presumed to be reasonable (for both the utility and customers).75 A party seeking to increase the total revenue has the burden of proof and this allocation of the burden of proof is repeated in Section 4928.143(C), Revised Code. A showing that a particular category of costs is not currently reflected in rates may be, circumstantially speaking, some indication that current rates and revenue may not provide adequate compensation, but it is not proof that current rates and charges and the revenue derived therefrom are inadequate or unreasonable. Also, while the Commission has effectively shifted cost responsibility to AEP's Ohio customers by increasing rates, the Commission appears to have not given 75 Section 4909.03, Revised Code. See IEU-Ohio's cross-examination of Mr. Cahaan at Tr. Vol. XII at 221-222. 37 221 customers credit for purposes of calculating the POLR charge discussed above. If the costs of these generating assets are being recovered through rates, customers should receive credit for the functional performance of the assets. Finally, while the Commission directed AEP-Ohio to adjust its ESP accordingly, it did not provide any procedural direction or indication of whether it would determine that AEP-Ohio's calculation of the jurisdictional share of the associated costs is reasonable or accurate. For these reasons and for the Commission's failure to provide its reasoning as described above, allowing AEP-Ohio to modify its ESP to increase rates selectively for costs associated with the above-mentioned generating assets is unjust, unreasonable and unlawful. IV. The Commission's selective distribution rate increases for gridSMART and a service reliability plan are unjust, unreasonable and unlawful. AEP-Ohio requested automatic distribution rate increases of 7 percent for CSP and 6.5 percent for OP. The meager explanation which AEP-Ohio offered in support of these automatic distribution rate increases includes vague references to illusory plans to implement an enhanced service reliability proposai ("ESRP"} and a gridSMART proposal that were strongly opposed. The Order's conclusions indicate that the Commission agreed with most parties' arguments (including IEU-Ohio); distribution service elements would be better addressed in a traditional distribution rate case where the Commission could consider all revenue and expense categories.76 But despite this holding, the Order proceeds to approve distribution rate increases for the mysterious 76 Order at 32. 38 222 gridSMART and service reliability plans. More specifically, the Order approves rate increases to recover gridSMART expenditures of $54.5 million, with initial recovery through a rider of $33.6 million of projected costs (not actually incurred costs), subjec#to annual true-up and reconciliation 77 In addition to the gridSMART rate increase, the Commission increased rates for projected incremental costs associated with a vegetation management program which may or may not improve senrice reliability.78 But, there is absolutely no basis in the record evidence or law for the Commission's approval of these distribution rate increases. hlotwithstanding provisions in SB 221 that require the Commission to ensure that costs passed on to customers are prudent, actually incurred and that customers should only be responsible for the costs based on the benefits they will derive, the PUCO approved these distribution rate increases with little regard for the speculative character of the plans and programs. The Order's rate increases for these two distribution initiatives (gridSMART and the ESRP) provide another example of how the Commission strayed from the goal of keeping rate increases as low as possible. While the language in the Order indicates that the Commission rejected AEP- Ohio's automatic distribution-related rate increase request and was selectively limiting AEP-Ohio to recovery of two parts of its total distribution plan, the Order's bottom line (as measured by AEP-Ohio's compliance tariffs) essentially produces a distribution rate " Order at 38. 78 Order at 34. The estimated incremental revenue requirements for each year of the three-year ESP are $17.5, $4.3 and $1.7 million for CSP and $17.3, $1.9 and $1.9 million for OP. 39 223 increase in 2009 that is worse for customers than AEP-Ohio's proposal would have produced in 2009. Based on the compliance tariffs filed for CSP, which the Commission allowed to go into effect over the objections of customers, the combination of the gridSMART and vegetation management cost recovery riders produces a distribution rate increase of 7.28531 percent, which exceeds AEP-Ohio's requested distributEon rate increase for 2009. In the case of OP, the compliance tariffs reflect an increase of 7.46876 percent in distribution rates. So on its way to rejecting AEP-Ohio's proposed 7 and 6.5 percent automatic annual distribution rate increases, the Order increased distribution rates in 2009 by more than the level proposed by AEP-Ohio. For these reasons and because the Commission failed to provide reasoning for its conclusions as discussed above, the Commission's approval of the distribution rate increases is unjust, unreasonable and unlawful. V. The Commission's failure to require AEP-Ohio to limit the total bill increases to the percentage amounts specified in the Order is unjust, unlawful and unreasonable and the Commission must immediateiy require AEP-Ohio to comply with the Order and to refund amounts billed and collected in excess of such caps. The Commission's Order states that an increase in excess of 15 percent would, during this difficult economic climate, impose a severe hardship on customers and that a 15 percent cap is too high.'g The Order states that AEP-Ohio must observe a limit on increases during 2009 of 7 percent of the total bill for CSP customers and 8 percent of the total bill for OP customers 80 Yet, and as the Commission well knows, the rates that the Commission permitted AEP-Ohio to begin charging over the objections of customers '9 !d at 22. 40 224 produce actual total bill increases substantially in excess of the total bill caps established by the Commission. In some cases, the actual total bill increases in 2009 will be above the 15 percent level that the Commission said would cause severe hardship. In all cases, the actual increases are well above the "virtuaUy no increase" expectation which Chairman Schriber created in his recent testimony before the General Assembly_ Despite being informed of this problem (the mismatch between the total bill cap established by the Commission and actual, much larger, increases produced by the compliance tariffs submitted by AEP-Ohio), the Commission did nothing to correct this problem before AEP-Ohio's rates were allowed to go into effect. The Commission's failure to require AEP-Ohio to limit the total bill increases to the caps specified in the Order is unjust, unlawful and unreasonable and cannot be reconciled with the goal of keeping rate increases as low as possible. Vi. The Commission's conclusion that the ESP Is more beneficial in the aggregate than the alternative under Section 4928.142, Revised Code, is unjust, unreasonable, unlawful and unsupported by the evidence. As discussed above, the Order concludes that the ESP manufactured in the Order is more favorable than the alternative under Section 4928.142, Revised Code (MRO).81 While the Order itself offers littie useful insight on just how this comparison was framed, the Order work papers (summary sheet attached hereto as Attachment B) indicate that the "market price" information relied upon by the Commission is the same information that was included with Staff witness Johnson's testimony. Staff witness 8' Id. at 72. 41 225 Johnson testified that his market price estimate (about $74 per MWH) was at the high end of the range which he developed (but did not proactively disclose) when he prepared his testimony. He agreed that market prices continued to fall after he prepared his testimony.$2 Since the close of the record in this proceeding, it is common knowledge that the wholesale price of electricity has continued to plunge; a condition that would likely be of interest to a regulator on a mission to keep rate increases as small as possible. If there is any doubt about the unreasonably high market price that was embedded in the ESP v. MRO comparison, the Commission need look no further than its decision in another recent ESP case_ More specifically, the market price the Commission appears to have used for the MRO v. ESP comparison in the AEP-Ohio case is almost identical to the average generation price of $75 per MWH which the Commission found to be excessive (by almost $8 per MWH) in the December 19, 2008 Opinion and Order modifying the ESP proposed in the FirstEnergy ESP Case.$3 Further, information which AEP presented to the public and the financial community shows that the doubt must be resolved against the conclusion reached but not explained in the Order. Page 6 of IEU°Ohio Exhibit 6, AEP's presentation slides from a conference that took place in November 2008, shows the sharp decline in electricity market prices (for 2009 delivery). e2 Tr. Vol. XII at 182, 187; Staff Exhibit 9 at $. 83 FirstEnergy ESP Case at 69. 42 226 GoalfuRF2eeE: NAq: C»% aro10: BSe% Dd. Cml P,ices :OUlA:3]E.58ilon lOWE:N6Gfiun 2pue eanmot^ nvmuHPidSY 7 Cuatpnzc^ryrc+eniezlmxlydNttAE%coMnttap^Rc,iqnznMxAeatumxnmf{2,OaE B eA Q iC.OWMNIatlU6lOro(comenion Q CealuedpbsFefa^(i[ityplmsrclkclmakdpnce8b[sdeMerysar]WPtleSVelymRE W'r^cse aatcs qrcm abola ^ .a ze The Order work paper (attached hereto as Attachment B) indicates that the MRO scenario included a generation-related revenue requirement based on the maximum blending percentages allowed by Section 4928.142, Revised Code, thereby using a worst case MRO assumption to show an ESP advantage. The Commission did this even after the General Assembly amended Section 4928.143, Revised Code, to make it absolutely unmistakably clear that the btending percentages that were used for purposes of the Order were not required. If the Commission was interested in keeping rate increases as low as possible, why would it assume that the MRO alternative scenario would be based on the maximum amount of wholesale market purchases permitted by law? Why did the Commission seek to obtain legislative authority to adjust ihe bfending perco-ntages if it does not intend to use the authorit{ to mitigate rate increases on customers? The same work paper shows that the MRO scenario relied upon by the Commission included $366 million in "cost„ for POLR even though POLR as proposed 43 227 by AEP-Ohio and approved by the PUCO is a distribution charge and even though there is nothing in Section 4928.142, Revised Code, that even hints that the PUCO has authority to approve a POLR charge in a Section 4928.142, Revised Code, proceeding. Rather than reasoned decision-making on the MRO v. ESP comparison issues, the Order contains a naked conclusion that appears to be based on the highest market price the Staff could come up with when the Staff prepared its testimony, a market price that is nearly $8 per MWH higher than the Commission found to be appropriate for purposes of conducting the same test in the FirstEnergy ESP Case and the Commission's self-imposed blindness to the fact that the forward market price of electricity has steadily declined since SB 221 became effective. In other words, the Order suggests that the Commission's decision was not reasonably balanced but titted to produce an outcome that unreasonably favors AEP-Ohio, prejudices customers and ignores the commands of the General Assembly. The Order's comparison of the MRO and ESP is unreasonable and unlawful. ViI. The Commission's unbundling of the non-fuel and fuel component of the generation rate based on something other than 2008 actual fuel costs is unjust and unreasonable. CSP and OP proposed an ESP pursuant to Section 4928,143, Revised Code, that included the establishment of an automatic adjustment mechanism (referred to as the fuel adjustment clause or "FAC") to recover the cost of fuel, non-fuel items, fixed costs and variabie costs. Despite its significance, AEP-Ohio's proposal was accompanied by little detait. To evaluate and potentially implement this proposal, it is necessary to unbundle the FAC and non-FAC portions of the current retail eiectric generation price and 44 228 determine what level of FAC costs should be attributed to the currently bundled retail electric service generation price. The required unbundling was complicated in this case by a lack of detail on just what AEP-Ohio was seeking in the way of relief. As Ms. Smith testified, AEP-Ohio's proposal was not accompanied by a"Fully fleshed out FAC tariff."84 In this context, the Order rejected the use of 2008 actual fuel costs as a basis for setting a baseline to separate the FAC and non-FAC components of current rates. The recommendation to use the 2008 actual costs was designed to make sure that the FAC baseline value was not too low and the non-FAC rate set too high.$' The Order indicates a decision was made to not use actual 2008 costs, saying that actual costs were not known at the time of the hearing even though the Order itself was issued well after the hearing concluded. Rafher than use actual 2008 prudently incurred cost levels as a basis for separating or unbundling the FAG and non-FAC rate elements, the Order is based on the use of a proxy that is not authorized by Section 4928,143, Revised Code. Regardless of what was known at the time of the hearing, the Commission could have nonetheless found in favor of the methodology that set the baseline based on 2008 actual prudently incurred costs and required AEP-Ohio to observe this requirement for purposes of developing compliance tariffs or rate schedules. Since 2008 actual fuel costs are now known, since they are significantly higher than the "proxy" adopted by the Commission, and since the "proxy" is, by definition, not the prudently incurred costs authorized in Section 4928.143(B)(2)(a), Revised Code, the Tr. Vol. VI at 79; OCC Exhibit 9 at 31. ^1d.at19. 45 229 Order results in the non-FAC portion of rates being too high and the risk of future increases in the FAC portion, as well as the amount of deferrals, too great. The Commission's failure to use actual prudently incurred costs as the basis to unbundle the FAC and non-FAC rate elements is not consistent with the goa{ of minimizing rate increases and is otherwise unreasonable, unjust and unlawful. In public presentations during 2008 and 2009, AEP indicated that its average price of coal delivered in 2007 was $36.58(ton, while its 2008 cost was reported to be $46.61/ton; a 27.4 percent increase over 2007. These data indicate that the Staff proxy for determining the 2008 baseline FAC costs produced a baseline FAC cost that was too low. Similarly, actual results for 2008, as reported in the SEC 10K Report, Indicate that OP had a $148 million increase in fuel and consumables compared to 2007, and that CSP had a $65 million increase in fuel, allowance, and consumables expenses in 2008. Based on the 3 percent escalation that Staff applied to CSP's 2007 FAC costs and the 7 percent escalation applied to OP's 2007 FAC costs to arrive at its 2008 proxy, the proxy baseline FAC costs are understated by tens of millions of dollars, whether the 2008 SEC actual data are used or the Commission uses the 2008 actual data otherwise publically reported by AEP. Now that AEP-Ohio's books have been closed for 2008 and the actual fuel costs are known, it would have been straightforward and lawful to require AEP-Ohio to unbundle its FAC and non-FAC rate elements based on these actual costs as was recommended during the {itigafion phase of this proceeding. There is no good reason for the PUCO to unbundle the FAC and non-FAC rate components based on a proxy 46 230 when the actual costs are readily available. Using a proxy in this context is not consistent with the goal of keeping rate increases as small as possible. Vltl. The scope of the fuel and other cost recovery mechanism authorized by the Commission is unreasonable, unlawful and unjust both because of the types of costs that are subject to recovery through the mechanism and the substantial negative effect that the kWh-based mechanism has upon larger, high load factor customers. AEP-Ohio's proposed FAG mechanism made it clear that the proposed FAG included costs related to much more than the costs of fuel consumed to produoe electricity; the costs which were historically subject to recovery through the Electric Fuel Component (°EFC") rate 85 As the Commission knows, the EFC was established by rule (Chapter 4901:1-11, O.A.G.) for uniform application to all electric utilities.87 Under Rule 4901:1-11-1(0), O.A.C., "fuel costs" were defined as the "... actual acquisition and delivery costs of fuel consumed, including the amortized costs of nuclear fuel expended, to generate electricity, unless otherwise provided in this chapter." But the opportunity to use the EFC to recover costs through an active adjustment clause came with obligations and a defined process by which compliance could be audited and evaluated by the Commission. The EFC mechanism was atso predicated on the Commission's ability to regulate the operation of the utility's generating units. For example, Rule 4901:1-11-02(A), Ohio eb OCC Exhibit 11 at 20. These additional elements comprise 21 percent of CSP's and 11 percertt of OP's estimated FAC. e' In 1998, the Commission completed Its periodic review of Chapter 4901:1-11, Ohio Administrative Code, as required by Section 119.032(8), Revised Code, in Case No, 98-967-EL-ORD, conctuding that no amendments to the rule were necessary. For purposes of this Brief, IEU-Ohio's citations to the EFC rule are citations to the rule attached to the Commission's July 2, 1998 Entry In Case No. 98-967-EL- ORD, which was the version of the rute in place when the EFC was eliminated by Ohio's electria restructuring legislation. 47 231 Administrative Code, required an electric utility to "... procure fuel, purchase power, and operate its generation, dispatch, transmission, and distribution systems at a minimum overall cost, taking into consideration its voltage, frequency, reliability, safety, environmental, and service quality requirements, as well as its existing contractuai obligations," (emphasis added). And, Rule 4901:1-11-02(t3), Ohio Administrative Code, required an electric utility to "... operate on an economic dispatch basis." AEP-Ohio's FAC proposal was focused exclusively on obtaining authority to automatically adjust rates to recover a broad range of costs. AEP-Ohio did not propose to take on the obligations that have been histotically part of a fuel adjustment clause, including the obligation to operate generation, transmission and distribution systems for the benefit of its retail customers subject to the regulatory oversight of the Commission. Therefore, AEP-Ohio's proposal was fundamentally unbalanced. For this reason alone, IEU-Ohio urged the Commission to not give AEP-Ohio authority to implement the proposed FAC. The Order indicates that lEU-Ohio's concems were ignored. As explained above, AEP-Ohia's FAG proposal included a broad range of costss$ that were not previously recoverable under the Commission's EFC rule.gs For example, AEP-Ohio's FAC proposal included the ability to recover demand and capacity-related costs that were not subject to recovery through the Commission's EFC rule.g0 Recovery of these costs through the FAC results in capacity or demand-related costs being 88 Tr. Vol. IV at 249-252. ea QCC Exhibit 11 at 20. 90 Tr. Vol. IV at 249-257; Tr. Vol. VI at 203-204; § 4901:1-11-04(D), Ohio Admin. Code; See In Re the Elecfric Fuel Component of Ohio Power Company and Columbus Southem Power, Case Nos: 98-101- EL-EFC and 98-102-EL-EFC, Opinion and Order (May 28, 1999). 48 232 allocated and recovered from customers on an energy or kilowatt-hour {"kWh") basi5.91 As Mr. Gorman explained, "... the Company's proposal to recover non-variable [or fixed] costs through the FAC, is inappropriate for several reasons."92 Recovery of fixed, capacity or demand-related costs on a volumetric or kWh basis also conflicts with the long-standing precedent of the Commission.93 AEP-Ohio's FAC proposal was designed to make the FAC play a "catch all" role which partly explains its broad scope. For example, the proposed FAC is where AEP- Ohio proposed to recover the "slice-of-system" costs and the FAC approved by the Commission appears to allow for inclusion of a portion of the costs associated with interests in generating assets that AEP-Ohio asked for authority to transfer while not having any plans to do so. While the Commission Staff provided some support far the scope of the Companies' proposed FAC, Mr. Strom made it clear that the scope of the proposed FAC should only be approved if the costs to be recovered through the FAC are not being recovered sameplaoe else.94 Unfortunately, the evidence does not B' Tr. Vol. IV at 257; Tr. Vol. V at 204. 92 Commercial Group Exhibit I at 4. " in the Matter of the Complaint and Appeal of Cofumbia Gas of Ohio, Inc., from Ordinance fJo. 11 92- 7S, of Columbus, Ohio, on July 19, 1976, to contrnue the Presentiy Established Schedules of Rates Being charged by Columbia Gas of Ohio. Inc., for Gas Servrce in the City of Columbus, Ohio, untrt August 1, 1978, Case No, 76-704-GA-CMR, Opinion and C7rder at 7 (June 29, 1977); In the Matter of the Application of Columbus Southern Power Company to AdJust its Power Acquisition Rider Pursuant to its Post-Market Development Perrod Rate Stabilization Pien, Case No, 07-333-EL-UNC, Application for Rehearing by the Offlce of the Ohio Consumers' Counsel and Ohio Partners for Affordable Energy at 7-8, 10, 17-18 (July 27, 2007); In the Matter of the Appttcation of Ohio Edison Company, The Cleveland Electric ifluminsting Company, and The Totedo Edison Company for Approval of a Market Rate Offer, Case No 08-936-EL-SSO, Opinion and Order at 22-24 (November 25, 2008), subject to application for rehearing); In the Matter of the Applicatron of Ohio Edison Company, The Cleveland Electric tifuminating Company, and The Toiedo Edison Company for Authority to Establish a Standard Servioe Offer Pursuant to Section 4928.143, Revised Code in the Form of an Efectric Security Plan, Case No 08-935-EL-SSO, Opinion and Order at 19-23 (December 19, 2008). 94 Staff Exhibit 8 at 3. 49 233 include a showing that current revenues are inadequate to provide compensation for any of the costs subject to collection through the FAC. As Mr. Cahaan testified, OP and CSP were obviously recovering their fuel costs (which he def€ned to include purchased power) in 2007 or their eamings would have been insufficient 93 Beyond the question of where the FAC and non-FAC line drawing should take place for purposes of unbundling the existirig rates, there is no basis in taw or fact for the PUCO to approve an FAC with the scope identified in the Order. The scope of the FAC is unreasonable and unlawful. In addition, and regardless of the scope of the FAC, the use of a kWh-driven FAC mechanism to recover fixed and demand-related costs is unreasonable, unjust and unlawful based on Commission precedent. Also, reoovery of demand and fixed cost through a kWh-based collection mechanism may be playing a role in creating the large mismatch that larger customers are observing as they compare the actual total bill increase to the total bill increase caps identified in the Commission's Order. In any event, the scope of the FAC described in the Commission's Order and the kWh allocation of fixed and demand-related costs through the FAC cannot be reconciled with the goal of keeping rate increases as low as possible or providing customers with predictable rates. IX. The Commission's determination that interruptible load may not be counted towards OP's and CSP's determination of their peak demand response compliance requirements Is unJust, unreasonable and unlawful. Without a single reference to the record or any reasoning whatsoever, the Commission held that it "agrees with the Staff and OCEA that interruptible load should 95 Staff Exhibit 10 at 3. 50 234 not be counted in the Companies' determination of its EEIFDR [energy efficiency and peak demand response] compliance requirements unless and until the load is actually interrupted:'96 The lack of reasoning extends further to Staft's and the Ohio Consumer and Environmental Advocates' ("OCEA") positions, apparently relied upon by the Commission. Specifically, the extent of Staffs discussion on the topic can be found in the testimony of Greg Scheck and is limited to the following question and answer: Q. What is the Staffs view with respect to crediting AEP Ohio's distribution utilities interruptible programs towards the annual peak demand reduction targets? A. Staff believes that such reductions must actually occur and be measured retrospectively in order to receive such credita7 Similarly, OCEA's discussion on this matter suffers from the same lack of reasoning, justification and record evidence. Specffically, on brief OCEA argued that counting interruptible load that has not actually been interrupted is contrary to SB 221, which mandates a peak reduction program "in order to improve the reliability of the grid"; "would provide a false representation of the grid's retiability, and thus would thwart the objectives of S.B. 221"; and, because customers are able to control part of the load when non-mandatory reductions are requested, it should not be counted.'e OCEA's arguments are contrary to the record evidence in the case and common sense. ^ order at 46, 97 Staff Exhibit 3 at 11. Moreover, the discussion of this issue in Staffs brief is limited to the foUoroving sentence: "But Staff does not recommend any credits being given towards the annual peak demand reduction targets for the Companies' interruptible programs unless reductions actually occur.° Brief at 19 (citing Staff Exhibit 3 at 11). 00 Initial Brief of Ohio Consumer and Environmental Advocates at 104 (December 30, 2008). 51 235 First, as Staff witness Scheck conceded, Section 4928.66(A)(1)(b), Revised Code, requires the Companies to implement peak demand reduction programs designed to achieve a one percent reduction in peak demand in 2009. Mr. Scheck acknowledged that a requirement to implement programs °designed to achieve" a reduction is different from a requirement to achieve a one percent reduction in peak demand s9 Moreover, as the Companies explained, interruptible senrice arrangements provide an on-system capability to satisfy reliability and efficiency objectives as part of a larger planning process.100 As the record shows, the interruptible load of customers can be and have been used to meet resource obligations established by RTQs regardless of the actual duration and frequency of interruptions.101 Thus, the goals of S8 221 are not thwarted, but rather are furthered by interruptible programs. OCEA's argument that, because customers control whether they buy-through a non-maridatory interruptible event, it should not count as a utility program, is unreasonable at best. Section 4928.66(2)(c), Revised Code, specifically encourages the use of mercantile demand response programs by reducing the EDU's baseline for calculating compliance with the law to exclude the effects of all such peak demarui reduction programs so long as the customer commits the capability for integration into the Companies' portfolio. These customer-sfted programs are ciearly controlled by the customers as they are designed and completed by customers and customers choose to commit them to the EDU's portfolio. Thus, the General Assembly clearly signaled that 99 Tr. Vol. VIII at 208. 10° AEP Brief at 112-115. t01 Tr. Vol. IX at 53. 