Supreme Court of Ohio Clerk of Court - Filed May 21, 2018 - Case No. 2018-0379
IN THE SUPREME COURT OF OHIO
OHIO EDISON COMPANY, THE ) CLEVELAND ELECTRIC ) CASE NO. 2018-0379 ILLUMINATING COMPANY, AND THE ) TOLEDO EDISON COMPANY ) Appeal from the Public Utilities ) Commission of Ohio Appellants, ) ) Public Utilities Commission of Ohio Case v. ) No. 16-0743-EL-POR ) PUBLIC UTILITIES COMMISSION OF ) In the Matter of the Application of the Ohio OHIO ) Edison Company, The Cleveland Electric ) Illuminating Company, and The Toledo Appellee. ) Edison Company for Approval of Their ) Energy Efficiency and Peak Demand ) Reduction Program Portfolio Plans for ) 2017 through 2019.
MERIT BRIEF OF APPELLANTS OHIO EDISON COMPANY, THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, AND THE TOLEDO EDISON COMPANY (VOLUME III of III)
Michael R. Gladman (Reg. No. 0059797) Michael DeWine (Reg. No. 009181) (Counsel of Record) Attorney General of Ohio Sergio A. Tostado (Reg. No. 0088376) JONES DAY William L. Wright (Reg. No. 0018010) 325 John H. McConnell Blvd., Suite 600 Section Chief, Public Utilities Section Columbus, Ohio 43215 Telephone: 614-281-3865 John H. Jones (Reg. No. 0051913) Facsimile: 614-461-4198 Assistant Section Chief [email protected] Public Utilities Section [email protected] Public Utilities Commission of Ohio 30 East Broad Street, 16th Floor Joshua R. Eckert (Reg. No. 0095715) Columbus, Ohio 43215-3793 FirstEnergy Service Company Telephone: 614-466-4397 76 South Main Street Facsimile: 614-644-8767 Akron, Ohio 44038 [email protected] Telephone: 973-401-8838 [email protected] [email protected]
COUNSEL FOR APPELLANTS OHIO EDISON COUNSEL FOR APPELLEE PUBLIC COMPANY, THE TOLEDO EDISON COMPANY, UTILITIES COMMISSION OF OHIO AND THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
Madeline Fleisher Bruce Weston (Reg. No. 0016973) (Counsel of Record) The Office of The Ohio Consumers’ ENVIRONMENTAL LAW & Counsel POLICY CENTER 21 W. Broad St., 8th Floor Christopher Healey (Reg. No. 0086027) Columbus, OH 43215 (Counsel of Record) Telephone: 614-569-3827 Zachary E. Woltz (Reg. No. 0096669) [email protected] THE OFFICE OF THE OHIO CONSUMERS’ COUNSEL COUNSEL FOR APPELLANT ENVIRONMENTAL 65 East State Street, Suite 700 LAW & POLICY CENTER Columbus, Ohio 43215 Telephone: 614-466-9571 Miranda R. Leppla (Reg. No. 0086351) Facsimile: 614-6466-9475 (Counsel of Record) [email protected] OHIO ENVIRONMENTAL COUNCIL [email protected] 1145 Chesapeake Drive, Suite I Columbus, OH 43212 Telephone: 614-487-5825 COUNSEL FOR APPELLEE THE OFFICE OF [email protected] THE OHIO CONSUMERS’ COUNSEL
COUNSEL FOR APPELLANT OHIO ENVIRONMENTAL COUNCIL
Robert T. Dove (Reg. No. 0092019) (Counsel of Record) THE LAW OFFICE OF ROBERT DOVE P.O. Box 13442 Columbus, OH 43213 Telephone: 614-943-3683 [email protected]
COUNSEL FOR APPELLANT NATURAL RESOURCES DEFENSE COUNCIL
-2- 14-1297-EL-SSO -49- with the significant risk of an increased cost of equity falling on FES (Co. Ex. 141 at 4-5; Tr. Vol. XXXII at 6542-43, 6557-58, 6616; Tr. Vol. I at 35-36; Tr. Vol. XVIII at 3621-22; Co. Ex. 27 at 10-11; Co. Ex. 33 at 8; Co. Ex. 156 at 13). Moreover, FhstEnergy asserts that the record demonsttates the reasonableness of the initially proffered 11.15 percent ROE, and so, an even lower negotiated ROE would be a significant benefit to customers (Co. Ex. 27 at 3-5; Tr. Vol. X at 2064).
OCC/NOAC, RESA, Dynegy, Cleveland, and Sierra Club contend that the Commission should not consider the illusory promise of rate stability as a qualitative benefit to customers under Stipulated ESP IV, as the Companies have offered no guarantee, and have failed to establish with any degree of certainty, that Rider RRS wUl produce a net credit to customers to offset market volatility, on an annual or aggregate basis (OCC/NOPEC Ex. 4 at 49-52; Sierra Club Ex. 95; P3/EPSA Ex. 12 at 5-6, 20; RESA Ex. 6 at 7-8). Instead, Dynegy, Cleveland, Power4Schools, Exelon, and OCC/NOAC propose that a CBP should be conducted for the capacity and energy that the Companies wish to include in Rider RRS. Furthermore, Envirorunental Groups, OCC/NOAC, RESA, Power4SchooIs and Sierra Club contend that FirstEnergy has failed to provide sufficient evidence to support the existence of benefits from the RRS or Stipulated ESP IV, specifically by failing to show that customers are actaally exposed to any volatility or that, if so, customers lack adequate tools, including energy efficiency measures, to address it (Tr. Vol. IV at 704, 706-07; Tr. Vol. VI at 1198-99; P3/EPSA Ex. 5 at 24; OCC/NOPEC Ex. 4 at 51-52; Sierra Club Ex. 84; Co. Ex. 13 at 14). In fact, OCC/NOAC contend no such volatility exists as SSO customers' rates are generally stable over time resulting from various competitive auctions (OCC/NOPEC Ex. 4 at 49-51). Moreover, NOPEC, OCC/NOAC, and Sierra Club also agree to the extent that customers are facing such volatility, there are adequate and less costly measures in place to mitigate such risk, noting CRES customers are protected through multi-year conttacts and SSO customers are protected by the laddered CBP auctions (OCC/NOPEC Ex. 4 at 49-52; Staff Ex. 12 at 14). Exelon also argues that the Comparues' promise of rate stabilit}' is illusory as the PPA is simply an effort to bolster FES' balance sheet and ensures FES will no longer be subject to PJM's capacity performance product penalties (Dynegy Ex. 1 at 9-10; Tr. Vol. XXXVI at 7704-09).
ii. Projected Ouantitative Benefits
FirstEnergy asserts the proposed PPA between the Companies and FES was the subject of extensive due diligence and negotiations conducted at arm's length, emphasizing that the individuals assigned to evaluate the PPA (EDU Team) collected cost information and operational data of the Plants, produced and verified various cost projections, and benchmarked those projections against industty data. The Companies then compared these confirmed costs with the projected revenues based on the energy, capacity, and carbon price forecasts of FirstEnergy witaess Rose. (Co. Ex. 33 at 4-5; Tr.
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Vol. Xni at 2761-68, 2787-89, 2885-89.) FirstEnergy contends that the forecasts and cost data were reasonable to rely upon, and the amount by which projected market prices consistently exceeded projected variable costs enabled the EDU Team to independently corroborate the revenue projections FES provided to the Comparues (Tr. Vol. XIII at 2773- 2774). FirstEnergy also states that during this process, the EDU Team consulted FirstEnergy witaess Murley for an analysis of the Plants' local and regional economic impacts (Tr. Vol. XIII at 2790-91). The EDU Team concluded that, based on the cost and revenue projections, as well as the modified term oi eight years. Rider RRS could potentially create a nominal benefit to customers of $561 million, or $260 million, net present value (NPV), while also noting that Rider RRS would continue to effectively hedge against market prices in the event the forecasts were incorrect (Sierra Club Ex. 89; Co. Ex. 155 at 12; Co. Ex. 33, Attachment JAR-l(Revised); Tr. Vol. XIII at 2769-77, 2896).
Although there were several projected credits or charges resulting from Rider RRS in this proceeding, FirstEnergy additionally notes that its projection is the only one that utilized a probability-weighted methodology, or expected value analysis, indicating that this fact alone would make the Companies' projection the only credible analysis. Moreover, FirstEnergy argues that its forecasts remain reliable, despite short-term changes in the energy and capacity markets. According to FirstEnergy, unexpected short-term changes in nataral gas prices would not necessarily dictate the energy pricing forecasts, as the nataral gas market is exttemely volatile and the short-term price changes would do little, if anything, to discredit the long-term ttends that indicate nataral gas prices will significantly increase over the duration of Rider RRS. (Co. Ex. 151 at 31-42; Tr. Vol. XXXV at 7327; Tr. Vol. XXXVIll at 8293-94.) In fact, FirstEnergy adds that coal has historically been the primary driver of electtical energy prices in Ohio (Co. Ex. 151 at 13). Additionally, FirstEnergy argues that market fundamentals also demonsttate the reliability of FirstEnergy witaess Rose's projections, noting that the modeling utilized by FirstEnergy witaess Rose also evaluated key supply and demand parameters, including the decrease in recent drilling activities for nataral gas (Co. Ex. 151 at 31-42). As such, FirstEnergy alleges the intervenors were very short-sighted in their contention that the forecasts are stale, and thus, the Commission should not rely on their projections. FirstEnergy also notes that, despite several intervenor arguments that the capacity performance requirements would sigruficantly increase capacity prices in the near futare, its capacity projections are equally reliable, noting that the PJM restticted peak load, or the actaal load required from generation owners, is unlikely to change during the term of Rider RRS and recent developments in the capacity market only bolster the capacity price projections (Co. Ex. 151 at 20-23; Tr. Vol. XXXIX at 8301). In fact, FttstEnergy contends that the capacity performance requirements will provide a substantial benefit to customers, rather than a cost (Co. Ex. 25; Co. Ex. 182; Co. Ex. 183; Tr. Vol. X at 2140-45, 2157-58). As for the various arguments regarding the lack of a sensitivity analysis, FirstEnergy notes that ICF was practically incapable to conduct such an analysis, given the natare of the complex and numerous variables used in its analysis, while also noting that
APP. 283 14-1297-EL-SSO -51^ its reliance on one single forecast would be appropriate in this case since it is a probability- weighted analysis which gives due consideration to uncertainty in various scenarios (Co. Ex. 151 at 9-10; Co. Ex. 17 at 6; Tr. Vol. XXXV at 7273-75, 7278, 7451-52; Tr. Vol. VI at 1145- 46). FirstEnergy argues this is also the reason FirstEnergy witaess Lisowski determined a sensitivity analysis was unnecessary for his dispatch model for the expected costs of the Plants and OVEC entitlement uruts, in addition to the fact he was provided with only one set of inputs (Tr. Vol. VIII at 1636). In fact, FirstEnergy alleges that the intervenors' various arguments regarding the analyses utilized by FirstEnergy witaesses Rose and Lisowski only demonsttates their lack of understanding of the methodology and industry practices used in such analyses.
As noted above, FirstEnergy does not believe the conttadicting analyses of various intervenor witaesses should be considered by the Commission, but in the event the Corrunission wishes to determine their respective reliability, FirstEnergy notes that the scenario utilized by OCC/NOPEC witaess Wilson that applied the U.S. Energy Information Admirusttation (EIA) 2014 and 2015 Annual Energy Outlook Reference Cases and tinderlying data (AEO Reference Cases) would be the most appropriate alternative, as these results proved to be very similar to that of an expected value analysis (Co. Ex. 151 at 42; Co. Ex. 60 at ii-iii; Tr. Vol. XXII at 4544-45). FirstEnergy also notes that the AEO Reference Cases project that nataral gas prices will rise (Co. Ex. 151 at 39), However, FirstEnergy argues the difference between the Companies' projectioris and the AEO Reference Cases is misleading, as OCC/NOPEC witaess Wilson failed to change the implied heat rate^ when he adjusted the nataral gas prices, wrongly assuming that this relationship would remain corrstant over time (Tr. Vol. XXII at 4546; Tr. Vol. XXXV at 7443; Co. Ex. 151 at 10). Additionally, FirstEnergy notes that OCC/NOPEC witaess Wilson failed to present any independent forecasts of energy, capacity, or nataral gas prices (Tr. Vol. XXII at 4542). Accordingly, FirstEnergy provides that its projections for the potential credit arising under Rider RRS are the most accurate and should be given their due consideration by the Commission.
Sierra Club, RESA, OCC/NOAC, OMAEG, CMSD, and Exelon contend that FirstEnergy failed to definitively show that customers would receive a net credit over the eight-year term of Rider RRS; rather, the evidence presented in the record demonsttates that customers will likely lose hundreds of millions of dollars, ranging from $793 million to $2.97 billion, NPV (Sierra Club Ex. 95 at 1, 3-4, 7, 19; P3/EPSA Ex. 12 at 13; OCC/NOPEC Ex. 9 at 12; OCC/NOPEC Ex. 11 at 18). Sierra Club argues that several factors have significantly changed in the market and regulatory framework since the forecasts and assumptions upon which the Companies based their projections of charges and credits under RRS were made, which would make such projections outdated and uiu-eliable (Sierra Club Ex. 95 at 11; Sierra Club Ex. 73 at 29; Co. Ex. 17 at 13; P3/EPSA Ex.
The implied heat rate is the ratio of electrical energy prices in the marketplace to gas prices.
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12 at 17; OCC/NOPEC Ex, 9 at 12; Tr. Vol. XXXV at 7228). Specifically, Sierra Club and Envirorunental Groups assert that FirstEnergy's projection of credits and charges under Rider RRS is based on market energy, nataral gas, and capacity price forecasts that are outdated, unreasonably high, and already proving to be wrong (Co. Ex. 171 at 88; Sierra Club Ex. 95 at 12,17; Tr. Vol. VI at 1140-47,1228-29; Sierra Club Ex. 88; Sierra Club Ex. 89; Tr. Vol. XXXV at 7258-64). Provided these projections are not accurate. Sierra Club contends these prices would have a significant impact on the ultimate result of Rider RRS (Sierra Club Ex. 9 at 18; Sierra Club Ex. 95 at 12-14; P3/EPSA Ex. 12 at 22). Additionally, Sierra Club and Envirorunental Groups argue the projected costs of the Plants and OVEC entitlement units are unsupported and disregard inevitable environmental compliance costs, while also echoing the concerns of other parties that the Comparues' projection utilized an unsophisticated single dispatch modeling run without the benefit of any accompanying sensitivity analyses or alternative scenarios to develop a range oi asset valuations or the means to verify the results independently by another party (Sierra Club Ex. 95 at 4; Sierra Club Ex. 89; Tr. Vol. VIII at 1559-62,1566-67,1577-80, 1583,1591; Sierra Club Ex. 69 at 9-10; Tr. Vol. X at 2227-2231). Sierra Ciub concludes by stating that other projections using more accurate information offered in this proceeding should be given more weight by the Commission as it determines the actaal benefit or cost of Rider RRS to customers (P3/EPSA Ex. 12 at 17; OCC/NOPEC Ex. 9 at 12). Exelon goes even further to state that its offer, as a more realistic, competitively-based market offer, proves that the Companies' forecast is inaccurate and could be exttemely dettimental to the Companies' customers (Exelon Ex. 4 at 2, 7; Tr. Vol. XXXVII at 7828-33).
Environmental Groups, Exelon, and CMSD also contend that the Companies' Rider RRS projection lacks any reference points for evaluating the magnitade of customer risk or the reasonableness of the proposed PPA terms, noting that this analysis would be consistent with FERC precedent, while also adding that the Companies failed to conduct any competitive or market procurement or even evaluate alternative resources of its own to determine whether the PPA proposal was reasonable (Tr. Vol. XIII at 2745-2750; Co. Ex. 33 at 4-5). Based on testimony presented at hearing, Environmental Groups also state that the Plants' costs are likely to be higher than projected, noting significant regulatory changes by the U.S. EPA would likely require additional action on behalf of the Plants to reach comphance (Tr. Vol. XIX at 3803-3807; Tr. Vol. XIl at 2548-49; Sierra Club Ex. 69 at 39-43; OCC Ex. 20 at 8-9). OCC/NOAC also provide that the uncertainty oi these looming regulations make it even more unlikely that the costs projected are accurate for the Plants (OCC/NOPEC Ex. 20 at 19; OCC Ex. 20 at 3). Environmental Groups also argue that Rider RRS may also reduce the benefits of efficiency and peak demand reduction for FirstEnergy customers and the general public since these types of programs would essentially lower the revenues of the Plants, and thus, lower the amount to net against the costs (ELPC Ex. 28 at 22). IMM additionally argues Ohio consumers could also be disadvantaged by the foreseeable iederal response to the Rider RRS, if approved. Specifically, IMM argues that federal action will be necessary to address the impact on competitive markets of subsidies.