52 236 such customer-controlled programs should be counted towards the EDUs' portfolio obligations. The buy-through opportunity, if any, only gives an interruptible customer the option to obtain an alternative supply and pay market-based prices for the alternative supply if an alternative supply is available. Finally, as EEU-Ohio noted on brief, the Commission's holding that interruptible capacity be counted only if it is actually interrupted will require the Companies to offer programs inferior to those available from RTOs and ultimately work against the type of resource planning that can provide reliabiiity and price benefits for all customers. The Commission's holding, coupled with its lack of reasoning, demonstrates that the Commission did not weigh the evidence or consider the result of its holding on ultimate customers. For these reasons, the Commission should reverse its determination that interruptible load may not be counted towards OP's and CSP's peak demand response compiiance requirements. X. The combined effect of the unexpiained conclusions fn the Commission's Order Is unreasonable, unjust and unlawful because the Commission arbitrarily and capriciously exercised its discretion to allow CSP and OP to bill and collect excessive rates. IEU-Ohio believes the Order is in error for each of the reasons described above. But even if each individual error might be regarded as forgivable based on the objective of keeping rate increases as low as possible or the requirements of Ohio law, the collective weight of the errors makes the Order unreasonable, unjust and unlawful. The goal of keeping rate increases as low as possible cannot be reconciled with the combined choices the Commission made to allow AEP-Ohio to bill and collect the surprisingly large rate increases that are showirig up in customers' bills. And, with all 53 237 the regulatory emphasis on stable and predictable bills, the Order effectively leaves customers guessing about what their rates will be in 2010, just a few months from now. Xi. Conclusion The Commission's Order unreasonably, unjustly and unlawfully sanctions rate increases that, in the aggregate, will cause AEP-Ohio customers to pay AEP-Ohio an additional $1.5 billion over the three-year ESP period and sets in motion obligations on the part of customers to pay non-bypassable charges for six years thereafter. The botfom line conclusions that appear in, or can be attributed to, the Order, cannot be reconciled with the goal of keeping rate increases as low as possible or with the letter and spirit of Ohio law. On the simplest level of analysis, the total bill limitation on the amount of the 2009 rate increase produced by the Order has been ignored by AEP-Ohio in developing the rates that it is presently billing and collecting under the Commission's supervision. And, the total bill increase limitation is being ignored in ways that produce increases that the Commission found would result in an unacceptable hardship on customers who have been hard hit by conditions in the general economy. For the reasons contained herein, IEU-Ohio urges the Commission to grant rehearing and, on an immediate and interim basis, order AEP-Ohio to revise its rates so that no rate schedule is subject to a greater total bill increase than the total bill increase limitation percentage specified in the Order computed based on the rates and charges in effect prior to the March 18, 2009 Order and make AEP-Ohio's collection of any increase subject to refund. By these actions, the Commission can begin to correct the 54 238 mismatch between what the Commission has said and what the Commission has actually done to fix the efectric rates and charges paid by the customers of AEP-Ohio. SaWel C. Randazzo Lisa G. McAlister Joseph M. Clark McNeES Wau.noe & NuRicicLLC 21 East State Street, 17T" Ffoor Columbus, OH 43215 Telephone: (614) 469-$000 Telecopier. (614) 469-4653 [email protected] [email protected] [email protected] Attorneys for Indugtrial Energy Users-Ohio 55 239 ^ Attachtnent A Gongwer House Activity Report, 3/512009 Page 2 of 14 tlB 61 U ESTATp,"1'AXES (Hattinger Grosma To reduce the estate tax by increaaing the credit amount, to authoriaa townships and municipal carporatiorta, or electors thereof by initiative, to exempt from the estate taa aud any estate property located in the township or municipal corporation, and to distribute all estate tax revenue originating in a townehip or muriicipal corporation that does aot exempt property from the tax to the township or municipal corporation. F)all Text MMMITTR^II FAR_ING Finance & Appropriutions: Agriculture & Development Sub. Alan Schriber, chairman of the Public Utilities Commission of Ohio, tes ited in support of the executive proposat for the utility regu3ating body_ White he noted that the PUCO is funded through assessments on utilities and not the general revenue fund, he said the commission's operatians are not free. C The chairman said the commission does occasionally belp ganerate money for the state, on the oceasion that it iseues civil finea against regulated companies. He aaid eommission finea over the last twoyears delivered about $7 million to the general revenue fund. The chairman said the agency has apent a significant amonnt of time ever the last year implementing the state's new electric law, a process that he said is nearing completion. "lt's heen a significant drain on onr resources," he said. Mr. Schr%ber said the commission continues to 6old vonsumer calls and coacerns, and also proeesses formal cnmplaint proceedings. In an era with more wmpetition in the telecom indusGy, he noted that the PUCO haa also seen an increase in complaints filed by one company against another, lie also noted that the commission rocently revised guidoli nee for programs involving low-income conswners, and anid commissioners are sensitive to the current economic conditions. "The ordinary citiz.cn feels like they're taking in on the chin" with utitity eosts, ltep. Yates observed. Mr. Schriber said thc commission has heard those sentiments in its public hearings on the electric rate plans. "We are very intent, in this day and age, to miUgate rate increases," he said, adding that the commission's goal, for the time being, is to have virtually no increase in utility rates. "I ehink we're doing a pretty decent job this year of doing that," he said.'This is not the year when you want to increase rates. There is no question that, over time, rates are going to go up:' Rep- Yates aaid it is his sense that cansumers feel their positions are not cunsidered, Rep. Goodwin advised the chnirman that there's a perception that the PUCO is ran by the utilities. Mr. Schriber said the commission tries to balance the needs of consumers and utilities, "Nobody likes the utilit.ies; " he said, adding that it is difficult to canvinoe Ohioans that commission actians are in the best interest of the stafe. "We don't make friends anywhere." The chairman also offered a brief run-down on the status of electric companies' rate plans under the new law, and exprassed concern about private company water rates that are inereasing_ "It needs to be addressed," he said, fileJ/C:1Documents and Set(ings\jclark\Local Settings\Temporary Internet Files\Of.R1781... 4/812009 240 'Attachment B EXHIBIT JEH-1 0 ^ m M w c^ ^ m uWi O N N m W N H M W ^ O m ^ N n m ^ N W W ^I} ^ ^4A N ^ ^ y^ ^y^ sA es m N ^ ua a^ vr w ^ 0 v vi N ^ V 1^ 0 m N W N h N Q 4 In N G9 fA tA.. fiA O l+) ^ N O f^. ^!a O M HT N ^ W 4^p ^ 4 V ^ 0 9> ^f) O A Q N M O 64 f9 ^ M 9 N9 U3 ^ r W ^ G ^vr W N aD N V 7 O> n0 N O O Yi ^ w n fl ^ a 4 N^ ^N M ^ ^ ^ ^ON ^ ^ F- w ^ W O 1n ^ dt W W M 1 ^ O ^ cD N N W ^fA 0 N ^ W (i3 H ^'^1 N1 M M ^A q"! Q w a 1^- W ^ O ^ N W m O W ^ c^vn C^J N n W N W NO W N 0 O ^ (9 tA 4 N 59 tA tli afl ^ o n Y!) w vi v w N' u^ v 0 N O c+) lII W (O t^ CJ N M N n ^ w N w 00 ^ n ^ w ^ O F fA O N N ry 241 CERTIFICATE OF SERVICE I hereby certify that a copy of the foregoing APPL1cATiON FOR REHEAR7NG AND MEMORANDUM IN SUPPORT OF INDUSTRIAL ENERGY USERS-(aN10 was served upon the following parties of reoord this 16th day of April 2009, via electronic transmission, hand- delivery or first class mail, postage prepaid. Manrin I. Resnik, Caunsel of Record John W. Bentine Steven T. Nourse Mark S. Yuriok American Elecbic Power Service Corporation Matthew S. White Chester, Willcox & Saxbe LLP 1 Riverside Plaza, 29'" Floor 85 East State Street, Suite 1000 Columbus, OH 43215 Columbus, OH 43215-4213 Selwyn J. R. Dias ON BEHALF OF THE KROGER CO. Columbus Southern Power Company Ohio Power Company Janine L. Migden-Ostrander 88 E. Broad Street - Suite 800 Consumers' Counsel Maureen R. Grady, Counsel of Record Columbus, OH 43215 Terry L. Etter Jacqueline Lake Roberts Daniel R. Conway Michael E. Idzkowski Porter Wright Morris & Arthur Office of the Ohio Consumers' Counsel Huntington Center 10 West Broad Street, Suite 1800 41 S. High Street Columbus, OH 43215-3485 Columbus, OH 43215 ON BEHALF OF THE OFFt6E OF THE OHIO CONSUMERS' COUNSEL ON BEHALF OF COLUMBUS SOUTHERN POWER AND OHIO POWER COMPANY Barth E. Royer, Counsel of Record Belt & Royer Co. LPA David F. Boehm 33 South Grant Avenue Michael L. Kurtz Columbus, OH 43215-3927 Boehm, Kurtz & Lowry Nolan Moser 38 East Seventh Street, Suite 1510 Air & Energy Program Manager Cincinnati, OH 45202 The Ohio Environrnental Council 1207 Grandview Avenue, Suite 201 ON BEHALF OF OHIO ENERGY GROUP Columbus, OH 43212-3449 242 Trent A. Dougherty GROUP, DIRECT ENERGY SERVICES, LLC, Staff Attomey INTEGRYS ENEROY SERVICES, INC., NATIONAL The Ohio Environmental Council ENERGY MARKETERS ASSOCUTION, OHIO SCHOOL 1207 Grandview Avenue, Suite 201 OF BUSINESS OFFICIALS, OHIO SCHOOL BOARD.S Columbus, OH 43212-3449 ASSOCIATION, BUCKEYE ASSOCIATION OF SCHOOL ADMINISTRATORS, AND ENERNOC, INC. ON BEIiALF OF THE OHIO ENVIRONMENTAL COUNCIL Craig G. Goodman National Energy Marketers Associat[on David C. Rinebolt 3333 K. Street, N.W., Suite 110 Colleen L. Mooney Washington, D.C. 20007 Ohio Partners for Affordable Energy 231 West Lima Street ON BEHALF OF NATK7NAL ENERGY MARKETERS Findlay, OH 45839 ASSOCIATION ON BEHALF OF OHIO PARTNERS FOR AFFORDABLE Barth Royer ENERGY Bell & Royer Co. LPA 33 South Grant Avenue Michael R Smalz Columbus, OH 43215-3927 Joseph V. Maskovyak Ohio State Legal Services Association Gary Jetfries 555 Buttles Avenue Dominion Resources Services Columbus, OH 43215-1137 501 Martindale Street, Suite 400 Pittsburgh, PA 15212-5817 ON BEHALF OF APPALACHIAN PEOPLE'S ACTION COALITION ON BEHALF OF DOMINION RETAIL, I Richard L. Sites Henry W. Edchart Ohio Hospital Associatlon 50 West Broad Streefi #2117 155 E. Broad Street, 151h Floor Columbus, OH 43215 Columbus, OH 43215-3620 ON BEHALF OF THE SIERRA CLUB, OHtO CHAPTER, ON BEHALF OF THE OHIO HOSPITAL ASSOCIATKYN AND THE NATURAL RESOURCES DEFENSE COUNCIL David I. Fein Langdon D. Bell Cynthia Fonner Bell & Royer Co., LPA Constellation Energy Group 33 South Grant Ave. 550 W. Washington Street, Suite 300 Columbus, OH 43215 Chicago, IL 60661 Kevin Schmidt ON BEHALF OF CONSTELLATION ENERGY GROUP. The Ohio Manufactaarers" Association 33 North High Street Bobby Singh Columbus, OH 43215 Integrys Energy Services, Inc. 300 West Wilson Bridge Road, Suite 350 ON BEHALF OF THE OHIO MANUFACTURERS' Worthington, OH 43085 ASSOCIATION ON BEHALF OF iNTEtiRYS °ENERGY"SEF:YICES, INC. Larry Gearhardt Ohio Farm Bureau Federation Howard Petricoff 280 North High Street, P.O. Box 182383 Stephen M. Howard Columbus, OH 43218 Vorys, Sater, Seymour & Pease LLP 52 E. Gay Street ON BEHALF OF THE OFnO FARM BUREAU Columbus, OH 43215 FEDERATION ON BEHALF OF CONSTELLATION NEw ENERGYAND CONSTELLATION NEW ENERGY COMMODITIES 243 Clinton A Vince C. Todd Jones Presley R. Reed Christopher Mllter Emma F. Hand Gregory Dunn Ethan E. Rii Andre Porter Sonnenschein Nath & Rosenthal Sdtottenstein Zox and Dunn Co., LPA 1301 K Street NW 250 West Street Suite600, East Tower Columbus, OH 43215 Washington, DC 20005 ON BEHALF OF THE ASSOCIATION OF INDEPENDENT ON BEHALF OF ORMET PRPMARY ALUMINUM COLLEGES AND UNIVERSITIES OF OHIO CORPORATION Douglas M. Mancino Stephen J, Romeo MoDermott Will & Emery LLP Scott DeBroff 2049 Century Park East Alicia R. Peterson Suite 3800 Smigel, Anderson & Sacks Los Angeles, CA 90067 River Chase Office Center 4431 North Front Street Gregory K. Lawrence Harrisburg, PA 17110 RltoDertnott Wi11 & Emery LLC 28 State Street Benjamin Edwards Boston, MA 02109 Law Offices of John L. Alden One East Livingston Ave. Steven Huhman Columbus, OH 43215 Vice President MSCG ON t3EHALF OF CONSUMERPOWERLINE 200 Westchester Ave. Purchase, NY 10577 Grace C. Wung McDermott Will & Emery LLP ON BEHALF OF MORGAN STANLEY CAPITAL 600 Thirteenth Street, NW GROUP, INC. Washington, DC 20005 John Jones Douglas M. Mancino Thomas Llndgren McDermott Will & Emery LLP Wemer Margard 2049 Century Park East Assistant Attorneys General Suite 3800 Public Udlities Section Los Angeles, CA 90067 180 East Broad Street Columbus, OH 43215 Steve W. Chriss Manager, Stale Rate Proceedings ON BEHALF OF THE PUBLIC UTILITIES COMMlSS1ON Wal-Mart Stores, Inc. OF OHIO 2001 SE 10'" Street Bentonville, AR 72716 Kimberiy Bojko Attomey Examiner ON BEHALF OF THE WAL-MART STORES EAST LP, Public Utifities Commission of Ohio MACY'S INC., AND SAM'S CLUB EAST, LP 180 East Broad StTeet, 12"' Floor Columbus, OH 43215 Sally W. Bluomtieid Terrence O'Donneii Greta See Bricker & Eckler Attomey Examiner 100 South Third Street Public Utilities Commission of Ohio Columbus, OH 43215 180 East Broad Street, 12t° Fioor Cafumbus, OH 43215 ON BEHALF OF AMERIOAN WIND ENERGY ASSOOIATION, WIND ON THE WIRES AND OHIO ATTORNEY EXAMINERS ADVANCEO ENERGY 244 5we PECEIYE: : EiltV: Lib BEFORE 1'HE PUBLIC UTILITIES CO117NIISSION OF OHI{1009 APR 17 p-M 2: 57 In the Matter of the Application of Columbus ) ^^^R Southern Power Company for the Approval of ) Case No. fi8-917-EI.-SS its Electric Security Plan; and Amendment to ) Its Corporate Separation Plan; and the Sale or ) Transfer of Certain Generation Assets ) In the Matter of the Application of Ohio Power ) Company for Approval of its Electric Security ) Case No. 08J918-EL-SSO Plan and an Amendment to its Corporate ) Separation Plan ) COLUMBUS SOUTHERN POWERCOMPANY'S AND 01110 POWER COMPANY'S APPLICATION FOR REHEARING Marvin I. Resnik, Counsel of Record Steven T. Nourse American Electric Power Service Corporation 1 Riverside Plaza, 29" Floor Columbus, Ohio 43215 Telephone: (614) 716-1606 Fax:(614) 716-2950 Email: ntiresnik&ep.com stnoursc ,,mp.com Daniel R. Conway Potter Wright Morris & Arthur Huntington Center 41 South High Street Columbus, Oluo 42315 Telephone: (614) 227-2270 Fax:(614)227-2100 dconyn^ipht.com Counsel for Columbus Southern Power Company and the Ohio Power Company Filed: April 17, 2009 Thln is to certify that the imasea aPgearing 8" 9a accurate and complete reproduction of a ca.ae file document delivered in -he reTil:s.r course of bus neas• Technician,^7-(_,.._.._ =te ^.:aa^sned 245 TABLE OF CONTENTS INTRODUCTI ON...».....» ...... »»...... »...... »...... »»...... 1 MEMORANDUMIN SUPPORT OF APPUCATION FORREBEARIT3G.»....».»4 I. The Commission's Expansion of the Statutory Test Under $492$.143 (C)(I), Ohio Rev. Code, for Comparing the Electric Security Plan to the Results That Would Otherwise Apply Under a Market Rate Offer Is Unlawful and Unreasonable...... ».... »....».».».... »..... 4 Il. 'fhc Commission's Rejection of the Companies' Proposed Line Eatension Provisions Is Unlawful and Unreasonable.... » ...... »...... :..».6 IIL The Commission's Rejection of the Companies' Proposal to Contmence in 2011 Recovery of Regulatory Assets Authorized in Previous Cammission ..... Proceedings is Unlawful and Uureasonable.» ...... »».9 IV. The Commission's Modification of the Companies' Praposed Phase-In Unreasonably Adjusts the Balance Between the Up-Front Revenue Recovery and Subsequent Recovery of Deferrala. Further, the Commission Failed to Clarify That Additional Revenues Authorized From a Distribution Base Rate Case or From the Energy Efficiency and Peak Demand Reduction Recovery Rider Are Not Inctuded In the Phase-InlDeferral Structure ...... » ...... »12 V. The Commission's Rejection of the Companies' Proposed Automatic Annuat Increases to the Non-FAC Portion of the Generation Rates is Unlawful and Unreasonable»...... »...... »» ...... ». .». ».14 VI. It was Unreasonable and Against the Manifest Weight of the Evidenee for the Commissioa to Conclude That the Load of the Former MonPower Service Territory Should not be Excluded From the Companies' Baseline Used for Compliance With §§4928.64 and 4928.66, Ohio Rev. Codo»..»....»....»....».. 17 VII. It was Unreasonable and Unlawful for the Commission to Set Aside §492&66, Ohio Rev. Code, and Determ'u ►e That the Companies' Interruptible Load Should Not be Counted in the Companies' Determination of its F,EIPDR Compliance "unless and until the load is actually interrupted." (Order, p. 46)...... »...... ».....»....:...... »...... »...... »...... »...... 24 I VIII. It was Unreasonable and Against the Manifest Weight of the Evidence for the Commission to Defer a Decision on Retail Participation in the PJM Demand Response Programs ...... »...... »...23 246 IX. It was Unreasanable and Unlawfal for the Commission to Set Aside §4928.143(B) (2) (h), Ohio Rev. Code, and Determine That the Companies' Distribution Proposals Must be Examined Through a Distribution Rate Case Where All Components of Distribution Rates are Subject to Review and the Order's Modification in this Regard Should be Clarified :...... »....27 X. The Order is Unlawful and Unreasonable to the Extent That it Intended to Allow Only Half of the Required Funding When Approving the gridSMART Rider and the Order's Modirication in this Regard Should be Clarified...... 35 XI. The Commission's Authorization for the Fuel Adjustment Clause for Only Three Years is Unreasonably Restricfive ...... 37 XII. The Commission's Modification of the Companies' Proposed T'ue1 Adjustment Clause Baseline in the Pre-Electric Security Plan Standard Service Offer Rates is Unreasonabie ...... 38 XIII. In Deferring Judgment on a Methodology for the Significantly Exeessive Earnings Test (SEET) and Directing Its Staff to Canvene a Workshop for Developing a Methodology to be Applied to AU Electric Utilities, the Commission Unreasonably Failed to Note the Appropriateness of the Companies' Proposal for Iiaving the SEET Applied to Them on a Combined Basis and That How That Would be Done Would be Considered in the Workshop and That a Common Methodology Does Not Require a Methodology Identical for Each Eleetrie Utility ...... »...... 4d CONCLUSION ...... »...... 42 CERTIFICATF. OF SERVICE.....»...... »» ...... :...... »..»...... 43 247 BEFORE TIIE PUBLIC UTILITIES CObU6+IISSION OF OHIO In the Matter of the Application of Columbus Southern Power Company for the Approval of Case No. 08-917-EL-SSO its Electric Security Plan; and Amendment to Its Corporate Separation Plan; and the Sale or Transfer of Certain Generation Assets In the Matter of the Application of Ohio Power Company for Approval of its Electric Security Case No. 08-918-EL-SSO Plan and an Amendment to its Corporate Separation Plan COLUMBUS SOUTHERN POWER COMPANY'S AND OFIIO POWER COMPANY'S APPLICATION FOR REHEARING INTRODUCTION In accordance with §4903.10, Ohio Rev. Code, and §4901-1-35, Ohio Admin. Code, Colu,nbus Southern Power Company and Ohio Power Company ("AEP Ohio" or "the Companies") apply for rehearing because the following aspects of the Commission's March 18, 2009 Opinion and Order ("Order") are unreasonable andtor unlawful: 1. The Commission's Expansion of the Statutory Test Under §4928.143 (C)(1), Ohio Rev. Code, for Comparing the Electric Security Plan to the Results That Would Otherwise Apply Under a Market Rate Offer Is Unlawful and Unreasonable. II. The Commission's Rejection of the Companies' Proposed Line Extension Provisions Is Unlawful and Unreasonable. III. The Commission's Rejection of the Companies' Proposal to Commence in 2011 Recovery of Regulatory Assets Authorized in Previous CommissionProceedings is lJnlawfuland Unreasonable. IV. The Conunission's Modification of the Compariies' Proposed Phase-In Unrcasonably Adjusts the Balance Between the Up-Front Revenue Recovery and Subsequent Recovery of Deferrals. Further, the Commission Failed to Clarify That Additional Revenues Authorized Froin a Distribution Base Rate Case or From the 248 Energy Efficiency and Peak Demand Reduction Recovery Rider Are Not Inciuded in the Phase-In/Deferral Structure. V. '€he Commission's Rejection of the Companies' Proposed Automatic Annual Increases to the Non-FAC Portion of the Genecation Rates is i.lnlawful and Unreasonable. VI. It was Unreasonable and Against the Manifest Weight of the Evidence for the Commission to Conclude That the Load of the Former MonPower Service Territory Should not be Excluded From the Companies' Baseline Used for Compliance With §§4928.64 and 4928.66, Ohio Rev. Code. VII. It was Unre.•asonable and Unlawful for the Commission to Set Aside §4928.66, Ohio Rev, Code, and Determine That the Companies' Interruptible Load Should Not be Counted in the Companies' Determination of its EE/PDR Compliance "unless and until the load is actually inteinrpted." (4hder, p. 46). VIII. It was Unreasonable and Against the Manifest Weight of the Evidence for the Commission to Defer a Decision on Retail Participation in the PJM Demand Response Programs. IX. It was Unreasonable and Unlawfirl for the Commission to Set Aside §4928.143(B) (2) (h), Ohio Rev. Code, and Deternrine That the Companies' Distribution Proposals Must be Examined Through a Distribution Rate Case Where AIl Components of Distribution Rates are Subject to Review and the Order's Modification in this Regard Should be Clarified. X. The Order is Unlawful and Unreasonable to the Extent That it Intended to Allow Otily Half of the Required Funding When Approving the gridSMART Rider and the Order's Modification in this Rega-d Should be Clarified. XI. The Commission's Authorization for the Fuel Adjustment Clause for Only Three Years is Unreasonably Restrictive. Xii. The Commission's Modification of the Companies' Proposed Fuel Adjustment Clause Baseline in the Pre-Electric Security Plan Standard Service flffer Rates is Unreasonable. Xlii. In Deferring Judgment on a Methodology for the Significantly Excessive Earnings Test (SEET) and Dirocting Its Staff to Convene a Workshop for Developing a Methodology to be Applied to All Electric Utilities, the Commission Unreasonably Failed to Note the Appropriateness of the Companies' Proposal for Having the SEET Applied to Them on a Combined Basis and That How That Would be Done Would be Considered in the Workshop and That a Coinmon Methodology Does Not Require a Methodology Identical for Each Electric Utility. 2 249 In presenting these grounds for rehearing in detail below, AEP Ohio nespectfully requests that the Commission clarify on rehearing certain modificatians contained within the Order (either as a direct request for clarification or as an alternative to granting rehearing) to enable the Colnpanies to make an informed decision on whether to accept or withdraw the Commission-modified plan. The Commission has previously held that an application for rehearing is the appropriate place to "seek ftuther understanding of the intent and effect of a commission order."t The importance of those clarifications are elevated in cases such as this where under § 4928.143(C)(2), Ohio Rev. Code, the utility must make a decision whether to withdraw its ESP application in light of the modifications made by the Carnmission to the filed plan. It is under this elevated statutory process that AEP Ohio seeks clarification on certain issues to ensure a full understanding of all of the t.erms of the Commission's order and the effect those changes have on AEP Ohio's ESP. Any clarification on these points that does not occur until montlis or years from now would diminish or undermine AEP Ohio's statutory right to withdraw from a modified plan. 'In the Matter of'the Applleation ofColurnbia Gas ofOhio, Ine, for Approwr( ofT'ariffs to Recover, Through an Aatomatic Adjustment CYause, Costs Assaciated with the EstablisPtment ofarc Infrartructare Replacement Program and forApproval ofCertain Accm,ntingTreatmenb Case No. 07-478-GA-UNC (Entry on Rehearing, 113) (September 12, 2007), citing In the Afatter ofthe Revtew afChapters 4901-1, 4901-3, and 4901-9 of the Ohio ddtnrnistrative Code, Case No. 06-685-AU-ORI) (Finding aad Ordeer, V 59) (DecemBer 6, 2006). 3 250 MEMORANDUM IN SUPPORT OF APPLICATION FOR RT.FIFARING 1. The Commission's Eapansion of the Statutory Test Under §4928.143 (C)(1), Ohio Rev. Code, for Comparing the Electric Seeurity Plan to the Results That Would Otherwise Apply Under a Market Rate Offer Is Unlawful and Unreasonable. The statutory test for approval of an ESP is set out in §4928.143 (C) (1), Ohio Rev. Code. That test requires that the Commission approve the ESP "if it finda that the electric security plan so approved, including its pricing and all other terms and conditions, including any defenals and any future recovery ofdeferrals, is more favorable in the aggregate as compared to the expected results that would otherwise apply under [an MRO]." The Commission also has the authority to modify and approve an ESP application if the F,SP, as modified, meets this statutory test. This authority, however, does not mean that the Commission can modify an ESP application w3uch meets the statutory test even absent the Commission's preferred modification. Stated differently, if the proposed ESP is not more favorable in the aggregate than the expected results of the MRO, then the Cominission can modify the proposed ESP and approve it. lf, however, an•ESP in the aggregate is more favorable than the expected results of an Iv]RO the Commission lacks the authority to modify that ESP to make it even more favorable than the expected results of an MRO. Nonetheless, this is whhat the Order does. The Commission justifies its rnodification of the Companies' ESP on its conclusion that its authority to make those modifieations to an ESP that, as proposed, already passes the statutory test, is not limited "to an after-the-fact determination of whether the proposed ESP is more favorable in the aggregate, Rather, the Cotnnvssion finds that our statatory authority includes the 4 251 authority to make modifications supported by the evidence in the record in this case." (Order, p. 72). By this rationale, the Commission concludes that its typical rate making authority to set just and reasonable rates presents a basis of authority that goes beyond the authority the General Assembly vested in the Comtnission in §4928.143 (C) (1), Ottio Rev. Code. With that extra layer of authority, the Commission examined individual components of the Companies' proposed ESP to determine whether to reject or modify those compouents. Using such a process, the Connnission rejected or modified certain provisions of the ESP, for instance, the Companies' proposal for automatic annual increases to their non-FAC portion of generation rates. SB 221, of course, did not implement a "typical rate making" process. Instead, it permits the Companies to propose an ESP that can include, without limitation, many different components. Those components are not to be judged on a component-by- component basis. The analysis is not to determine if each component is reasonable, cost based, prudent or on its own more favorable than a related component within a possible MRO. Instead, the components of the ESP are to be analyzed "in the aggregate" and the aggregate impact is to be coinpared to the expected results that otherwise would apply under an MRO. On rehearing, the Commission shouid modify its Order to reflect the statutory test established by the General Assembly. Based on the record as discussed throughout the Companies' post-hearing briefs, and particularly the portions of those briefs conce2ning the ESP Y. MRO comparison, the Commission should approve the ESP as proposed by the Companies. 252 U. The Commission's Rejection of the Companies' Proposed Line Extension Provisions Is Unlawful and Unreasonable. The Companies' ESP proposal sougbt to continue the up-front payment concept established in Case No. 01-2708-EL-CQ1,2 at an increased level. The Commission rejected this proposal, finding that the policy of requiting up-front payments had not been shown by the Companies to be consis-tent with SB 221 or to advance the policy of the state. "The Commission went on to state that in light of the statutory mandate that the Commission adopt statewide line extension rules, it was unwilling to adopt a unique policy for the Companies at this time.; Consequently, the Cotnpanies were directed "to account for all line extension expenditures, excluding premium services, in plant in service until the new line extension rules become effective...." Recovery of the an7ounts placed in the plant-in-service accounts "will be reviewed in the context of a distribution -rate case." (Order, p.49). On rehearing the Commission should authorize the Companies to implement the up-front payments contemplated by the Commission in its November 5, 2008 Finding and Order in Case No. 06-653-EL-ORD. In that order, the Commission adopted Rule 4901:1-9-07 (D). That rule would permit up-froat recovery of: non-premium line extension costs that exceed five thousand dollars for single family homes, (D) (1); non- premiurn line extension costs that exceed twenty-five hundred dollars per unit for 1 In the ,ttatterofrheCommission's7mesfigationintothe Polrcies atulProcedures ofOAio PowerCompany, Columbos Southern Power Compatry, The Cleveland E(ectric Ifluminating Company, Ohio Edison Conrpany, The Totedo Edison Company and Monongahela Power Company Regording the Instatlation ofNew Line Exfensions, Case No. 01-2708-ELrCOI, et al., Opinion end Order (November 7, 2002). 8ee /n the Matter ofthe CommLssion's Review ofChapiers 490I:1-9. 4901:1-10, 4901:1-22, 4901:1-22, 4901:1d3, 4901:1-24, mtd 4901:1-25 ofthe Ohio Adrninistrailve Code, Case No. 06-6S3-Ei,-O11I), Finding and Order (November 5, 2008), Entry on Rehearing (Deeeniber 17, 2008), 6 253 residential, non-master-metered mult.ifamily installations, (D) (2); and forty percent of the total cost of the line extension, excluding premimn service incremental costs, for non- residential installations, (D) (3). While several rehearing applications were filed in Case No. 06-653-EL-0RI?, no party sought rchearing on the basis that ihe up-front payment amounts adopted in Rule 4901:1-9-07 (D) were too high.4 Therefore, it appears that once the Commission issues its Entry on Rehearing in that docket and the review process before the Joint Committee on Agency Rule Review is completed, the up-front payment amounts adopted in the Commission's November 5, 2008 Finding and Order will become effective. If no inodification regarding up-front line extension payments is aathorized through this rehearing, the Cammission's order in the Companies' ESP proceeding will result in the Companies, and the customers and developers with whom they work on line extension matters, bouncing frotn the pre-ESP up-front payment provisions to no up-front paymertts, except in very limited circumstances, and then to re-implementation of new up-front payment amounts under the Commission's adopted rule. Moreover, during the interim period when non-residential developers would make no contribution to the line extension non-premium service costs there would be no incentive for those developers to consider cost implications associated with the siting oftheir development The Companies contend that because no party in the rutemaking case has ehallenged the adopted up-frrnit payments as being too high it woufd be more efficient, less confusing and better regulatory policy to permit the Companies to implement the adopted up-front payments as part of their ESP, subject to reimbursement to ° The Application for Rehearing filed on behalf of the FirstE.nerp+utilities argued that there shoeild be some up-finnt payment ohtigation in the singic family home context in addition to the payment when costs exceed five thousand doqars. 