APP. 285 14-1297-EL-SSO -53- effectively expanding the Minimum Offer Pricing Rule (MOPR) to address all cases where subsidies create an incentive to offer capacity into the PJM Capacity Market at less than an unsubsidized, competitive offer. As a result, IMM warns there would be no market revenues to offset the costs they would be required to pay under the Rider RRS, thus exacerbating the charges derived from Rider RRS.
iii. Additional Protections Recognized in the Proposed PPA
The Companies also assert the EDU Team negotiated several other protections for customers, including the Companies' ability to audit costs charged to the Companies, review and conunent on FES' capital improvement plan and scheduled outage program, withhold consent for any accelerated depreciation, and hold FFS subject to a standard of good utility practice for any operating costs incurred (Co. Ex. 156 at 3, 9-10; Co. Ex. 33 at 9; Tr. Vol. XIII at 2781-82; Tr. Vol. 2878-82; Tr. Vol. XXIV at 4879; Tr. Vol. at XXX at 6301; Tr. Vol. XIV at 3000-3003; Tr. Vol. XXI at 4066; Tr. Vol. at 4233-34; Tr. Vol. at XXVIII at 5620-21; Tr. Vol. XXXI at 6418). Additionally, FirstEnergy argues that Rider RRS is not an anti competitive subsidy, noting that it is supported by a market negotiated cost-based conttact and such conttacts are common and frequently used in the industty as a Commission approved-means to mitigate and manage risk (Tr. Vol. XXI at 4169). The Companies also assert that the material provisions of the PPA are final and the Companies are not at risk from unilateral termination of the agreement (Co. Ex. 156; Co. Ex. 141 at 6; Tr. Vol. XXXIl at 6567). Moreover, the Companies assert that there are substantial incentives for them to maximize revenues, as well as for FES to conttol costs (Co. Ex. 156; Tr. Vol. XIII at 2809-10; Tr. Vol. XIV at 3002, 3033; Tr. Vol. XXXVI at 7686-87; Tr. Vol. XXII at 4532-33; Co. Ex. 155 at 4).
Sierra Club and Cleveland contend that the very sttuctare of FirstEnergy's proposal exacerbates the financial risk of Rider RRS and the protective provisions alleged by FirstEnergy will not shield customers (Co. Ex. 156; Tr. Vol. I at 40; Tr. Vol. XI at 2333). Sierra Club also notes that no final PPA has yet been created, and, thus, any alleged protections are not necessarily guaranteed to be included in the finalized agreement (Tr. Vol, I at 56-57; Tr. Vol. XIII at 2750-51; Tr. Vol. XXXVI at 7526-27). Even in the event the term sheet is finalized. Sierra Club states that it exposes customers to additional financial risks as it excuses FES' provision of energy, capacity, and ancillary services during many unit outages, allows FES to continue to conttol capital expenditares, which will not be subject to the good utUity practices standard, and omits any protections against modification or early termination oi the PPA (Co. Ex. 156 at 2-6, 10; Sierra Club Ex. 89; Tr. Vol. I at 81; Tr. Vol. VI at 2296-98; Tr. Vol. XI at 2284-86, 2472; Tr. Vol. Ill at 530, 535-36, 2783-84). Sierra Club further asserts the Companies failed to adequately define or quantify the legacy costs for which they are seeking approval, and notes these costs would not be subject to audit or prudency review in futare Commission proceedings (Tr. Vol. I at 79, 88, 92-93; Co. Ex. 7 at 14-15). As for the actaal negotiation. Sierra Club argues that the
APP. 286 14-1297-EL-SSO -54-
PPA was not the result of an arm's length ttansaction since the Companies consistently failed to independently verify FES' information or consider alternatives that would better serve their customers (Sierra Club Ex. 52 at 2; Tr. Vol. XIII at 2754, 2765-66, 2834-35). Finally, Sierra Club contends that the Comparues failed to adequately evaluate, scrutinize, and negotiate the terms of the PPA in order to protect consumers in the Companies' service territories, noting that the Companies conducted their review in an inwardly focused fashion without sufficient insttuction or information or the consideration of any alternative proposals or options (Tr. Vol. XIII at 2758-60, 2766-67,1776-77, 2830, 2843, 2861- 62,2871).
iv. Generation Resource Diversity
FirstEnergy, MSC, OEG, and Nucor further assert the Economic Stability Program benefits customers and is in the public interest because it enhances reliability by preserving and promoting generation resource diversity, which includes both fuel and asset diversity. FirstEnergy notes that maintaining adequate generation resource diversity will effectively maximize the sttengths that each type of resource exhibits. (Co. Ex. 28 at 6.) Further, FirstEnergy states that the Corrunission needs to be aware of the resource diversity within Ohio in order to effectively balance those resources, especially due to the increased reliance on gas-fired generation in the PJM markets (Co. Ex. 28 at 4, 7-%; Tr. Vol. X at 2217; Tr. Vol. XXX at 6278-79). Along these same lines, FirstEnergy contends that maintaining adequate generation resource diversity is important to avoid potential catasttophic reliability issues related to over-reliance on any single class of generation, such as nataral gas generation (Co. Ex. 28 at 7-8). FirstEnergy further maintains that generation assets fueled by interruptible gas supplies were not intended or designed to replace baseload coal and nuclear units, and moreover, are not adequate to handle the total load or to provide continuous service for prolonged periods (Co. Ex. 13 at 8; Tr. Vol. IV at 756-757). FirstEnergy asserts that Rider RRS will enable baseload generating units to remain online, and thus, encourage a more diverse and reliable supply of generation. Additionally, FirstEnergy alleges the generation resource diversity provided by the Plants will further conttibute to retail rate stability, as diversification of the generating assets will promote lower and more stable fuel costs. (Co. Ex. 28 at 6-7; Co. Ex. 42 at 13; Tr. Vol. XXI at 4205; Tr. Vol. XXV at 4941-42; Tr. Vol. XXVIII at 5643.) The Companies note that nataral gas prices are subject to extteme volatility and an over-reliance on nataral gas generating assets would lead to higher wholesale and retail prices when nataral gas prices inevitably rise (Co. Ex. 28 at 7; Tr. Vol. VI at 1168; Co. Ex. 151 at 30; see also Tr. Vol XXV at 4939).
OCC/NOAC and Power4Schools argue that the Commission should not consider an increase in reliability and fuel diversity as a qualitative benefit to customers under Stipulated ESP IV, noting the PJM wholesale markets are wholly adequate to address the reliability and fuel diversity needs of the grid and it is not the Commission's responsibility to maintain generation reliability (OCC/NOPEC Ex. 7 at 28-29, 53; Tr. Vol. XXX at 6266).
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Sierra Club, Exelon, and Dynegy contend that these resource diversity benefits are also illusory, noting these benefits wrongfully assume that the Plants would retire in the absence of Rider RRS, but would nonetheless be meritless in the event this assumption were ttue. Exelon specifically notes that FES has no power to retire the OVEC entitlement units and the Companies continue to aver that the Plants are, and will continue to remain, competitive in both energy and capacity markets. (P3/EPSA Ex. 1 at 42; Tr. Vol. XXXIII at 6686; Tr. Vol. XI at 2305; Tr. Vol. II at 414.) Sierra Club and Dynegy add that no FirstEnergy witaess was able to identify the optimal generation mix for Ohio, and still others testified about resource diversity without knowing the current generation mix (Tr. Vol IV at 752, 785-86; Tr. Vol. XI at 2254, 2311-12; Tr. Vol. XVII at 3502, 3506; Sierra Club Ex. 7.) Sierra Club further asserts that FirstEnergy's claims regarding the superior reliability of coal and nuclear resources o\'er other types of resources is significantly and inaccurately inflated, while discounting the reliability provided by other resources such as wind (Tr. Vol. IV at 758-59, 768, 772-73; Tr. Vol. X at 2217; OCC/NOPEC Ex. 4 at 53-54; Sierra Club Ex. 8 at 21).
v. Avoiding Transmission Upgrade Costs
FirstEnergy and MSC warn that if Rider RRS is not appro-s^ed and the Plants subsequently close, the loss of over 3,000 MW of baseload generation would have a negative impact on the stability of the ttar^smission system, thus, necessitating substantial ttansmission upgrades (Co. Ex. 37 at 2-3; Co. Ex. 39 at 5-7; Tr. Vol. XV at 3254-56; Tr. Vol. XVI at 3293-94). Based on the analysis of FirstEnergy witaess Phillips, FirstEnergy and MSC assert the costs associated with these necessary ttansmission upgrades would fall within the range of $436.5 million and $1.1 billion, and would require PJM and ttansmission owners to develop a solution consisting of new facilities, as well as a combination of re-conductoring and rebuilding existing facilities (Co. Ex. 39 at 8-10; Tr. Vol. XVI at 3285). Even with such upgrades, the Companies assert that outages would still be more likely to occur due to the fact that increasing the distance between generation units and a load center increases the potential for outages on the ttansmission system (Co. Ex. 39 at 6). Additionally, as the need for ttarrsmission upgrades would be largely driven by the Companies' load, FirstEnergy asserts a significant portion of these costs would be borne by the Companies' customers (Co. Ex. 37 at 3; Co. Ex. 33 at 8; Co. Ex. 39 at 8-10; Tr. Vol. XXV at 5152-54). The Companies and MSC add that only a small percentage of the plarmed generation projects actaally go into service and that it is not uncommon for developers to withdraw these projects from the PJM queue. Moreover, FirstEnergy witaess Phillips testified that the Commission has authority over generation projects, noting that PJM does not have the authority to direct the consttuction of generation or to direct the generation to be built at any specific location; rather, PJM is limited to determine where overloads occur and attempt to identify a ttansmission solution, concluding that the former issues remain within the jurisdiction of the state (Tr. Vol. XVI at 3329). Thus, FirstEnergy and MSC conclude that the Economic Stability Program benefits customers by
APP. 288 14-1297-EL-SSO -56- avoiding the need for these costly ttansrrussion system upgrades that the retirement of the Plants would otherwise require (Tr. Vol. I at 96; Tr. Vol. XV at 3240).
OCC/NOAC and Sierra Club contend the Commission should also not consider the effects of plant retirement, such as ttansmission investment, as a qualitative benefit to customers under the Stipulated ESP IV, as no evidence has been presented in the record that the Plants would retire in the event that Rider RRS is not approved; rather, OCC/NOAC points to the significant evidence that these Plants would remain economically viable (OCC/NOPEC Ex. 7 at 34-44; OCC/NOPEC Ex. 8 at 34; Co. Ex. 29 at 1-4; Tr. Vol. II at 418; Tr. Vol. XI at 2305-07; Tr. Vol. XV at 3076-77; F3/EPSA Ex. 5 at 11; Co. Ex. 143 at 2-3). Sierra Club adds that, even in the event the Plants were to retire and PJM required ttansmission upgrades, FES would have the opportaruty to enter into a Reliability Must Run (RMR) conttact^o to effectively subsidize the continued operation of the Plants while such upgrades were completed, which Sierra Club notes is a common approach in sitaations where a generator deactivation may alter reliability (Sierra Club Ex. 67 at 9-10). Sierra Club and Envirorunental Groups also note that the cost projections for these ttansmission upgrades, if required, were derived from a flawed, non-independently conducted ttansmission impact stady that relied on outdated information and unrealistic assumptiorrs involving the simultaneous retirement of Sammis and Davis-Besse, and, thus, should be disregarded by the Commission (Co. Ex. 39 at 4, 8; Tr. Vol. XV at 3223-26, 3229- 32, 3259, 3264; Tr. Vol. XVI at 3318-19; Sierra Club Ex. 95 at 11,17-18; Sierra Club Ex. 67 at 6-7). Further, Environmental Groups allege there is no evidence that reliability in PJM is at risk; rather, there is significant testimony in the record that states new generation is coming online and in significant amounts across the PJM market, including Ohio (Sierra Ciub Ex. 95 at 11; OCC/nOPEC Ex. 5 at 8-11). Exelon also echoes the assertions of OCC/NOAC and contends that it is PJM's, and not the Commission's, responsibility to ensure ttansmission grid reliability, noting PJM is effectively managing the capacity market with its newly implemented capacity performance product (Dynegy Ex. 1 at 10; Exelon Ex. 1 at 16; IMM Ex. 2 at 3-4).
vi. Consideration of AEP Ohio Order Factors
Pursuant to the Commission's decision in AEP Ohio ESP III, FirstEnergy, OEG, and Staff also assert that Rider RRS satisfles all of the AEP Ohio Order Factors (Co. Ex. 9 at 3- 14). OCC/NOAC initially note that, while they address each of these factors, they believe the Commission should find the AEP Ohio Order Factors are an insufficient means to
^^ An RMR contract is an agreement between a generator and PIM that is utilized to mitigate temporary system impacts and capacity shortfalls caused by generating plant closures. Practically speaking, once PJM receives notice of a generator's intent to close a plant or various imits of a plant, PJM can enter into a RMR contract witii the generator to provide payments for a fixed period of time to continue to run the units or plant while PJM addresses the potential reliability concerns.
APP. 289 14-1297-EL-SSO -57- assess whether customers are appropriately served and protected. In fact, OCC/NOAC recommend several factors they believe the Conunission should consider in addition to the AEP Ohio Order Factors, including, but not necessarily limited to: requiring FirstEnergy to submit an independent assessment of the PPA and Rider RRS under independentiy produced futare price scenarios so consumer interests are adequately protected; the effects of FirstEnergy's offer sttategy into PJM on customers; the incentives, or lack thereof, of FirstEnergy to conttol the cost of the Plants and OVEC entitlement units so consumer interests are protected; the incentives, or lack thereof, for FirstEnergy and FES to make rational market-based retirement decisions pertaining to the Plants and OVEC entitlement units so consumer interests are protected; the economic impact of higher retail rates that would be imposed on FirstEnergy's customers, who OCC/NOAC assert are captive; and the cost of achieving the same benefits that Rider RRS and the PPA provide compared to other alternatives, such as the development of a least-cost combination of new and existing generation and/or ttansmission assets, competitive solicitation, or other market-based solutions. FirstEnergy believes the Commission should not afford any weight to these proposed factors, since the Commission has already determined which factors should be probative in its consideration.
In response to the first factor, FirstEnergy and MSC assert that the economic viability of the Plants remains in doubt, alleging that revenues have been at historic lows and are insufficient to cover the Plants' costs in the short-term, and thus, insufficient to continue to operate the Plants and make any necessary investments. The Companies provide that FES may not be able to financially bear short-term losses even if long-term projections of market prices show significant increases. Thus, based on a weak balance sheet caused by historic losses, and near-term forecasts of the Plants, FirstEnergy states that FES has identified these Plants to be financially at risk of closure prior to the end of their usehil lives. (Co. Ex. 28 at 2-4; Tr. Vol. X at 2184-85; Tr. Vol. XI at 2395; Tr. Vol. XXXII at 6541-42; Tr. Vol. XXXIII at 6818; Co. Ex. 143 at 5.) The Companies conclude by stating that the Plants' recent performance is indicative of industty ttends, noting that several other FES plants were recently retired due to projected near-term losses (Co. Ex. 28 at 4). FirstEnergy witaess Lisowski also raised concerns regarding the Plants' cash flows in the near term, explaining that avoidable costs fail to consider this crucial aspect of financial viability (Co. Ex. 143 at 3-4). Thus, FirstEnergy believes it has adequately demonsttated the financial need of the Plants.
Sierra Club, P3/EPSA, OCC/NOAC, IMM, Dynegy, and OMAEG argue that, based on FirstEnergy's own projections regarding the Plants and OVEC entitlement units, these generating units are not in financial need. P3/EPSA and OCC/NOAC even contend that it is conttadictory for FirstEnergy to argue that the Plants are in dire financial need when their own projections indicate that customers will receive a $260 million, NPV, benefit resulting from the operations of those Plants and OVEC entitlement units through Rider RRS. P3/EPSA also contends that significant capital investments recently made in the
APP. 290 14-1297-EL-SSO -58-
Davis-Besse and Sammis Plants indicate that FES believes these plants will not retire in the short-term (P3/EPSA Ex. 1 at 41; P3/EPSA Ex. 2C at 43-44; Sierra Club Ex. 89; OMAEG Ex. 18 at 9). Exelon, OCC/NOAC, and Dynegy add that none of the Companies' witaesses testified that the plants were unecononuc ot set for closure in the event that Rider RRS was not approved (Tr. Vol. XXXIl at 6636-37, 6686). Exelon additionally notes that the Companies' short-term projections do not incorporate capacity performance revenue and that FES is now obligated to provide its portion of the FirstEnergy committed capacity through May 31, 2019 (Tr. Vol. XXXVI at 7669, 7674, 7704). OMAEG agrees with Sierra Club, Exelon, and P3/EPSA in that the Comparues have not demonsttated the financial need of the Plants and the OVEC entitlement units, also asserting that market forces should be the ultimate determinate of a generating unit's financial need (OCC Ex. 25 at 9). OMAEG adds that allowing these subsidized units to participate in the wholesale market against unsubsidized units will desttoy efficiency benefits and market price signals, thereby potentially increasing the cost of supplying customers with energy and capacity needs (OCC/NOPEC Ex. 1 at 4). Though NOPEC initially notes that the Commission has not provided a definition for "financial need," it also agrees that the Companies have failed to address this factor and concludes that the appropriate threshold for establishing the financial need of the Plants and OVEC entitlement units should be whether these units recover their avoidable costs (OCC/NOPEC Ex. 5 at 22-23).