7 254 customers/developers who make those payments if, for some reason, the Conunission did reduce the payment amounts in the rules that ultimately become effective. Permitting the Coinpanies to irnplement the up-front payments adopted by the Commission would be consistent with Chapter 4928, Ohio Rev. Code, as well as, state policy. As the Commission recognized in its November 7, 2002 Opinion and Order in Case No. 01-2708-EIs-COI, both §§4928.15 (A) and 492$.35 (C), Ohio Rev. Code: provided the Commission with the authority to approve the establishment of new line extension policies and procedures. Pursuant to those sections, the Commission cati establish how the cost of new facilities are to be recovered from customers requesting service to be provided from line extensions as well as those customers requesting that liue extensions be built. (p. 30) 5 Finally, the Commission has held in Case No. 06-653-EL-OR17 that non- residential customers should be. required to contribute, up-front, forty percent of the total cost of a requested line extensioxt, plus the incremental costs of premium s8rvices. The Commission's decision to require up-front payment of forty percent of non-premium costs was based on the policy arguments made by the Industrial Energy Usera-Ohio that requiring "the electric utilities to fund one hundred percent of the upfront cost of non- premium line extension costs will have a negative impact on existing businesses, creating intra-class subsidies." (Finding and Order, pp. 4, 5). For these reasons, the Companies ask the Commission to modify on rehearing the line extension portion of its Order, so that the Companies can implement the up-front payment provisions of Rule 4901:1-9-07 (D) subject to reimburseinent as described above. Such modification would be consistent with §§4928.15 (A) and 4928.35 (C), S 13oth of tlwse sectians provide that °acus[omer requesting that service may be required to pay all or part of the rensonable inercmental cost of the new facilities, in accordance with rules, policy, precedents, or orders ofthe Commission." This ianguage remains unchnnged by SB 221. 8 255 Ohio Rev_ Code, would be consistent with the policy decisions made by the Commission in Case No. 06-653-EL-ORD, and would be consistent with reasonable and efficient regulatory practices. III. The Conimission's Rejection of the Companies' Proposal to Commence in 2011 Recovery of Regulatory Assets Authorized in Previous Commission Proceedings is Unlawful and Unreasonable. The Companies' ESP contained a provision that would pennit the recovery of regulatoty assets, the creation of which previously had been authorized by the Commission: As set out on page 58 of the Companies' Initial Post-Hearing Brief, there are five different categories of these regulatory assets: I. Consumer education, customer choice implementation and transition plan filing costs plus carrying charges in accordance with the Commfssion's September 28, 2000 order in CaseNos. 99-1729 and 99-1730-EL-ETP. 2, Rate case expense plus carrying charges in accordance with the Commission's January 26, 2005 order in the Companies' Rate Stabilization Plan Filing in Case No. 04,-169-EL-Z7NC. 3. Carrying charges on distribution line extension charges in accordance with the Commission's November 7, 2002 order in Case No. 01-2708-EL-COI, ct al. 4. Monongahela Power Company transfer integration costs plus carrying charges and acquired net regulatory assets in accordance with the Commission's November 9, 2005 order in Case No. 05-765-EL-UNC. 5. The Companies' voluntary Ohio Green Power Pricing Program costs in accordance with the Commission's March 23, 2007 order in Case No. 06- 1153-EL-UNC. The Companies proposed to begin the amortization of the December 31, 2010 regulatory asset balance in 2011. This proposad delay until 2011 would minimize the impact on customers during the three-year ESP period. The Companies identified the 9 256 regulatory asset balances as of June 30, 2008 and the projected balances as of December 31, 2010. (Companies' Ex. 6, p. 36). No party challenged the actual or projected balances. The Comrnission rejected the Companies' proposal, stating that the Companies had not denmQnstrated that recovery of these regulatory assets, as a single-issue rate making item for distribution infrasteucture and modemization incentives, meets the requirements of SB 221 or state policy. The Conimission's reasoning is misdireeted. The Cornpanies were not relying on §4928.143 (B) (2) (h), Ohio Rev. Code, the provision explicitly permitting ESP provisions regarding the utility's distribution service. Even if the Companies had relied on that provision, such a proposal would not be limited to distribution infrastructure and modernization incentives. This is because even tlus provision refers to distribution service "including, withoart limitataon" infrastruettue and modenuzation incentives. (emphasis added). 'fhe Companies' historic regulatory assets recovery proposal is clearly pennissible under §4928.143 (B) (2), Ohio Rev. Code, which states that an ESP "may provide for or include, without Iimitation, any of the following:" (emphasis added). Therefore, even if the regulatory asset recovery proposal were not pennissible under subdivision (B) (2) (h), (which because of the subdivision's own "without limitation" language the proposal is permissible), the proposal is permitted under the broader "without limitation" language wbich precedes the listing of possible ESP provisions. The Comniission's conclusion that the regulatory asset recovery proposal did not comply with state policy also is in error. Each of these regulatory assets is consistent with state policy. Consumer education, customer choice implementation, and transition 10 257 plan filing costs all were incurred in futtherance of the state's policy favoring customer . choice. Rate case expenses associated with Rate Stabilization Plan proceedings all were incurred in furtherance of the state's policy favoring such plans over a flash-cut to market rates. Line extension regulatory assets all are consistent with §§4928.15 (A) and 442835 (C), Ohio Rev. Code, as applied by the Commission to address cost recovery of line extension facilities. The regulatoryassets related to integrating the former Monongahela Power Company service territory into CSP's service territory was strongly encouraged by the Connnission and are consistent with state policy. Lastly, the regulatory assets related to the Ohio Green Power Pricing Program are consistent with state policy set out in SB 221 to eneourage the use of renewable energy resources. These regulatory assets are plainly consistent with state policy. The Commission authorized the creation of these regulatory assets. T'herefore, on rehearing the Commission should authorize the Companies to begin amortizing these regulatory assets in 2011 as proposed in the Companies' ESP, At a nunimum, even if such amortization is not authorized the Commission should accept the June 30, 2008 balances of these regulatory assets as the starting point for additions to these balances. All parties bad a full opportunity to challenge the June 30; 2008 balances and the Commission should not perniit a chance to re-litigate these balances. 11 258 IV. The Commission's Modification of the Companies' Proposed Phase-In Unreasonably Adjusts the Balance Between the Up-Front Revenue Recovery and Subsequent Recovery of Deferrals. Further, the Commission Failed to Clarify That Additional Revenues Authorized From a Distribution Base Rate Case or From the Energy Efficieney and Peak Demand Redaetion Recovery Rider Are Not Ineluded in the Phase-Inll/eferral Straeture. As part of their filed ESP, the Companies proposed to phase-in the impacts of the ESP, including the implementation of the FAC. The Companies proposed to -defer incremental FAC expenses so that for each year of the ESP the rate increase would be limited to approximately fifteen percent. Recovery of charges through the Transmission Cost Recovcry Rider (TCRR) and charges associated with new government mandates were to stand alone and not be included in the proposed limitation. In its Order, the Commission adopted the Companies' phase-in proposal conceptually, but relying on its interpretation of §4928.144, Ohio Rev. Code, it modified the phase-in structure that the Companies had proposed. The Commission substant'sally adjusted the balance between the charges that would be collected during the ESP and the amount of the FAC deferrals that will accumulate during the ESP period. As the Connnission characterized its approach, it was balancing its objectives of limiting eurrent charges with wanting to minimize the deferrals and carrying charges. (Order, p. 23). 'I'he Companies recognize the authority placed in the Conunission by the enactment of §4928.144, Ohio Rev. Code.6 Nonetheless, the Companies believe that the Comnussion's adjustment to the balance between these competing interests was too severe. Keeping in mind that some intervenors expressed their preference for no phase-in because of the deferrals which are a legacy of a phase-in (See OCEA Initial Brief, pp. 87- 6 Ttte Companies believa this authority must be exercised in the total context of Ci apter 4928, Ohio Rev. Code, particutarly in the context of the standard for approval of an ESP without modification. 12 259 89), the Commission should rebalance the authorized increases and the size of the deferrals. The Companies believe that the percentages and associated resulting overall average generation rates set out on page 22 of the Order should be adjusted to reflect at least an annua110 percent increase throughout the ESP period. Even if the Commission does not modify the phase-in it authorized, it still must clarify the intended scope of the increase limitations it has imposed. Because the Commission has put off to a distribution rRte case many of the distribution rate increases the Conipanies proposed as part of their ESP, and has substantially reduced the extent of the overall revenue increase that had been sought by the Companies, the Commission should clarify on rehearing that its phase-itrJdeferrat structure does not include revenue increases associated with a distribution base rate case or the revenues associated with the Energy Efficiency and Peak Demand Reduction Cost Recovery (E.E/1'DR) Rider.7 This "empty" rider has been initiatly set at zero cost recovery. This clarification is needed in order for the Companies and the intervenors to fitlly understand tlre import of the Commission's Order. From the Companies' perspective, it seems obvious that the Commission did not intend to include revenue increases from a distribution base rate ease or the EE/PDR rider in the overall limitation imposed in the phase-in. A contrary position would result in the untenable view that a distribution base rate case would have no effect other than further increasing the overall phase-in related deferrals and carrying charges. The same is_true for tlie costs the Companies will incur related to the EE/PDR rider. Therefore, on rehearing the Commission should clarify that ' As noted elsewhere in this Application for Rehearing the Companies seek rehearing of the Commission's deferral of issues to a distribution rate case and the reduction in revenue increase sought by the Companies. By asking for this peint of clarification the Companies are not abaudoning their arguments conceming those other issues. 13 260 revenues from these sources do not coimt as part of phase-in limitation imposed by the Commission. If the Commission intended to include revenue increases from distribution base rate cases or from the EE/PDR rider in the phase-in limitation then the Companies request that the Commission modify that position on rehearing. Such a position would unreasonably result in nothing more tlian increased deferrals and carrying charges. Further, it would preclude the Comparues from recovering the distribution-related revenues to which they are entitled. Such a preclusion would have the effect of limiting distribution revetiue recovery because of generation-related Standard Service Offer rates, thereby violating the policy guidelines set forth in §4928.02 (H), Ohio Rev. Code. Therefore, the Commission should rule on rehearing that revenue increases resulting from a distribution base rate case or from the EE/PDR rider will not count toward the phase-in limits set by the Commission. V. The Commission's Rejection of the Companies' Proposed Automatic Annual Increases to the Non-FAC Portion of the Generation Rates is ITnlawfal and Unreasonable. As part of their ESP, the Companies proposed to increase their non-FAC generation rates annually by 3 percent (for CSP) and by 7 percent (for OP). These automatic increases were intended to recover costs during the ESP period associated with environmental investments made during that period, as rvell as cost increases in providing generalion service and unanticipated non-mandated generation°reiated cost increases. The Coinlnission's Staff recognized the value of this aspect of the ESP, but presented a different approach. The Staff suggested that the annual automatic increases should be 14 261 reduced to 1.5 percent (for CSP) and 3.5 percent (for OP). In addition, Staff recommended recovery of a carrying charge on environmental investment made in each year of the ESP. The Stafl''s method for carrying charge recovery was through annual filings after the investments have been made. In its Order, the Commission denied the Companies any automatic annual increases, but did adopt the Staffs proposal regarding recovery of carrying charges on new environmental investments. The Convnission's denial of any automatic annual increases was based on its balancing "the economic conditions.... against the Companies' provision of electric service under an ESP." (Order, p. 30). On rehearing, the Commission should modify this ruling and adopt the annual autolnatic increases. SB 221 specifically provides for such incrcases during the term of an ESP 8 In addition, the Comntission's consideration of "economic conditions" as a reason for denying this aspect of the Companies' proposed ESP incorrectly suggests that the current econoniic conditions are not adversely affecting the Companies and their ability to operate and maintain their generation facilities. The ESP concept which sets the Standard Service Offer for a period of time - in this case three years - must have a sufficient degree of flexibility built into it in recognition of the Companies' limited opportunities to respond to generation cost increases. That flexibility must be broader in scope than addressing only new environmental investments. The Companies recognize that the Commission has to some extent addressed part of the Companies' support for their proposed automatic percentage increases to the non-FAC portiorr of generatioir rates. Therefore, the Companies ask that on rehearing the Commission authorize the a §4928.143 (B) (2) (e), Ohio Rev. Code. 15 262 automatic annual 3 and 7 percent increases, offset by whatever revenue increase is granted in relation to the recovery of carrying costs related to new enviroamental investtnent. There is an issue also regarding the authority the Commission granted for the Companies to recover carrying costs related to envirolunental investments made during the ESP period. The Staff's approach, which apparently the Conunission adopted, would have the Companies request recovery of the canying cost after the investments have been made. This requirement to wait until after the investments have been made may not present a problem for 2009 and 2010 investments 9 The investments made in 2011, however, will require a request to be made late in 2011 or early in 2012. In either case, since this ESP period ends at the end of 2011 it is not clear that the Companies will- be able to recover the carrying costs associated with 2011 new environmental investment. To avoid this procedural problem, the Commission on rehearing should permit the Companies to recover carrying costs based on projected new envirottrnental investment in each year. This would enable the Companies to recover on a current basis the carrying costs based on such projections. In 2010 the Companies can true-up iheir 2009 carrying cost recovery to what it would have been if actual environmental investments had been known in advance. The recovery for 2010 can be trued-up in 2011 and the recovery for 2011 can be trued-up in 2012 with a one-time credit or surcharge. Because this process will result in more timely and accurate recovery of carrying costs associated with 9 There will, however, be a delay in commencement ofthe carrying cost recovery since the Conipenies' filing wiil be made after the investment is made and some time for regulatory processing will be needed 16 263 generation-related cnvironmental investments it should be adopted by the Commission on reheatring. VI. It is Unreasonable and Against the Manifest Weight of the Evidence for the Commission to Conclude That the Load of the Former MonPower 5ervice Territory Should Not be Eacluded From the Companies' Baseline Used for Compliance With §§4928.64 and 4928.66, Ohio Rev. Code. The Order conchides that the load of the fonner MonPower service territory should not be excluded from the Companies' baselines for calculating benchmark conipliance under §§4928.64 and 4928.66, Ohio Rev. Code. (Order, p. 43). The Commission's reasoning was twofold: (1) the MonPower load was not a load that CSP sen,ed and would have lost, but for some action by CSP, and (2) not all economic development should automatically result in an exclusion from the baseline. (Id.) Both of these reasons are erroneous and the Commission should modify its findings on rehearing to allow exclusion from the Companies' baselines of theload from the former MonPower service territory. The approach of adjusting the baseline for economic development load growth is consistent with §4928.64(B), Ohio Rev. Code, for alternative energy resources and §4928.66(A) (2) (a), Ohio Rev. Code, with respect to energy efficiency and peak demand reduction programs. The Order ciTed by not addressing the Companies' demonstration that the record in Case No. 05-765-BL-UIVC reflects the Commission's concerns for MonPower's customers if they were not served under an RSP. Staff witness Scheck acknowledged that MonPower customers were facing electricity prices dircetly based on wholesale market prices that far exceeded the level of retail prices being offered by 17 264 MonPower. ("i'r. VIII, pp. 201-202). This prospect of a dramatic rate increase was viewed as a major threat to the economic health and development of the area. As quoted in Mr. Baker's tastimony in this case, Staff witness Cahaan had testified in Case No. 05-765-EL-UNC that there were important "economic developiuent" issues involved in that docket. (Companies' Ex. 2A, p. 48). The Staff in its post-hearing brief in that case also stated that if CSP did not absorb MonPower's service tetTitory, prices would leap to a level that "almost certainly will drive out major employers frorn a region whicli already has very few. This is a crushing blow to a region which has weathered many, too many, in recent years." (Id. at 49). Ultimately, the Comniission concluded in Case No. 05-765-EL-UNC that with the service territory transfer "economic benefits will inure to all citizens and businesses in both regions by helping to sustain economic development in southeastern Ohio." (Case No. 05-765-EL- UNC, Opinion aud Order at 11, emphasis added). It is unfair for the Commission to now conclude in the current case that acquisition of the load in the former MonPower service territory is not economic development in the true sense. Separate and apart from the state of facts as reflected in the record in Case No. 05-765, it is not reasonable for the Commission to presently take a narrow technical view of economic development and reject exclusion of the MonPower load because it was "not a load that CSP served and would have lost, but for some action by CSP." As the Comniission is aware, econo.mic development rates are typically offered to attract or retain load and to create/retain jobs and promote favorable economic conditians far businesses in the State of Ohio. Thus, although the load may not have been subject to being entirely "lost" to the State of Ohio or even to CSP, the former MonPower 18 265 customers would have effectively gone to market (at that time yielding much higher prices) and would have been lost as SSO-regulated load. As was recognized at the time of facing that threat, the entire issue was a significant challenge that would have otherwise yielded a substantial adverse impact on economic development within the former MonPower territory. The underlying policy for permitting exclusions from the baselines should be to remove the disincentive to the utility for encouraging econonuc development that would otherwise manifest in higher benchmark mandates for development of alternative energy, etficiency and demand response. This policy applies equally to the situation where economia development load is taken over by a"white knight" electric utility such as the situation with MonPower as it does to the situation where the load is retained by the same eleetric utility. The Commission's conclusion that not all economic development load should be excluded is arbitrary and contrary to and undermines the policy and intent of §§4928.64 and 4928.66; Ohio Rev. Code. The Commission also erred by not addressing the Companies' alternative position that if the Conunission were to somehow detenaine that CSP's acquisition of the load of thc formcr MonPower service territory was not economic dcvelopment, EE/PDR baselines can also be adjusted to ensure that the compliance measurement is not timduly influenced by other factors beyond the utility's control. See Companies' Initial Brief at 103 (discussing §4928.66(A) (2) (c), Ohio Rev. Code). Thus, the Conunission on rehearing could altematively adopt the Companies' proposed baseline adjustnients based on the fact that CSP's acquisition of the MonPower-related load was beyond its control 19 266 and that situation should not unduly influence compliance with the benchmarks. Either way, the Conimission should modify its conclusion on rehearing. V:iI. It is Unreasonable and Unlavvful for the Commission to Set Aside §4928.66, Ohio Rev. Code, and Determine That tlte Companies' Interruptible Load Should Not be Counted in the Companies' Determination of its EE/PDR Compliance "unless and untiE the load is actually interrupted:" (Order, p. 46). The Commission agreed with the Staff that interruptible Ioad should not be counted in the Companies' detennination of EEfPDR compliance mquirements unless and until the load is actually interrapted. (Order, p. 46). The ability to interrupt is a significant demand reduction resource of the Companies. Not counting interruptible capacity could significantly increase the cost to the Companies (and their customers) of achieving compliance with the statutory mandates for peak demand reduction. Further, because interruption of service has a real impact on customer operations, the Companies do not wish to be required to unnecessarily interrupt service if there is no system or market need to do so. (Companies' Ex. 1, p. 5). The Qrder would require AEP Ohio to unnecessarily interrupt industrial customers at a time when fragile economic conditions exist and would directly curtail the econoinie output of those customers at a time when it is needed most. In addition, a customer's right to buy through and keep business operatioiis running (to the extent they are fortunate enough to have the need to do so) would be adversely affected by the approach taken in the Order. The Order is urilawfitl and unreasonable in this regard because it fails to address or distinguish ABP Ohio's detailed statutotyarguments. 20 267 A plain reading of the law supports the Companics' position. In contrast to the requirement in §4928.66(A)(1)(a), Ohio Rev. Code, for an EDU to implement progranns that "achieve" specified levels of cnergy savings, §4928.66(A)(1)(b), Ohio Rev. Code, requires an EDU to implement programs "designed to achieve" specified peak demand reductions. The General Assembly used two distinct and different phrases to convey that a distinct and different standard applies for peak demand reductions than for energy effi.ciency achievements. Requiring that peak demand programs be "designed to achieve" the stated benchmarks is quite different than requiring that energy efficiency programs "achieve energy savings" at the stated benehmarks. When asked during his cross examination to describe the difference between progranis that achieve energy efficiency and programs designed to acbieve peak demand reductions, Stafl' witness Scheck stated as follows: "Well, one would presume that achieved means you actually did it. Designed means you designed something to do it, but maybe yon didn't [do it]" (Tr. VIII, p. 208). Mr. Scheck's plain interpretation of the language is appropriate and straightforward. Yet, his recommendation against counting interruptible capabilities does not seem to recognize or incorporate this critical difference. Because this posture was adopted by the Conunission, the Order suffers from the same flaw. The General Assembly's deliberate and unequivocal distinotion between the requirement to "achieve" versus being "designed to achieve" recognizes important differences between the nature of energy efficiency programs and the nature of peak demand reduction programs. Energy efficiency programs are ongoing efforts that produce energy savings during any given period of tinie; unused energy savings capabilities do 21 268 not achieve energy reductions during the time period being measured and the opportunity to do so is lost after the time period elapses. The policy or social underpinnings for energy etficiency - such as depletion of fossil fuel resources or reducing environmental impacts associated with fossil fuel - are not directly advanced when measured energy reductions do not occur over a particular period of tinie. By contrast, peak demand reduction programs create a capability to reduce peak demand that c reduction capabilities are still "designed to achieve" the same level of peak reduction and reinain available for future use when needed. If a peak demand reduction resource or capability is not needed for operational reasons or because weather is mild and a critical peak will not be reached, or there is surplus energy in the market, that peak demand reduction capability is fully reserved for firture use without depletion or diminishing its value as a resource. The policy and social undeipinnings for peak dentand reduction - avoiding the need to build additional power plants to meet increasing load - continue to be fulfilled even where the peak demand resources are not immediately needed and those resources are held without diminution for future use. These logical and policy distinctions dovetail neatly with the "achieve" versus "designed to achieve" language used by the General Assembly. Excluding interruptible load for purposes of long-term resciutce planning is reasonable and appropriate. The Commiss'ion's decisiozi also fails to acknowledge or address the argument rnade by AEP Ohio that in tihe context of integrated resouree planning, interruptible capability can count as capacity and avoid the need to plan for and deploy new power plants. (Tr. VIII, pp. 209-210). Similarly, in the Commission's just- 22 269 adopted 1RP rules, native load is defined as intemal load minus interruptible load. See Rule 4901:5-5-01(R) (Case No. 08-88$-EIrORi3 April 15, 2009 Opinion and Order). It follows that a titility's interruptible capability should be counted tnward compliance with the peak demand reduction mandates. The Commission's rejection of this position wiil cause unnecessary intemlptions and will unnecessarity increase AF.P Ohio's cost of compliance with the peak demand reduction mandates. This one-two punch will 'uierease customers' bills and needlessly interrupt industrial customers' output during a fragile economy. Because the Commission's Order also contravenes the controlling statute, the Commission should reconsider and declare that interruptible capability is appropriately "designed to achieve" peak deniand reductions when needed and counts toward compliance under §4928.66, Ohio Rev. Code. VIII. It is Unreasonable and Against the Manifest Weight of the Record for the Commission to Defer a Decision on Retail Participation in the PJM demand Response Programs. AEP Ohio respectfully disagrees with the Order's conclusion that the Commission does not have sufficient infornsation to decide the issue of retail participation in P]M demand response programs, given the exhaustive treatment of these issues by the parties in merit briefing (both in the context of the 1J1I09 briefs and the full merits briefs), in motions and inemorandum in support and in opposition, multiple sets of written testimony and substantial cross examination during the 1'ieza-ing. The thorough lit'agatio'-t of this issue is evidenced by the Order's substantial recitation of the arguments and issues relating to AEP Ohio's proposal to restrict retail participation in the wholesale PJ1vI 23 demand response programs. (Order, pp. 53-58). The merits of AEP Ohio's position (as- well as that of all the parties) have-been fully developed during briefmg and motions in this case and will not be revisited again in this application for rehearing. If resolution of the issue did not have urgency, then deferring it into an unspecified docket witli an undetermined schedule for resolution might not cause a problem, other than the inefliciency associated with the parties repeating the activities of tliis case. With respect to this issue, however, the maxim that "justice delayed is justice denied" applies with full force. Not only will the current registrants be able to participate through the middle of 2010 under the status quo (halfway through the ESP term), but additional customers now even have the opportunity to register. That is because the FERC recently re-opened registration for participation in the demand response programs for the 2009-2010 PJM planning year until May 1, 2009 and partics that have not already registered may be able to successfully register. PJMlnterconnection, 126 FERC ¶61,275 (March 26, 2009 Order), 189. But the fact that the registration process is reopened also appears to present an opportunity for the Comniission to resolve this issue without any negative repercussions on prospective registrants. That is because the extended registration deadline re-opens the entire registration process and, just as new parties can be added through registration, current registrants can be eliminated or vrithdrawn without prejudice through a timely decision from the Comtnission to restrict retail parkicipation. AEP Ohio urges the Commission to reconsider its decision to defer this issue. AEP Ohio's proposed ESP, including the proposed restriction on retail pae'cieipaiion iri the wholesale demand response programs, was timely submitted in July of 2008 and deserves to be resolved one way or another. Rather than deferring a decision and 24 271 defaulting to full participation in the P7M whotesale programs for the 2009/2010 planning year (i.e., through the entire first half of the ESP term), the Commission should default to no participation if it is going to defer its ultimate decision on tlris issue. The Indiana Conunission recently granted a request by AEP to continue the Commission's default prohibition against retail participation in the PJM demand response programs ( while it further considers a more permanent resolution to the issue otherwise only entertaining individual customer requests to participate ou case-by-case basis). In the Matter of lhe Cominission's Investigation Into Any And All Matters Related to Canznzission Approval of Participation By Indiana End-Use Customers in Demand Cause No. Response Programs Offered by the Midwest LSO and P,TM Interconnection, 43566 (February 25, 2009 Order).1° Using such an approach would better preserve SB 221's statutory plan for utilization of in-state demand resources and enable AEP Ohio's own retail demand response programs to be refined to meet the aggressive mandates for peak demand reductions. Delaying a decision on the issue will inject substantial uncertainty into AEP Ohio's plan for compliance with the peak demand reduction mandates of SB 221 and will impose unnecessary additional costs on AEP Ohio's ratepayers in two related but distinot ways: (1) it will cause AEP Ohio's comptiance costs to increase significantly due to the exportation of Ohio's demand response resources through retai3 participation in the PJM programs that cutrently benefit the East Coast, and (2) it w?ll cause additional long-ternt capacity costs on other non-participating customers due to AEP Ohio's obligation to coritinue providing firni service even though the participating customers are using their '° The IURC Order can be found on the Internet at the foltowing address: https://rnyweb.in. gov/i UftCleds/ModuiesfEcros/Cases/Docketed_CaseslViewDocumentaspx?DocIf3-09o0 b63180103fi11 25 272 load in a manner that is akin to intertuptible service. As Companies' witness Roush testified, AEP Ohio would like to emulate the PJM demand response programs at the retail level, to the extent possible. (Companies' Ex. 1, p_ 7; Companies' Initial Brief, p. 117). Indeed, if the Commission were to adopt the retail restriction on rehearing and prevent the exportation of Ohio's valuable demand resources, it could order the Companies to modify their demand response programs to emulate, to, the maximum extent possible, the customer benefits achieved under the PJM demand response programs. Indeed, this outcome seems to line up squarely with the letter and spirit of the concurring opinion filed in this case by Chairman Schriber and Convnissioner Centolella. The concurring opinion states that it is essential that consumers benefit from demand response in terms of a reduction in the capacity for which AEP Ohio customers are responsible and it encourages AEP Ohio to work with stakeholders to ensure that predictable coiisumer demand response is recognized as a reduction in capacity that it must carry under PJM market rules. When these goals are coupled with AEP Ohio's existing obligation for achievhrg compliance under SB 221's aggressive peak denrand reduction mandates, the best solution for the Companies and their customers is to develop better retail programs and make them available to customers (to the exclusion of the wholesale programs). The Conunission should modify its decision in this regard on rehearing. 