FirstEnergy also asserts that it has demonsttated the necessity of the Plants and OVEC entitlement units as generating units that promote reliability and supply diversity in the Companies' service territories. In addition to other arguments presented above, FirstEnergy and MSC note that Rider RRS should also satisfy the second factor. FirstEnergy notes that coal and nuclear plants provide a much needed baseload generation source which can be supplemented with, but not replaced by, renewable resources (Co. Ex. 32 at 9; Co. Ex. 28 at 10). Likewise, unlike the coal and nuclear baseload generation provided by the Plants and OVEC entitlement units, the Companies also argue that nataral gas plants lack significant on-site fuel storage and rely on "just in time'^ delivery of their fuel (Co. Ex. 29 at 7-8; Tr. Vol. XI at 2255). As such, the Companies maintain that the Plants and OVEC entitlement units remain an essential part of the diverse generation mix necessary to ensure the reliable delivery of electtic service in the near and long term (Co. Ex. 32 at 9). Additionally, as noted earlier, FirstEnergy asserts that the Plants and OVEC entitlement uruts also have reliability benefits based on their location in close electtical proximity to the Companies' load (Co. Ex. 39 at 6). MSC further adds that FES' Plants and OVEC entitlement units have been negatively affected by improperly valued diversity, resulting from an irrherently flawed market that produces artificially low cash flows which do not cover the costs of the power supply portfolio and environmental policies that encourage other types of resource generation (Co. Ex. 42 at 3, 6). Accordingly, FirstEnergy asserts the second factor of the AEP Ohio Order Factors should weigh in its favor.
APP. 291 14-1297-EL-SSO -59-
Sierra Club and OMAEG also contend that the purported reliability benefits of Rider RRS are illusory because Sammis and Davis-Besse are not at risk of retirement. P3/EPSA and Exelon agree with Sierra Club, noting that if the Comnussion determines there is little to no risk of retirement for the Plants, that determination would rule out any concerns about rehability or supply diversity (Tr. Vol. XI at 2305; Co. Ex. 9 at 7; Tr. Vol. Ill at 521). P3/EPSA, IMM, and Exelon also believe that allowing the Plants to continue to operate would have a negative effect on futare reliability, noting customers would bear the risk of capacity performance penalties while FES would be left with mirumal incentives to make additional investments to avoid outages (IMM Ex. 2 at 3-4; Tr. Vol. X at 2215; Dynegy Ex. 1 at 9-10). Furthermore, Sierra Club, OCC/NOAC, and OMAEG note that, as described in their earlier arguments, the ttansmission upgrade cost estimate is based on outdated information and unrealistic assumptioris and the resource and diversity purported benefits are unsubstantiated and vague (OCC/NOPEC Ex. 1 at 26). OMAEG and OCC/NOAC contend that it is the responsibility of PJM to determine procedures for meeting the reliability needs of the region and that determination should not be made on a plant-specific basis by the Conunission (OCC Ex. 26 at 6). As noted before, OMAEG, OCC/NOAC, and NOPEC assert that PJM has effective measures to mitigate the threat of a jeopardized reliability system, specifically noting the provision of RMRs, incentives from the Reliability Pricing Model (RPM), and new generation projected to come online in the near futare (Sierra Club Ex. 67 at 10; Exelon Ex. 1 at 16). Responding to the Companies' assertions about supply diversity, OMAEG and NOPEC argue that maintairung the coal- fired generating uruts through Rider RRS will only further limit supply diversity, noting coal remains the highest utilized generation type in Ohio (OCC/NOPEC Ex. 1 at 28). NOPEC also states that extteme weather events, such as the Polar Vortex, should not validate FirstEnergy's assertions regarding reliability concems, since all generation resources are challenged under such conditions (Sierra Club Ex. 8 at 24-25).
FirstEnergy and MSC also believe that Rider RRS has satisfied the third factor of the AEP Ohio Order Factors and that the Economic Stability Program affords several envirorunental compliance benefits. The Companies, MSC, OEG, and Nucor also believe that the Plants will continue to provide significant environmental compliance benefits, for both the U.S. EPA's Clean Power Plan (CPP) as well as other existing and pending environmental regulations (Co. Ex. 48 at 1-3, 6; Co. Ex. 12 at 9-12; Co. Ex. 145 at 2). FirstEnergy notes that Davis-Besse, as a zero-emissions resource, is well positioned to assist the Companies with their comphance with futare U.S. EPA carbon reduction standards, adding that no issues have been raised by any party regarding Davis-Besse's envirorunental compliance (Co. Ex. 28 at 8,12; Tr. Vol. IV at 877). FttstEnergy maintains that Sammis is also compliant with all existing envirorunental regulations and will continue to comply with futare regulations, due to recent significant capital investments (Co. Ex. 32 at 9-12; Co. Ex. 46 at 2-3). FirstEnergy notes that Sarrunis is either fully in compliance or has a plan to comply with pending environmental regulations, including all of the following: (1) solid waste regulations, including the Coal Combustion Residuals
APP. 292 14-1297-EL-SSO -60-
(CCR) rule; (2) air regulations, including the National Ambient Air Quality Standards (NAAQS), the Cross State Air Pollution Rule (CSPAR), the Mercury and Air Toxics Standard (MATS) and the CPP; and (3) water regulations, including the Section 316(b) Cooling Water Intake Sttuctares at Existing FacUities (316(b)) rule and the Effluent Limitations Guidelines and Standards (ELG) rule. FirstEnergy also states that any projected costs that the Plants may incur to comply with these regulations have already been included in the Companies' cost forecast provided by FirstEnergy witaess Lisowski (Co. Ex. 46 at 3-5, 9). Furthermore, FirstEnergy argues it is urueasonable to give "proposed regulations" more consideration until their finalization, especially with regard to cost estimates for compliance, as several changes may occur to the proposed language before formal adoption of the language occurs (Co. Ex. 145 at 1-2). As evidence of its commitment to environmental compliance, FirstEnergy also states that Sarrunis has installed sigrrificant environmental upgrades and rettofits that are much more resttictive than current regulations, including conttols for sulfur dioxide, nittogen oxides and particulate matter (Co. Ex. 46 at 4, 6; Co. Ex. 32 at 7,10-11; Co. Ex. 135; Tr. Vol. XII at 2519- 22, 2536, 2552, 2577). Thus, despite the allegations that Sanunis will be affected by the CPP or other pending envirorunental regulations, FirstEnergy argues that intervening parties have failed to produce any evidence that confirms their speculation. In the alternative, FirstEnergy argues that any unanticipated costs for such compliance, especially for the OVEC entitlement units, would be immaterial to the Companies' cost forecasts.
In addition to asserting that the Companies failed to consider envirorunental costs in their projections to calculate the ultimate credit afforded to customers. Sierra Club, IMM, and Envirorunental Groups argue that the Companies have failed to satisfy the third factor, noting that the Sammis and OVEC entitlement units face regulatory risk and potential unanticipated costs due to recently adopted regulations by the U.S. EPA. OMAEG, OCC/NOAC, and NOPEC add that the Conunission should also consider any futare requirements, even though the timing of the final rules is unknown, as compliance with these rules will have a significant imipact on the coal-fire generation unit operations (OCC Ex. 20 at 3-6,10, 24; OMAEG Ex. 17 at 8). OMAEG concludes by stating there would be considerable doubt as to whether the coal-fired generation units would be able to competitively operate in the energy market after achieving compliance with the new environmental regulations and their associated costs (Tr. Vol. XXIII at 4701-03). OCC/NOAC again sttess that the impact of Rider RRS cannot be projected with a reasonable degree of certainty, and moreover, will not produce a benefit for customers commensurate with its potential cost (OCC/NOPEC Ex. 9 at 7-8). Sierra Club and Envirorunental Groups further emphasize that the Companies will be required to pay depreciation, interest expense and the ROE on such investment and failed to adequately address these issues during their analysis (Tr. Vol. XII at 2536; Tr. Vol. XIX at 3800-03; Tr. Vol. XXXIII at 6787-88, 6794.)
APP. 293 14-1297-EL-SSO -61-
Finally, FirstEnergy and MSC state that closing the Plants would have a significant negative impact on electtic prices and retail rate stability, with a resulting negative impact on econonaic development, both locally and regionally. In addition to the earlier arguments regarding effect of a potential closure on electtic prices and rate stability, which included significant costs atttibuted to necessary ttansmission upgrades, FirstEnergy argues taat this would also lead directly or indirectly to the loss of thousands of jobs, millions of dollars in tax revenue, and over $1 billion in economic activity annually (Co. Ex. 35 at 2-3; Co. Ex. 36 at 6, 10-11; Tr. Vol. XV at 3214-17). Thus, the Companies assert that the fourth AEP Ohio ESP HI Order factor should also weigh in their favor considering that closing the Plants would have a sigruficant negative impact on economic development within the region (Tr. Vol. XI at 2371-72; Tr. Vol. XV at 3176-77).
OCC/NOAC, NOPEC, IMM, OMAEG, and Sierra Club assert that the Companies have failed to satisfy this factor, stating that Davis-Besse and Sammis are not at risk of retirement, and even in the event the Conunission was to assume this could potentially be the case, the Companies' projections for ttansmission upgrades are significantly overinflated, adding that ttansmission and reliability concerns are best addressed at PJM (OCC/NOPEC Ex. 1 at 23-24). These parties contend the Commission should also not consider the effects of plant retirement, such as job loss, as a qualitative benefit to customers under the Stipulated ESP IV, as no evidence has been presented in the record that the plants would retire in the event that Rider RRS is not approved; rather, OCC/NOAC points to the significant evidence that these Plants would remain economically viable (OCC/NOPEC Ex. 7 at 34-44; OCC/NOPEC Ex. 8 at 34; Co. Ex. 29 at 1-4; Tr. Vol. II at 418; Tr. Vol. XI at 2305-07; Tr. Vol. XV at 3076-77; P3/EPSA Ex. 5 at 11; Co. Ex. 143 at 2-3). OMAEG, NOPEC, Environmental Groups, and Sierra Club further argue that several of the underlying assumptions supporting the economic development analysis conducted by FirstEnergy witaess Murley are flawed. OMAEG, OCC/NOAC, and NOPEC specifically contend that the Companies' analysis ignores the potential economic benefits that might arise following the closure of a plant or potential mitigation of the economic consequences that may also occur (OCC/NOPEC Ex. 2 at 16; OMAEG Ex. 17 at 5; OMAEG Ex. 18 at 12). These parties specifically note the analysis ignores the opportanity costs of spending or any offsetting economic costs as well as the likely new generation or ttansmission upgrades that would occur in the event of the retirement (Tr. Vol. XV at 3064-65, 3077-81, 3090-91, Sierra Club Ex. 89; Sierra Club Ex. 73 at 34-35; OMAEG Ex. 18 at 10-13, 15). As a result, these parties request that the Commission disregard the economic impact analysis conducted by FirstEnergy witaess Murley. OMAEG also maintains that Rider RRS and underlying PPA could potentially harm the economic development of the region from an environmental perspective, noting that the cost of continued operation of the coal-fired units may increase due to environmental regulations and discourage businesses from locating or expanding in Ohio. NOPEC adds that the retail rate increases may also impair Ohio manufactarers' ability to compete with other manufactarers regionally, in the United States, and globally (OMAEG Ex. 17 at 5).
APP. 294 14-1297-EL-SSO -62-
Additionally, OMAEG argues that the Economic Stability Program will also deter new enttants from entering the power generation market because FES will be fully compensated for the operations of the Plants and OVEC entitlement units, thereby providing FES with a competitive advantage over its competitors (OMAEG Ex. 17 at 6,11- 12; OMAEG Ex. 18 at 6-7). Dynegy argues the Companies' proposal will create uncertainty in the wholesale markets and the discouragement of the development of new fuel-efficient, state-of-the-art generation in Ohio (Dynegy Ex. 1 at 6; RESA Ex. 6 at 4). Thus, these intervening parties do not believe FirstEnergy has satisfied the fourth factor.
FirstEnergy and MSC further assert that Rider RRS would be subject to rigorous Commission oversight with full information sharing and incorporates a risk-sharing mechanism. FirstEnergy witaess Mikkelsen testified that an annual filing for Rider RRS would be submitted and would be subject to a two-part review by the Commission, which would include a review for mathematical errors, consistency with Commission-approved rate design, and incorporation of prior audit filings, as well as a second review to audit the reasonableness of the actaal costs. (Tr. Vol. I at 58-59, 68; Tr. Vol. XXIV at 4879; Tr. Vol. at XXVI at 5198; Co. Ex. 7 at 15.) In fact, FirstEnergy provides that the audit would constitate the same level of review as the historic test the Corrunission employed when the plants were regulated, which would include full participation by intervening parties (Tr. Vol. I at 77-78, 82). In order to assist Staff in its reasonableness review of Rider RRS, FirstEnergy has also conunitted to provide Staff with FES' fleet information on any cost component, pursuant to a reasonable request, adding that FES also made such a commitment to supply tins information (Tr. Vol. 1 at 82-84; Tr. Vol. XXXVT at 7519-20). Additionally, the Comparues state that the Commission would have the ability to ultimately determine whether a request was "reasonable" for purposes of the review (Tr. Vol. XXXVl at 7519). Despite the fact that many intervenors objected to the proposed process for the review of legacy cost components, the Comparues assert that parties had the opportanity to challenge legacy costs in this proceeding but elected not to do so (Tr. Vol. I at 79,162; Co. Ex. 7 at 14-15). FirstEnergy further argues that the Companies, and not their customers, would be responsible for amounts disallowed for recovery through Rider RRS because the Commission deems those costs as unreasonable (Co. Ex. 8 at 21; Tr. Vol. I at 60-61; Tr. Vol. II at 448; Co. Ex. 154 at 8). FirstEnergy also emphasizes that a risk-sharing mechanism that potentially provides up to $100 million in credits to customers for Years 5 through 8 of the Economic Stability Program will also foster greater rate certainty and stability (Co, Ex. 155 at 3-4; Tr. Vol. XXXVI at 7523; Tr. Vol. XXXVII at 7770; Co. Ex. 154 at 7-8). Finally, FirstEnergy contends the severability provision provided in Stipulated ESP IV is consistent with the requirement set forth in the AEP Ohio ESP III Order and provides sufficient guidance as to the remedy process if any portion of Rider RRS is determined to be deficient by a court of competent jurisdiction (Co. Ex. 9 at 13).
OCC/NOAC advance their concerns that consumers will not have the protection of cost conttol incentives due to a lack of regulatory oversight regarding cost-of-service
APP. 295 14-1297-EL-SSO -63-
pricing. Notably, they argue that FES will have little incentive to aggressively conttol costs and it is not clear what the review process would allow for interested stakeholders or what would constitate a reasonable cost under such a review paradigm. (OCC/NOPEC Ex. 1 at 15, 19; Tr. Vol. I at 80-81; Co. Ex. 154 at 8.) Sierra Club also maintains that the proposed audit review process provides inadequate protections agairrst the financial risks of customers associated with Rider RRS, noting it limits the Commission's oversight over some costs associated with Rider RRS (Sierra Club Ex. 89; Sierra Club Ex. 95 at 5). Sierra Club, RESA, OCC/NOAC, NOPEC, Exelon, and P3/EPSA argue that Stipulated ESP IV does not provide for rigorous review of Rider RRS and does not properly allocate risk between FirstEnergy and ratepayers. P3/EPSA, Exelon, OMAEG, OCC/NOAC, NOPEC, CMSD, and RESA further allege that the commitments to rigorous review and full information sharing are illusory. Specifically, P3/ESPA, OCC/NOAC, and RESA note the Commission will lack oversight or review authority over FES, Staff will not be provided all information pertaining to FES' fleet unless a "reasonable request" is submitted to FirstEnergy, which FES may ultimately deny, and this commitment will never include access to bilateral conttacts between FirstEnergy and third parties. (Co. Ex. 154 at 8.) OCC/NOAC further opines the Commission should modify Rider RRS to provide Staff with complete access to all pertinent records, much like the requirement found in R.C. 4905.15," rather than limit the scope of Staff's review to only those requests which are deemed "reasonable" during the review process. RESA and NOPEC raise a particular concern for the vaguely defined "legacy cost components" that will escape Commission review, noting that FirstEnergy failed to provide sufficient information regarding the natare or potential cost exposure for these various components (Co. Ex. 7 at 14-15; OCC Ex. 25 at 4; Tr. Vol. I at 89). NOPEC and Exelon add that additional deficiencies exist in the promise of a rigorous review since information pertaining to the OVEC uruts was never addressed. OMAEG, while agreeing with the arguments of Sierra Club, Exelon, and P3/EPSA, also argues that it would be wholly unreasonable that the reviews conducted by the Commission would not occur until after the bids and auctions have ensued and when the resulting revenue from the energy, capacity, or ancillary services is realized, or that such review would be based on the facts and circumstances that were known at the time the offer was made (OCC Ex. 25 at 4; Tr. Vol. I at 67; Tr. Vol. XXXVI at 7618-19).
P3/EPSA, Exelon, NOPEC, CMSD, and RESA also state that there is no alternative plan to allocate Rider RRS' financial risk between both FirstEnergy and its customers, noting the nominal benefits from the risk-sharing mecharusm proposed by the Companies would pale in comparison to the forecasted charges customers will likely experience over the term of Rider RRS (Sierra Club Ex. 89; Tr. Vol. XXXVI at 7733). Moreover, RESA, Sierra Club, and OMAEG add that no cap has been implemented to protect customers
11 R.C. 4905.15 states that "Each public utility shall furnish to the pubKc utilities commission, in such form and at such times as the commission requires, such accounts, reports, and information as shall show completely and in detail the entire operation of the pubhc utility in furnishing the unit of its product or service to the pubhc."