26 273 IX. It is Unreasonable and Unlawful for the Commission to Set Aside §4928.143(B) (2) (b), Ohio Rev. Code, and Determine That the Companies' Distribution Proposals Must be Examined Through a Distribution Rate Case Where All Components of Distribution Rates arc Subject to Review and the Order's Modification in this Regard Should be Clarified. Although the Companies are providing adequate and reliable electric service, they understand that customers' service reliability expectations are increasing and therefore proposed an Enhanced Service Reiiability Plan (ESRP) in order to maintain and enhance reliability. While the components of the ESRP are adjustable as circumstanees warrant, the components together represent a detailed set of plans and programs designed to target the most effective use of limited resources. Under the proposed ESRP, ABP Ohio merely sought incremental funding to support an incremental level of reliability activities designed to rnaintain and enhance service reliability levels. In the Order, the Commission recognized that SB 221 perntits single issue ratemaking for distribution infrastructure and modernization initiatives but proceeded to fmd that the legislative "intent could not have been to provide a`blank check' to electric utilities." Order at 32. The Order went on to set aside the statute and instead conclude that "the only way to examine the fall distribution system, the reliability of such system, and tha customer's expectations, as well as whether the programs proposed by AEP Ohio are `enhanced' initiatives (truly incremental), is through a distribution rate case where all components of distribution rates are subject to review." Order at 32 (emphasis added). The Conunission's conclusion that a distribution rate case is "the only way" to cvaluate AEP Ohio's ESRP unavoidably conflicts with the express provision within SB 221 permitting single-issue ratemaking proposals for distribution infrastructure and 27 274 modemization initiatives within ESP proposals and outside the context of a full exaniination of the distribution system: §4928.143(B)(2)(h), Ohio Rev. Code. As a related matter, while the Commission properly concluded that the proposed vegetation management program is incremental in nature and is sufficiently tied to reliability impacts and aligned with customer expectations so as to warrant adoption, the Order erred in failing to reach similar conclusions based on the record for the remaining ESRP programs. In short, the Order's key conclusion regarding the ESRP contravenes the governing statute and the Commission otherwise failed to acknowledge the manifest weight of the record regarding the ESRP programs other than vegetation management. As a legal matter, imposing a requirement to conduct a distribution rate case prior to cost recovery has the effect of bypassing the General Assembly's provision for single- issue rate tnaking in the context of an ESP. The General Assembly knew that electric utilities had not all conducted recent distribution base rate cases when it passed S.B. 221. The General Assembly knew when it allowed single-issue rate making that a clear and comprehensive view of a utility's finances or distribution system would not be conducted as it otherwise would be in the context of a base rate case. Since all of these limitations are inherently present when engaging in single-issue ratemaking, pointing out these same limits cannot form an appropriate basis for rejecting a distribution proposal in the context of an ESP. Section 4928.143(B)(2)(h), Ohio Rev. Code, was enacted as a key part of the legislative package contained within SB 221 to enable an EDU to propose a long-terrn energy delivery infrastructure modernization plan such as the ESRP and to encourage electric utilities to file ESPs instead of Iv1KOs. There can be no question that single-issue ratemaking is permitted iviihin an ESP case and pursuant to the statutory 'deadlines 28 275 imposed by the C,eneral Assembly for an ESP case. The Companies are only seeking recovery of transparent ineremental costs for incremental reliability activities - something that is clearly permitted under §4928.143(B) (2) (h), Ohio Rev. Code. On a qualitative basis, AEP Ohio's ESRP proposal cannot accurately be considered a "blank check." Each of the pro6qams was described in detail by Companies' witness Boyd and the Company agreed to be accountable for incremental spending to fund the programs, if cost recovery was apptoved. (Companies' Ex. 11, p. 37, Chart 10; Tr. V, pp. 253-254). The total incremental cost of the ESRP was estimated to be $282.6 million in capital and $163 million in O&M over the three-year term of the ESP. (Id.) Each program had specific cost projections that were explained in great detail in testimony, in written discovery and during cross examination. Further, AEP Ohio indicatcd its aeceptance of a rider for the ESRP (instead of a flat percentage increase designed to collect the projected cost as was origirtally proposed) and clearly stated its understanding that only prudently incurred costs would be recovered through the rider and agreed that it would be accountable for the fimds transparently eollected through rates reconciled with the incremental amounts spent. (ABP Ohio Reply Brief at 62-63). Regarding an assu.rance for reliability impacts of the ESRP, Companies' witness Boyd also indicated that the Companies are willing to work with Staff to determine target reliability benefits based an implementation of the ESRP. (Tr. V, pp. 252-253). Another indication that the Companies were not simply asking for 'a "blank check" is evidenced by their proposals for Ahernative reed Service (AFS) and Adet Energy Metering Service (NF..MS).17 The AFS proposal was designed for customers who " AEP Ohio is not seeking rehearing ort the Order's AFS and NEMS rulings but is merely using those aspects of the proposed ESP as an example in this context. 29 276 desire a higher level of reliability and wish to subscribe to a premium service to meet their particular needs. Similarly, the NEMS proposal (including a specific NEMS-H version specifically designed for hospitals) was developed in order to cooperatively help eustomers with generation capabilities manage their energy costs. In ma:king the AFS and NEMS proposals, the Coinpanies sought to provide bilateral benefits to customers and enhance reliability - not to unilaterally cash in on a blank check. In short, as a well- developed and detailed proposal thai required substantial accountability and dollar-for- dollar reconciliation with prudently incurred expenditures, AEP Ohio's ESI2P is the opposite of a "blank check" and that charaeteriaation was an erroneous basis for rejecting the balance of the ESRP. T7ie Commission should have evaluated each of the ESRP programs based on the record and issued specific findings about each program based on the same criteria used to evaluate the vegetation initiative (incremental reliability impacts and alignment with customer expectations). The Order rendered a meaningful evaluation only for the vegetation management initiative and merely glossed over the non-vegetation ESRP prograins. The Commission should have reached specific findings with respect to each of the F,SRP programs - not just the vegetation managenient program that it was approving. If it had performed a broader evaluation of the ESRP, the manifest weight of the record would have compelled similar fmdings for AEP Oltf o's other ESRP programs. For example, the Commission cited Companies' witness Boyd's testimony as record support for concluding that increased spending eannarked for specific vegetaiiou management initiatives can reduce tree-caused outages, resulting in better reliability. Order at 33. But the same testimony also supports making such findings for the other 30 277 ESRP programs. Besides vegetation management, the ESRP also included the following strategically designed components: • Enhanced overhead line inspection approach, targeting specific asset modernizationlreplacements and reliability enhancements; • Targeted distribution automation; and • Targeted underground residential distribution cable replacement and rejuvenation. (Companies' Ex. 11, p. 17). The ESRP programs were designed to work in concert to effectively address the leading outage causes (botli motnentary and sustained) to significantty enhance the overall "customer exper•ience." The manifest weight of the record demonstrated that each of the ESRP programs - not just the vegetation tnanagement initiative - would contribute substantial reliability impacts if implemented. In particular, Companies' witness Boyd, thmugh his testimony, specifically established that positive reliability impacts are expected if the ESRP programs are undertaken and he presented a solid enhanced reliability plan for the Commission to consider as part of the entire ESP package.t2 (See e.g. Companies' Ex. 1I; pp. 24, 25, Chart 4 and p. 30, Chart 6). Other record evidence also supports the positive reliability impacts expected for the ESRP. (See e.g., Tr. V, pp. 228; Staff Ex. 2, p. I l citing the response to Staff data request 4-2(b); OCC Ex. 9A, Response to Staff Data Request 3- 83). Further, during cross examination, OCC's owm witness (Mr. Cleaver) testified that he expected the ESRP programs would positively affect the Companies' reliability. ("I'r. VII, pp. 63-64). 12 0f course, evettts beyond the Companies' controt could have an adverse impact on reliability index perforniance even though the ESRP would have othettivise resulted in positive reliability impucts. 31 278 One of the primary reasons for the Companies proposing to enhance service reliability levels is that customers are more sensitive to power quality issues today. As demonstrated by AEP Ohio in its testimony, this has come about due to the proliferation of electronically-controlled devices heavily relied upon by customers within the home and workplace and, as a related but distinct matter, the pervasive presence of digital technology. (Companies' Ex, 11, pp. 10-11). The Companies' survcy results show, for the first half of 2008, that one in every four residential respondents (24%) and one in every three cotmnercial respondents (33%) believed their future reliability expectations would increase over the next five years. (Id. at 13). Again, this data is consistent with the trends of more electronically-controlled and digital devices and increasing sensitivity to momentary interniptions. In order to meet these challenges and ensure that the reliability of its distribution system is aligned with customers' expectations, AEP Ohio is proposing to pursue its ESRP. Although the Commission recogtnized this impact associated with the vegetation management initiative, the other ESRP programs were also designed to address the same reliability impacts and align with the same customer expectations. With respect to cost recovery, the Commissian also held (page 34) that the ES12P rider will not include costs for any of AEP Ohio's other enhanced service reliability programs (i.e., non-vegetation management programs) "until such time as the Commission has reviewed the programs, and associated costs, in conjunction with the current distribution systein in the context of a distribution rate case as explained above." It is not clear, but this aspect of the Order appears to presume (or to potentially even require) that AEP Ohio would retain the ESRP to broadly track reliability-related 32 279 programs and costs - even after conducting a distribution base rate case and possibly beyond the ESP term. To the extent that this conclusion would require the Companies to track costs for all reliability programs once a distribution rate case is filed or beyond the term of the ESP, the Conunission erred in imposing this requirement and should eliminate any such requirement on rehearing. Imposing such a requirement would only exacerbate the Commission's rejection of the ESRP programs that were properly proposed in this ESP case under the single-issue ratemaking provisions of SB 221. It is one thing to provide that the ESRP rider presently being established in this case rnay be used by AFP Ohio in recovering other incremental or enhanced reliability programs that AEP Ohio may propose as part of a future distribution base rate case; it is another matter entirely to require that any reliability programs proposed or adopted by AEP Ohio as part of a fature distribution case be funded alid tracked through the current ESRP rider. It would be unfair and "the worst of both worlds" to deny the Companies the opportunity to establish a fully-funded ESRP in this case, while at the same time imposing an obligation to utilize the ESRP in the context of a future traditional distribution rate case to track costs relating to futute reliability initiatives. If the Cornnussion is convinced that a distribution rate case is the inore appropriate vehicle than the single-issue raternaking provision in SB 221 for adopting the other ESRP reliability programs, it should not simultaneously proceed to force the use of an empty rider (other than for the vegetation program) created in an ESP for purposes of a future traditional base rate oase. The distribudon rate case will capture a retrreseiiiutive level of distribution reliability expenditures as reflected in the test period. Consequently, the Coinmission should clarify on rehearing that AEP Ohio retains the option to dissolve 33 280 the ESRP (or limit it to the ongoing vegetation management initiative being approved in this case) when filing a distribution rate case. Finally with respect to the vegetation management initiative component of the ESRP tliat was approved, there appears to be a potential mismat,ch between the vegetation initiative evaluated and approved and the related costs included in the ESRP rider. The Comniission evaluated "the proposed vegetation initiative" in discussing the incremental nature of the program and costs (Order, p. 33); considered "the Companies' proposal" in concluding that it more closely aligns the customers' expectations with the Companies' expectations (Order; pp. 33-34); and provided that the rider "will include only the incremental costs associated with the Companies' proposed enhanced vegetation iilitiative." (Order, p. 34) Yet, the Comniission found that the "enhanced vegetation initiative proposed by the Companies, with Staff's additional recommendations, is a reasonable program that will advance the state policy." (Id.) Presuming that this reference is to Staff witness Roberts' reconmmndations as discussed on page 33 of the Order, this could have a significant impact on tlie projected costs of the modified vegetation initiative. For example, the recomrnesidation to achieve greater clearance of all overhang above single- pliase lines would be very costly with limited overall reliability benefit; and the cost to remove the overhang above single phase lines was not included in the plan. Rather than categorically grafting these additional Staff reconmiendations onto the Companies' vegetation initiative without a record basis for fne implementation and cost ira.pacts of such a hybrid program, the Commission should indicate that AEP Ohio and the Staff can work together to modify the vegetation initiative within the cost level established in the 34 281 rider that is based on the Companies' proposal. Alternatively, the Commission should acknowledge that it understands the actual/reeonciled costs of the modified program (i. e., including the StafPs recommendations including greater clearance of overhang above single-phase lines) will be significantly higher than were estimated for the Companies' original proposal. X. The Order is Unlawful and Unreasonable to the Extent That it Intended to Allow Only Hitlf of the Required Funding When Approving the gridSIVIART Rider and the Order's Modification in this Regard Should be Clarified. 'I'he Companies appreciate that the Commission "strongly supports" AEP Ohio's gridSMART Phase I proposal to implement Advanced Metering Infrastructure (AMI), Distribution Autamation (DA) and Home Area Network (HAN) technology. (Order, p. 37). In establishing the initial rider, however, the Coinmission noted that "recent federal legislation makes matching finlds available to smart grid projects." (Order, p. 38). As a result, the Cointnission directed CSP "to make the necessary filing for federal monies under the American Recovery and Reinvestment Act of 2009 (ARRA) for the balance of the projected costs of gridSMART Phase I." (Order at 38), The Conunissiori established the initial gridSMAItT rider at "half of the Companies' requested arnount"13 (Id.) To the extent that the Commission merely set the initial rider amount at half the required investment under the rebuttable presumption that AEP Ohio could pursue and obtain full matching funds for the gridSMART Phase I project, AEP Ohio can ass'ure the 13 The Order references $109 million over the term ofthe ESP as being tho Companies' requested amount and, thus, the Commission indicated its inteart to set the initial rider at half that amount or $54.5 tnitlion. (Urder, p. 3&). flt reality, the Companies had developed an incremental revenue requirement for gridSMART Phase I of approximately $64 million during the ESP term. (Companies Ex. t, DMR-4). Thus, in submitting its compliance tariffs after issuance of the Order, the Companies inaluded an initial rider rate designed to recover approximately $32 million or half of the gridSMART Phase I incremental revenue requirement. 35 282 Commission that it is pursuing available federal funding with diligence. In other words, if the Commission clarifies that it intends to fully fund the project through rates in the event federal funding is ultunately not made available despite the Companies' best efforts, AEP Ohio would not be presented with an "unfunded" mandate situation. On the other hand, if the Commission only intends to allow rate recovery of half the required investment using a conclusive presmnp6on that federal funds will be made available, that would constitute a significant error. The Commission lacks the authority in this case to order enhancemetit programs without recovery by the Companies. The Supreme Court of Ohio found in Forest Hills Utility Cn_ v, Pub. Util. Camm. (1972), 31 Ohio St. 2d 46, 57; 285 N.E.2rl 702,709, that the Commission must provide recovery for improvements it orders utilities to institute. Specifically the Court stated, Public Utilities Cotmnission possesses the power to require a utility to render adequate service, but it lacks the authority to require that certain installations and irnprovements be made before the utility may claim and receive a just and reasonable rate for the services actually being rendered with its existing property and facilities. Id. Any Commission order td proceed with gridSMART Phase I without commensurate rate relief is in direct contradiction to the Forest Hills doctrine and will be subject to reversal by the Supreme Court of Ohio. Morcover, the Conunission's discussion of the ARRA and the availability of federal funding makes assumptions that extended beyond the record in this proceeding. There was no discussion in the Order or the record of the details conceming the actual availability of federal funding or the likelihood (or even possibility) of AEP Ohio obtaining doll ar-for-dollar matching funds for its gridSMART Phase I project. The details of federal funding for smart grid projects are not yet fully developed. Indeed, on 36 283 April 16, 2009, the U.S. Department of Energy released a "Notice of Intent to Issue a Funding Opportunity Announcement for the Smart Grid Investment Grant Program:"14 The Nt}I states that "DOE will provide fimding covering un ta 50% of qualified at "DOE anticipates providing funds in the range of $500,000 to investments" and tl► $20,000,000 for smart grid technology deployment grants." To the extent that DOE implements a cap of $20 million per project and/or funds projects at less than 50%, those factors would be beyond the control of AEP Ohio. (NOI, p. 2) Hence, there are nunierous material uncertainties for obtaining full federal matching funds and it would be unreasonable and unlawful for the Comnussion to establish a conclusive presumption that federat matching funds will be made available for every dollar funded by AEP Ohio and its customers. ln addition, the uncertainties of obtaining federal funding also create logistical challenges of timing and scoping the project (i.e., will the Companies need to delay implementation until federal funding is granted and distributed?) Accordingly, the Cotnmission should clarify that it intends to allow full recovery in the gridSMART rider of all prudently incurred expenditures in deploying gridSIviART Phase I that are not othenvise offset by federal funds made available for the project. X[, The Commission's Authorization For the Fuel Adjustment Clause For Only Three Years is Unreasonably Restrictive. At page 14 of the Order, the Comtnission states, "[g]iven that the [Fuel Adjustment Clause] mechauism is authorized pursuant to the ESP provision of SB 22 1, we will limit our authorization, at this time, to the term of the ESP." It would be unreasonable for the FAC, once authorized, simply to expire without providing for either `^ The NOf can be found at the following Intemet address: https://www.tbo.gov/index?&s=opportunityd`cmoda --^form&id=ebe206ba070c516398e5f58aladD979f&tab° core&tabinode=list. 37 284 its renewat or replacement by a suitable substitute. This is particularly true since a fuel adjustnlcnt clause would be rcquirec3 in an MRO (§4928.142(D), 4hio Rev. Code), another ESP (§4928.143(B)(2)(a), Ohio Rev. Code) and even in the context of a withdrawn ESP application (§4928.143(C)(2)(b), Ohio Rev. Code). Aceordingly, the Companies respectfully request that, on rehearing, the Commission futd that the FAC meehanism will remain in effect for the term of the ESP and until specifically ordered otherwise by the Commission. XII. The Commission's Modification of the Companies' Proposed Fuel Adjustment Clause Baseline in the Pre-Electric Security Plan Standard Service Offer Rates is Unreasonable. At pages 18-19 of the Order, the Commission addressed what the appropriate FAC basetiue component of the current SSO rate should be. The Companies had proposed to establish their baseline FAC rates by identifying the FAC components of their current SSOs. The Companies began with the electric fuel component (EFC) rates in effect as of October 1999 that were unbundled as part of the Electric Transition Plan (ETP) proceedings; added additional rate elements correspond'uig to 1999 amounts for additional categories of costs that are included in their proposed FAC mechanism; and then adjusted ihe 1999 rate levels for the EFC rates and the additional rate elements for subsequent rate changes, in order to identify the portion of the current 2008 SSO rate that is the FAC baseline rate. The Staff had recommended that the FAC baseline component should be deternuned based on a ineasure of FAC costs being recovered through the current SSO. Staff recommended using 2007 acwa7 cost data, escalated by 3 percent for CSP and 7 38 285 percent for OPCo, as a reasonable proxy for 2008 actual costs, since there is no, and could not be any, record evidence of calendar year 2008 actual costs. Staff contended that utiliziug actual 2007 costs and updating them to 2008 is appropriate because, in Staffs view, the Companies should be recovering that amount of costs through their existing SSOs. The Staff also believed its proposal was reasonable because it produced a result very close to the result produced by the Companies' methodology. At page 19 of the Order, the Cornmission agreed with the Staft's value for the appropriate FAC basel'uie. In support of its finding, the Commission stated that "the Companies and Staff proposed methodologies to obtain a proxy for 2008 fuel costs" and that "[w]hile both had a different starting point to the calculation of the 2005 proxy, we agree that in the absence of known actual costs, a praxy is appropriate to establish a baseline." While the two methods that the Companies and the Staff have proposed do produce values for the baseline FAC rate that are close to one another, the methodologies are not the same. Specifically, the Companies have proposed a rnethodology that identifies the portion of the 2008 SSO rate that correlates to the new FAC rate;,they have not proposed a niethodol.ogy that is based on a proxy for 2008 fuel costs: As Companies' witness Nelson explained, using the Companies' approach to deternune the FAC baseline rate avoids the baseline FAC and the non-FAC portions of the 2008 SSO geueration rates floating in response to whatever assumption is made regarding the amount of FAC costs being recovered by those rates. (Companies' Ex. ',B, pp. 2-5). Accordingly, the Companies request that the Commission adopt the Companies' proposed methodology for identifying the baseline FAC components of their 2008 SSOs. 39 286 XItI. In Deferring Judgntent on a Methodology for the Siguificantly Ezcessive Earnings Test (SEET) and Directing its Staff to Convene a Workshop for Developing a Methodology to be Applied to All Electric• Utilities, the Commission Unreasonably Failed to Note the Appropriateness of the Companies' Proposal for Having the SEET Applied to Them on a Combined Basis and That How That Would be Done Would be Considered in the Workshop and That a Common Methodology Dues Not Require a Methodology Identical for Each Electric TTtility. At pages 65-69 of the Order, the Commission discussed the various proposals the parties made regarding the Significantly Excessive Earnings Test (SF.ET) that Secfion 492$.143(F), Ohio Rev. Code, requires the Commission to apply after each year of the ESP. 