APP. 296 14-1297-EL-SSO -64- over the term of Rider RRS (Tr. Vol. XXXVI at 7523-26). Sierra Club also emphasizes that FES, as the generating owner, will not share any of the financial risk (Tr. Vol. XIII at 2830; P3/EPSA Ex. 1 at 8-9, 25; OCC/NOPEC Ex. 4 at 58; Staff Ex. 12 at 13,16-17). Sierra Club and RESA also maintain that proposed risk sharing mechanism provides inadequate protections against the financial risks oi customers associated with Rider RRS, noting no credits were offered to alleviate charges to customers accrued in the first three years oi the term when millions in actaal charges have been predicted to occur (Tr. Vol. I at 67, 69-71, 73-76, 79, 81-83; Tr. Vol. Ill at 519; Tr. Vol. XXXVI at 7525, 7600, 7741; Sierra Club Ex. 89; Sierra Club Ex. 95 at 5). OMAEG and NOPEC also question the validity of this mechanism, as the credit merely acts as a slight cost reduction to customers and does not change the fact that the entirety of net costs will be passed to customers (OCC/NOPEC Ex. 9 at 18-19; Tr. Vol. XXXVII at 7771-72). RESA further contends fliat tiiese credits will provide litfle to no incentive to FES or OVEC to manage the costs of the Plants or OVEC entitiement uruts (Tr, Vol. XXXVI at 7733). Additionally, given the projected charges customers may face during the course of the Rider RRS term, RESA notes that nominal credits customers would receive could not reasonably be considered to be a risk-sharing mechanism (OCC/NOPEC Ex. 9 at 8). Exelon, RBSA, and OMAEG add that the nominal natare of these credits is exacerbated by the fact that they are applied on an armual basis, rather than in the aggregate. RESA agrees that it is unlikely Rider RRS would be conducive to rate stability, asserting that the Companies should stand behind the projections and offer an aggregate Rider RRS credit at least equal to any Rider RRS charges plus carrying charges, which would ttuly constitate an equitable risk-sharing mechanism (RESA Ex. 6 at 7-8). For similar reasons, RESA and Cleveland also request the Commission impose a floor and ceiling to safeguard customers affected by Rider RRS. Rather than accepting the proposed risk-sharing mechanism, OCC/NOAC and NOPEC suggest an asynunettic sharing mechanism where only 50 percent of the net charges under Rider RRS would be imposed upon customers during the first three years of ESP IV, with 25 percent imposed on customers thereafter (OCC/NOPEC Ex. 4 at 6-7). CMSD also requests the Commission to implement changes to the risk-sharing mechanism to better allocate the financial risk amongst all involved parties, further noting that Rider RRS, as proposed, would adversely affect the Companies' ratepayers, and thus, cannot be considered an effective hedge.
Additionally, P3/EPSA and RESA argue the proposed severabihty provision is insufficient to satisfy the conditioris proffered by the Commission in AEP Ohio ESP III, as it allows FirstEnergy to cure defects in Rider RRS and discourages parties opposing the manner of the cure to raise the issue for fear of forfeiting its stipulation provision (Co. Ex. 154 at 8-9; Tr. Vol. XXXVI at 7681-83). Exelon further argues that the severability clause language would create a very limited focus for any modified Rider RRS proposal, which would ignore any applicable statatory or regulatory requirements that may exist at the time of its proposal (Co. Ex. 154 at 8-9). OMAEG, Cleveland, OCC/NOAC and CMSD also agree that the severability provision acts as an additional protection for FES, stating
APP. 297 14-1297-EL-SSO -65- that it would serve to make FES whole at the expense of ratepayers in the event that Rider RRS is later invalidated and, pursuant to rettoactive ratemaking principles, would prohibit a refund to ratepayers (OCC Ex. 20 at 27; Co. Ex. 154 at 9).
d. Generation Cost Reconciliation Rider
FirstEnergy and MSC note that Stipulated ESP IV will continue the Generation Cost Reconciliation Rider (Rider GCR), arguing the proposed modifications will ensure additional stability and certainty. The proposed modifications will make costs recovered under Rider GCR bypassable unless the balance oi the rider exceeds ten percent oi the applicable generation expense in two consecutive quarters during the term of the Stipulated ESP IV, which is an increase of five percent from the previous threshold. (Co. Ex. 8 at 3; Tr. Vol. XVIII at 3609.) FirstEnergy notes the bypassability threshold has never been achieved in two consecutive quarters and adds that increasing the threshold from five percent to ten percent will make it less likely to be ttiggered in the futare (Co. Ex. 43 at 7).
RESA does not oppose reimbursement through Rider GCR, but is opposed to the sttuctare of the rider which automatically converts any imbalances from bypassable to non-bypassable once the threshold point is reached. RESA recommends that Rider GCR be modified so that if the threshold point is reached, FirstEnergy files a request for reimbursement explaining why it is not collecting the authorized expenses and then present solutions.
e. Delivery Capital Recovery Rider
FirstEnergy also argues that Stipulated ESP IV benefits customers and the public interest by helping to ensure reasonably priced and reliable disttibution service. Initially, FirstEnergy contends that continuing the disttibution rate freeze will also benefit customers (Co. Ex. 155 at 3). In connection with the freeze, FirstEnergy states the continued recovery of lost disttibution revenue will appropriately balance the interests of customers with the interests of the Companies' shareholders (Co. Ex. 7 at 8). Further, the Companies sttess that they will be required to show total investment amounts and provide justification as to why it is appropriate to recover these investments through Rider DCR, which will then be subject to an annual audit. As Rider DCR provides the Companies with the opportanity to invest in infrasttuctare in a more proactive marmer, FirstEnergy asserts that the Companies have consistently outperformed their system average interruption frequency index (SAIFI)'^ and customer average interruption
12 Represents the average number of interruptions per customer.
APP. 298 14-1297-EL-SSO -66- duration index (CAIDI)^^ minimum rehability standards since Rider DCR has been in effect (Co. Ex. 50 at 9). Additionally, the Companies propose to increase the armual cap for revenue recovered under Rider DCR from $15 rrullion per year to $30 million for the first three years, with a $20 million increase annually tor the subsequent three years and $15 million armually for the final two years of the proposed eight-year term (Tr. Vol. XX at 3961-64). During the evidentiary hearing, FirstEnergy alleged that no intervening witaesses could contest that actaal revenue requirements have increased $30 million annually on average (Tr. Vol. XXI at 4117-19; Tr. Vol. XXXVIII at 8231).
While OCC/NOAC initially contends that Rider DCR will not result in a financial "wash" under the MRO v. ESP test, as proffered by FirstEnergy witaess Fanelli, OCC/NOAC, NOPEC, and RESA argue the alleged qualitative benefits arising from Rider DCR will not actaally accrue to customers and, instead, will cause customers to pay more than they otherwise would be required to pay under a disttibution rate case (Co. Ex. 50 at 7; OCC Ex. 18 at 17; OCC/NOPEC Ex. 8 at 30; OCC/NOPEC Ex. 11 at 22-23). OCC/NOAC, NOPEC, and RESA argue these revenue cap increases could ultimately result in customers paying an additional $240 to $330 million in revenues, for a total of $915 mfllion in Rider DCR charges over the term of Stipulated ESP IV (OCC/NOPEC Ex. 11 at 23-24). Additionally, OMAEG and NOPEC maintain the Companies have provided no evidence showing the need for this increased cap, especially since no major disttibution capital projects are currentiy planned (Co. Ex. 50 at 4; Staff Ex. 6 at 7-9; OCC Ex. 18 at 19). OCC/NOAC, Power4Schools, and OMAEG further assert that Rider DCR will function more efficiently or foster greater reliability when collecting these costs through a base disttibution rate case (OCC/NOPEC Ex. 8 at 31). OMAEG, NOPEC, and Power4Schools assert it would not be reasonable or prudent for the Corrunission to allow the Companies to incrementally increase the disttibution rate, absent a thorough Conunission review of such rates in a disttibution rate case, noting it has already been seven years since the Companies' last disttibution rate case (OCC Ex. 22 at 3; Tr. Vol. XX at 3901). Moreover, OMAEG and NOPEC add that, in the event the Companies are earning retarns that exceed their actaal costs of capital, additional Rider DCR increases are both urmecessary and inappropriate (OCC Ex. 18 at 11). OCC/NOAC further asserts that allowing Rider DCR to continue to be charged to customers in the event the ESP is terminated pursuant to R.C. 4928.143(E) would be harmful, due to the fact, in their opinion. Rider DCR conttibutes to the failure of the MRO v. ESP test.
f. Government Directives Recovery Rider
FirstEnergy believes that the Goverrunent Directives Recovery Rider (Rider GDR) proposed in its application will permit timely recovery of futare costs related to implementing programs required by legislative or governmental directives over which the Companies would have no conttol (Tr. Vol. I at 180; Co. Ex. 16 at 4). Given the proposed
^3 Represents iJie average interruption duration.
APP. 299 14-1297-EL-SSO -67- eight-year term of Stipulated ESP IV, FirstEnergy argues that it is appropriate to establish a cost-recovery mechanism now for possible future charges incurred because of governmental actions or directives in order to ensure the recovery oi such costs is completed in a uniform and consistent manner subject to Commission review and approval. (Tr. Vol. XXIV at 4905; Co. Ex. 16 at 3). As a part of Stipulated ESP IV, the Companies are specifically requesting deferral authority and recovery of the costs associated with the supplier web portal and bill logos through Rider GDR. Additionally, the Companies note that no costs related to proposed Rider GDR had been incurred at the time of the evidentiary hearing. (Co. Ex. 15 at 7-8; Tr. Vol. V. at 1030-33,1079-83,1101.)
Similar to its objections to Rider DCR, OCC/NOAC, Power4Schools, and NOPEC argue the alleged benefits resulting from Rider GDR are without merit, noting that this is again an attempt by the Companies to request approval of an asymmettic, single-issue ratemaking request when substantial excess earnings are already being recovered by the Comparues. OCC/NOAC additionally contend that the proposed Rider GDR provides no incentive or requirement for Companies to file for rate reductions resulting from changes hi governmental regulations. (OCC/NOPEC Ex. 7 at 32.) OMAEG also adds that FirstEnergy witaess Mikkelsen even testified that it is too early to ascertain the types of costs that will result from implementing these directives or to estimate the amount of costs to be recovered under the rider from customers (Co. Ex. 7 at 25).
g. Legacy RTEP and MTEP Costs
FirstEnergy alleges Stipulated ESP IV will continue the Companies' commitment not to seek recovery from retail customers for certain legacy PJM Regional Transmission Expansion Plan (RTEP) costs, as well as certain legacy Midwest ISO (MISO) Transmission Plan (MTEP) charges. FirstEnergy states that Stipulated ESP IV will continue the commitment originally made in the ESP II Case and forego recovery of at least $360 million of the RTEP charges, with the MTEP costs counting toward that commitment. (Co. Ex. 7 at 17-18; ESP II Case, Opinion and Order at 13.)
OCC/NOAC, Power4Schools, and NOPEC contend that recovering MTEP charges would potentially harm customers and would also be premature, as FERC has not approved recovering such costs through the American Transmission Systems, Inc. (ATSI) tariii. These parties also argue that allowing the Companies to count these MTEP costs toward the previous commitment to not seek recovery of the $360 million of RTEP costs would violate the terms and spirit of the earlier settlement agreement (OCC Ex. 19 at 7-11; ESP 11 Case, Opinion and Order at 13).
APP. 300 14-1297-EL-SSO -68-
h. Resource Diversification and EE/PDR Commitments
FirstEnergy avers that Stipulated ESP IV contains significant connmitments to resource diversification, including establishing a goal to reduce CO2 emissions by 90 percent from their 2005 levels by 2045; evaluating investment in battery resources and technology contingent upon Commission approval of cost recovery for such investments; reactivating all of their EE/PDR programs that were previously suspended and expanding, in accordance with best utility practices, EE/PDR offerings through the end of the eight-year term of Stipulated ESP IV; seeking to procure at least 100 MW oi wind or solar energy sourced in Ohio, thereby, diversifying Ohio's energy portfolio; and filing a report every Ave years with the Conunission that explains the progress with the resource diversification efforts. (Co. Ex. 154 at 11-12; Tr. Vol. XXXVII at 7775-76; Tr. Vol. XXXVII 7873.) Further, FirstEnergy claims Stipulated ESP IV will also provide support to several EE/PDR programs (Co. Ex. 2 at 10-11; Co. Ex. 154 at 15; Co. Ex. 155 at 5): The Companies also state that cost-effective EE programs will be eligible for shared savings, with after-tax annual cap increased from $10 to $25 million, which will continue to be recovered in Rider DSE (Co. Ex. 154 at 11-12). The Companies note the cost-effective EE prograuns will include the proposed Customer Action Program. FirstEnergy witaess Mikkelsen also stated that, in the event the Companies are unable to achieve these various objectives, there will be penalties in the form of futare negotiating opportanities with regulators (Tr. Vol, XXXVI at 7529). Accordingly, FirstEnergy believes that because these various commitments go above and beyond that which the Companies are currently legally obligated to do, these provisions should qualify as benefits for customers.
Environmental Groups, OCC/NOAC, and OHA contend that the lack of enforceability of these various targets and goals should lessen the weight the Commission affords to it when considering these provisions as a potential benefit to customers and the public interest. NOPEC agrees with other opposing parties that the Companies will not be held accountable for any of the goals made to further resource diversification,, and thus,, should not be considered as conunitments nor corisidered by the Commission when it evaluates whether the ttaditional three-prong test has been met (Co. Ex. 154 at 9,11-12; Tr. Vol. XXXVI at 7529, 7531-35, 7541, 7549). Sierra Club and RESA agree that these provisions are subject to several contingencies or are otherwise completely unenforceable and so they should be disregarded by the Commission (Tr. Vol. XXXVI at 7532-35; RESA Ex. 6 at 8-9). Sierra Club goes further to state that some of these provisions are empty commitments as the Companies were already projecting to supply certain levels of energy savings above the goals provided in Stipulated ESP IV (Tr. Vol. XXXVI at 7536-40; Sierra Club Ex. 93; Sierra Club Ex. 94). OCC/NOAC asserts that, without any further detail than what has been provided thus far, the Commission cannot reasonably determine whether such a proposal would be beneficial to the public interest or FirstEnergy's customers.
Environmental Groups also argue that this constitates a 150 percent increase in the Companies' shared savings cap, with absolutely no explanation in the record as to the
APP. 301 14-1297-EL-SSO -69- basis for that increase. Envirorunental Groups further state that this goes against the inherent purpose of shared savings, which is to provide motivation to a utility to discover ways to encourage energy efficiency. (ELPC Ex. 27; Tr. Vol. XXXVII at 7866-67; OCC/NOPEC Ex. 11 at 26.) Environmental Groups note that counting the savings derived from the proposed Customer Action Program should not be included for the purposes of determining FirstEnergy's shared savings incentive payment. OCC/NOAC further add this increase in the shared savings cap will likely cause unreasonable additional costs to customers, especially impacting those low-income customers who are participating in the Percentage of Income Payment Plan (PIPP) program (OCC/NOPEC Ex. 11 at 26).
i. Grid Modernization Program
FirstEnergy alleges that the Stipulated ESP IV will also benefit customers through its grid modernization provision, as this provision contains several initiatives that would further promote customer choice in the Comparues' service territories, including, but not limited to. Advanced Metering Infrasttuctare (AMI), DACR, Volt/VAR, engaging Staff to attempt to remove any barriers for disttibuted generation, consulting with Staff regarding net-metering tariffs, and full deployment of advanced smart meters (Co. Ex. 154 at 9-10). The Companies believe implementation of such irritiatives will ultimately lead to customer savings and promote retail competition in the state of Ohio (Co. Ex. 154 at 3). Additionally, FirstEnergy states that the Companies will file a grid modernization plan with the Commission within 90 days of the filing of Stipulated ESP IV, in which all interested parties would have the opportaruty to participate (Co. Ex. 154 at 9-10; Co. Ex. 155 at 4; Tr. Vol. XXXVI at 7584-85, 7624). The Companies state that costs associated with any approved grid modernization project would be recovered through Rider AMI, commencing within three months after Commission approval of the project and would be calculated based on a forward-looking formula rate (Co. Ex. 154 at 9-10). Further, FirstEnergy provides that the ROE would be initially set at 10.88 percent based on the currently approved ROE for ATSI plus a 50 basis point incentive mechanism to incentivize grid modernization investment over other potential types of investment (Co. Ex. 154 at 10; Tr. Vol. XXXVI at 7631-32; Tr. Vol. XXXVII at 7775).
Envhonmental Groups and OCC/NOAC allege that the Stipulated ESP IV may actaally harm customers, noting the preclusion to terminate Rider RRS and Rider DCR before 2024 and arguing the Companies' commitment to file a grid modernization plan does not warrant the Corrunission approving an incentive ROE on grid modernization investments absent any evidence showing that it will not provide windfall profits to the Companies (ELPC Ex. 28 at 13-14). OCC/NOAC further asserts that the proposed ROE is unjust and urueasonable, as it is higher than the current ROE approved for FirstEnergy's SmartGrid pilot (Tr. Vol. XXXVII at 777^-7775). OCC/NOAC and OHA also contend that it would be unwise for the Commission to agree to an upfront fixed ROE for facility
APP. 302 14-1297-EL-SSO -70- deployment regarding DACR and Volt/VAR technologies before any details of the grid modernization plan are known.
j. Sttaight-Fixed Variable Rate Design
FirstEnergy asserts Stipulated ESP IV benefits customers through the potential ttansition to a sttaight-fixed variable (SFV) cost recovery mechanism. Per the terms of Stipulated ESP IV, the Companies would file an Application for Tariff Approval (ATA) case with the Conunission by April 3, 2017, for the consideration of a ttansition to SFV cost recovery mechanism for residential customers' base disttibution rates. (Co. Ex. 155 at 13.) Interested parties would then have the opportanity to provide input regarding the merits and details of an SFV rate design. FirstEnergy states that the SFV mechanism would be phased in over a period of three years, with 25 percent fixed costs and 75 percent, variable costs in Year 1, 50 percent fixed costs and 50 percent variable costs in Year 2, and 75 percent fixed costs and 25 percent variable costs m Year 3. (Co. Ex. 154 at 12-13.) FirstEnergy further argues that the proposed rate design under Stipulated ESP IV supports gradualism in rates and benefit economic development and job retention, specifically referencing this rate design's eiiect on Riders EDR(d) and DRR (Co. Ex. 8 at 12).
Environmental Groups contend the Commission should not make any preliminary findings on SFV rates without a full record, arguing that this issue was never raised before its inclusion in the Third Supplemental Stipulation and the Companies have failed to explain how it will benefit customers or why it should be considered outside of a rate case (Co. Ex. 155 at 4; ELPC Ex. 28 at 18, Attachment KRR-4; Tr. Vol. XLVII at 7856-57). OCC/NOAC notes that a corresponding rate of retarn reduction should be utilized to match the lowered business risk afforded to FirstEnergy. OMAEG further asserts this rate design undermines the cost incentive for efficiency programs and discourages energy efficiency (OMAEG Ex. 28 at 14).
k. Economic Development Benefits
In addition to the economic development benefits provided by the Economic Stability Program, FirstEnergy also maintains that Stipulated ESP IV includes several economic development provisions that will help stimulate the economy in the Companies' service territories, noting some of the provisiorrs will be funded through the Companies' Economic Development Rider (Rider EDR), while others will be funded through conttibutions by the Companies' shareholders. Notably, FirstEnergy contends that the Companies will provide a total oi $3 million per year in economic development and job retention funding over the term of Stipulated ESP IV, with no associated recovery from customers. (Co. Ex. 154 at 17; Co. Ex. 155 at 12; Tr. Vol. XXXVl at 7734-36.) FirstEnergy
APP. 303 14-1297-EL-SSO -71- and OEG also add that interruptible riders such as Rider ELR also benefit customers by promoting economic development and encouraging job retention in the region (Co. Ex. 8 at 3; Tr. Vol. Ill at 491; Tr. Vol XXX at 6171; OEG Ex. 1 at 9).
i. Economic Development Rider
FirstEnergy notes various other benefits derived from Rider EDR can be found within Stipulated ESP IV, including the automaker provision (Rider EDR(h)), the interruptible credit provision (Rider EDR(b)), and the ttansmission provision (Rider EDR(d)). OEG also believes the gradual phase-out of rate GT load factor provision should be approved, as many large customers have relied on this provision being included in Stipulated ESP IV and by allowing the gradual phase out, the Commission would be promoting gradualism (OEG Ex. 1 at 4-5,17; Co. Ex. 8 at 12), FirstEnergy also claiiris that Rider DRR will provide economic benefits to customers (Co. Ex. 8 at 3-4; Tr. Vol. II at 277- 78; Co. Ex. 154 at 14-15; Co. Ex. 146 at 18). OEG further provides that the automaker credit has already been successfully adopted in FirstEnergy's service territory, and acts to bolster economic development in the region. OEG also notes that the credit is being reduced to $0.01 per kWh, which limits the exposure of other customers to the costs of that credit. In addition to intta-company competition, OEG also provides that the automaker credit helps this region's auto industty compete with unaffiliated foreign producers and creates additional employment opportanities in the region. (OEG Ex. 1 at 4, 16; Co. Ex. 8 at 11.) MSC and Nucor agree with the overarching benefits of Stipulated ESP IV, but specifically note that it and Ohio's other largest energy users require economic development and job retention measures to remain competitive in the global market and will recognize such benefits by receiving service under Rider ELR and other price reducing provisions.
NOPEC states that, as an initial point, the principle of gradualism should not be cor\sidered by the Commission as it is premised upon FirstEnergy's speculation that electticity prices will rise significantly in years four through eight of Stipulated ESP IV (OCC/NOPEC Ex. 9 at 12). NOPEC also asserts the Companies failed to present any evidence on the record that the discounts provided to large industtial customers will allow them to compete better in the global marketplace. OHA also asserts that Rider EDR cannot reasonably be considered to promote gradualism, as it has extended beyond its original purpose, as evidenced by its omission in FirstEnergy's initial application. Exelon also argues that proposed rate design of Rider DRR merely shifts the allocation costs to different classes of ratepayers and provides no actaal benefit to consumers, also noting that the cost allocation unfairly results in residential and commercial customers paying a larger proportional share of these costs than industtial customers.
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ii. Economic Load Response Rider
FirstEnergy states that the Stipulated ESP IV will continue the Companies' interruptible service offerings through Rider ELR, noting interruptible tariff provisions such as Rider ELR benefit all customers by providing system reliability and stability. FirstEnergy adds that the availability of interruptible load during an emergency, such as an extteme weather event, may help prevent the need to resort to load-shedding, a clear benefit to both firm and non-firm customers. (Tr. Vol. XXX at 6131, 6154, 6156; Tr. Vol. II at 259-260.) Under the Stipulated ESP IV, FirstEnergy provides tiiat Rider ELR will be available to both shopping and non-shopping customers to promote the competitive retail market throughout the entire term of the ESP (Co. Ex. 8 at 3; Tr. Vol. II at 237-38). OEG further agrees with the multiple benefits the Rider ELR interruptible load program would provide to large customers within the Companies' service territory, noting that increased reliability provided by this program is a key component to meeting firm loads and maintaining a reliable grid, especially in the face of upcoming plant retirements (OEG Ex. 1 at 4, 9). OEG witaess Baron also noted that interruptible resources can provide economic benefits by lowering the market price for all consumers during peak times and reducing the need for additional capacity resources to be consttucted (OEG Ex. 1 at 9). OEG believes this is a crucial program to continue as approximately 39 percent of the Companies' total sales are industtial sales (Tr. Vol. XXII at 4393). Additionally, OEG notes this may also be a benefit for EE/PDR requirements, as interruptible load programs increase energy conservation by reducing the amount of power that would otherwise be consumed during peak times and by advoiding the impacts of consttucting and operating fossil generation. Additionally, interruptible load also serves as a demand response resource that FirstEnergy can use to satisfy its requirements under R.C. 4928.66. (OEG Ex. 1 at 10; Nucor Ex. 1 at 6.) Nucor also agrees the use of interruptible rates will support economic development and job retention in this region, while also noting the fact that Rider ELR has been included in all Commission-approved FirstEnergy ESPs dating back to 2009 (Nucor Ex. 1 at 8; Co. Ex. 146 at 18-19; Tr. Vol. XXX at 6133-34, 6172-75). Nucor, lEU- Ohio, and OEG agree that the several key improvements to this program help satisfy the second prong of the test, including removing the prohibition on shopping in order to allow ail customers to participate on the rider, removing the economic buy-through option events, and including up to 136,250 kW of additional curtailable load to the current ELR load for customers who have historically been eligible for Rider ELR (Nucor Ex. 1 at 13-14; Co. Ex. 2 at 8; Co. Ex. 3 at 2; Co. Ex. 146 at 20). Nucor witaess Goins also concluded that the valuation of the combined ELR credit is reasonable (Nucor Ex. 1 at 10).
OCC/NOAC and RESA assert the retention and 75 MW expansion of Rider ELR is not in the public interest, noting that there is a potential $27 million additional cost, not every customer is eligible to receive the benefit, and effectively forces customers to subsidize the program (OCC/NOPEC Ex. 8 at 25-27; Tr. Vol. XXI at 4038). OMAEG adds that the Companies have failed to quantify the alleged benefits associated with the ELR program (Co. Ex. 8 at 11; Tr. Vol. Ill at 574). OMAEG also notes that due to the eligibility
APP. 305 14-1297-EL-SSO -73- limitations to the ELR program, new customers that enter the service territories, including new customers, new buildings, or new accounts of existing customers, will not be eligible to take service under the ELR program (Tr. Vol. II at 261, 274-276). OHA further provides that together. Rider ELR and EDR(b) provide a very select number of customers with credits of $10 for each eligible kW of demand, to be paid for by other customers.
1. Customer Retail Rate Programs
FirstEnergy generall}' asserts that Stipulated ESP IV includes at least three provisions that promote customer choice: the extension of the time-differentiated time-of- day (TOD) pricing options under Rider GEN, the Experimental Critical Peak Pricing Rider and the Experimental Real Time Pricing Rider; the establishment of the Rider NMB Pilot Program; and the Conunercial HLF/TOU. FirstEnergy states the extension of time- differentiated time-of-day pricing options under Rider GEN, the Experimental Critical Peak Pricing Rider and the Experimental Real Time Pricing Rider, will enhance customers' opportanities to lower their electtic bills and understand the benefits of time-differentiated pricing. Nucor also believes extending the TOD SSO generation rate should also be approved, even if TOD rates are offered in the market, as they should help lower prices bid by SSO suppliers as well as lower real-time market prices in PJM (Nucor Ex. 1 at 14- 15). The Companies have also corrunitted to supply CRES providers with customer interval data and will provide Staff with plans for achieving this objective as a part of their commitment to file a grid modernization business plan (Co. Ex. 154 at 10).
RESA does not oppose the TOD option of Rider GEN, but does request the Commission require the Companies to provide an "action agenda" to Staff identifying how the Companies would provide interval data to CRES providers by June 2016 and linuting this program to only those customers currently taking service under it.
Similarly, FirstEnergy provides that Stipulated ESP IV will lower costs associated with non-market based charges by modifying the existing Rider NMB to have the Companies, rather than SSO suppliers and CRES providers, pay certain non-market based PJM billing line items, thereby reducing the risk premium added by SSO suppliers and CRES providers to bids and service prices (Co. Ex. 14 at 12,16; Tr. Vol. V. at 940, 996-97, 1002). Specifically, the Comparues propose to be charged directly for the following PJM billing line items that were determined to be non-market based: 1250, 1218, 2218, 1260, 2260, 1375, 1376, 1378, 2375, 2376, and 2378 (Co. Ex. 14 at 13-15; Tr. Vol. V at 941-43). FirstEnergy also requests the Commission to approve the Rider NMB Pilot Program, where the Companies will seek to stady the administtative burden and costs of allowing customers the option to have their CRES providers pay Rider NMB charges, as well as whether such a program would result in benefits to both participating and non- participating customers (Co. Ex. 10 at 2; Tr. Vol. II at 470, 670-71). OEG supports the inclusion of the Rider NMB Pilot Program, noting that a customers' allocation of charges
APP. 306 14-1297-EL-SSO -74- from such a program would be based on the customer's own annual ttansmission coincident peak demand. Nucor and lEU-Ohio conclude that the Rider NMB Pilot Program offers an alternate method of acquiring ttansmission and ttansmission-related services from PJM that will provide improved price signals and promote economic development and job retention, as well as provide benefits to all customers in the Companies' service territories. (Co. Ex. 3 at 3; Tr. Vol. XXXIV at 7021-22; Tr. Vol. XXVI at 5325-26, 5357.) FirstEnergy, as well as several other signatory parties, also contend that a pilot program is, by its very natare, linuted in participation in order to better evaluate the results, adding that the Corrunission is not precluded to approve experimental rates with limited participation.
Several intervening parties argue that the Rider NMB Pilot Program is discriminatory as it only allows participation from a few select customers, all of which are signatory parties to Stipulated ESP IV. In addition to arguing that the proposed pilot program is discriminatory, RESA contends that the Comparues failed to provide the Corrunission with the necessary information to determine if the pilot was justified on a cost basis or if it violated the principles of gradualism. RESA further argues that PJM billing item 1375 should not be directly charged as it is not ttuly non-market-based, since the Companies would be unable to conttol operational costs associated with this line item. (Co. Ex. 154 at 9; RESA Ex. 5 at 7-8.) Exelon supports RESA's argument and agrees Rider NMB should continue but finds that the following eight other PJM billing line items should also be omitted: Items 1376,1378, 2375, 2376, 2378,1450,1218, and 2218. OMAEG raises concerns regarding the potential for CRES suppliers and the Companies to charge customers twice for several of the enumerated items, noting that several of the costs being requested are already being recovered by CRES suppliers through their current rates and conttacts.
The Companies also note Stipulated ESP IV includes a Commercial HLF/TOU rate that will provide qualifying HLF customers an opportanity to reduce their peak usage, reduce their overall energy bills and learn about time-of-use rates. Overall, FirstEnergy alleges that, in addition to providing economic benefits, these provisions also promote stability and certainty regarding retail electtic service (Co. Ex. 8 at 4; Tr. Vol. Ill at 542-43). Nucor also reiterates OEG's praises to the several modifications and additional customer protections included within Stipulated ESP IV (Co. Ex. 154 at 7-8; Co. Ex. 155 at 7). Kroger also asserts that the Commercial HLF/TOU experimental rate will benefit the Companies' commercial HLF customers that participate in this pilot by providing these customers with the opportanity to reduce their overall energy bills and learn about the potential value of time-of-use rates, noting also that if customers participating in the experimental program are able to further improve their consumption profile during the peak periods, this will potentially result in a more cost-efficient energy consumption by these customers (Tr. Vol. 11 at 291, 302).
APP. 307 14-1297-EL-SSO -75-
Several parties argue the eligibility requirements for this program should be modified by the Commission for similar reasons as those raised against the Rider NMB Pilot Program. RESA argues that the Conunercial HLF/TOU rate is unduly discriminatory and unjust, adding that due to the eligibility requirements of the program, very iew (and, in fact, perhaps only one) customers would be eligible to participate. RESA also questions the fact that the few customers who would be able to initially qualify could remain in the program despite any subsequent changes in its eligibility requirements. (Tr. Vol. II at 289-90; Tr. Vol. XXXVII at 7788; RESA Ex. 5 at 10.) RESA concludes by stating that these products are competitive services that should be offered by the competitive market without such narrow eligibility requirements.
m. Low-Income Customer Assistance Programs and Initiatives
As discussed earlier, FirstEnergy and Citizens Coalition maintain that Stipulated ESP IV will benefit customers and the public interest by supporting low-income customers. Apart from all customers enjoying reliable power at market-based prices, FirstEnergy has corrunitted to provide funding for several programs geared toward assisting low-income customers, including the Community Coruiections program, the Cleveland Housing Network, the Council for Economic Opportanities in Greater Cleveland, the Cor\sumer Protection Association for a Fuel Fund Program, OPAE, and the Customer Advisory Agency. (Co. Ex. 7 at 30; Tr. Vol, I at 44, 65, 200-201, 205; Tr. Vol. II at 427; Co. Ex. 154 at 17; Co. Ex. 155 at 11.) Citizens Coalition also emphasizes the importance of and demonsttable need for maintaining these various low-income programs, adding that the funding provided as a part of Stipulated ESP IV will help promote involvement in these programs.
OCC/NOAC state that, conttary to FirstEnergy's assertions, low-income customers will be significantly impacted by Stipulated ESP IV, as it is does not continue certain low- income assistance programs and will significantly increase costs charged to these customers through Rider RRS, Rider DCR, and Rider GDR. Moreover, OCC/NOAC believe that, due to the exorbitant costs to low-income customers, the amount of customers whose electtic service is terminated for non-payment may increase as a result oi approving Stipulated ESP IV. Further, NOPEC points out that while many low-income groups will be receiving payouts funded by shareholders, the Stipulated ESP IV does little to benefit the Companies' ratepayers, who NOPEC asserts are captive and will be required to pay the eventaal cost of Rider RRS. (OCC/NOPEC Ex. 9 at 7,12; OCC Ex. 27 at 7-9,13- 14,16,19,22.)
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n. Market Enhancements
FirstEnergy asserts that Stipulated ESP IV benefits the competitive retail market by eliminating perceived barriers to competition and enhancing the information available to CRES providers in the Companies' service territories through the establishment of a supplier web-portal (Co. Ex. 50 at 9; Tr. Vol. XX at 3940). Additionally, the Companies state that Stipulated ESP IV will have no: (1) minimum stay provisions for customers electing to retarn to the Companies' SSO; (2) minimum default service charges; (3) standby charges; and (4) shopping credit caps (Tr. Vol. V at 1059-1060). Further, the Comparues will delete existing language referring to minimum stays, minimum notice requirements for customers retarning to the Companies' SSO service, and references for time requirements for selecting a new CRES provider (Co. Ex. 15 at 10). The Companies also note the modifications to Rider ELR, as discussed earlier, will support the competitive retail market by now allowing these customers to shop (Co. Ex. 8 at 11; Tr. Vol. II at 237- 38). While IGS is requesting the Commission authorize a placeholder retail incentive rider, IGS also provides that IGS and FirstEnergy have agreed to develop and submit an application to the Commission at a later date to recover costs associated with a mechanism to provide additional incentives to encourage retail shopping and customer engagement in the Companies' service territories (IGS Ex. 11 at 17; Tr. Vol. XXXVII at 7927-34). The Companies further assert that the Conunission should disregard the allegations that Stipulated ESP IV, through Rider RRS, will adversely affect wholesale markets, not only because consideration of this issue is within the exclusive jurisdiction of FERC, but also because intervening parties have not provided any probative evidence in the record of such an expected effect or that PJM's market design and prevailing business practices will be sufficient to remedy any such effect in order to protect ratepayers. As a final matter, FirstEnergy and Staff further contend that Exelon's offer is not a ttue alternative offer to the Economic Stability Program, as it has not been accepted or vetted through the appropriate channels of Exelon's administtation and contains a significant amount of additional risk when compared to the forecasted risk of Rider RRS. Staff also notes this offer covers a smaller amount of capacity and does not include ancillary services. (Tr. Vol. XXXVIII at 8024-26, 8030, 8035-39, 8046-51, 8068-70.) Additionally, Staff asserts that while several intervening parties have made anti-competitive allegations, no quantitative analysis on a wholesale or retail basis has been provided in the record. Furthermore, Staff asserts that Stipulated ESP IV will not deter entty into the competitive market; rather, it will provide that the PPA units are managed efficiently and bid competitively in the PJM markets with full Conunission oversight to assure compliance (Co. Ex. 154 at 8).