'I"he Commission stated that determining the appropriate methodology for the SEE'1' is extremely important. The Commission found that a common methodology for the SEET is appropriate, and it directed its Staff to convene a workshop for the purpose of developing sucli a methodology. However, the Comznission recognized that the Companies need clarifieation regarding how the SEET would be applied to them so that they can decide whether to accept or reject the ESP as modified by the Order. Accordingly, the Commission resolved important issues regarding how the SEET would be applied, including the exclusionfrom the SEET of impacts from off-system sales margins and deferred fuel costs. On rehearing, the Companies request that the Commission provide additional clarification regarding the SEET and the scope of proposals that may be addressed by the upcoming workshop. First, the Companies explained that the SEET logically should apply to them on a combined basis because investments in them are raade, and their operatiotis are conducted, on a combined basis. Applying the SEET to the Companies on a combined basis was supported by the Staff as well. Staff's witness Cahaan testified that 40 287 the asymmetric risk associated with the SEET "would also be mitigated if the earnings of both jurisdictional operating companies could be taken into account "(Staff Ex. 10, p. 25). He noted that since "there is a commonality between operating companies in terms of both operations and planning, the application of an eamings test might be able to incorporate this fact into any resultant action in a way as to mitigate asymmetric risk. I woutd view this approach as consistent with the concept of `significantly' as a faimess issue and not merely a. statistical exercise.°" (Id.). Accordingly, the Companies ask that the Commission clarify the appropriateness of treating them on a combined basis for purposes of tlie SEET and that how that would be done is a proper subject to be considered in the workshop process. Second, the Companies ask the Cornrnission to confirm, on rehearing, that the Comm.ission's finding that a common methodology for the SEET is appropriate does not mean that the methodology must be.identical for cach electric utility. In that regard, the Companies pointed 6ut that there are significant differences between the Ohio electric utilities that can have an impact on the appropriate SEET methodology for, and its application to, a particular electric utility. For example, the FirstEnergy electric utilities are distribution-only companies that have divested their generation and transmission assets, wliile the AEP Ohio Companies continue to own their generation and transmission assets. As another example, Duke Ohio and The Dayton Power & Light Company differ from the AEP Ohio Companies because neither of them has an affiliated electric utility in Ohio. Such differences can lead to differences in the appropriate SEET tne'thodology, and its application, to the subject electric utility. 41 288 CONCLUSION For the foregoing reasons, the Commission should grant rehearing or clarification as requested by the Companies. Respectfully submitted, Marvin I. Resnik, Counsel of Record Steven T. Nourse American Electric Power Service Corporation I Riverside Plaza, 29th Floor Colmnbus, Ohio 43215 Telephone: (614) 716-1606 Fax:(6144)716-2950 Email: miresnikPaen.com stnourset^a.aep.com_ Daniel R. Conway Porter Wright Morris & Arthur Huntington Center 41 South High Street Columbus, Ohio 42315 Telephone: (614) 227-2270 Fax: (614) 227-2100 Email: [email protected] Counsel for Columbus Southern Power Company and the Ohio Power Company 42 289 CERTIFTCATE OF SERVICF. I hereby certify that a copy of Columbus Southem Power Company's and Ohio Power Company's Application for Rehearing was served by U.S. Mail and electronic mail upon counsel identified below for all parties of record this 17' day of April, 2009. Marvin I. Resiuk Warner L. Margard Maureen R. Grady John H. Jones Terry L. Etter Thomas G. Lindgren Jacqueline Lake Roberts Assistant Attorneys General Michael E. ldzkowslti Public Utilities Comtnission of Ohio Richard C. Reese 180 East Broad Street Assistant Consumers' Counsel Columbus, Ohio 43215 lfl West Broad Street Columbus, Ohio 43215-3485 David F. Boehm John W. Bentine Michael L. Kurtz Mark S. Yurick Boehm, Kurtz & Lowry Matthew S. White 36 East Seventh Street Chester, Wilcox & Saxbe, LLP Suite 1510 65 East State Street Cincinuati, Ohio 45202 Suite 1000 Colurnbus, Ohio 43215-4213 Samuel C. Randazzo David C. Rinebolt Lisa G. McAlister Colleen L. Mooney Joseph M. Clark nbio Partners for Affordable Energy McNees, Wallace & Nurik, LLC 231 West Lime Street 21 East State Street P.O. Box 1793 170' Ploor Findlay, Ohio 45839-1793 Columbus, Ohio 43215-4228 Barth Royer M. Howard Petricoff Bell & Royer Co., LPA Mike Settineri 33 South Grant Avenue Betsy L. Elder Columbus, Ohio 43215-3927 Stephen M. Howard Vorys, Sater, Seymour & Pease, LLP 52 East Gay Street Columbus, Ohio 43216-1008 43 290 Bobby Singh Grcgory H. Dunn Integrys Energy Christopher L. Miller 300 West Wilson Bridge Road Andre T. Porter Worthington, Ohio 43085 Schottenstein, Zox, Seymour & Pease, LLP 250 West Street Columbus, Ohio 43215 Thomas J. O'Brien Cn'ace C. Wun$ 13ricker & Eckler McDermott, Will & Emery, LLP 100 South Third Street 600 Thuteenth Street, N.W. Columbus, Ohio 43215 Washington, D.C. 20005 Michael R, Smalz Cynthia A. Fonner Joseph E. Maskovyak Constellation Energy Group, htc. Ohio State Legal Services Association 550 West Washington Blvd. 555 Buttles Avenue Suite 3000 Cohunbus, Ohio 43215 Chicago, Illinois 60661 Langdon D. Bell Kevin Schmidt Bell & Royer Co., LPA Ohio Ivlanufachuers' Association 33 South Grant Avenue 33 North High Street Columbus, Ohio 43215-3927 Columbns, Ohio 43215-3005 sbaronCu?jkenn.coni imaskovyak^la oslsa.org ]kollen r^ kenn.com ricksCg7ohanet.arg charlieking@snavely-kin^ . com tobrienn bricker.com mkurtz^bkllawf rm.com dav3d [email protected] [email protected] pynthia a.fonner(a^.constellation.com gradyC^a,occ.state.oh.us mhpetricoff(a}vssp com etter occ.state.oh.u.s smhoward2vssp.com robertsna.occ.state.oh.ns [email protected] idxkowski(&occ.statc.oh.us [email protected] stnourse cr ae .corn [email protected] dconway crporterwright.com kschmidt(@ohioiuf&.com i bentine(alewslaw.com sdebroff('rlsasllj2.com [email protected] Vetersen(a^® s_asilp com m_white(7ewslaw.com 5romeU(&saslln.eom khi aains(&,cnergystrat. com bedward aldenl w.ne barthrover(u^aol.com sbloomfreidQbricker.com gary. a. i efI'riesH)dom. com todonnell bricker.com nmoser theOEC.org r.vinr son ensc heln.conl trent(n^thcOEC.ora n reed(^Sonnenschein-Com 44 291 henryeckhartic aol.com [email protected] nedford a fuse.net erii&onnenschein.com [email protected] tornmy temle(rr?ormet com dsullivan @.nrdcorg agamaga n wrassoc.com [email protected] steven huhman^a,morganstanlcy.com thoma .tindgren @puc.state.oh.us dinancino6@,inwe.com wernet'.margard dpuc.state.oh.us glawrenceCcr7^mwe.com john.j([email protected] wun mwe.com [email protected] gohe,[email protected] lmcalister&rnwncmh.com Igearhardt ofi>€.or^ }clarkg?nwncmh.com cmillerfa7¢szd.cam drnieboltC^a aol.com gdunn(u3szd.com cmoone 2@ oolunmbus.rr.cotn [email protected] msmalzna,oslsa.or 45 292 BEFORE THE PUBLIC UTILTl'IES COMMISSION OF OHIO In the Matter of the Application of Calumbus Southern Power Company for the Approval of Case No: 08-917-EL-SSO its Electric Security Plan; and Amendment to Its Corporate Separation Plan; and the Sale or Transfer of Certain Generation Assets In the Matter of the Application of Ohio Power Company for Approval of its Eleetric Security Case No. 08-918-EI.-SSO Plan and an Amendment to its Corporate Separation Plan COLUMBUS SOUTHERN POWER COMPANY'S AND OHIO POWER COMPANY'S MEMORANDUM CONTRA INTERVENORS' APPLICATIONS FOR REHEARING Marvin I Resnik Counsel of Record, Steven T. Nourse American Electric Power Service Corporation 1 Riverside Plaza, 29`4 Floor Columbus, Ohio 43215 Telephone: (614) 716-1606 Telephone; (614) 716-1608 Fax:(614)716-295Q miresnikften.com [email protected] Daniel R. Conway Porter Wright Morris & Arthur Huntington Center 41 South High Street Columbus, Ohio 42315 'I'el.ephone: (614) 227-2270 Fax: (614) 227-2100 dconway@porterwri ght.com Attorneys for Columbus Southem Power Company and Ohio Power Company Filed: April 27, 2009 Tnia is to certify that tho images appearing are aA accurnts and cospl.sts rnprsduotioa of a case file docunasut dallr4red in the rftu2er oourme of.'^ff.p'spi^^a,,,e., Pechnician Datt lrocesasd _ ±^..F (^Zog 293 TABLE OF CONTENTS INTRODUCTION ...... 1 II. ARGUMEIV'I` ...... 2 The Commission Did Not Violate §4928.20 (7), Ohio Rev. Code ...... 2 Th.e POLR Riders Approved By the Connnission Are Lawful and Reasonable ...... 3 The Commission Explained the Bases For Its Determination of Issues in This Proceeding In a Manner That Satisfies §4903.09, Ohio Rev. Code ...... 8 The Cotnmission's Authorization of Recovery of the Revenue Requirement Associated With Specific Sources of Generation Supply Is Lawful and Reasonable ...... I I The Commission's Comparison of the Modified ESP to the Results That Would ...... 12 Otherwise Apply Under a Market Rate Offer Is Lawful and Reasonable .. The Order's Provision For a lligher 2009 Revenue Entittement is Not Retroactive Ratemaking and is Lawful and Reasonable ...... 14 The Order's Adoption of CSP's gridSMART Phase I Initiative is Lawful and ...... 25 Reasonable ...... The Order's Approval of the Enhanced Vegetation Managcment Initiative, Through Adoption of the Enhanced Service Reliability Plan (ESRP) Rider, is Lawful and ...... 30 Reasonable ... The Order's Adoption of the Economic Development Ridcr is Reasonable and Lawful and OCC's Rehearing Requests Should be Denied...... 36 Fuel Adjustment Clause (FAC) Mechanism ...... 38 a. The Baseline FAC Component Of The Current SSO Rate Cannot, and Should Not, Be Based On A Measure Of Actual 2008 Costs ...... 38 b. The Commission Properly Rejected Arguments That Off-System Sales Margins Should Be Used To Offset FAC Costs ...... 40 c. 'I'he Costs Recoverable Through The FAC Under §4928.143(B)(2)(a), Ohio Rev. Code Are Not Limited To Costs Recoverable Through the Prior EFC ...... 41 d: The Rate Design For The FAG -i'hat The Commi.ssion Apliroved Is Lawful ...... 41 Phase-in And FAC Deferrals ...... 41 i 294 ...... 45 Non-FAC Generation Rate Increases ...... a. The Commission Properly Approved The Companies' Proposal To Recover Capital Carrying Costs On Their Incremental 2001-2008 Environmental Investment ...... 45 Significantly Excessive Eamings Test ...... 4b a. OCC's Objection to Eliminating the Impact of FAC Cost Deferrals on the Companies Earnings When Applying The SEET Is Meritless ...... 47 b. The Commission Should Provide the Clarification That OEG Seeks Regarding How The FAC Cost Deferrals Shoul.d Be Treated For SEET Purposes ...... 49 c. Intervenors' Contention That Off-System Sales Profits May Not Be Excluded From The SEET Is Meritless ...... 50 III. CONCI..USION...... 52 ii 295 BEFORE THE PUBLIC UTILITIES COIVIlVIISSION OF OHIO In the Matter of the Application of Columbus Southern Power Company for the Approval of Case No: 05-417-EL-SSO its Electric Security Plan; and Amendment to Its Corporate Separation Plan; and the Sale or Transfer of Certain Generation Assets In the Matter of the Application of Ohio Power Company for Approval of its Electric Security Case No. O8-918-EL-SSO Plan and an Amendment to its Corporate Separation Plan COLUMSUS SOUTHERN POWER COMPANY'S AND OHIO POWER COMPANY'S MEMORANDUM CONTRA INTERVENORS' APPLICATIONS FOR REHEARING INTRODUCTION Applications for Rehearing regarding one or more of the Comnussion's March 18, 2009 Opinion and Order (Order), March 30, 2009 Entry Nunc Pro Tune and March 30, 2009 Entry, all issued in these dockets, were timely filed on behalf of the following intervenors: Industrial Energy Users-Ohio (IET1); Ohio Energy Group (OEG); Ohio Hospital Association (OHA); Ohio Manufacturers' Association (OMA); Ohio Association of School Business Officials, Ohio School Boards Association and The Buckeye Association of School Administraturs (collectively, Schools); The Kroger Company (Kroger); and Ohio Consumers' Counsel (OCC). A single page letter un behalf of Abbott Nut.rition dated April 13, 2009, but docketed on April 20, 2009 "request[s] a 296 rehearing." The letter was not served on the parties and Abbott Nutrition is not a party of record. Similarly, the Stark County Commissioners sent to the Chair of the Commission a letter dated April 13, 2009. The letter which was docketed on April 23, 2009 and was not served on the parties requested a series of rehearings. t Pumuant to §4901-1-35 (B), Ohio Adnrin. Code, Columbus Southem Power Company and Ohio Power Company, collectively AEP Ohio or the Companies, submit this Memorandum Contra to all of the above-referenced Applications for Rehearing. ARGUNIEN'I' The Commission Did Not Violate L4928.20 {.T), Ohio Rev. Code. (OCC 9) OCC contends that the Conunission violated §4928.20 (J), Ohio Rev. Code, by requiring customers of governmental aggcegators to pay a POL1t charge even if that aggregation group gives notice to the Comnussion of its election to not receive standby service and to agree to pay market price for power incurred by the utility, along with other costs listed in that statute, to serve such customers that do return to the electric distribution utility's Standard Service Offer. OCC's understanding of the Commission's Order is incorrect. As noted at page 40 of the Order, the Commission modified the ESP to allow: ' It is not clear if Abbott Nutrition intended to file a formal application for rehearing or if because it mentiotis `Yehearing" in its letter the Comniission's docketing department simply designated the letter as such an application. To the extent the Commission treats the letter as a formal application for rehearing, it should be denied, along with tha request from the Stark County CommissioneYs. Abboit Nutrition and the Stark County Cornmissioners are not parlies of record and have not sought leave to file a rehearing application. (Sea §4903.10, Ohio Rev_ Code). They have not met the further statutory requirements of establishing just cause for failing to enter an appearance prior to issuance of the order for which rehearing is sought; nor have they demonstrated that their interests were not adequately cons'tdered. (k). Finally, their letters were docketed after the statutory time period for filing an application for rehearing and the letters were not served on the parties. 2 297 customers that switch to an altemative supplier (either through a governmental aggregation or individual CRES providers) to agree to return to market price, and pay market price, if they return to the electric utifity after taking service from a CRES provider, for the remaining period of the ESP t.erm or until the customer switches to another altemative supplier. In exchange for this commitment, those customers shall avoid paying the POLR charge. We believe that this outcome is consistent with the requirement in Section 4928.20 (J), Revised Code, which allows governmental aggregations to elect not to pay standby service charges, in exchange for agreeing to pay market price for power if they return to the electric utility. (emphasis added). In addition, the Provider of Last Resort Charge Rider filed in both Companies' tariffs addresses not only how individual customers that shop can avoid the POLR charge, but also states: Customers of a governmental aggregation where the legislative authority that formed such governmental aggregation has filed written notice with the Commission pursuant to Section 4928.20 (J), Ohio Revised Code, that it has elected not to receive default service from the Company at standard service offer rates shall not be subject to charges under this Rider. Based on the Conunission's Order and the Companies' compliance tariffs, it is clear that OCC simply misunderstands the import of the Order and has failed to review the POLR rider filed by the Companies. OCC's request for rehearing on this matter should be denied. The POLIt Riders Approved By the Commission Are Lawful and Reasonable. (OEG 3• i)HA 2; OMA 3; Iiroaer lt OCC 7; IEU 2) Each of the applications for rehearing, except the application filed on behalf of the Schools, has raised at least one issue conceming the Provider of Last Resort charge authorized by the Commission. When considered collectively, these applications simply 3 298 re-argue the points they presented in testimony, the points on which they conducted cross-exaniination, and the points they addressed in their post-hearing briefs. In other words, their arguments on rehearing ainount to nothing more than a rehash of arguments the Commission already has considered and rejected. For this reason alone, rehearing on the POIR-related issues should be denied. OBG argued at page 18 of its initial post-hearing bricf, and again on rehearing, that customers should not have to pay a PdI,R charge if they do not want to "purchase" the option to shop. OMA raises the same argument in its application for rehearing. As the Companies explained in their Reply Brief, they ate not selling the option to customers. The option to switch generation service to a competitive provider was legislatively provided by SB 3, and SB 221 enhances the opportunities for that option by providing added encouragement for government aggregation. (§§4928.20 (3) and (K), Ohio Rev. Code. There is no basis for the Commission to change its position regarding OEG's argumetits. OHA's arguments regarding the Comnassion's POLR charge determination are that the Commission's Staff took a position which differed from the Convnission's ruling and that OMA relied on testimony of a witness who opposed the POLR charges. Simply relying on testimony the Commission already has regarded as non-compelling does not provide a basis for rehearing, even if the testimony is offered by the Staff. Further, with due respect for counsel for OMA, the fact that on brief he presented an argument similar to an argument made by a witness for another intervenor does not make the witness' testimony any more compelling. 4 299 OHA also challenges the Commission's reliance on the results of the Companies' use of the Black Sholes model. Kroger, OCC and IEU make their own arguments regarding the applicability of the Black Sholes model to determining costs associated with the POLR obligation. While most of these intervenors' arguments regarding the Black Sholes model are a rehash of their prior arguments, ]EU adds a new dimension to its attack on the model by suggesting that the Black Sholes model helped send the nation's and the world's economy "into an abyss." (IEU Memorandum in Support p lfi). Such melodramatic attucks do not inject any new support for these intervenors' arguments which already have been rejected. The Black Sholes model is an appropriate tool for measuring the Companies' risk associated with meeting their obligations as providers of last resort. The Cotnmissions' reliance on the model's results is reasonable and well within the bounds of determinations the Commission can make in an ESP proceeding. OCC continues to attack the Companies' inputs used for applying the Black Sholes model to the cost of the POLR obligation. OCC's pleading reflects an apparent lack of understanding of how the model works. OCC claims on rehearing, as it did in its post-hearing briefing, that the Companies used too high a market price, which resulted in too high a POLR cost. The fact is that the smaller the difference between the ESP and the market prices the greater the value of the optionality to switch and consequently, the greater the risk to the Companies of providing POLR service. Therefore, even assuming the Companies used too high a market price input, that would have the effect of understating the Companies' POLR risks. (Tr. XI, p. 156)? akes the same mistaken argument as OCC, at pages 32 and 33 of its Memurandum in Support. 5 300 OCC and IEU also continue to focus on the percentage increases the Commission authorized for the POLR charges. These percentage increases say more about haw low the prior POLR charge was than they do about the reasonableness of the new POLR charge. The current POLR. charges are an outgrowth of the Companies' Rate Stabilization Plan (RSP) proceeding.3 The Companies did not request a POLR charge in that proceeding. Nonetheless, the Convnission considered two aspects of the RSP proposed by the Companies - RTO administrative charges and carrying charges associated with Construction Work in Progress and in-service plant expenditures - and authorized the rate recovery amounts sought by the Companies for those items as POLR charges and established those POLR charges as unavoidable riders applicable to all distribution customers. (Opinion and Order, January 26, 2005, pp. 27, 29). OCC witness Medine was generally familiar with the way the current POLR 10, P. 33). Assuming OCC also understood the background charges were set. (OCC Ex. of the current POLR charges, it is surprising that they would argue that there is no evidence that the pre-ESP charges - which have nothing to do with POI.R cost - are insufficient. The Companies' burden in this case was to' prove that its POLR rate proposals are reasonable, not that the prior POLR charge was unreasunable. Given the origin of the prior POLR charges, any atternpt to compare those charges with the Companies' POLR charges authorized in this case is fruitless and should be rejected. IFU yet again raises additional arguments concerning the Conunission's POLR determination. For instance, while noting that its argument regarding the effect of the 3 ln the Matter of the Application of Coiutnbas Southern Power Company and Ohio Power Company for Case No. 04-t69-EL-UNC. Approval of a Post-Market Devetopment Period Rate Stabitiratron Plan, 6 301 Companies' participation in P7M already has been presented in its Reply Brief, IEU gives it another try. However, IEU's discussion at pages 27-30 of its Memorandum in Support focuses on capacity obligations and rights, whereas the POLR obligation risks as requested by the Companies in their testimony are associated with the energy requirements and costs. The Commission once again should reject IEU's PJM-related arguments. IEU also reargues that the Companies can mitigate the POLR risk by purchasing "options to cover the risk." (Id. at 30). As Companies' witness Baker testified, customers should be indifferent to whether the Companies exercise an option related to the POLR obligation. (Tr. X, pp. 213, 214). This is because if the POLR risk has been properly priced, which it was, the POLR charge should reflect the cost of an option in the same sense that the cost of self-insuring should equal the cost of acquiring insurance. IEU also criticizes the Commission's reference to the Companies' testimony in Mr. Baker's Limited Rebuttal Testimony (Companies' Ex. 2) that the Companies' pre- ESP POLR charge "is significantly below other Ohio electric utilities' POLR charges." (Order, p. 38). IEU's first critieism is that pursuant to a stipulation, the FirstEnergy companies do not have a charge comparable to the Companies' POLR charge. No conclusion can be reached about the reasonableness and significance of one provision of a 53-page settlement agreement, which incidentally, IEU, as a signatory to the stipulation, agreed "would not be offered or relied upon in any other proceedings, except as necessary to enforce the terms of this Stipulation." (Stipulation, p.45). Moreover, IEU's reliance on the FirstEnergy companies' situation is misplaced since those are distribution-only companies which do not reserve generation for meeting 7 302 their POLR obligation. Instead, those companies would pass on POLR risks to suppliers and would charge market prices for any POLR service that they provide in the future, lEU's second criticism of the Commission is that Mr. Baker's testimony was offered only within the scope of the intsrim rate issues addressed at the outset of the hearing. IEU's natrow focus on the time period to which the testimony was to apply is inappropriate. Mr. Baker's testimony was accurate and was in the record. The Commission's reference to that portion of the Companies' testimony was appropriate ^ The Comndssion Explained the Bases For Its Determination of Issues in This Proceeding In a Manner That Satisees §49t13.09, Ohio Rev. Code. (IF.U 1; OCC 14A) IEU has identified the Commissions rulings on seven different issues which IEU believes do not comply with the requirenrents of §4903.09, Ohio Rev. Code regarding setting forth the reasons prompting the decisions arrived at. Those issues relate to the FAC, the allegedly "missing rate increase cap," carrying costs, Provider of Last Resort rider, the treatment of the generation asset transfer request, gridSIvIART and other distribution increases,s and the ESP versus MRO cornparlson_ As the Supreme Court of Ohio has held, "[i]n order to meet the requirements of R.C. 4903.09, * * * the PUCO's order must show, in sufficient. detail, the facts in the record upon which the order is based, and the reasoning followed by the PCTCO in ° IEU's reference to the Companies' willingness to accept half of their requested POLR increase for the interim period then being debated, does not support CEU's position that authorizing 90 percent af the increase in the ESP Order was unreasonable. Instead, Mr. Baker's Limited Rebuttai Testimony reflecis the Companies' wiliingness to reach a reasonable compromise on the interim ratc question. Unfortunately, many intervenors were unwilling to consider some eompromise resotution regarding interim rates. 5 OCC's Assignment of Error No. 14, Part A, concerning gridSMART, also alleges that the Commission did not comply with §4903.09, Ohio Rev. Code. OCC's claim is addressed below in connection with the other gridSMART issues. 8 303 reaching its conclusion." Indus. Energy Users-Ohio v. Pub. Ulil. Comm., 117 Ohio St. 3d 486, 493 (2008 Ohio 990 130) quoting MCI Telecommuniculions Corp. v. Pub. Util. Comm. (1987), 32 Ohio St_3d 306, 312, 513 N.E.2d 337. Strict compliance with the terms of § 4903.09, Ohio Rev. Code, which requires the Comm[ssion to file a written opinion setting forth its reasons for its decision, is not required but the Conunission needs to have record support for its orders. Tongren v. Pub. Util. Comm. (1999), 85 Ohio St. 3d 87, 90, (1996), 1999 Ohio 206, 706 N.E.2d 1255; Cleveland Elec. Ilium. Co. v. Pub. Uril. Comm. 76 Ohio St. 3d 163, 166, 1996 Ohio 296, 666 N.E.2d 1372. Thus, as long as there is a basic rationale and record supporting the Order, no violation of §4903.09, Ohio Rev. Code, exists. When evaluating the merits of IEi7's claim under §4903.09, Ohio Rev. Code, it is necessary to consider the uniqueness of §4928.143, Ohio Rev. Code. Unlike the rate making statute found in Chapter 4909, Ohio Rev. Code, an Electric Security Plan is relatively unstructured. The utility's application is not based on a test year, date certain concept and no reasonable return on investment is determined, Instead, §4928.143 (B) (2), Ohio Rev. Code, lists nine different categories of components that can be included in an ESP. Further, as the Companies repeatedly have pointed out, those categories do not liinit the components a utility can propose in an ESP. Consistent with this lack of structure, it is not surprising that the General Assembly created a single test for approval of an ESP - is it more favorable in the aggregate than the expected results under an MRO. (§4928.143 (C) (1), Ohio Rev. Code). Contrary to lEU's assertion, the Commission addressed this test head on. 9 304 First, the Coinmission rejected the Companies' argument that the Commission's authority to modify the proposed ESP is limited to a determination of whether the proposed ESP is more favorable in the aggregate than an MRO. Having said that, the Commission went on to cornpare its modified ESP to the MRO and held that "the cost of the ESP is $673 million for CSP and $747 niillion for OP, and the cost of the ]vIRO is $1.3 billion for CSP and $1.6 billion for OP." (Order, p. 72). While the Companies do not agree that the Commission is free to make modifications to an ESP which already is more reasonable than an MRO, and IEU may not agree with the conclusions reached by the Commission based on the modified ESP versus MRO comparison, the obvious fact is that the Commissiott's reasoning is set out in sufficient detail to satisfy §4903.09, Ohio Rev. Code. A sitnitar analysis of the Commission's order regarding the FAC, carrying cost, POLR rider, generation asset transfer request and gridSMART/other distribution increases reveals the Comniission's compliance with §4903.09, Ohio Rev. Code.6 IEU might not like the reasons given by the Commission, but the reasons are there. The Commission's reasoning might seem more subjective to IEU than reasoning based on test year or date certain considerations with which IEU might be more familiar in the context of traditional rate making. That, however, is the product of the Commission modifying the proposed ESP in the context of the Commission's view that §4928.143, Ohio Rev. Code, permits modifications even if the proposed ESP is more favorable than an MRO.7 6 IEU's discussion of the issue regarding the allegedly missing rate increase cap does not address a failure to set forth the Commission's reasoning. Instead, it complains that the Commission has not addressed IEU's corrtplaints, which "the Commission well knows." Those complaints do not implicate §4903.09, Ohio Rev. Code. 7 The Companies continue to believe that such modifications are not permitted if the Commission determines that the proposed ESP is more favorable in the aggregate than the expected results of a MRO. 10 305 The Commission's Authorization of Recovery of the Revenue Re'juirement Associated With Specitic Sources of Generation Supply Is Lawful and Reasonable. (IEU 31 IEU's application for rehearing asserts that the Commission unlawfully and unjustly modified the proposed ESP by allowing the Companies to recover the jurisdictional share of costs associated with maintaining and operating electric generating facilities which are not included in rate base. IEU characterizes the Commission's modifications as a selective use of traditional cost-based rate making. IEU's arguments overlook the unusual cireumstances regarding these generating facilities. These facilities were acquired in 2007 (Darby) and 2005 (Waterford), under a regulatory structure that placed the entire cost and risk associated with these facilities on CSP. With the enactment of SB. 221, and the amendment to §4928.17 (E), Ohio Rev. Code, in particular, it was entirely reasonable for the Commission to conclude that if it were "going to require that the electric utilities retain these generating assets, then the Commission should also allow the Companies to recover Ohio customer's jurisdictional share of any costs associated with maintaining and operating such facilities." (Order, p_ 52)$ The Commission's decision regarding this issue also is lawful. Arguments to the contrary ignore the relatively flexible nature of §4928.143, Ohio Rev. Code, in comparison to traditional rate making. While the Commission did not engage in a dissertation setting forth its.legal reasoning, the decision is no less lawful. Tlte adjustment made by the Commission, including the adjustment related to purchases fmm $ This explanation satisfies IEU's concertt that tha Commission did not coniply with §4903.09, Ohio Rev. Code, regarding its decision on this issue. 11 306 Ohio Valley Electric Corporation, is lawful since there are no limits to the components that can be included in an ESP. Moreover, even with the adjustment the ESP is more favorable in the aggregate than the MRO alternative. IEU's application for rehearing of this issue should be denied. The Commission's Comparison of the Modified ESP to the Results That Would Otherwise Apply Under a Market Rate Offer Is I.awful and Reasonable. (IEU 6) IEU relies upon "common knowledge" of events occurring after the close of the record in this proceeding to argue that the Commission's ESP versus MRO comparison was flawed. IEU's suggestion that the Commission should have considered extra-record "common knowledge" is contrary to sound regulatory and evidentiary practices and must be rejected. Otherwise, there would be no end to an ESP proceeding as partiEs would have the Commission continuously evaluate the ESP versus l1%1120 comparison as market prices fluctuate over an endless period of time. All parties had the opportunity to submit evidence while the record was open. Based on that evidence the Commission, as noted by IEU, used the market price supported by its Staff. It cannot be said that using Staff's rnarket price was unlawful and IEU's assertion that based on post-hearing events the Commission now should use a lower market price in its analysis is unreasonable and unlawful and, therefore, should be rejected. IEU attacks the ESP versus MRO comparison on two other fronts. First, IEU argues that the blending percentages for market price that the Comnussion used in valuing the NIRO alternative were unreasonable. IEU alleges that the Commission used the worst case blending assumption and that doing so was unreasonable. As the 12 307 Companies previously have pointed out, the statutory blending percentages that were in effect at the time the Companies filed their application are applicable to this proceeding, not the percentages that subsequently became effective. Since the then-effective language in §4928.142 (D), Ohio Rev. Code, refers to ten per cent in year one and "not less than twenty per cent in year two, (and] thirty per cent in year three" the blending percettages used in the Commission's analysis wene the minimum percentages that could be used. Even if lower percentages of market price blending could be used, IEU has not shown that the blending percentages used by the Commission were unreasonable. Second, IBU argues that costs associated with the POLR obligation should not have been included in the MRO portion of the ESP versus MRO comparison. IEU's argument appears to be premised on the erroneous belief that the Companies' POI.R obligation in some manner terminates in the MRO context. The Companies' risk associated with the POLR obligation under §§4924.14 and 4918.141, Ohio Rev. Code, continues regarding the non-market portion of the MRO. The Commission's analysis is consistent with that approach. It is unrealistic to evaluate the cost of the MRO without the POLR obligation being included. Finally, IEU's arguments are internally inconsistent. If the Commission had used a lower market price in its ESP versus MRO comparison, as argued by IEU, .that lower market price wouid result in a higher POLR charge being assigned to the MRO side of the comparison. This is because, as discussed in the Companies' Initial Post-Hearing Brief at page 44, the greater the spread between the market price and the SSO, the less value there is to the option to shop. Consequently, to the extent the market price is higher, the risk of the POLR obligation is lower. As Mr. Baker testified: 13 308 "As a direct result of the difference between the Companies' proposed ESP rates and the much higher competitive retail electric service prices, the cost of fulfilling the Companies' POLR obligation is significantly lower than if the difference were not as large: '(Companies Ex. 2A, p. 33) IEU's argument should be rejected. The Order's Provision For a Higher 2009 Revenue Entitlement is Not Retroactive Ratemaking and is Lawful and Reasonable. (OCC 4, 5, 6 and 8• OHA I.OMA I; Kroger IIII The Order, as clarified in the Entry Nunc Pro Tunc, provides for a modified ESP with a term commencing January 1, 2009 and ending December 31, 2011. (Entry Nunc Pro Tunc, p. 1). Because the Commission had previously extended the Companies' old rates into 2009 (when they.were otherwise set to expire at the end of 2008), the Order provides that the new rates adopted in the ESP commenced with the first billing cycle of April 2009 and were to be offset by revenues collected from customers during the interim period. (Id, p. 2; Order, p. 64). In filing their compliance tariffs, the Companies accounted for that offset process and proposed rates that also complied with the other aspects of the Order, including the rate increase phase-in and increase pereentage Ii The Commission issued an Entry on March 30, 2009 and determined the Companies' proposed tariff filing to be °reasonable and consistent with [the Order]." (March 30, 2009 Entry, p. 4). OCC and other intervenors claim that the Order engages in unlawful retroactive ratemaking and raise multiple arguments in support of this claim. OCC raised four related and overlapping arguments in its attempt to portray the Order as engaging in retroactive ratemaking: (1) that the Order permits the Companies to apply their amended tariff schedules to services rendered prior to the Entry, in violation of §§4905.22 and 14 309 4905.32, Ohio Rev. Code [Assignment of Error 4]; (2) that the ESP term cotnmencing 7anuaty 1, 2009 and the required offset can only mean that the rates are retroactive in violation of Ohio statutes, Supreme Court case law and the Ohio and U.S. constitutions [Assignment of Error 5]; (3) that the Cotnmission erred by denying the motion for stay or making the rates subject to refund [Assignment of Error 6]; and (4) that the PO7.R. charge revenues allowed by the Order also aniount to unlawful retroactive ratemaking [Assigttment of Error 8]. ORA, OMA and Kroger also raise their own claims of unlawful retroactive ratemaking, though they are duplicative of OCC's claims and will not generally be discussed separately by AEP Ohio. These claims of retroactive ratemaking are all without merit and should be rejected 9 OCC's Assignment of Error 4 advances the notion that §§4905.22 and 4905.32, Ohio Rev. Code, are violated because the Order allows the rate increases on a "bills rendered" basis and allows billing for services that were provided prior to the effective date of the tariffs. (OCC Memorandum in Support, pp. 18-19). Section 4905.22, Ohio Rev. Code, requires a public utility to render charges that are "not more than the charges allowed by law or by order of the public atilities commission and no unjust or unreasonable charge shall be made ... in excess of that allowed by law or by order of the comtnission" (§4905.22, Ohio Rev. Code). Similarly, §4905.32, Ohio Rev. Code, prohibits a public utility from charging a"different rate, rental, toll, or charge for any service rendered, or to be rendered, than that applicable to such service as specified in its 9 QCC's endoisement of a functionally siniilar remedy, as proposed in Section V.E. of the Companies' GSP application, also demonstrates that a truc•up provision is not necessarily unlawful. (See AEP Ohio Memorandum Contra Motion for Stay, pp. 1-3). Because the Commission found the proposal to bo moot in light of the other provisions in the Order, it did not rule on the Companies' proposal. (Order, p. 64). But the Companies believe that the Commission should nonetheless render a finding on rehearing, in order to scrangthen defense of the Order on appeal, that OCC previously endorsed Section V.E. of the Companies' ESP application as reasonable and should be estopped from pursuing its arguments concerning retroactive rates. 15 310 schedule filed with the public utilities commission which is in effect at the time." (§4905.22, Oliio Rev. Code). These statutes simply require that the public utility charge the rates that are authorized by the Commission, as reflected in approved tariffs at the time of the billing. Although OCC claims these statutory violations, it does not even allege that AEF' Ohio violated the Order or the approved compliance tariffs. And there can be no question that AEP Ohio has followed the Commission's Order and the compliance tariffs that were approved by the Commission. Rather, OCC's real disagreement is with the Commission Order and the Commission's practice, not the Companies' implementation of it. Indeed, OCC generally maintains that the Commission should adopt rate increases on a service- rendered basis rather than a bills-rendered basis. Ordering rate increases effective on a bills-rendered basis is a widely used and established practice in various types of rate cases. Thus, the broad issue raised by OCC in Assignment of Effor 4 is not unique to the ESP rate increases or to the Order specifically. More importantly, the fact that OCC does not like the Order or the approved tariffs does not mean that AEP Ohio has violated either ® AEP Ohio has followed the Order and the approved compliance tariffs and that is all that is required by §§4905_22 and 4905.32, Ohio Rev. Code. Accordingly, it cannot establish that §§4905.22 and 4905.32, Ohio Rev. Code, are violated because the Order was followed and the Companies' approved tariffs were followed. OCC's Assignment of Error 5 contains the primary arguments in support of its unlawful retnoactive ratemaking theory. First, OCC charaeterizes the Order as permitting the Companies to collect retroactive rates for the period of January 2009 through March 2009 and states that the effect of the Order "remains unchanged" by the Entry Nunc Pro 16 311 Tunc. (OCC Memorandum in Support, p. 20). OCC argues that the retroactive character of the Order is confirmed because the rates for 2009 are designed to collect twelve months of revenue in the remaining nine months of 2009. (Id). As a related matter, OCC asserts that the Order's provision for offsetting the new rates with revenue received by the Companies in the first quarter of 2009 "can only mean one thing - that the new rate increases are being implemented in a manner that allows the Companies' increased rates as if the newly announced increases were effective during the first three months of 2009, consistent with the term of the E5P beginning January 1, 2009." (Id., p. 21). These characterizations of the Order are inaccurate, ignore the effect of the Entry Nune Pro Tunc and are othetwise based on flawed assumptions. The Order authorized approval of the three-year term for the ESPs from January 1, 2009 through December 31, 2011. (Order, p. 64). In doing so, the Commission also provided that the revenues collected during the interim period (as authorized by the orders in Case No. 08-1302-EL-ATA) must be recognized and offset by the new rates. (Id). Thus, the Commission did not establish retroactive rates but instead allowed for a prospective rate mechanism to implement its decision to approve the ESP for the full three-year term. While the Commission's decision may yield a similar financial impact as would have occurred if a decision had been issued by December 28, 2008 (the deadline for deciding AEP Ohio's case under §4928.143(C)(1), Ohio Rev. Code), it is not the same as making rates retroactive or backbilling individual customers for service alxeady provided and paid for. The Order and AEP Ohio's tariffs implementing the prder do not provide for new rates during the first quarter of 2009 and individual customers are not being re-billed for 17 312 first quarter consumption at the higher rate. For example, if there is a flower shop business that only operates during the month of February or another business that operated during the first quarter and went out of business, neither business would receive a bill under the new rates for service billed and paid for under the previous tariffs. Rather, the Order and AEP Ohio's implementing tariffs provide for incrementally higher rates during the nine remaining months of 2009, which rates are designed to collect, on a total company basis for CSP and OP, the 2009 revenue authorized by the Order during the remaining months of 2009. There has been no retroactive application of the new rates and the approach taken in the Order is lawful and reasonable. OCC maintains that the prospective rates authorized by the Order for 2009 nonetheless violate the longstanding principle established in Keco Indusiries, Inc. v. Cincinnati & Suburban Bell Tel. Co., 166 Ohio St. 254 (1957) that retroacdve ratemaking is prohibited. (OCC Memoranduni in Support, pp.22-Z4). This argument misperceives Keco and its progeny. The key principles in the Keco decision form Ohio's version of the so-called "filed rate doctrina" and establish that: • rates set by the Comnvssion are lawful until such time as they are set aside by the Supreme Court and modified on remand by the Commission; • a utility has no option but to collect the rates set by the Commission, unless a stay order is obtained; ® there is no automatic stay of any order and it is necessary for an aggrieved party to affirmatively obtain a stay and post a bond; and • no action for unjust enrichment lies to recover the rates that were subsequently deterrnined to be unlawful because the comprehensive regulatory scheme in Title 49 abrogates any common law action in this regard. (Keco, 166 Ohio St. at 256-259). Thus, Keco held that there is no retroactive judicial remedy for rates that were charged pending rehearing and appeal and were subsequently determined to be unlawful. 1$ 313 Keco addresses issues relating to a post-appeal remedy (or lack thereof) and does not restrict the Commission when initially establishing rates in a rate order. In effect, OCC turns Keco on its head by attempting to use the principles to block the effectiveness of the Conunission's approved rates during rehearing and appeal. The distinction between a prospective adjustment (as contemplated by Keco) and retroactive raternaking is not merely "form over substance" but is meaningful in that it reveals whether retroactive ratemaking has occurred. Hsre, it has not. It is telling that OCC believes that the retroactive character of the Order is confirmed through rates for 2009 designed to collect the authorized 2009 revenue in the remaining nine months of 2009. (OCC Memorandum in Support, p. 20). OCC's application for rehearing is replete with references to cost and it persistently advocates matching rates to cost; yet, as discussed above, ESP rates under SB 221 need not be based on cost and the time period when rates are in effect need not match the costs incurred during that period. AEP Ohio submits that the reason that OCC opposes the concept of recovering twelve months of revenue over nine months is because it is so engrained in the traditional cost-based ratemaking formula under R.C. Chapter 4909. Traditional ratemaking might not permit such an approach because it is not strictly cost justified and would not match the expected expenses to the time period of revenues authorized. That appears to be the fundalnentat reason for OCC's position that the incrementally higher 2009 rates authorized by the Order amount to retroactive iatemaking - using a traditional view of ratemaking. Yet, this position ignores the fundamental changes adopted both as part of SB 221 and the prior electric restracturing law, Senate Bill 3. Although the General Assembly 19 314 has generally chosen to retain the use of traditionat R.C. Chapter 4909 ratemaldng for noncompetitive services (such as distribution services) outside the context of an ESP proceeding, conipetitive services (such as generation) and noncompetitive services considered as part of an ESP proceeding are not subject to rate regulation under R.C. Chapter 4909. (§4928.05, Ohio Rev. Code). Today, the parameters of an electric utility's Standard Service Offer is governed by §4928.141, Ohio Rev. Code, and other applicable provisions within SB 221. The entirety of R.C. Chapter 4909 (including the detailed and prescriptive ratemaldng for7nula found in §4909.15, Ohio Rev. Code) does not apply when setting ESP rates under §4928.143, Ohio Rev. Code. Hence, just because a rate or revenue authorization might not be permitted under the traditional ratemaking statutes does not mean that the same rate or nevenue authorization is not petmitted as part of an ESP adopted under SB 221. To this extent, the Commission (and perhaps ultimately the Supreme Court of Ohio) must fully exaniine the letter and spirit of SB 221 and avoid any notion of mechanically applying statutory or case law precedent developed in the context of traditional regulation. In other words, even if an aspect of the Order could be interpreted as retroactive ratemaking in a traditional sense, it should be the provisions within R.C. Chapter 4928 that detennine whether it is prohibited - not a traditional concept that was developed in the context of R.C. Chapter 4909. For example, §4928.143(B)(2), Ohio Rev. Code allows both riders that are based on cost and rate adjustments that are automatic or pre-determined; even cost-based riders are adjusted and reconciled to prior periods of usage and revenue collection. Such riders would necessarily be encompassed within OCC's broad view of retroactive ratemaking 20 315 since they would "reach back" and adjust future rates "on the basis of the revenues collected in past rates." (OCC Memorandum in Support, pp. 23-24). An even more strildng example is found in SB 221's "significantly excessive earnings test" that applies to ESPs adopted under §4928.143, Ohio Rev. Code. That provision could operate to reach back and capture earnings that were realized in prior years and refund them to customers through a prospective adjustment. That would clearly be considered retroactive ratemaking under any notion of traditional ratenaaking. Of course, OCC does not discuss or even acknowledge such features of SB 221 when making its claim of retroactive ratemaking. In any case, the Order's provision for incrementally higher rates in 2009 easily fits within the Commission's authority in approving an ESP under Section 4928.143, Ohio Rev. Code. SB 221, of course, did not implement a "typical rate making" process. Instead, it permits the Companies to propose an ESP that can include, without limitation, many different components. Those components are not to be judged on a component-by- component basis. The analysis is not to determine if each component is reasonable, cost based, prudent or on its own more favorable than a related componen# within a possible MRO. Instead, the components of the ESP are to be analyzed "in the aggregate" and the aggregate impact is to be compared to the expected results that otherwise would apply under an MRO. Although AEP Ohio readily understood the Order prior to issuance of the March 30, 2009 Entry Nunc Pro Tunc (as is evident by AEP Ohio's March 27, 2009 Memorandum in Opposition to the Motion for Stay), the ^DCC continues to ignore the Order's prospective effect even after the Commission clarified its original intent. For this 21 316 reason, the Commission may wish to further clarify the prospective nature of its order. In this regard, it should be noted that the additional revcnue authorized for the remainder of 2009 was not necessari ly related to the first quarter of 2009 but was a decision to grant an incrementally larger increase for the remainder of 2009 rates as part of the m.od.ificd ESP package and to recognize the timing of the decision -all while ensuring that the statutory standard for approving an FsSP was met (i.e., it is more favorable in the aggregate than the expected results under an MRO). As a related matter, it is AEF' Ohio's understanding that the "offset" required by the Order for revenues collected during the interim rate period was simply an equitable adjustment that the Commission thought would be fair in calculating the increnlentall.y higher revenue approved for 2009, given the timing of the Comtnission's decision and the temporary implementation of intetim rates during the first quarter of 2009 -this rationale may also prove useful to explain on rehearing. Next, OCC argues that the Order also violates §4928.141, Ohio Rev. Code, based on the same miseharacterization that the Order retroactively changes the rates in effect from January 2009 through March 2009. (OCC Memorandum in Support, pp. 25-26). As discussed above, the incrementally higher 2009 rate increase authorized by the Order was not effective until the first billing cycle of April 2009 and no backbilling or rebilling of any kind occurred. The rates in effect during the first quarter of 2009 complied with the Comniission's interpretation and application of §4928.141, Ohio Rev. Code, as reflected in the orders in Case No. 08-1302-EL-ATA. OCC's argument lacks any factual basis and must fail. 22 317 OCC's Assignment of Error 6 re-argues the motion for stay and, in the alternative, requests that the rates be implemented subjcct to refund. (OCC Memorandum in Support, pp. 27-29). To be clear, this argument does not challenge the Order but relates to the March 30, 2009 Entry in this case. OCC claims that the Commission did not set foith sufficient detail in that Entry so as to constitute a violation of §4903.09, Ohio Rev. Code. As discussed above, the Supreme Court of Ohio has held that, as lbng as there is a basic rationale and record supporting the Order, no violation of §4903.09, Ohio Rev. Code, exists. Indus. Energy Users-Ohio v. Pub. Util. Comm., 117 Ohio St. 3d 486, 493 (Ohio 2008 990 130) quoting MCI Telecommunications Corp. v. Pub. Util. Comm. (1987), 32 Ohio St.3d 306, 312, 513 N.E.2d 337; Tongren v. Pub. Iltil. Comm. (1999), 85 Ohio St. 3d 87, 90, 1999 Ohio 206, 706 N:E.2d 1255; Cleveland &lec. Iltum. Co. v. Pub. UtiI. Comm. (1996), 76 Ohio St. 3d 1.63, 166, 1996 Ohio 296, 666 N.E.2d 1372. The Commission's Entry easily fulfills this standard. The March 30 Entry contained a detailed recitation of the facts and arguments rrtade regarding the stay request and directly indicated that the Commission is not persuaded that a stay is warranted under the circumstances of this proceeding. (Entry, pp. 1-3). The Entry went on to indicate that the movants had not demonstrated that the four- factor test goveming a stay has been met. When considering that a Court typically enters a one-sentence order to dispose of a stay request and given the inherent discretion involved in ruling on such requests, the Commission's Entry seems more than sufficiently detailed. Nonetheless, the Commission could further clarify its reasoning on rehearing if it wishes to further discourage pursuit of this argument on appeal by OCC. If 23 318 so, AF1' Ohin refers the Commission to the detailed arguments made in its Manch 27, 2009 Memorandum Contra Motion Stay. Finally regarding the retroactive ratemaking allegations, 0CC launches a separate but indistinct attack on the approved POLR rates through its Assignment of Etror 8. (OCC Memorandum in Support, pp. 34-36). OCC misperceives the risk associated with the POLR obligation under the new SSO versus the prior rate plan and concludes that the Order "allowed AEP to collect from customers revenues allegedly associated with a risk for a period when that risk, i.e_, the difference between the SSO authorized in the Order and the market rate, did not exist." (OCC Memorandum in Support, p. 35). OCC goes on to claim that customers were charged twice for the POLR risk. (Id). Both of these claims are without merit. As with the other rate components, AEP Ohio's compliance tariffs incneased the POLR charge to retlect the Order's 2009 higher authorized revenue levels and offset the revenues collected in the tirst quarter. There simply was no double-recovery or overlap. Rather, as with the other rate components, the POLR charge for the remainder of 2009 is incrementally higher under the modified ESP. As alluded to above, OCC is also wrong when it says the risk associated with the new POLR charge did not exist during the period of interim rates: AEP Ohio was not insulated from shopping or customer choice during the period of the interim rates.1° The unique provisions and hybrid regulatory structure of SB 221 was in effect during the period of interim rates. Thus, the compliance tai9ffs' adjustment to the POLR charge is 10 Indeed, it is a maner of record in this case that the members of the Schools, an active party and applicant for rehearing concerning shopping issues, are currently not buying generation service from the Companies. (Schools' Application for Rehearing, p. 1). 24 319 no different from any of the other rates concerning the retroactive ratemaking claims. OCC's arguments should be rejected. The Order's adoption of CSP's gridSMART Phase I initiative is lawful and reasonable. (OCC 14. IEU LF and IV) The Order stated that the Commission "strongly supports" AEP Ohio's gridSMART Phase I proposal to implement AMI, DA and HAN. (Order, p. 37). In establishing the initial rider, the Conunission noted that "recent federal legislation makes matching funds available to smatt grid projects" and directed CSP "to make the necessary filing fnr federal monies under the American Recovery and Reinvestment Act of 2009 for the balance of the projected costs of gridSMART Phase L" (Order, p. 38). As a result, the Commission established the initial gridSMART rider to "half of the Companies' requested amount." (Id.) Notwithstanding the claims of OCC and IEU, AEP Ohio submits that the Order is lawful and reasonable in adopting the gridSMART Phase I initiative.lt OCC advances two primary points in support of its rehearing argument against the Commission's adoption of the gridSNIART Phase I initiative, alleging that: (1) the Order does not satisfy the requirement of $4903.09, Ohio Rev. Code, to set forth reasons supporting its decision, and (2) the evidence presented at hearing does not support the Comtnission's authorization of the gridSMART Phase I initiative. (OCC Memorandum in Support, pp. 47-55). Similarly, IEU makes a claim that the Otrler.violates §4903.09, Ohio Rev. Code, regarding adoption of the grid"sIJ]1=iRT proposai artd did -tiot suffciently o AEP Ohio requested that the Commission ctarify on rehearing that it intended to fully fund the gridSMART Phase I initiative through rates, to whatever extent that federal funding is not received by AEP Ohio for this initiative. Subject to that clariflcation (or, in the alternative, request for rehearing), AEP Ohio submits ntat the Order is lawful and reasonable in supporting the gridSMART Phase I initiative. 25 320 demonstrate the cost-effectiveness of gridSMART Phase I. (IEU Memorandum in Support, pp. 21-22)•" Through these arguments, OCC and IEU plainly attempt to second-guess the Commission's appraisal of the record evidence and those parties merely reveal that they disagree with the Commission's findings. The Order has ample record basis to support the conclusions reached and the fact that OCC or IEU oppose the result is not a valid basis for rehearing. First, reggarding the allegation that the Order does not satisfy the requirements of §4903.09, Ohio Rev. Code, as discussed above, the Supreme Court of Ohio has held that, as long as there is a basic rationale and record supporting the Order, no violation of 117 §4903.09, Ohio Rev. Code, exists. Indus. Energy Users-Ohio v. Pub. Util. Corrun., Ohio St_ 3d 486, 493 (Ohio 2008 990 9[30) quoting MCI Telecommunications Corp. v. Tortgren v. Pub. Util. Pub. Util. Comm. (1987), 32 Ohio St.3d 306, 312, 513 N.E.2d 337; Cleveland Elec. Comm. (1999), 85 Ohio St. 3d 87, 90, 1999 Ohio 206, 706 N.E.2d 1255; Iltum. Co. v. Pub. Utit. Comm. (1996), 76 Ohio St. 3d 163, 166, 1996 Ohio 296, 666 N.E.2d 1372. The Order specifically recognized the features and benefits of the proposed gridSMART Phase I initiative, as evidenced by detailed recitations of the pertinent record evidence on pages 34-37 of the Order. The Order proceeds to make specific findings that gridSMART Phase I"will provide CSP with beneficial information as to implementation, 12 [EU also criticizes the Order for approving a stighdy higher distribution inorease Por 2009 than was proposed by AEP Ohio, even though the Commission did not accept part of the ESRP. (IEU Memorandum in Support, pp. 39-40). By focusing solely on 2009 in making this criticism, [EU fails to recognize: (1) that the Companies' proposal was to levelize costs over tha three-year ESP term while, under the Order's than those approach, the 2010 and 2011 increases for gridSMART Phase [ and ESRP will be lower proposed by the Companies, and (2) that the Companies had less than a full year to recover these revenues. Moreover, the Commission did not reject the Companies' proposed percentage distribution increase as being inappropriate or unreasonable; it deemed the proposal °unneeessary" because of the decision made on the ESRP and gridSMART riders. (Order, p. 38). Accordingly, this argument should be rejected or disregarded. 