Several of the intervening parties raised concerns that Rider RRS constitates an anti-competitive subsidy which could harm FirstEnergy's customers and the public interest OCC/NOAC specifically provide that allowing subsidized power plants to participate in a wholesale market against unsubsidized power plants desttoys the benefits to customers of a properly functioning competitive wholesale market, noting that both the short-run efficiency benefits and long-run efficiency benefits to customers and the market
APP. 309 14-1297-EL-SSO -77- would be undermined (OCC/NOPEC Ex. 1 at 10-15). NOPEC, OMAEG, IMM, P3/EPSA, and RESA also believe Rider RRS, as a large portion of Stipulated ESP IV, will result in an anti-competitive subsidy which only benefits the Companies and FES (OCC/NOPEC Ex. 1 at 16-17). Dynegy further asserts that if Rider RRS is approved, FES will be in a uruque position compared to Dynegy and other merchant generators because of its non-market based PPA with the Companies, as well as distort wholesale markets and negatively impact the retail market (IMM Ex. 2 at 1, 5-6). Power4Schools and IMM also raise concerns that the Companies' proposed Rider RRS and underlying PPA will undermine the PJM market signals critical to maintairung and atttacting adequate generation supply (IMM Ex. 2 at 3-5). Although RESA agrees that the web portal proposal should be approved, it recoirunends that the Commission direct the Companies to hold stakeholder collaborative meetings to assist with its development and implementation. Additionally, RESA also contends that the proposed changes to FirstEnergy's tariff will not result in any ttue retail market enhancement. In fact, RESA maintairrs that the several alleged market enhancements are mandated actions required by the Corrunission in prior proceedings or constitate improvements in existing systems that will do very little to enhance Ohio's retail market (Tr. Vol. V at 1059-60; Co. Ex. 1 at 19, Attachment 3, Attachment 5; Co. Ex. 15 at 5,11). NOPEC and OCC/NOAC contend the agreement between IGS and FirstEnergy was nothing more than blatant violation of the first prong of the three-prong test and there is not sufficient evidence in the record to approve such a rider, even if it is merely a placeholder rider.
o. Various Other Benefits Derived Under Stipulated ESP IV
FirstEnergy further provides that while the costs of the Companies' compliance with renewable energy requirements will continue to be recovered through the Alternative Energy Resource Rider (Rider AER)," the rate design of Rider AER will be modified so that estimated costs are recovered within the quarter they are expected to be incurred. FirstEnergy also states that the Companies seek to eliminate the loss differentiation of Rider AER and that these modifications are in compliance with the recommendations made in the financial audit report in Case No. 11-5201-EL-RDR. (Co. Ex. 45 at 5; Co. Ex. 14 at 11; Tr. Vol. XVIII at 3635.) FirstEnergy further maintains ti:\at Stipulated ESP IV includes provisions that will adjust the Companies' SEET calculation and electtic service regulations and associated riders and tariffs, as well as engage in good faith in federal advocacy, all of which will benefit the public interest and customers (Co. Ex. 154 at 9). Stipulated ESP IV includes updates to the Companies' tariffs to provide clarity to customers, remove inconsistencies, and make the Companies' tariffs more user- friendly. (Co. Ex. 8 at 4,12; Co. Ex. 10 at 2; Co. Ex. 11 at 2.) The Companies also propose to continue the current storm deferral mechanism during Stipulated ESP IV held to the
•'•^ Rider AER is a bypassable generation rider that recovers the costs of the Companies' compliance with the alternative energy portfoho standards.
APP. 310 14-1297-EL-SSO -78- same terms and conditions that exist under the ESP HI Case, with the disposition of any regulatory asset or liability balance at the end of Stipulated ESP IV to be addressed in a futare proceeding (Co. Ex. 7 at 8). FirstEnergy further explains that under the current deferral mechanism, actaal storm damage expenses in excess of the test year levels are added to the deferral, while actaal storm damage expenses that are less than the test year levels are subttacted from the deferred amount (Co. Ex. 7 at 7). Moreover, the Companies propose to recover the costs associated with providing credits for excess generation to net- metering customers in the Companies' non-bypassable Disttibution Uncollectible Rider (Rider DUN).^^ The Companies state the inclusion of these credits in Rider DUN will allow the Companies to recover the costs associated with providing the credits to net- metering customers when their generation produces more kilowatt supply than what the Companies bill them during the respective billing cycle. The Companies also state that they are currently not recovering these costs; rather, they are subsidizing from the net metering customers. FirstEnergy alleges the inclusion of such costs in Rider DUN would help facilitate the efficient recovery of expenses associated with excess net metering customer generation. (Co. Ex. 7 at 26.) Furthermore, the Comparues contend that the Master SSO Supply Agreement (MSA) does not require any amendments as it has effectively functioned for several years to procure sufficient and reasonably priced SSO load.
OCC/NOAC, OMAEG, OHA, and RESA argue that the provision coromitting FirstEnergy to engage in federal advocacy lacks any firm commitment from the Companies (OCC Ex. 9 at 20-21). Additionally, RESA proposes several modifications to the Companies' proposed tariff and bill format changes, as well as various amendments to the Companies' MSA.
p. Commission Decision
The Corrunission again emphasizes the importance of our mission in assuring all customers access to safe and reliable utility services at fair prices as well as the difficulty of balancing numerous important interests in deciding these sensitive and complex issues. We find that, subject to the modifications ordered by the Conunission below, as a package, the Stipulations benefit ratepayers and are in the public interest. In making this determination, we have reviewed the Economic Stability Program and Rider RRS, which form the centerpiece of the proposed ESP IV; the additional provisions of the proposed ESP IV; and the additional programs which FirstEnergy will propose and which will require futare Commission approval. Based upon our review, we find that the record in this case demonsttates a projected net credit to customers of $256 million under Rider RRS for the eight years of ESP IV. Further, we find that the Stipulated ESP IV, as modified, will
^^ Rider DUN is a nonbypassable rider that recovers distribution uncollectible expenses associated with the Universal Service Fund/Percentage of Income Payment Plan.
APP. 311 14-1297-EL-SSO -79- protect consumers against rate volatility and price fluctaations by promoting rate stability for all ratepayers in this state, modernize the grid through the deployment of advanced technology and procurement of renewable energy resources, and promote competition by enabling competitive providers to offer innovative products to serve customers' needs.
Additionally, we note that this portion of the three-part test specifically requires that we evaluate the Stipulations as a package. In prior cases, the Commission has considered and approved stipulations that address a wide variety of issues, often resolving several pending proceedings at the same time, and specifically emphasizing that the stipulation must be viewed as a package. See, e.g.. In re Ohio Power Co., Case No. 94- 996-EL-AIR, et al. Opinion and Order (Mar. 23, 1995) at 20-21; In re Columbus Southern Power Co. and Ohio Power Co., Case No. 99-1729-EL-ETP, et al., Opiruon and Order (Sept. 28, 2000) at 44; In re Dayton Power & Light Co., Case No. 02-2779-EL-ATA, Opinion and Order (Sept 2, 2003) at 29. We have repeatedly found value in the parties' resolution of pending matters through a stipulation package, as an efficient and cost-effective means of bringing issues before the Corrunission while also, often times, avoiding the considerable time and expense associated with the litigation of a fully-contested case. See, e.g., ESP III Case Order at 42; In re Columbus Southern Power Co. and Ohio Power Co., Case No. 11-5568- EL-POR, et al.. Opinion and Order (Mar. 21, 2012) at 17. Consequently, we reaffirm that the Stipulations must be viewed as a whole.
As a preliminary matter, the Commission notes that the proposed ESP IV carries forward ir\any elements of the previous FirstEnergy ESPs and that these elements are not seriously disputed by any party. Under the proposed ESP IV, FirstEnergy will continue to procure 100 percent of the load for SSO service on a conapetitive basis. FirstEnergy has not proposed any significant changes to the auction process which it has successfully used to procure the load for SSO service since 2009. Further, we note that, consistent with R.C. 4928.03, there are no captive retail customers as retail customers are free to choose any generation supplier. Wholesale competition and retail competition are different. Wholesale competition involves generators of power selling energy, capacity and ancillary services into the PJM market. Retail competition involves competitive retail electtic service suppliers reselling power purchased from the wholesale market to retail consumers. Further, retail competition is robust in the Companies' service territories. According to the record, 72 percent of customers, and 84 percent of customer load, is provided by CRES providers in the Companies' service territories.^^ These percentages reflect that customer shopping and choice in FirstEnergy's service territory is robust. Customers have choices of electtic supplies. The Stipulations will allow for the continuation of choice and robust shopping by customers in the FirstEnergy service territory.
^^ The Commission hereby takes administrative notice of the latest available customer choice switch rates available on its website.
APP. 312 14-1297-EL-SSO -80-
i. Consideration of Rider RRS
The centerpiece of the proposed ESP IV is the Economic Stability Program, which includes Rider RRS. Rider RRS will operate as a form of rate insurance. If energy market prices stay at the current low levels, customers will pay a charge under Rider RRS; however, if energy market prices rise from the current low levels, customers will begin to receive a credit under Rider RRS, which will mitigate the increases customers see on their bills (Co. Ex. 13 at 10,12,14-15; Co. Ex. 14 at 4; Tr. Vol I at 75; Tr. Vol. XVIII at 3650). The higher energy market prices rise, the greater the amount of credit customers will see.
The first task in our analysis of Rider RRS is to determine a reasonable estimate of the net credit or charge based upon the evidence in the record of this case. The Commission notes that the record in this proceeding contains several publically available projections of the net revenues to be recovered under Rider RRS as well as multiple other analyses oi revenue under the Rider. One of these projections was prepared by FirstEnergy witaess Rose, while three projections were prepared by OCC witaess Wilson. Each of these projections involved numerous variables, many of which are interrelated, over both an eight-year and fifteen-year span of time. The challenge before the Corrunission is to determine which projections are sufficiently reliable and how to harmonize the varying results of the projections which the Commission determines to be reliable. We note at the outset that projections and forecasts are predictions. They are predictions of futare conditions and are based upon what is happening now and multiple additional assumptions. Considering the natare of the proposed Rider RRS as a potential hedge or irisurance on electticity rates, in making its determination the Commission must choose from the most reliable of these projections and forecasts to make a determination of whether the Stipulations, as a package, benefit ratepayers.
With respect to the projection prepared by Mr. Rose, the evidence in the record demonsttates that Mr. Rose's firm, ICF, is a recognized leader in the field (Co. Ex. 18 at 2; Tr. Vol. VI at 1300). In fact, the EIA uses ICF public projections of energy prices, as well as projections by other notable firms such as Energy Ventares Analysis benchmarks for comparisons of EIA projections (Co. Ex. 60 at CP-6 through 7, Table CP4, CP-9 through 10, Table CP-5).
The only full projection of energy prices, as well as the net revenues to he recovered or credited under Rider RRS, was produced by FirstEnergy witaesses Rose and Lisowski. Mr. Rose prepared the projection of energy prices, while Mr. Lisowski used such prices to determine the net annual revenues to be recovered or credited under Rider RRS using the Companies' dispatch modeling. The Commission notes that Mr. Rose forecasts higher energy prices in the futare, based upon a number of factors, including higher forecast nataral gas prices; greater reliance on nataral gas as the price setting fuel; greater reliance on more costly units as demand grows and units retire; growth in demand for electticity;
APP. 313 14-1297-EL-SSO -81- power plant retirements; new environmental regulations; new FERC policies; inflation; and carbon emission regulations (Co. Ex. 7 at 5-6. 19-20; Tr. Vol. VI at 1287-88). Likewise, Mr. Rose forecasts higher capacity prices in the future based upon: elimination of excess capacity due to plant retirements; demand growth; less capacity price suppression from demand response; less capacity imports from other regions; environmental regulations, rising financing and other capital costs; inflation; and greater nataral gas infrasttuctare leading to higher costs as gas is shipped elsewhere (Co. Ex. 17 at 6-9, 41-43). According to the Companies' forecasts, the projected net revenues to be charged or credited to customers will result in an aggregate $561 million credit (in nominal dollars) over the eight-year term of ESP IV (Co. Ex. 155 at 11-12).
Despite the various criticisms of the projections prepared by FirstEnergy witaess Rose and the modeling prepared by FirstEnergy witaess Lisowski, we are not persuaded by arguments against giving weight to the projections and models. Although we are mindful of the fact that FirstEnergy has the burden of proof in this proceeding, no other party has presented a full projection of energy prices and the net revenues under Rider RRS. Even OCC witaess Wilson derives much of his projection from the numbers prepared by Mr. Rose and Mr. Lisowski. Further, Mr. Rose observes that one of the EIA cases used by Mr. Wilson, the Reference case, projects nataral gas prices which are comparable to, but slighfly lower than, the nataral gas prices projected by Mr. Rose (Co. Ex. 151 at 41-42).
We note that several parties criticize FirstEnergy for not updating its projection since it was prepared prior to the filing of the application in this proceeding in 2014. However, the EIA noted in its Armual Energy Outlook for 2015 that the projected electticity prices for the Reference case, over the long term, actaally increased in comparison to the Reference case for the Armual Energy Outiook for 2014. EIA noted that;
In the AEO2015 Reference case delivered nataral gas prices to electticity generators are lower than in the AEO2014 Reference . case in the first few years of the projection but higher flrroughout most of the 2020s. From 2020 to 2030, the generation cost of component of end-use electticity prices is, on average, 4% higher in AEO2015 than in AEO2014.
(Co. Ex. 166 at E-7).
Therefore, it is likely that, even if Mr. Rose had updated his projection, the resulting higher electticity prices would have made Rider RRS appear to be more favorable to customers rather than less favorable.
Accordingly, based upon the evidence in the record, the Commission finds that this projection by FirstEnergy witaess Rose (Rose projection) is reliable, and we will include
APP. 314 14-1297-EL-SSO -82- the Rose projection in our determination of an estimate of the net re^'enues under Rider RRS.
One of the projections prepared by OCC witaess Wilson ("Scenario 2") substitates the energy and nataral gas prices forecast by FirstEnergy witaess Rose with nataral gas prices forecast by the EIA and with energy prices derived from such forecasts b}'" Mr. Wilson based upon the relatiorrship between nataral gas and energy prices (OCC/NOPEC Ex. 9 at 12). Mr. Wilson prepared this projection twice: first, for the full 15-year term of Rider RRS initially proposed by the Companies, based upon the EIA Annual Energy Outiook for 2014 (Co. Ex. 60) and, second, for the eight-year term of Rider RRS provided for in the Third Supplemental Stipulation, based upon the EIA Annual Energy Outlook for 2015 (Co. Ex. 166). For this projection, Mr. Wilson used the High Oil and Gas Resource case prepared by the EIA, and this projection resulted in a net charge to customers of $2.7 billion over tae eight years of ESP IV. The Commission agrees with numerous witaesses that the EIA is a source of reliable, unbiased of information, including projections of futare energy prices. However, we find that the use of this projection by Mr. Wilson is fundamentally flawed in two respects.
First, OCC witaess Wilson's forecast is unreliable because it is internally inconsistent. Although Mr. Wilson changed the price of nataral gas in FirstEnergy witaess Rose's forecast to the price predicted by the EIA in the High Oil and Gas Resource case and changed the price of electticity to reflect that price of nataral gas, Mr. Wilson failed to change all of the interrelated variables in FirstEnergy witaess Rose's forecast and FirstEnergy witaess Lisowski's model. First, although Mr. Wilson substitated his projected nataral gas prices for Mr. Rose's forecasted nataral gas prices, he did not change the implied heat rates, which are the ratio of electtical energy prices in the market to nataral gas prices (Tr. Vol. XXII at 4545-46; Co. Ex. 151 at 10). Mr. Rose claims that the failure to change the implied heat rate causes Mr. Wilson to significantly underestimate the price of electtical energy (Co. Ex. 151 at 11). Mr. Rose's claim that implied heat rates change over time was corroborated, on cross examination, by Sierra Club witaess Comings (Tr. Vol, XXXIX at 8299). Moreover, the EIA assumes that the price of nataral gas, coal, and electticity are all dkectly related (Co. Ex. 166 at D-1). However, Mr. Wilson did not change the coal cost assumption provided by Mr. Rose even though the EIA High Oil and Gas Resource case predicts that the price of coal will remain at or below 2013 levels through 2020 and rise gradually through 2030 (Tr. Vol XXXVIII at 8113, 8115). The cost oi coal is a significant factor in determining the cost oi generatmg electticity in a coal- fired power plant (Tr. Vol. XXXVIII at 8084). The net effect of Mr. Wilson's selective use of the ElA's projected nataral gas and coal prices is to suppress the revenue from the sale of electticity under Rider RRS because of low forecasted electticity prices while keeping the costs of generating such electticity constant by failing to modify the assumed coal prices. This inconsistent application of related variables artificially suppresses projections oi the net revenue recovered or credited under Rider RRS.