26 ^ ^ ^ 321 equipment preferences, customer expectations, and customer education requirements" and that "these advanced technologies are the foundation for AEP-Ohio providing its customers the ability to better manage their energy usage and reduce their energy costs." (Order, p. 37). These evidence recitations and findings are sufficient to explain the Commission's rationale for adopting the gridSMART Phase I initiative. Of course, if the Commission chooses to expand its reasoning and to detail the rationale supporting adoption of the gridSMART Phase I initiative through its entry on rehearing, that would further ensure that OCC's and IEU's clainis cannot be successfully pursued. OCC and IEU also argue that §§4928.02(l]) and 4928.64(E), Ohio Rev. Code, require gridSMART to be cost-effective and that the Order does not support such a conclusion. (OCC Memorandum in Support, pp. 49-5 1; IEU Memorandum in Support, p. 22). Based on the quoted language, it is evident that OCC and IEU are actually intending to reference §4928.04(E), not §4928.64(E).'3 In any case, these "policy" arguments are not binding on the Commission and are otherwise misguided. OCC and IEU focus on selected language within §4928.02(D), Ohio Rev. Code, white an unquoted portion of that policy statement also specifically includes deployment of advanced metering infrastructure as an example of cost-effective demand-side retail electiic service. Another portion of that policy is to "encourage innovation and market access" for supply- and demand-side options such as time-differentiated pricing. Time- differentiated pricing that emulates market prices wiU be facilitated by deptoyment of 13 Tnterestingly, the identical typographical references appear in both OCC's and IEU's briefs: although those parties had not made this argument bafore, the identical argument waz made in OCEA's merit brief at pages 77-80 -including the same typographical reference to °4928.64(E)" in all three places. It would appear that, although OCEA has dropped the argument, OCC and IEU have merely done a "cut and paste" from OCE A's earlier argument without even checking or understanding the citations. This detracts credibility from an argument that otherwise lacks merit. 27 322 gridSMART Phase I, as was explained through the Companies' testimony. (Companies' Exhibit 1, p. 6; Tr. III, pp. 304-305). Further, OCC's and IEU's argument focuses solely on one policy while the Commission's responsibility is to consider all of the policies within §4928.02, Ohio Rev. Code. And the concept of being cost-effective does not mean that a network component (or group of components like the gridSIWIART initiative) pays for itself but, rather, that it is a reasonable and prudent approach to deploying needed funcfiionalities and features. In any case, reliance on selected language within one of the policies does not provide support for OCC's or IEU's rehearing request. As AEP Ohio argued on brief, the Commission should also consider tlte several provisions within SB 221 adopted by the General Assembly designed to promote the deployrnent of smart metering. Sec. 4905.31(E), Ohio Rev. Code, creates a specific cost recovery mechanism opportunity for "acquisition and deployment of advanced metering, including the costs of any meters prematurely retired as a result of the advanced metering implementation." Further, in setting forth the energy policy for the State of Ohio, the General Assembly also included new language to ensure that the Commission will encourage "implementation of advanced metering infrastructure." (§4928A2(D), Ohio Rev. Code). In the specific context of an ESP, the General Assembly included a long- term energy delivery infrastructure moderniaa6on plan as an item that can be included in an ESP. (§4928.143(C)(2)(h), Ohio Rev. Code). Finally in this regard, given the potential for significant enhancements in customers' energy management capabilities that are associated with gridSMART technology, the General Assembly's inclusion of mandates in §4928.66, Ohio Rev. Code, for energy efficiency and peak demand reductions also implicitly supports deployment of 28 323 advanced metering. Indeed, Ms. Sloneker testified that the demand response capabilities associated with gridSMART Phase I will be critical to achieving the benchmarks required by SB 221. (Tr_ III; pp. 252-253). In short, the General Assembly's deliberate and consistent effort to promote advanced metering through the passage of SB 221 should be implemented by the Commission in eonsidering ABP Ohio's gridSMART Phase I proposal. OCC also re-argues its position that AEP Ohio should have been required to demonstrate customer and societal benefits. AEP Ohio addressed this issue in its merit brief and will not repeat that argument here. (Companies' Initial Brief, pp. 64-65). The Order sufficiently addressed this issue, concluding that "we do not believe that all information is nequired before the Commission can conclude that the program is beneficial to ratepayers and should be implemented." (Order, p. 38). OCC is merely re- asserting the same arguments and the Commission should, again, reject them on rehearing. In a final effort to overturn the Commission's approval of gridSMART Phase I, OCC transparently attempts to impose its own standard of proof by claiming that "[gliven the obvious ties between Phase I and the full gridSMART rollout, AEP Ohio should have been required to provide specific Phase I performance criteria and a detailed full system cost estimate and implementation plan before any Commission approval of Phase L" (OCC Memorandum in Support, p. 53). Again, the Order already rejects OCC's arguments that all the answers to all questions about the gridSMART initiative need to be answered up front, by concluding that "we do not believe that all information is required before the Commission can conclude that the program is beneficial to ratepayers and 29 324 should be implemented." (Order, p. 38). The Commission should reject OCC's and IBU's bid to second-guess the approval of gridSMART Phase I. The Order's Approval of the Enhanced Vegetation Management Initiative, Through Adoption of the Enhanced Service Reliability Plan (FSRP) Rider, is I,awfttl and Reasonable. (OCC #15 16 17 and 18) The Order found that AEP Ohio's proposed enhanced vegetation initiative, with Staff's additional recorrunendations, is a reasonable program that will advance the state policy and approved the ESRP rider under §4928.143 (13)(2)(h), Ohio Rev. Code, to recover the associated prudently-incurred incremental costs. (Oixler, p. 34). OCC sets forth four arguments on rehearing to challenge the Commission's approval of the ESRP rider, alleging that: (1) the Order violates §4903.09, Ohio Rev. Code [OCC Assignment of Error 15]; (2) the Companies have not met the burden of proving that the vegetation management plan is in the public interest [Assignment of Error 16]; (3) the Commission erred by characterizing the vegetation management initiative as "cycle-based" [Assignment of Error 171; and (4) that AEP Ohio's original ESRP filing does not comply with adopted filing requirements that just became effective after the merit decision in this case was issued [Assignment of Error 18] (OCC Memorandum in Support, pp. 55-65). An examination of each of these arguments against the vegetation management initiative reveals that OCC is again merely second-guessing the Commission's evaluation of the evidence and ignoring the Commission's statutory discretion to approve the program. OCC's Assignment of Eiror 15 claims that the Order violates §4903.09, Ohio Rev. Code. As discussed above, the Supreme Court of Ohio has held that, as long as there is a basic rationale and record supporting the Order, no violation of §4903.09, Ohio 30 325 Rev. Code, exists. Indus. Energy Users-Ohio v. PUC, 117 Ohio St. 3d 486, 493 (Ohio Comm. (1987), 32 2008 990 130) quoting MCI Telecomnaunications Corp. v. Pub. Util. (1999), 85 Ohio St. Ohio St.3d 306, 312, 513 N.E.2d 337; Tongren v. Pub. Utit. Comtn. Util. 3d 87, 90, 1999 Ohio 206, 706 N.E.2d 1255; Cleveland F'lec. IlIum. Co. v. Pub. Comm. (1996), 76 Ohio St. 3d 163, 166, 1996 Ohio 296, 666 N.E.2d 1372. The ESRP findings within the Order easily meet this standard, and OCC's arguments shoutd be rejected. In support of its claim under §4903.09, Ohio Rev. Code, OCC argues that the ESRP rider amounts are not set forth in the Order, that the rider was not proposed by any of the parties; and that there has been no "proper review" of the Companies' prior vegetation management expenditures. (OtAer, pp. 55-57). As to the first point, there is no requirement that the Commission specify actual rates in its order within the context of an ESP case or within the context of any rate order. Historically, it has not been the Commission's practice to do so. Instead, the Commission generally decides the merit of issues affecting rates; tariffs containing the resulting rates are filed, reviewed and, if found to be compliant, are approved (either affirmatively or by not suspending the filed tariffs). This routine and well-established approach was used in this case and the Commission issued a separate Entry on Niarch 30, 2009 finding that the proposed tariffs properly implemented the Order. OCC's second supporting argument is equally unavailing: OCC claims that none of the parties proposed the rider and no testimony was provided, so the Commission violated §4903.09, Ohio Rev. Code, by adopting it. This claim is factually incorrect and legaUy without basis. In response to the Companies' proposal for a percentage 31 326 distribution increase, Staff witness Scheck proposed a rider for the gridSMART Phase I initiative and Staff witness Baker recommended a rider for distribution automation and was cross examined extensively regarding the general operation of such a rider mechanism (which was part of gridSMART and part of ESRP). (Staff Ex. 3, pp. 4-5; Staff Ex. 5, pp. 6-7; Tr. XII, pp. 85-99). Moreover, the Companies affirmatively agreed that, in light of parties' concerns about the proposed distribution percentage increase, a rider would be acceptable since they merely sought to reeover their ineremental costs associated with the enhanced programs. (Companies' Reply Brief, pp. 62-63). As a legal matter, the Commission's decision to adopt a rider instead of a percentage increase is a classic example of a rate design matter that is within the Commission's discretion and expertise. The Supreme Court of Ohio has often recognized the Conunission's "unique rate design expertise" and the "wide discretion" afforded to the Commission on rate design issues. Green Cove Resort I Qwners' 11ss'n v. Pub. Util. Comm., 103 Ohio St. 3d 125, 129 (2004); Columbus S. Power Co. v. Pub. Util. 47 Ohio Comm., 67 Ohio St. 3d 535, 540 (1993); Gen. Motors Corp. v. Pub. Utit. Comm., St.2d 58, 351 N.E.2d 183 (1976). In considering these matters, the Order held that "in balancing the customers' expectations and needs with the issues raised by several intervenors" the Comntission "approves the establishment of an ESRP rider as the appropriate mechanism pursuant to Section 4928.143(B)(2)(h), Revised Code, to recover such costs." (Order, p. 34). Finally regarding its argument that the Order violates §4903.09, Ohio Rev. Code, OCC argues that there has been no "proper review" of the Companies' prior vegetation management expenditures. "I'his complaint seems to misapprehend the ESRP rider 32 327 approved by the Commission. Per the Order, only prudently-incurred incremental vegetation management costs will be collected through the ESRP rider. (Order, p.34). The Commission further provided that the ESRP rider will be "subject to Commission review and reconciliation on an annual basis." (1d). There can be no doubt that the Commission made clear that a "proper review" of the costs is integral to the ESRP rider approved in the Order. In short, the Commission's reasoning and record basis for adopring a rider is more than sufficient to pass muster under §4903.09, Ohio Rev. Code. OCC's Assignment of Error 16 contends that §4928.143(B)(2)(h), Ohio Rev. Code, imposes the burden of proof on AEP Ohio to show that its vegetation management proposal is in the public interest, while the Order allegedly "places the burden on the parties to the case to disprove the enhanced nature of the programs." (OCC Memorandum in Support, pp. 57-61). OCC's claim that the burden of proof was improperly placed on the parties is based on the Comniission's observation that "OCC offered no evidence that the proposed initiative is already included in the current vegetation management program, and thu.s, is not inctrmental:" (Order, p. 33). What OCC fails to acknowledge is that the quoted staternent follows a direct and explicit finding in the Order that "[t]he Commission is satisfied that the Companies have demonstrated in the record that the costs associated with the proposed vegetation initiative, included as part of the proposed three-year ESRP, are incremental to the current Distribution Vegetation Management Program and the costs embedded in distribution rates." (1d). OCC also admits with consternation that the Commission accepted the Companies' record evidence in support of the ESRP regarding customer survey results in concluding that the enhanced vegetation management proposal better 33 328 aligns the Companies' and customers' expectations as to tree-caused outages, service interruptions, and reliability of customers' service. (OCC Memorandum in Support, p. 59 citing Order, p. 33). Companies' witness Boyd also testified that the proposed ESRP programs were all designed to be incremental activities beyond existing activities and that the Companies were only seeking recovery of incremental vegetation management costs that are above current costs. (Companies' Ex. 11, p. 37; Tr. V., p. 179). Thus, in reality, the burden of proof was not placed on the parties; the Companies satisfied their burden of proof and the opposing parties then bear the burden of going forward with contrary evidence (rather than just making bald assertions without support). The Conunission found that the Companies met their burden of proof and the opposing parties failed to present sufficient evidence. Once again, although disguised as a legal argument regarding shifting the burden of proof, OCC merely disagrees with the Commission's assessment of evidence and reveals that a different result would be reached if OCC were charged with deciding the case_ OCC's Assignment of Error 17 attacks the ESRP rider because OCC betieves that "the Commission erred in characteriZing AEP-Ohio's proposed vegetation initiative as `cycle-based."' (OCC Memorandum in Support, pp. 61-63). In reality, the Order repeatedly recognized that the ESRP rider would involve an enhanced vegetation management initiative that moves toward a cycle-based approach - not that the transformation would occur instantaneously (as is apparently presumed by OCC). For example, the Order indicated the Commission's belief that the Companies should "have a balanced approach" and explicitly recognized that the Companies' proposal would "place a greater emphasis on cycle-based planning and scheduling." (Order, p.33) (emphasis 34 329 added). Regarding the Staff's additional recommendations that were incorporated into the ESRP rider, the Commission also characterized the enhanced progratn as a "move to" a cycle-based approach. (Id.). Thus, OCC does not present any basis to conclude that the Commission erred or rnisapprehended the evidence. Finally regarding the ESRP, OCC's Assigntnent of Error 18 claims that AEP Ohio's original ESRP filing proposal does not conform to the filing requirements found in adopted rule 4901:1-35-03(A) and that the Commission, after having granted the application, should requiTe an a.mendment based on a failure to comply with the filing requirements. (OCC Memorandum in Support, pp. 64-65). This is an absurd conclusion that should be summarily rejected for several reasons: (1) the rules were not effective as of the date of the Order and substantive changes were made to the rule relied upon by 0CC on March 18, 2009 - months after the ESP case was fully submitted and was to be decided under the statutory deadline, (2) §4928.143(A), Ohio Rev. Code, only requires an application filed before the effective date of the rules to be conformed "as the commission determines necessary", (3) AEP Ohio's waiver request covering such issues was denied and it subsequently made a compliance filing on October 16, 2008 in this docket stating its understanding of Staff's view that it substantially complied with the rules as proposed, (4) it is untimely for OCC to raise a filing compliance issue after the merit decision has been issued, and (5) OCC's argument is simply another form of second-guessing the Order's approval of the ESRP rider and is without merit. In sum, the Commission's decision to adopt the vegetation management initiative was supported by a key finding that customer expectations are better aligned with the Companies' expectations under the enhanced vegetation management initiative, 35 330 consistcnt with §4928.143 (B)(2)(h), Ohio Rev. Code. (Order, pp. 33-34). The Comrnission also cited Companies' witness Boyd's testimony as record support for finding that increased spending earmarked for specific vegetation management initiatives can reduce tree-caused outages, resulting in better reliability. (Order, p. 33). Consequently, the Commission had sufficient record basis for adopting the enhanced vegetation management initiative and OCC's attempt to merely re-argue the same determination on rehearing should be rejected. The Order's Adoption of the Economic Development Rider is Reasonable and Lawful and OCC's Rehearing Requests Should be Denied. (OCC #11 and 19) The OCC raises two challenges against the Economic Development Rider (EDR) approved by the Order. In Assignment of Error 11, OCC asserts that the Commission unreasonably discontinued its policy of dividing the recovery of foregone revenue subsidies equally between ratepayers and shareholders. (OCC Memorandum in Support, pp. 3941). In Assignment of Error 19, OCC claims that the approved EDR is anticompetitive and does not ensure enforcement of customer commitments. (Id., pp_ 65- 66). These attacks are misguided and, in some cases, premature. In suggesting through Assignment of Error 11 that the Comrnission unreasonably modified its policy of delta revenue sharing, the C)CC inexplicably starts its argument by acknowledging that "the amount and allocation of the costs to be recovered is up to the discretion of the Commission _.." (Id., p. 39). It is not clear how the OCC can simultaneously claim that delta revenue sharing is within the Commission's discretion and elaim that the Commission erred in not ensuring the sharing arrangement advocated 36 331 by the OCC. Further, AEP Ohio does not agree with OCC's supposition that it was previously established Commission policy to require sharing of delta revenue, as that practice is not reflected in the few special arrangernents that AEP Ohio has with its customers prior to implementation of SB 221. In any case, to the extent that the policy of not requiring sharing is considered a change that requires a reason, OCC's position fails to acknowledge that the new language added to §4905.31, Ohio Rev. Code, as amended by SB 221, provides an obvious and compelling basis for allowing full revenue recovery for economic development discounts. Specifically, the General Assembly explicitly included recovery of foregone revenue associated with an economic development contract, as part of the SB 221 amcndments, as being recoverable under §4905.31(E), Ohio Rev, Code. By cl,aiming in Assignment of Error 19 that the approved EDR is anti-competitive and does not ensure enforcement of customer commitments, OCC raises issues that are premature. The Commission will address the specific circumstances of individual special arrangements as they are presented for approval. To the extent enforcement issues arise in the future, the Commission's continuing jurisdiction over special arrangements can be used to address those issues arise. Finally, OCC challenges the non-bypassable nature of the EDR as being anti- competitive. (OCC Memorandum in Support, p. 66). On the contrary, that the EDR is non-bypassable helps to ensure that it is competitive-neutral; whereas, a bypassable EDR would give CRES providers an unduc advantage. All customcrs and the public-at-large benefit from econonVc development discounts. Although CRES providers' rates are unregulated and their rates do not reflect recovery of such "public interest" discounts, an 37 332 EDU's SSO rates are regulated and do include the foregone delta revenue associated with economic development contracts. If a competitive rate were offered to a customer that is lower than the electric utility's SSO rate, there would be no need for an econonuc development discount from the utility. Thus, recovering economic development discounts from all distribution customers (regardless of whether they talte generation service from the Companies) preserves a level playing field. Fuel Adiustment Clause (FACl Mechanism a. The Baseline FAC Component Of The Current SSO Rate Cannat, And Should Not, Be Based On A Measure Of Actual 2008 Costs. (IEU 7; OCC 1) At pages 18-19 of the Order, the Commission addressed what the appropriate FAC baseline component of the current SSO rate should be. The Commission adopted its Staff's recommendation to determine the FAC baseline component using 2007 actual cost data, escalated by 3 perceut for CSP and 7 percent for OPCo, as a proxy for 2008 costs. OCC recommended at the hearing and in its post-hearing initial brief, at. pages 12- 15, that the Commission use actual 2008 fuel costs to develop the FAC baseline components. The Commission rejected this approach, and observed that even OCC's witness for this issue conceded that 2008 actual fuel costs were not known at the time of the hearing, which took place in 2008. For their part, the Companies have asked the Commission, at pages 38-39 of their Application for Rehearing, to adopt their proposed methodology for identifying the baseline FAC components. Now OCC, at pages 12-14 of its rehearing application, contends again that the Commission erred by adopting a baseline for the FAC that was not based on actual 2008 cost data. OCC also claims that 38 333 the Commission petmitted the Companies "to manipulate the process." (p. 13).14 IEU similarly argues, at pages 44-47 of its rehearing request, that using any basis other than 2008 actual fuel costs to determine the FAC baseline rate (and, thus, the non-FAC rate) is unjust and unreasonable. The Commission has already considered and rejected OCC's and IBU's argument, As the Commission observed in its Order, at page 19, there is no - and indeed could not have been any - record evidence of calendar year 2008 actual costs because the Application was filed on July 31, 2008 and the hearing took place during 2008. In short, it is not feasible to do what OCC and lEU recommend because there is no record basis for it. Nor is it possible (or appropriate) to overcome this deficiency by now adding evidence into the record regarding 2008 actual fuel costs. The evidentiary hearing was completed months ago, the record was closed, and the case was submitted to the Commission for decision based on that record. In any event, cven if there were evidence of 2008 actuat costs available in the record, it would require substantial modification. As Companies' witness Mr. Nelson explained, the volatility of fuel costs in 2008 and the extraordinary nature of significant fuel procurement activities in 2008 would make use of such costs inappropriate, absent significant adjustments. (Cornpanies' Ex. 7B, pp: 2-3; Tr. XIV, pp. 74-75). Moreover, as the Companies have argued, 2008 fuel costs are not the proper focus for setting the FAC baseline. Instead, the Cotnnussion should use the Companies' rate analysis for deterniining the FAC baseline. 14 OCC's claim of "manipulating the process" is remarkable in light of OCC's well-documented abandonment of positions it took when urging the Cummission to exteud the procedural schedule for this proceeding. 39 334 b. The Commission Properly Rejected. Arguments That Off-System Sales Margins Should Be Used To Offset FAC Costs. (OCC 3) OCC argues, at pages 16-18 of its application for rehearing, that the Commission erred by not offsetting FAC costs by profits from off-system sales (OSS). OCC contends that offsetting FAC costs by OSS margins is consistent with Commission precedent for sharing profits from OSS between customers and utilities. OCC also claims that by not offsetting FAC costs by OSS margins the Commission has faited to respect its own Comm., 41 Ohio precedents in violation of Cleveland Electric Iltum. Co. v. Pub. Uril. St.2d 403 (1975). First, OCC's argument that OSS margins should be used to offset FAC costs is one that the Commission considered and rejected in its Order, at pages 16-17. Neither §4928.143(B)(2)(a), Ohio Rev. Code, which specifically authorizes the FAC, nor any other provision of SB 221, would permit requiring that an Ohio electric distribution utility (EDTJ) offset FAC charges with OSS margins. Second, the Conuttission's decision is not inconsistent with any of its precedents regarding the sharing of profits from OSS between a utility and its customers. Those profits were not used as an offset to costs recoverable under the previously effective Electric Fuel Clause (EFC). The Commission's decision is in compliance with §4928.143(B)(2)(a), Ohio Rev. Code. Since there is no Commission precedent regarding OSS margins under that section that is inconsistent with its Order in this proceeding, Cleveland Electric Illuminating is inapplicable. 40 335 c. The Costs Recoverable Through The FAC Under §4928.143(It)(2)(a), Ohio Rev. Code Are Not Lin-ited To Costs Recoverable Through the Prior EFC. (IEU 8) At pages 47-50 oP its rehearing application, IEU argues that the Commission erred by approving a FAC for the Companies that includes costs beyond those that the prior EFC statute (and related rule) permitted. This is the same argument that IELJ made, at pages 9-13 of its Initial Post-hearing Brief. IEU's criticisms are objections to SB 221's provision that govems the FAC, §4928.143(B)(2)(a), Ohio Rev. Code, and the Commission's rule which will implement that statutory provision, Rule 4901:1-35-09, Ohio Admin. Code. IEU's EFC-based objections to the FAC that the Order has approved are irrelevant and rneritless. Approved Is d. The Rate Design For The FAC That The Comnulssion Lawful. (IEU 8) At page 50 of its application for rehearing IEU argues that a FAC that recovers costs on a per-kWh basis is unreasonable, unjust and unlawful based on Commission precedent. IECT provides no support for the proposition that the rate design the Order has approved for the Companies' FAC mechanism under §4928.143(B)(2)(a), Ohio Rev. Code, is inconsistent with that statute or with any other decision the Commission has rendered under that section. IEU's argument is without merit. Phase-in And FAC Deferrals (OCC 2 12 13: Schools 1) In order to moderate the rate impacts of the Companies' ESP, the Order concluded that a phase-in of the ESP rate increases, pursuant to §4928.144, Ohio Rev. Code, is appropriate. The phase-in of the rate increases is accomplished by, first, the 41 336 deferral of a portion of FAC costs during the three-year ESP period and, subsequently, recovery of the defezred costs during 2012-2018 through non-bypassable charges. Carrying costs on deferred costs must be allowed (and also deferred) from the time costs are deferred until they are finally recovered in order to enable the deferrals and thus the phase-in of rates to occur. The Order specifically authorizes the cost deferrals, including carrying costs, that the statute required in order to enable the phase-in of rate increases. txC raises three objections to the Commission's decision to authorize a phase-in of rates and the underlying cost deferrals. At pages 42-44 of its rehearing request, OCC contends that FAC cost deferrals destabilize customer prices and introduce uncertainty regarding retail electric service. OCC argues that these results are incompatible with §4928.143(B)(2)(d), Ohio Rev. Code. After reviewing the record and all of the arguments, the Commission came to the opposite conclusion, stating "that a phase-in of the increases is necessary to ensure rate or price stability and to mitigate the impact on customers during this difficult economic period..." There is ample, indeed overwhelming, support for the Commission's decision in the record. The phase-in of rate increases, and the related cost deferrals, comply with the requirements of §4928.144, Ohio Rev. Code which is the basis for the Commission's decision (and it is also fully compatible with §4928.143(B)(2)(d)) Ohio Rev. Code. OCC also argues, at pages 14-16 of its application for rehearing, that catrying costs on deferrals should be calculated on a net-of-tax basis. This is the same argument that OCC made in its Initial Post-hearing Brief, at pages 63-64. The Commission considered this argument thoroughly and rejected it, at pages 23-24 of its Order. The Commission noted that if it adopted OCC's argument, the Companies would not recover 42 337 the full carrying charges on the authorized deferrals, which would be inconsistent with the explicit directive of §4928.144, Ohio Rev. Code. OCC tries to avoid this result by arguing that §4928.144, Ohio Rev. Code, does not apply because the Commission did not authorize a phase-in of rates, but rather only cost deferrals. This argument evinces a basic misunderstanding of what the Commission has done. As explained above, the FAC cost deferrals (and the carrying costs) are necessary to reflect on the Companies' books of account, the phase-in of rate increases through the deferral of fuel expense for future recovery. In short, the Commission did authorize a phase-in of rate increases. OCC also criticizes the Commission for authorizing the use of a weighted average cost of capital (WACC) to calculate carrying costs for the FAC deferrals. OCC contends that a short-term debt interest rate, rather than the WACC, should be used. OCC Application for Rehearing, at pages 45-46. This is the same argument that OCC made at pages 64-66 and 92-93 of its Initial Post-hearing Brief, which the Commission reviewed, at page 21, and declined to accept, at page 23, of its Order. As the Companies explained, and the Commission agreed, because the period of cost deferrais and their subsequent recovery will take place over the next ten years (2009-2018), use of a WACC, which includes both the costs of equity and long-term debt capital, is appropriate. Even in situations where the carrying cost applies for significantly shorter periods, such as deferral of storm damages or the annually adjusted Transmission Cost Recovery Rider, the Comniission permits the use of the long-term cost of debt. The Schools raise an additional criticism of the Order's phase-in of rate increases. The Schools contend that by approving deferrals of FAC costs now and then allowing recovery of the deferred costs througli a non-bypassable surcharge in the future, without 43 338 establishing a credit for School Pool participants who buy generation service finm competitive retail electric service providers, the Commission has unreasonably and unlawfully created a subsidy to SSO customers in violation of §4928.02(H), Ohio Rev. Code. The Schools request that the Comnrission provide a credit to School Pool participants on their monthly bills identical to the value of the FAC deferral. The Schools' argument is not persuasive. As explained above, the Commission's decision to adopt a phase-in of rate increases is authorized by, and complies with the requirements of, §4928.144, Ohio Rev. Code. With respect to the Schools' contention regarding §4928.02(H), Ohio Rev. Code, the Commission explained that the policy provisions of §4928.02 are to be used "as a guide" in its decision-making in this proceeding. In that regard, the Commission specifically stated, at page 13 of its Order, that "[it] has reviewed the ESP proposal presented by AEP-Ohio, as well as the issues raised by the various intervenors, and we believe that, with the modifications set forth herein, we have appropriately reached a conclusion advancing the public interest." Nor would it be appropriate, in any event, to give schools who shop during the term of the ESP a credit on their bills for distribution service in the amount of FAC deferrals. Essentialty, the Schools are requesting a rate decrease for shopping schools during the terni of the ESP in order to offset the impact of surcharges during the post-ESP period. But this is simply, at best, a proposal to make the future surcharges avoidable, in violation of the requirement in §4928.144, Ohio Rev. Code, that they be non-bypassable. There is no basis in the law for giving some customers a rate decrease today that they do not have any right to receive, in order to enable them to avoid a statutorily required rate 44 339 increase in the future. The School rehearing request should be det2ied because their quarrel is with the Legislature, not the Conunission. Non-FAC Generation Rate Increases a. The Commission Properly Approved The Companies' Proposal To Recover Capital Carrying Costs On Their Incremental 2001-2008 Environmental Investment (OCC 10) The Companies included in their ESP a provision to enable them to recover the capital carrying costs of their 2001-2008 incremental environmental investments not already reflected in their existing rates through adjustment made during their RSP authority. In its Order, at page 28, the Commission agreed that the Companies should be allowed to recover those incremental capital carrying costs and approved this aspect of their ESP. At pages 37 to 39 of its rehearing application, OCC contends that the Commission erred because §§4928.143(B)(2)(a) and (b) do not permit recovery of these costs in an ents that OCC made in its Initial Post-hearing Brief, at ESP. These are the same argun► pages 69-70, which the Comtnission thoroughty considered in its Order, at pages 25-26, but declined to accept, at page 28. The most glaring flaw in OCC's position is that it, again, has mischaracterized the statutory basis for the Companies' proposal. The Companies' primary source of statutory authority for their proposed recovery of the environmental capital carrying costs is the "without limitation" language of §4928.143(B)(2), Ohio Rev. Code. That section provides that an ESP may provide for or include without limitation, any of the provisions identified in paragraphs (a) through (i) of that subdivision. In other words, while the list of provisions may be illustrative, it is not exhaustive. 