APP. 315 14-1297-EL-SSO -83-
The next flaw in OCC witaess Wilson's second projection is that Mr. Wilson arbittarily chose to use the High Oil and Gas Resource case out of the numerous other cases prepared by the EIA for both the 2014 and the 2015 Annual Energy Outlook. The Commission notes that, at the time of the hearings in this proceeding, the price of nataral gas was near historic lows. The High Oil and Gas Resource case postalates that the price of nataral gas, as well as electticity, remains at historic lows; specifically, the High Oil and Gas Resource case predicts that the price of nataral gas and electticity, as well as oil, will remam below 2013 prices through at least 2030 (using 2013 dollars) (Co. Ex. 166 at D-1). The evidence also illusttates that the High Oil and Gas Resource case predicts substantially lower nataral gas prices through 2040 than any other case prepared by the EIA (Co. Ex. 166 at 6, Figure 6; Co. Ex. 60 at MT-22, Figure MT-41) and substantially lower electticity prices through 2040 than any other case prepared by the EIA (Co. E. 166 at 8, Figure 9). In other words, the claims by OCC and NOPEC, and other intervenors relying upon Mr. Wilson's testimony, that Rider RRS will cost consumers $2.7 billion rely upon a projection which assumes that the price of nataral gas, electticity and oil will remain below 2013 prices (in 2013 dollars) for at least the next 15 years.
The Commission does not believe that the evidence supports OCC and NOPEC's prediction that we have entered a period of energy price Utopia where the price of nataral gas, electticity and oil remains flat for a period of 15 years nor do we believe it would be responsible for the Commission to base its decision on such a prediction. The evidence in the record demonsttates that the predicted prices for nataral gas are sigiuficantly below recent history dating to 2005 (Co. Ex. 166 at 6, Figure 6). In fact, the evidence in the record demonsttates that the oil and gas drilling rig count has dropped sharply, which may reduce futare production of nataral gas (Co. Ex. 151 at 31-33). In fact, the most current information from the EIA available at the hearing indicates that the rig count is at its lowest level since 1999 (Co. Ex. 173 at 1; Co. Ex. 174 at 1).
In addition, the High Oil and Gas Resource case is based upon the occurrence of several developments and improvements in oil and gas production (Co. Ex. 166 at 1, 21). The EIA cautions that "[tjhere is still a great deal of uncertainty in the projections of U.S. tight oil production" (Co. Ex. 60 at IF-10). OCC witaess Wilson, however, provides no evidence that such developments and improvements in oil and gas production have occurred or will occur (Tr. Vol. XXXVIII at 8157-58). Accordingly, we will place no weight on the projection prepared by Mr. Wilson which relies upon the ElA's High Oil and Gas Resource case.
The Commission notes that OCC/NOPEC witaess Wilson based a second projection ("Scenario 3") on tae prices of forward markets. Mr. Wilson considers this projection to be the "most likely and reasonable estimate" because it is based upon updated market conditions. (OCC/NOPEC Ex. 9 at 12.) However, although even
APP. 316 14-1297-EL-SSO -84-
FirstEnergy witaess Rose concedes that forward market prices may be relied upon in the short term, for two or three years, the evidence in the record demonsttates that forward markets beyond three years are thinly ttaded and that forward market prices beyond three years do not necessarily reflect actaal ttansactions but reflect offers which may or may not have been accepted instead (Co. Ex. 151 at 49-50). Mr. Wilson addresses this issue by simply predicting that nataral gas prices will rise by the rate of inflation in the out years (OCC/NOPEC Ex. 9 at 7; Tr. Vol. XXII 4571). We note that, by simply adjusting the forward prices for inflation, Mr. Wilson is once again predicting that nataral gas prices will remain flat, in real dollars, in the futare (Tr. Vol. XXII at 4571). However, Mr. Wilson presents no testimony regarding this projection as to why nataral gas prices will remain flat in real dollars. Instead, Mr. Wilson defends this forecast as the most reliable based upon current market data (OCC Ex. 9 at 10). However, the current market data Mr. Wilson relies upon are very short term prices which were heavily influenced by warm weather conditions (Tr. Vol. XXXVIII at 8119-21; Co. Ex. 167 at 10). Accordingly, the Commission finds that the eight-year (and fifteen-year) projection based solely on forward market projections lacks sufficient reliability and should be given no weight by the Conunission.
The third projection ("Scenario 1") prepared by OCC witaess Wilson also substitates the energy and nataral gas prices forecast by FirstEnergy witaess Rose with nataral gas prices forecast by the EIA and with energy prices derived from such forecasts by Mr. Wilson based upon the relationship between nataral gas and energy prices. Once again, Mr. Wilson prepared this projection twice: first, for the full 15-year term of Rider RRS initially proposed by the Companies, based upon the EIA Annual Energy Outlook for 2014 (Co. Ex. 60) and, second, for the eight-year term of Rider RRS provided for in the Third Supplemental Stipulation, based upon the EIA Annual Energy Outlook for 2015 (Co. Ex. 166). For this projection, however, Mr. Wilson used the Reference case postalated by the EIA, which resulted in a net cost to customers under Rider RRS of $50 million (in nominal dollars) over the eight years of the proposed ESP IV (OCC/NOPEC Ex. 9 at 12). Even Mr. Rose concedes that the Reference case is based on sound forecasting methodology (Co. Ex. 151 at 42). The Reference case "is a business-as-usual ttend estimate, given known technology and technological and demographic ttends" (Co. Ex. 166 at iii). Accordingly, we find use of the Reference case to be reasonable.
We note that this projection shares the same flaw as OCC witaess Wilson's other projections in that he did not modify either the implied heat rates projected by FirstEnergy witaesses Rose and Lisowski or the coal prices assumed by Mr. Rose to the coal prices predicted by the Reference case. However, these flaws are somewhat mitigated by the fact that the nataral gas prices predicted by the Reference case are not abnormally low as in the High Oil and Gas Resource case. Further coal prices and production projections in the Reference case are generally more in line with projections published by ICF (Co. Ex. 60 at CP-16 through -17, Table CP7). Therefore, the Commission finds that Mr. Wilson's
APP. 317 14-1297-EL-SSO -85- projection based upon the EIA Reference case is reasonable and reliable, and we will consider this projection in our determination of the estimated net credit or charge of Rider RRS.
Additional analysis was performed by EPSA/P3 witaess Kalt. However, it should be noted that this analysis was a sensitivity analysis related to one variable, the price of nataral gas, and was not intended to be a full projection of the costs to be recovered under Rider RRS (Tr. Vol. XLI at 8706-8707). Dr. Kalt demonsttates in his sensitivity analysis that, holding all other variables constant, ii nataral gas prices stay at current, historic low levels, it will substantially increase the costs to be recovered under Rider RRS. However, we are skeptical that all other variables will remain constant. The evidence in the record is that the prices of nataral gas, electticity, coal, oil and other energy-related products are sttongly correlated (Co. Ex. 166 at C-1 through C-12, D-1 through D-14). Thus, a serrsitivity analysis solely on the price of nataral gas is helpful to the extent that it demonsttates that revenues under Rider RRS will be sttongly correlated to the price of nataral gas, but it is of little value as a projection of the net credits or costs of Rider RRS over the eight-year term.
Therefore, as discussed above, in determining an estimate of the net revenues to be recovered or credited under Rider RRS over eight years, the Comrmssion has found that two publically available projections are reliable: the Rose/Lisowski projection of a credit of $561 million and the Wilson projection of a charge of $50 million. We note that testimony in the hearing agreed that the Conunission could aggregate projections which were found to be reliable by averaging the projection (Tr. Vol. XXII at 4384-86). Averaging a credit of $561 million and a charge oi $50 million results in a reasonable estimate of a projected $255.5 million (or $256 million, rounded up) net credit to customers over the eight years of Rider RRS. Accordingly we will rely upon that estimate for purposes of this proceeding. Thus, in approving Rider RRS today, we base our decision on these projections.
Sierra Club witaess Comings also produced a projection of net charges or credits under Rider RRS (Sierra Club Ex. 96C at 2, 6). This projection is based upon confidential information obtained from FES in discovery, subject to the reduction in the length of Rider RRS from 15 years to 8 years and the reduction in the ROE from 11.15 percent to 10.38 percent (Sierra Club Ex. 95 at 3; Sierra Club Ex. 96C at 3). As this projection is based upon confidential information, it is impossible for us to include this projection in our estimate of the net credit or charges to customers under RRS without confidential information being easily derived from the calculation. However, we will note that, if we had included this projection in the average with the other two projectioris to develop our estimate, it would not change our decision in this case as there would continue to be a projected net credit to customers over the eight years of Rider RRS (Sierra Club Ex. 96C, Co. Ex. 155 at 11, OCC/NOPEC Ex. 9 at 12).
APP. 318 14-1297-EL-SSO -86-
The Commission acknowledges that the projections presented in this case are simply predictions of futare market prices and costs; thus, even the most reliable projections may be proven wrong in the futare, particularly over an eight-year timeframe. Therefore, in order to protect customers against rate volatility and price fluctaations and to provide additional rate stability for customers, the Corrunission wUl modify the Stipulations to include a mechanism to limit average customer bills. This will ensure that the average customer bill will see no total bill increase for two years.
Therefore, the Commission directs the Comparues to ensure for the period of June 1, 2016, through May 31, 2017, that average customer bills do not increase as compared to average customer bills for the period of June 1, 2015, through May 31, 2016, the last year of FirstEnergy's ESP III, taking into account any seasonal rate differential and any over and under recoveries of Rider RRS for prior periods. Further, the Commission directs the Comparues to ensure for the period of June 1, 2017 through May 31, 2018, that average •customer bills do not increase as compared to average customer bills for the period of June 1, 2015, through May 31, 2016, taking into account any seasonal rate differential and any over and under recoveries of Rider RRS for prior periods. FirstEnergy is authorized to defer expenses for futare recovery in an amount equivalent to the revenue reduction resulting from the implementation of the mechanism for the period of June 1, 2017 through May 31,2018.
The mechanism limiting average customer bills shall be subject to certain limits. First, costs recovered for smart grid deployment will be excluded from consideration. Likewise, costs for renewable energy procurement and for Rider AER will be excluded from consideration. The impact on riders resulting ttom credits to customers due to a disallowance ordered by the Commission will also be excluded. This mecharusm will not apply during periods where Rider RRS is a credit for customers.
The Commission notes that the Companies voluntarily included Rider RRS as part of their ESP and chose to file an ESP to fulfill the obligation to provide SSO service under R.C. 4928.141. Further, the Companies' have the option, under R.C. 4928.143, to reject any Commission modifications to the ESP and withdraw their application for an ESP. Therefore, ii the Companies proceed with Rider RRS by filing tariffs and finalizing a power purchase agreement with FES based upon the term sheet, we will consttue such actions as the voluntary acceptance of the mechanism limiting average customer bills.
Having determined that the best projection or forecast, based upon the record, of the credit to be produced by Rider RRS is $256 million, we will tarn to other factors to be considered in determining whether Rider RRS is in the public interest. The Commission notes that, its approval of Rider RRS, as a retail hedge, is based upon retail ratemaking authority under state law, which does not cor\fiict with or erode federal laws or the
APP. 319 14-1297-EL-SSO -87- responsibility of FERC to regulate electticity at wholesale. Charges at wholesale are exclusively within the jurisdiction oi the FERC. Here, the Commission specifies the reasonable amount to pay at retail. The Companies are under no requirement by this Commission or FERC to enter into the arrangements proposed under the Economic Stability Program. Penn. Power Co. v. Pennsylvania Pub. Util Comm., 127 Pa.Commw. 97, 561 A.2d 43 (1989); Pike County Light and Power Co. v. Pennsylvania Pub. Util Comm., 77 Pa. Commw. 268,465 A.2d 735 (1983).
Recently, in the AEP Ohio ESP III Order, we declined to adopt a PPA rider proposal, as put forth in that proceeding; however, we authorized the establishment of a placeholder PPA rider, at the initial rate oi zero, with AEP Ohio being required to justify any requested cost recovery in futare filings before the Commission. AEP Ohio ESP III Order at 24-25. Accordingly, we address the relevant factors we highlighted as important to consider. While the Commission is sympathetic to concerns surrounding the potential additional ttansmission costs, resource diversity, and local economic impact, the Commission's decision does not tarn on such issues. As stated above, our decision today is based upon our retail authority under state law and is consistent with federal law.
The record demonsttates that, in the event of plant closure, substantial ttansmission investments would be necessary (Co. Ex. 37 at 2-3; Co. Ex. 39 at 5-7; Tr. Vol. XV at 2354-56; Tr. Vol. XVI at 3293-94). According to testiinony in the record, the low estimates for such ttansmission investments is $400 million while the high end estimate is $1.1 billion (Co. Ex. 39 at 8-10; Tr. Vol. XVI at 2385). These estimates are unconttoverted by opposing parties in this proceeding. As with all such estimates, it is likely that neither the low end of the range nor the high end of the range are correct; therefore, in the event that Sanunis and Davis-Besse were to close, in order to maintain reliability, ttansmission investments in the range of $400 million to $1.1 billion would be required simply to maintain reliability.
On the other hand, the Economic Stability Program will encourage resource diversity in the state. Rider RRS will support 2,220 MW in existing coal-fired generation capacity and 908 MW in existing nuclear generation (Co. Ex. 32 at 9; Co. Ex. 28 at 10). In addition, the Stipulatior\s provide for the implementation of energy efficiency programs, with a goal of saving 800,000 MWh of energy annually (Co. Ex. 154 at 11-12) and expanded energy efficiency funding for small business and independent colleges and universities. Moreover, the Stipulations provide for the opportanity to procure at least 100 MW in wind and solar generation, sourced in Ohio, in the event that the market fails to adequately spur development of new renewable energy generation resources. In addition, the Stipulations will enhance the deployment of disttibuted generation by beginning the process for the widespread deployment of advanced metering and smart grid infrasttuctare in the Companies' service territories. Such deployment will be contingent upon the business case for deploying advanced metering and smart grid infrasttuctare; however, advanced
APP. 320 14-1297-EL-SSO -88- metering and smart grid infrasttuctare is essential to support disttibuted generation in Ohio. This is consistent with Ohio policy to encourage smart grid programs, advanced metering infrasttuctare and disttibuted generation. R.C. 4928.02(D) and (F).
The testimony in this case establishes the plants to be included in the Economic Stability Program have a sigruficant economic impact upon the regions in which the plants are located (Co. Ex. 35 at 2-3; Co. Ex. 36 at 4, 9; Tr. Vol. XV at 3214-17). The Commission also notes that we have received numerous public conunents from government entities near where the plants are located and from businesses which supply goods and services to the plants verifying the economic impact of the plants. FirstEnergy witaess Murley testified that every $1 million of power produced at Sarrunis results in an additional $180,000 of econonuc activity (Co. Ex. 36 at 4) and that every $1 million of power produced at Davis-Besse results in an additional $390,000 oi economic activity (Co. Ex. 36 at 9). Consequently, Sammis and Davis-Besse have a total economic impact of over.$1.1 billion armually (Co. Ex. 36 at 11). The economic impact of plant closures and the impact on local conununities is of concern to the Corrunission. Rider RRS will provide support for the identified generation assets and will provide the other benefits described for ratepayers in this Order. We are mindful of the competing interests for any potential additional cash flow and encourage FirstEnergy to place the long-term interests of its employees and the grid first. Rather than any short-term opportanity to increase dividends, or otherwise impact earnings, we suggest that the retirement plans of hardworking employees, such as those working in plants, providing customer service, and responding to power outages, and the infrasttuctare needs of the grid be corisidered first.
Additionally, the Commission agrees that the allocation of costs under the proposed rate design for Rider DRR will promote economic development in the region by encouraging large industtial customers to locate or expand in the Companies' service territories in order to take advantage of lower competitive rates.
ii. Rigorous Review of Rider RRS
The Conunission in AEP Ohio ESP III Order also indicated that a power purchase agreement rider proposal must include additional provisioris specified by the Commission: provide for rigorous Conunission oversight of tae rider, including a proposed process for a periodic substantive review and auditi corrunit to full information sharing with the Commission and its Staff; and include a provision to allocate the rider's financial risk between both the Company and its ratepayers. Further, the proposal must include a severability provision. AEP Ohio Order at 25-26. The Stipulations contain the provision for review of Rider RRS as specified by the Conmiission. The Companies have proposed a process under which Staff will be able to review all futare costs incurred by Sanunis and Davis-Besse (Co. Ex. 7 at 15; Tr. Vol. I at 58-59, 68; Tr. Vol. XXIV at 4879; Tr.
APP. 321 14-1297-EL-SSO -89-
Vol XXVI at 5198). In addition, the Companies agree that the armual compliance reviews will include actioris taken by the Companies when selling the output from the generation uruts included in Rider RRS into the PJM market (Tr. Vol. XXXVII at 7889). FirstEnergy agrees that the Companies, not customers, will be responsible for the adjustments made to Rider RRS for actions deemed urueasonable by the Commission (Co. Ex. 8 at 21; Co. Ex. 154 at 8; Tr. Vol. I at 60-61; Tr. Vol. II at 448).