45 340 OCC continues to state, on rehearing, that the Companies are basing their recovery of carrying costs for the environmental capital investments on §4928.143(B)(2)(a), Ohio Rev. Code. That is incorrect, and OCC's arguments that flow from that incorrect assumption are also flawed as a result. OCC's argument that §4928.143(B)(2)(b), Ohio Rev, Code, precludes the Companies from recovering these capital costs because that section requires the cost to be incurred on or after January 1, 2009, also remains misguided on rehearing. OCC made this same argument in its post-hearing initial brief at pages 58-70. As the Companies pointed out in their Reply Post-hearing Brief, at page 30, that statutory section does not prohibit the recovery of carrying costs on environmental investments, as long as those catrying costs are incurred on or after January 1, 2009. While the investments involved in this aspect of the Companies' ESP were made prior to January 1, 2009, "the carrying cost itself is the carrying cost [the Companies are] going to incur in 2009." (Tr. XIV, p., 93, 114 (Nelson)). Similarly, OCC's argument that there must be an after-the-fact examination of whether the costs were prudently incurred before recovery of them may be permitted has no basis. Section 492$.143(B)(2), Ohio Rev. Code, does not require the Companies to wait for the completion of a future proceeding that does not even start until after the 2009-2011 carrying costs have been incurred before it may begin to recover those costs. Significantly Excessive Earnines Test In connection with the SigniOeantty Excessive Earnings Test (SEET) that §4928.143(F), Ohio Rev. Code, requires after each year of the ESP, the Commission 46 341 found that it should develop a common methodology for the SEET and directed its staff to convene a workshop for the purpose. However, the Commission did resolve two important issues regarding how the SEET would be applied. The Commission concluded that FAC cost deferrals, underlying the phase-in of rate increases, should not have an impact on the SEET until the revenues associated with the deferrals are received. In addition, in order not to discourage the efficient use of generation facilities, to the extent the Companies' earnings result from wholesale sources, the Comniission determined that Off Systern Sales (OSS) profits should not be considered in the SEET calculation. Accordingly, the Comniission found that a determination of the Companies' earnings as "significantly excessive" necessarily excludes the impacts of the cost deferrals and OSS margins.' Several Intervenors raised objections to or sought clarification of the Commission's rulings regarding the SEET. OCC contends that the impact of deferrals may not be removed from the SEET. Second, while OEG agrees that an adjustment regarding the impact of deferrals on the SEET is appropriate, it requests a clarification regarding how the adjustment will occur. Third, Kroger, OMA, and OEG object to excluding OSS margins from the SEET. a. OCC's Objection to Eliminating the Impact of FAC Cost Deferrals on the Conipanies Earnings When Applying'The SEET Is Meritless (OCC 20) 15 The Companies also requested additional clarification regarding the SEET and the scope of proposals that may be addressed in the upcoming workshop. Specifically, the Companies asked that the Commission clarify that treating them on a combined basis for purposes of the SEET and how that might be done is a proper stibject for the workshop. Thep also asked the Commission to confirm that the Commission's finding that a common methodology for the SEET is appropriate does not mean that the methodology must be identical for each utility. Companies' Application for Rabearing, at pages 40-41. 47 342 The Companies explained in their testimony and in their Initial Post-Hearing Brief, at pages 139-140, that the deferral of FAC costs, which enable the phase-in of rate increases, will produce earnings. Yet, the Companies further explained, the reality is that the Companies will not obtain revenues from customers at the time those deferral-created eamings are produced. They will receive revenues from customers that correspond to the deferrsl-related samings in future periods through the non-bypassable surcharge that allows tbem to recover the deferred costs. They pointed out that it would be inappropriate to base a finding of significantly excessive eamings on revenues that the Companies had not received and, worse, order them to return the revenues before customers had even paid them. The Commission agreed, and in its Order confirmed that such "paper" earnings should not be allowed to distort the SEET and, instead, should be exeluded from the test. OCC contends, at pages 67-68 of its rehearing application, that §4928.143(F), Ohio Rev. Code, prohibits the Commission from making this sensible adjustment, stating that "[t]here is no provision specifically perrnitting accounting adjustments for deferrals." Moreover, aCC contends, making such an adjustment would lead to a mismatch between expenses and revenues, and that the statute "does not permit the Commission to create such a distortion in earnings for the purpose of calculating the Test." OCC has gotten both points exactly wrong. The statute nowhere says that the Conunission may not, when determining what eamings to include in the calculation of the Companies' earned return, make an adjustment that is appropriate to obtain an accurate measure of earnings and, thus, an accurate measure of the earned return on equity. In any event, even if the statute was so rigidly interpreted as to preclude the 48 343 Commission from making such an adjustment to the earned return, there would be no barrier to the Commission's exercising its discretion to exclude deferral-created earnings from the detennination of what is "significantly excessive." b. The Comanission Should Provide the Clarificatian That OEG Seeks Regarding How The FAC Cost Deferrals Should Be Treated For SEET Purposes. (OEG 2) In the portion of its Order providing clarification as to how FAC deferrals would be treated in the context of the Significantly Excessive Earnings Test (SEET), the Commission noted "that deferrals should not have an impact on the SEET until the revenues associated with deferrals are received." (Order, p. 69). Based on that reasoning, the Commission held that "deferrals, as well as the related expenses associated with the deferrals," should be excluded from the SEET. (Id.) In its application for rehearing, OEG asks the Commission to claiify how deferrals will be incorporated in the SEET. Spec.7fically, OEG wants the Commission to clarify that during the deferral portion of the 10-year phase-in (2009-2011) all deferrals of expenses will be excluded from the SEET and during the recovery period of the phase- in (2012-2018) the amortization expenses associated with the amounts previously deferred i.e., the "re(ated expenses" to which the Commission referred, will be excluded. As OEG explains, were it not for the symmetrical treatment it proposes, the deferred FAC expenses "would reduce eamings twice instead of only once." Memorandum in Support, pp. 4-5). The Companies believe that the clarification sought by OEG is cons'rstent with the Commission's Order and nesults in the proper treatment of deferred FAC costs and related carrying costs in the SEET. Therefore, the Commission should provide the 49 344 clarification sougbt by OEG. In doing so it should be clear, however, that during the deferral portion of the phase-in (2009-2011), the SEET will reflect the actual FAC expenses, but will reflect only the FAC-related revenues that are collected. Auring the recovery period of the phase-in (2012-2018), the SEET will reflect the revenues to recover previously deferred FAC expenses and related earrying costs that are being recovered during that period. As explained by OEG, for accounting purposes the amortization of the deferral is an expense that will reduce eatnings. For SEET purposes, however, the amortization expense would need to be eliminated during the recovery period just as the deferral of expenses needs to be eliminated during the defeiral portion of the phase-in for SEET purposes. The one-time reduction of FAC expenses in the recovery portion of the phase-in by removing the amortization wili match the one-time elimination of the credit to FAC expense during the deferral portion of the phase-in. For these reasons, the clarification sought by OEG should be provided in the Commission's entry on rehearing. c. Inteevenors' Contention That Off System Sales Profits May Not Be Excluded From The SEET Is Meritless (OMA 2; OEG 1; Kroger 2) OMA, OEG, and Kroger claim that the Order erred by excluding Off-System Sales margins froin the SEET. OMA App. for Reh., at pages 4-5; oEG App. for Reh., at pages 1-4; Kroger App. for Reh., at pages 6-8. OMA contends that excluding OSS profits renders the "comparables" test a fiction. fJEG argues that it creates a fundamental asymmetry by comparing only a part of the Companies' eamings with the full earnings of the comparable companies. Kroger claims that the exclusion of the margins from the SEET is contrary to Ohio law, and that 50 345 the Commission did not adequately explain its decision to exclude the margins from the SEET_ Nevertheless, Kroger allows that, if the Commission would use the OSS margins as an offset to FAC costs, it would be appropriate to exclude those margins from the SEET_ The Intervenors' argument that the exclusion of OSS margins from the SEET renders the comparison of earned returns of the Companies and those of businesses that face comparable business and financial risks fictional, or asymmetrical, or otherwise in conflict with the requirements of §4928143(F), Ohio Rev. Code, misses the point. The Commission's Order concluded that it would be inappropriate to treat OSS margins, which result from wholesale sources, as being, or causing, significantly excessive earnings under the SEET. The Commission thoroughly explained its reasoning why the OSS margins should not be, nor lead to, significantly excessive eatnings. Accordingly, in order to effectuate that judgment, the Commission excluded the OSS margins from the SEET's calculations. Section 4928.143(F), Ohio Rev. Code, provides the Commission with the authority to make that,judgment, and it does not prevent the Commission from effectuating that decision in the manner the Commission has selected.16 Kroger also criticizes the Commission's observation that it is inconsistent for Intervenors to argue that 0SS margins should be used both to offset FAC costs and as a source of significantly excessive earnings. Kroger contends that by rejecting Intervenor requests to use OSS margins as an offset to FAC costs and then excluding them from the SEET, the Commission improperly has let the Companies "have it both ways." This criticism is not valid either. First of all, the Commission's observation - that Intervenors 16 Kroger s concession that, if the Commission would use OSS margins as an offset to FAC costs. Kroger would agree that the Commission should exclude the margins rmm the SEET belies the notion that the Commission is statutorily precluded from excluding the margins from the SSET. 51 346 arguments that OSS margins should be used to offset FAC costs are inconsistent with an argument that OSS margins should also be used, again, to eitlier inflate the Companies' earnings subject to the SEET or comprise "significantly excessive" earnings - is correct. Such arguments are not reconcilable because they would, essentially, credit customers with the same profits twice. However, it is not inconsistent to conclude, on the one hand, that OSS margins should not be used as an offset to FAC costs and to also conclude, on the other hand, that they should not be used in the SEET. In both cases, the rationale is that OSS margins should not be credited to (or shared) with customers as part of the ESP. Specifically, with regard to using those niargins as an offset against PAC costs, §4928.143(B)(2)(a), Ohio Rev. Code, which governs the FAC, does not provide for such an offset. With regard to using the margins in the SEET, the Commission properly concluded that such margins should not be considered, in any event, as being, or causing, significantly excessive earnings. Indeed, including OSS margins in the SELET, after having first concluded that they should not be an offset to FAC costs, would have amounted to a reversal of that first conclusion. Accordingly, the Commission's decision to exclude OSS margins from the SEET was completely consistent with its decision that they could not be used as an offset to FAC costs. CONCLUSION Except as specifically noted herein, the Intervenors' applications for rehearing should be denied. 52 347 Respectfully submitted, Marvin I Resnik. Steven T. Nourse Ameriean Electric Power Service Corporation 1 Riverside Plaza, 29n' Floor Columbus, Ohio 43215 Telephone: (614) 716-1606 Telephone: (614) 716-1608 Fax:(614)716-295© [email protected] [email protected] Daniel R. Conway Porter Wright Morris & Arthur Huntington Center 41 South High Street Columbus, Ohio 42315 Fax:(614)227-2100 [email protected] Attorneys for Columbus Southem Power Company and Ohio Power Compsny 53 348 CERTIFICATE OF SERVICE I hereby certify that a copy of Columbus Southern Power Company's and Ohio Power Company's Memorandum Contra Intervenor's Applications for Rehearing was served by electronic mail upon the individuals listed below this 27th day of April, 2009. Marvin I Resnik [email protected] [email protected] [email protected] [email protected] charliekina @ snavelY-kin-9.com david [email protected] mkurtz@bkilawfnmcom cvnthia:[email protected] dboehm@ kllawfirm.com [email protected] grad,v @ occ. state.oh. as [email protected] [email protected] oodman@ener marketers_com roberts@occ state.oh.as bsinnh@ intPgUsenerev.com idzkowski@occ state.ah.us [email protected] [email protected] [email protected] dconwayDorterwricoin [email protected] ibentine@ cwslaw.com apetersen Co? sasllp.com nyurickocwsiaw.com [email protected] mwhite @cwslaw.com [email protected] khiggins @energystrat.corn sbl [email protected] [email protected] todonnell @bricker.com eary.a ieffriesCwdom.com cvincr@snnnenschein com [email protected] [email protected] [email protected] ehand @ sonnenschein.com heiuyeck6arE@aolcom erii @ sonnenschein.com [email protected] tomm r,[email protected] [email protected] [email protected] [email protected] steven. @mor anstanle .com ed.hess@ouc state oh us dmancinoCrPmwe.com thomas lindQrenCaJnuc state oh.us ¢[email protected] werner [email protected] [email protected] }ohn ionesftuc state.oh.us stephen [email protected] [email protected] 1p,[email protected] lmcalisterVmwncmh.com [email protected] [email protected] [email protected] [email protected] [email protected] [email protected] [email protected] [email protected] 349 BEFORE THE PUBLIC UTILITY COMMISSION OF OHIO In the Matter of the Application of Columbus Soutltern Power Company for Approval of an Iaectric Secm-ity Plan; an Amendment to Case No. 08-917-EL-SSO its Corporate Separation PEan; and the Sale or Transfer of Certain Generating Assets. Cn the Matter of the Applieation of Ohio Power Conipany for Approval of its Electric Case No. 08-918-F,I, SSO Security Plan; and an Aniendment to its Corporate Separation Plan. COLUMBUS SOUTHERN POWER COMPANY'S APPLICATION FOR REHEARING Pursuant to §4903.10, Ohio Rev. Code, and §4901-1-35 (A), Oliio Admin, Code, Columbus Southern Power Cotnpany (CSP) seeks rehearing of the Commission's July 23, 2009 Entry on Rchearing. The Commission's Entry on Rehearing reversing its Vtarch 18, 2009, Opinion and Order in this proceeding regarding CSP's proposal to sell or transfer its Waterford Energy Center (Waterford) and Darhy Electtic Genei-ating Station (Darby) is unlawfiil and unreasonable. On rehearing, since the Commission revokecl CSP's authority to recover its customers' jurisdictional share of the costs associatecl with maintaining and operating Waterford and Darby, the Commission should concw•rently exercise its autliority under §4928.17 (B), Ohio Rev. Code, to authoiize CSP to scl! or transfer these two faci(ities. This i.s to certify that the 9,au3g66 apgear3nq atj,-^ M aocuraGe and coaqple,tfa reprUductioai of a aase file dacument dal.ivored in riica ,eaou,7,ai courae of busineai$ Techairian ^_ ^? _ __ Data Pr.ocesae$ _ 1Z.5 t D q 350 MEMORANDUM IN SUPPORT OF REHEARING In its March 18, 2009, flpinion and Order, the Commission stated: [f the Conunission is going to require that the electric utilities retain these generating assets, then the Connnission should also allow the Coinpanies to recover Ohio customers' jurisdictional share of any costs associated with niaintaining and operating such facilities. (Opinion and Order, p. 52). 'I'his ruling resulted from CSP's proposal to acquire authority to sell or transfer these mercantile generating facilities. As CSP's witness, Mr, Baker, explained, the Waterford plant was purchased in 2005 and Darhy was purchased in 2007. (Co. Cx. 2 A, p, 42). "Neither of these units have ever been in CSP's rate base and custoniers' generation rates have not reflected CSP's investment in the plants or the expenses of operating and maintaining the plants." (Id.) With no rate recovery, these plants were purchased in anticipation of generation rates being marlcet-based under SB 3. CSP "took thc rislc on these plants and therefore, ... its appropriate for us to have the authority to, if we choose, to transfe• or sell the assets at our discretion." (Tr. XIV; p. 155). In rebuttal testimony, Mr. Baker testified that if CSP is prohibited from selling or transfen•ing these nrits, any expense not recovered in the Fuel Adjustment Clause (FAC) should be recovered in the non-FAC rate. (Co. Ex. 2 E, p. 21). In its March 18, 2009, Opinion and Order, the Commission denied CSP the authority it sought under §4928.17 (E), Oliio Rev. Code. However, based on its reasoning quoted above, it author-ized cost rccovery associated with Waterford and 2 351 Darby. The Com pany viewed the Cotnmission's ruting as a fair balance regarding that issue and did not challcngc the ruling on rehearing. Now, however, the Comntission's Entry on Relzearing has completely upset the balance it struck in its Opinioti and Order. If the Comntissiotl were going to revoke the ratc authorization it provicled in the Opinion and Order it also should have reconsidered its ruling as it related to authority to sell or tt-arisfer the Waterford and Darby facilities and granted CSP thc authority it sought under §4928.17 (E), Ohio Rev. Code, regarding Waterford and Darby. Having failed to do so, thc Commission's orders are umeasonable anct unlawfitl and should be modiCed on rehearing to authoriz,e the sale or transfer of Waterlord atut Darby. [t is tulreasonable to force CSP to keep these generating units and not be able to t-ccover aiiy costs associated with these units. The Commission already has recognized this. Therefore, with the cost recovety pt-ovisiort of the Opinion and Order being revoked on rehearing, the fair and reasonable course of action now is to authorize CSP to sell or iransfer those units. Authorization of a sale or transfet- also is legally required if the Commission is not allowing cost rccovery associated with these merchant plans. The unbundling process required by S.B. 3 resulted in a generation rate that reflected previously-detennined cost recovery for CSP's geneiating facilities. T'lie generation rates under the "rate platt" (tlie Standard Service Offer in effect on the effective date of S.B. 221) did not include recovcry of costs associated with maiutaining and operating Waterford or Darby or of a rettn-n on CSP's investment in those plants. With the Commission's reversal in its Entry on Rehearing of ihe Waterford and Darby cost recovery, CSP is unlawfully put in the 3 352 position of being required to i-etain these facilities but not being permitted to make any adjustment to the rate plan i-ate to recover costs of maintaining and operating those units or recovei- a retui-n on the investinent in those pla its. On rehearing the Conimission should rectify this unlawful situation by granting CSP the authority it sought in the proccecling to sell or transfer Waterford and Darby. Respectfully ubniitted, ^^,x-•C. e-^-- rX^= ^^^ Marvin I. Resnik Steven T. Nonrse American Electric Power Service Cotlioration I Riverside Plaza, 29"' Floor Columbus, Ohio 43215 Teleplione: (614) 7t6-1606 Telephone: (614) 716-1608 Fax: (614) 716-2950 Eniail: tniresnik@ae^m [email protected] Daniel R. Conway Porter Wright Morris & A-thui- Huntington Center 41 South High Street Columbus, Ohio 42315 Fax: (614) 227-2100 clconwaY(c^^porterwrig_ n t conl Counsel for Columbus Southern Power Company and Ohio Power Cornpany 4 353 CERTIFICATE OF SERVICE 1 hereby certify that a copy of Columbus Southern Power Conlpany's and Ohio Power Company's Application for IZehearing was served by electronic mail upon the individuals listed below this 31 " day of.fuly 2009. Ivlarvin I. Resnilc sharon cYkemt.com ricks0eohanet.or Ikollcn rJlicno.com tobrien c brioker.com charlickin=r rranavely_kin^.com david fein{c^)constellation.eom mknrtr ci?blzllawfrm.com cvnthia.a.fonner aonstellation.com .dboehm ckbkllawfirrn.com mb eti•igoff(cyss.eoni ggu^v( occ.state.nh,ns smhoward(cr?,vssp, com ettcr cc oeastate,oh.us c oodman c ener marketeis.com roberts idocc.statc,oh.us bsin h c integtvsenerQy.COm i d zk owsk i[occ. statc. o h, us lbell33 a,aol.corn stnou-tsc c^ac^cCni kschmidt c ohionifg . con-j dconwa u)porlcrwri^ht.com sdchrof'Fc sasilp.com 'bentine ^cwslrtw.com a etersen sasllp.com Myurick cJcwslawcom sromeo(crsasllp.com mtivhitc u cvvslaw•cmn bedwards c aldenlawnet klr =rins (kcner==ystrat.cont shloomfreIdQcbriclcer.com barthroVcrCcl)ao l. com todonnell cr^briclcer.com eat' .[l.^CfCI9eS Ct dOm.eonl cvinee sonnenschein.corn nnroser cDtheOGC. -orsy p reed c^satmenscheiti.com tttint u.thcOLC,= ehanc^ sonnenschein.com henryeckharl (iDaol.com erii c son»cnschein.coon tiedfor(i (c?fuse.net tounn ^^.temple(c^ormet.com rstanliold cr,nr•dc.m^^ kganlarra(r^wras soc. com dsullivam c nrdc.or) steven.ltuhman r morp an stan€e .cotn ttm^ny teukcntonCcr7puastate,oh.us dmancino a.rnwe,coin thomas.lindmren u).puc.state.oh.us ^ 1awtence c mwecom wcr^icr.mar=d ^i? auc.state.oh us wung a mwe conr john:ioncs c>>uc.stateoh.us ste}?hen.chriss wal-mart.com s unCrbmwncmh.com I earhardt ofb.f.org In^calisie3'^i^mwncmh.com emiller a szd.com Iclark c mwncmh.com dunn c sAcom drinebo(l c,nolcom a orter .szd.com ct^zooney2^?columUus.rr.con3 5 354 Lawriter - OAC - 4901:1-37-09 Sale or transfer of generating assets. Page 1 of 1 4901:1-37-09 Sale or transfer of generating assets. (A) Consistent with division (E) of section 4928.17 of the Revised Code, an electric utility shall not sell or transfer any generating asset it wholly or partly owns without prior commission approval. (B) An electric utility may apply for commission approval to sell or transfer its generating assets by filing an application to sell or transfer. (C) An application to sell or transfer generating assets shall, at a minimum: (1) Clearly set forth the object and purpose of the sale or transfer, and the terms and conditions of the same. (2) Demonstrate how the sale or transfer will affect the current and future standard service offer established pursuant to section 4928.141 of the Revised Code. (3) Demonstrate how the proposed sale or transfer will affect the public interest. (4) State the fair market value and book value of all property to be transferred from the electric util Y, and state how the fair market value was determined. (D) Upon the filing of such application, the commission may fix a time and place for a hearing if the application appears to be unjust, unreasonable, or not in the public interest. The commission shall fix a time and place for a hearing with respect to any application that proposes to alter the jurisdiction of the commission over a generation asset. (E) If, after such hearing or in the case that no hearing is required, the commission is satisfied that the sale or transfer is just, reasonable, and in the public interest, it shall issue an order approving the application to sell or transfer. (F) Staff shall have access to all books, accounts, and/or other pertinent records maintained by the transferor and transferee as related to the application to sell or transfer generating assets and in accordance with rule 4901:1-37-07 of the Administrative Code. Replaces: 4901:1-20-16 Effective : 04/02/2009 R.C. 119.032 review dates: 09/30/2013 Promulgated Under: 111.15 Statutory Authority: 4928.17, 4928.06 Rule Amplifies: 4928.17 Prior Effective Dates: 3/10/00, 10/23/04 355 http://codes.ohio.gov/oac/4901 `/`3AI-37-09 3/9/2010 PROOF OF SERVICE I certify that Columbus Southern Power Con2pany's Merit Brief and Appendix of Appellant was served by First Class U.S. Mail upon counscl identified below for all parties of record this 19`h day of March, 2010. Maivin 1. Resnik, Counsel of Record Richard Cordray Janine L. Migden-Ostrander Attorney General of Ohio Consumers' Counsel Duane W. Luckey Terry Etter Cbief, Public Utilities Section Counsel of Record Werner L. Margard llJ Maureen R. Grady Thomas G. Lindgren Assistant Consumers' Counsel John H. Jones Office of the Ohio Consumers' Counsel Assistant Attorncys General 10 West Broad Street, Suite 1800 180 East Broad Street Cohimbus, Ohio 43215-3485 Columbus, Ohio 43 21 5-3 793 Counsel for Intervening Appellee, Counsel for Appellee, Office of the Ohio Consumers' Counsel Pnblic Utilities Commission of Ohio Samuel C. Randazzo David F. Boehm Lisa G. McAlister Michael L. Kurtz Joscph M. Clark Boehm Kurtz & Lowry McNees Wallace & Nw-iek LLC 36 East Seventh Street, Suite 1510 21 East State Street, 17`}' Floor Cincinnati, Ohio 45202 Columbus, Ohio 43215 Counsel for Intervening Appellee Ohio Counsel for hitervening Appellee Energy Group Industrial Energy Users-Ohionatural gas combined cycle power plant, on September 28, 2005, which has a generating capacity of 821 MW (Cos. App. at 14). On April 25, 2007, CSP purchased the Darby Electric Generating Station, a natural gas simple cycle generating facility, with a generating capacity of 4601VIW and a summer capacity of approximately 450 MW (Id.). Although AEP-t)hio is requesting authority to transfer these generating assets pursuant ta 5ection 4928.17(F), Revised Code, C57' has no iunmediate plans to sell or transfer the generating facilities. If AEP-Ohio obtains authorizatiun to sell these generating assets through this proceeding, AEY-fJhio will notify the Commission prior to any such transaction (Id. at 15).