We disagree with claims that this review is inadequate or illusory. The armual review provided for under the Stipulations talfills the recommendation set forth by Staff (Staff Ex. 12 at 15-16; Tr. Vol. XXXVI at 7702-03). The Commission has always provided for the periodic review and reconciliation of riders created under ESPs. It is well- established that state commissions can review whether a utility prudently entered into a particular ttarrsaction in light oi the alternatives. Pike County Light and Power Co. v. Pennsylvania Pub. Util Comm., 77 Pa.Commw. 268, 465 A.2d. 735 (1983). FERC acknowledges the authority of states to review the prudence of ttansactions. Duke Energy Retail Sales, LLC, 127 FERC H 61027 (2009). This authority also has been recognized by Federal courts:
Regarding the states' ttaditional power to consider the prudence of a retailer's purchasing decision in setting retail rates, we find no reason why utilities must be permitted to recover costs that are imprudently incurred; those should be borne by the stockholders, not the ratepayers. Although Nantahala underscores that a state caxmot independently pass upon the reasonableness of a wholesale rate on file with FERC, it in no way undermines the long-standing notion that a state commission may legitimately inquire into whether the retailer prudently chose to pay the FERC-approved wholesale rate of one source, as opposed to the lower rate of another source.
Kentucky West Virginia Gas Co. v. Pennsylvania Pub. Util Comm., 837 F.2d 600, 609 (3d Cir. 1988)(dting Nantahala Power & Light Co. V. Thornburg, 476 U.S. 953, 106 S.Ct. 2349, 90 L.Ed.2d. 943 (1986).
Further, we note that the Comparues have consented to this review as an integral part of Rider RRS under the ESP pursuant to R.C. 4928.143, specifically including both the costs of generating power and the ttansactiorrs involving the sale of the power into the PJM market (Co. Ex. 155 at 4). Kentucky West Virginia Gas Co., 837 F.2d at 617 (finding that tae utility could not complain about process used by Commission to which it had consented).
Regarding the process for updating Rider RRS, ongoing Staff review and armual audits of Rider RRS, the Commission will modify the Stipulations to provide that
APP. 322 14-1297-EL-SSO -90-
FirstEnergy will file armual forecasted values subject to quarterly ttue-ups to reflect actaal values rather than the armual updates to Rider RRS proposed in the application. Further, we expect that tae audit process will be carried out in a marmer that is consistent with past practice. Accordingly, with respect to FirstEnergy's quarterly Rider RRS filings, which should mclude appropriate work papers. Staff should review each such iiling ior completeness, computational accuracy, and consistency with any prior Commission determinations regarding the adjustments. If Staff raises no issues prior to the billing cycle during which the quarterly adjustments are to become effective, the adjusted Rider RRS rates shall become effective for that billing cycle. Rider RRS, however, remains subject to adjustment during the annual audit and reconciliation, through which Staff, or another auditor selected by the Commission, will review the accuracy and appropriateness of the rider^s accounting and the prudency of FirstEnergy's decisions and actions as set forth in the Stipulated ESP IV. In order to facilitate the audit of FirstEnergy's Rider RRS filings, the Companies should open a new case each year in which they should file taeir quarterly Rider RRS adjustments and in which the audit report for that year should also be filed. The quarterly Rider RRS adjustments should be filed on or before March 1, June 1, September 1, and December 1 of each year, unless otherwise agreed upon by Staff and the Companies. FirstEnergy and Staff should work together to determine the specific content and format for the quarterly Rider RRS filings. We also note that interested stakeholders may seek to intervene and participate in the armual audit process, consistent with any established procedural schedule.
With respect to legacy costs, the Commission directs the Companies to provide to the Staff audited accounting information establishing the amount of legacy costs. Further, the Conunission directs the auditor in the first armual audit to verify the information provided by the Comparues to serve as a baseline for futare audits.
Some parties have raised the possibility that the Companies would sell the output from the generation units included in Rider RRS to an affiliate at a below-market price. The Companies have made it clear that their mtent is to sell the energy, capacity and ancillary services into the PJM markets and that any sales under a bilateral conttact would be subject to the Corrunission's review (Tr. Vol. XXXVI at 7685-88, 7695-96). This is an issue of importance considering the previously mentioned success of retail shopping in the Companies' service territories. It is the destte of the Commission that such robust shopping continues. We emphasize that any bilateral ttansaction between the Companies and any affiliate would be sttingently reviewed to ensure that it did not adversely affect retail electtic service competition in this state. We note that, consistent with Commission precedent, the Comparues will bear the burden of proof in demoristtating the prudency of all costs and sales during the review as well as that such actions were in the best interest of retail ratepayers; however, no presumption of management prudence will apply to any bilateral sales by the Comparues to affiliates.
APP. 323 14-1297-EL-SSO -91^
With respect to bidding behavior, the Corrunission is mindful of the issues raised by PJM in its brief. Further, the Commission appreciates the continued investments in generation in our region by merchant generators. We note that PJM could impose the very same bidding standards it proposes on all bidders, or all similarly-sitaated bidders, in PJM auctions rather than only on the plants at issue in this proceeding. We are not persuaded that Sanunis and Davis-Besse should be held to different standards than other generation plants, particularly those in states which already provide for full cost recovery of generation plants. Retail cost recovery may be disallowed as a result of a prudence review if the output from the units was not bid in a marmer that is consistent with participation in a broader competitive marketplace comprised of the sellers attempting to maximize revenues. As noted above, the Companies will bear tae burden of proof m demonsttating that bidding behavior is prudent and in the best interest of retail ratepayers.
We find that the Stipulations contain a provision for full information sharing as specified by the Corrunission in the AEP Ohio ESP III Order and as outlined in the testimony presented by Staff witaess Choueiki (Staff Ex. 12 at 16). Under the Stipulations, FES fleet information will be provided to Staff pursuant to a reasonable Staff request as Staff reviews any specific component of Rider RRS (Co. Ex. 154 at 8; Tr. Vol. XXXVI at 7517-20). In the event that the Companies dispute whether a Staff request is "reasonable" and the Companies and Staff cannot resolve the dispute, the Conunission will determine whether the request is "reasonable." We note that, as discussed above, the Companies bear the burden of proof regarding the prudency of costs evaluated during the armual reviews. If the Companies are unable to obtain required information from FES, the Companies will be unable to meet their burden of proof during the review.
iii. Risk Sharing
Under the Stipulations, the Companies are liable for credits to customers of up to an aggregate of $100 million in years five through eight of Rider RRS, in the event that the net revenues from the output of the generation units do not exceed the costs of the generation uruts in each year by the amount of the stipulated minimum credit (Co. Ex. 154 at 7-8; Co. Ex. 155 at 3-4; Tr. Vol. XXXVI at 7723, 7726; Tr. Vol. XXXVII at 7720). We find that the mechanism appropriately balances legitimate customer concerns about prices with the interests of other stakeholders. Further, we will clarify the Stipulations and note that the Companies will be precluded from recovermg the costs associated with the credits in any future Commission proceeding, which is consistent with their mtent as evidenced during the hearing. (Tr. Vol. XXXVI at 7525-26.).
The Commission will also clarify and modify the Stipulatioris in order to ensure that additional financial risk under the Stipulations is properly avoided and in the public
APP. 324 14-1297-EL-SSO -92- interest. We will modify the Stipulations to clarify that no plant retirement costs may be recovered through Rider RRS. We also agree with PJM that the Stipulations do not properly allocate risk in light of PJM's new capacity performance standard. FirstEnergy, rather than ratepayers, will bear the burden for any capacity performance penalties incurred by the generation units. Under no circumstances will capacity performance penalties be considered recoverable under Rider RRS. However, we will further n^odiiy the Stipulations to provide that all capacity performance bonuses will be retained by the Comparues. Additionally, the Commission reserves the right to prohibit recovery of any costs related to any unit for any period exceeding 90 days for any forced outage durmg the term of ESP IV, uriless otherwise recommended by Staff and approved by the Commission.
The Third Supplemental Stipulation contains a severability provision in the event a court of competent jurisdiction invalidates Rider RRS in part or in whole (Co. Ex. 154 at 8- 9). This provision attempts to preserve the benefits to customers under the proposed ESP IV while the parties negotiate in good faith to restore the invalidated provision or its equivalent value.
The Commission finds that the severability provision requires modification in order to be in the public interest. Accordingly, we will modify the provision to add that we reserve the right to reevaluate and modify the Stipulations if there is a change to PJM's tariffs or rules which prohibits the plants ttom being bid into PJM auctions. The modification is consistent with our intent in requiring a severability provision in the AEP Ohio ESP III Order; thus, we find that the severability provision, as modified, adequately addresses our concern specified in the AEP Ohio ESP III Order.
iv. Additional Benefits of Stipulations
The Corrunission notes that, in addition to the Economic Stability Plan and Rider RRS, the Stipulations contain several additional provisions which benefit ratepayers, are in the public interest, and are consistent with the policy of the state as set forth in R.C. 4928.02. These additional provisions include provisions related to disttibution rates, proposals mtended to facilitate the state's effectiveness in the global economy, and provisions to restart and revitalize FirstEnergy's energy efficiency programs.
The key provisions in the Stipulations related to disttibution rates is the continuation of tae base disttibution rate freeze for eight years under ESP IV. The extension of the disttibution rate freeze will promote stable rates, as base disttibution rates will not rise during the term of ESP IV (Co. Ex. 155 at 3). The Commission notes that base disttibution rates have not increased in the Companies' service territories since 2009. In re FirstEnergy, Case No. 07-551-EL-AIR et. al., Opuiion and Order (Jan. 29, 2009). However,
APP. 325 14-1297-EL-SSO -93- in light of the proposed disttibution rate freeze, it is necessary and appropriate to continue the existing Rider DCR mechanism, which allows the Companies to recover reasonable investments in plant in service associated with disttibution, subttansmission, and general and intangible plant, which was not included in the rate base oi the Companies' last disttibution rate case. We note that Rider DCR was first approved by the Commission in FirstEnergy's ESP II and has been in effect since January 1, 2012. ESP II Case, Opinion and Order at 11. The Stipulations provide for continued annual audits of recovery under Rider DCR and requires the Companies to demonsttate what they spent and why the recovery sought is not urueasonable. These disttibution investments are necessary to maintain disttibution reliability at current levels. Likewise, the storm cost deferral mechanism facilitates the disttibution rate freeze by allowing the Companies to defer unusually high storm damage expenses in the event such expenses are actaally incurred.
In addition, in light of tae eight-year disttibution rate freeze. Rider GDR will allow the Companies to request Corrunission authorization to recover unforeseen expenses related to government mandates imposed during ESP IV (Co. Ex. 16 at 4; Tr. Vol. I at 180). The Commission finds that the duration of the eight-year proposed ESP IV distinguishes the proposed Rider GDR from a similar rider proposed in the AEP Ohio ESP III proceeding. AEP Ohio ESP III Order at 62. Rider GDR will be set initially at zero. FirstEnergy may file an application in a separate proceeding to recover any costs which it currently contemplates recovering through Rider GDR, and the Companies will bear the burden of demonsttating that such costs are just and reasonable (Co. Ex. 16 at 3; Tr. Vol. XXIV at 4905). The Commission will clarify that Rider GDR should be limited to Federal and state government mandates enacted after the filing date of the application m this proceeding and that no generation or ttansmission related expenses will be eligible for recovery under Rider GDR.
Further, the Companies have agreed to file an application to ttansition to SFV rate design for disttibution rates (Co. Ex. 155 at 13). Implementation of SFV rate design removes disincentives to electtic utilities to promote energy efficiency, is more consistent with principles of cost causation, and has been a policy goal for the Commission for some time. In the Matter of Aligning Elec. Distribution Utility Rate Structure with Ohio's Public Policies to Promote Competition, Energy Efficiency and Distributed Generation, Case No. 10- 3126-EL-UNC, Finding and Order (Aug. 21, 2013). We are unpersuaded by the testimony of OCC witaess Rubin opposing the SFV rate design proposal because he appears to have based his testimony on an earlier draft stipulation rather than the Third Supplemental Stipulation as tiled (Tr. Vol. XXVUI at 8261-62, 8271-72). Although we may have preferred to address implementation of SFV in FirstEnergy's next disttibution rate case, the Commission notes that R.C. 4928.143(B)(2)(h) specifically permits an ESP to include provisions for a revenue decouplmg mechanism; and we find that it would not be in the public interest to delay implementation of SFV rate design until tae end of the proposed eight-year disttibution rate freeze. In addition, the Stipulatior\s provide for a separate
APP. 326 14-1297-EL-SSO -94- proceeding where any interested party will have a full and fair opportanity to address whether the proposed SFV should be implemented and to raise any other issues specific to the Companies' service territories (Tr. Vol. XXXVI at 7577).
In addition to the proposal to ttansition to a SFV rate design, the Stipulatiorrs provide for a number oi other provisions intended to promote the state's effectiveness in the global economy. The Companies will provide $3 million per year in shareholder fundmg to promote job retention and economic development in the region (Co. Ex. 154 at 7; Co. Ex. 155 at 12; Tr. Vol. XXXVI at 7734-36). Additional provisions in the Stipulations include continuation of the automaker credit, continuation and expansion of Rider ELR, and a pilot program for large customers to obtain non-market based ttansmission services outside of Rider NMB. The automaker credit is intended to incentivize increased production from automaker facilities located in the Companies' service territories. This provision was initially approved in FirstEnergy's ESP II. FirstEnergy ESP II Case, Opinion and Order (Aug. 25 2010) at 16. With respect to the continuation and expansion of Rider ELR, the evidence in the record demonsttates that interruptible load programs provide reliability, economic and energy efficiency benefits to customers (OEG Ex. 1 at 9-13; Co. Ex. 8 at 3; Tr. Vol II at 259-60; Tr. Vol. HI at 491; Tr. Vol. XXX at 6131, 6154, 6156, 6171). Rider ELR was approved by the Commission FirstEnergy's fttst ESP and has continued in place since then. FirstEnergy ESP I Case, Second Opimon and Order (Mar. 25, 2009) at 10. The Stipulations also include an experimental time-of-use rate for high load factor commercial customers. The experimental HLF/TOU provides an incentive for large retailers to retain or relocate taeir corporate headquarter to this state (Tr. Vol. II at 291, 302). The experimental HLF/TOU fits squarely under Ohio policy, which encourages irmovation and market access for cost-effective retail electtic service, including demand- side management and time-differentiated pricing. R.C 4928.02(D), Finally, the pilot program for large customers to obtain non-market based ttansmission services outside of Rider NMB provides the opportanity to determine if industtial customers can obtain substantial savings by obtaining certain ttansmission services outside of Rider NMB witaout imposing significant costs on other customers. The Rider NMB pilot program will provide better price signals to mdusttial customers and promote job retention and economic development in this region (Co. Ex. 3 at 3; Tr. Vol. XXIV at 7021-22; Tr. Vol. XXVI at 5325-26). All of these programs should facilitate the state's effectiveness in the global economy in accordance with R.C 4928.02(N).
As stated above, the Stipulations provide for the implementation of energy efficiency programs, with a goal of saving 800,000 MWh of energy armually (Co. Ex. 154 at 11-12). In addition, the Stipulations provide expanded energy efficiency funding for mdependent colleges and universities and for small businesses, including funding for energy efficiency audits for commercial and industtial customers (Co. Ex. 154 at 15). These provisions for energy efficiency funding for small businesses are consistent with Ohio policy which encourages "the education of small business owners in this state
APP. 327 14-1297-EL-SSO -95- regarding the use of, and encourage the use of, energy efficiency programs and alternative energy resources in then businesses." R.C. 4928.02(M).
In addition, the Stipulatior\s would increase the cap on shared savings to $25 million (Co. Ex. 154 at 12). We note that shared savings are the result of the Companies exceeding the statatory mandates for energy efficiency. The current cap of $10 million was set or\ly for the purposes of the Comparues three-year program portfolio plan for 2014 through 2016; thus, the Conunission made no ruling on the appropriate cap for 2017 and beyond. At that time, the Corrunission noted that the cap could be increased from $10 million to $20 million if the Companies implemented a decoupling mechanism. The Comparues have now committed to file an application to implement a decoupling mechanism in the form of SFV rate design.
Further, as discussed by Company witaess Mikkelsen, any programs eligible for shared savings must be cost-effective; thus the Companies only earn shared savings if they implement cost-effective energy efficiency programs that produce energy savings in excess of the statatory mandates (Tr. Vol, XXXVI at 7639). We find, therefore, that the increase in the shared savings cap is in the public interest because it encourages the Companies to seek to provide to their customers all available cost-effective energy efficiency opportanities. As the Commission has previously stated "because * * * energy savmgs must be cost-effective, by definition, customers in the aggregate save money when the Companies deliver energy savings opportanities to their customers instead of energy. To the extent tae Companies accelerate the delivery of cost-effective energy savings opportanities to their customers, they will also accelerate the net cost savings which customers enjoy. Thus every kWh of energy that can be displaced through cost-effective energy efficiency programs is a savings, not a cost, to the Companies' customers." In re Application of FirstEnergy, Case No. 09-1947-EL-POR, et al. Entry on Rehearing (Sep. 7, 2011) at 6.
The Stipulations have a number of other provisions, in addition to the ttansition to SFV rate design, where FirstEnergy will file applications for new programs for the Commission's consideration (Co. Ex. 154 at 9-10). These provisioris include the filing of a proposal for a grid modernization program. This provision is consistent with the Staff's previous recommendation presented in this proceedmg (Staff Ex. 8 at 1-3). Under the Stipulations, FirstEnergy will file an application wita a busmess case supportmg the full deployment of smart grid meters across all of its service territories (Co. Ex. 154 at 9-10). In that separate proceeding, FirstEnergy will bear the burden of demonsttating that the application is just and reasonable, and any interested party may raise any issues regarding the business case (Co. Ex. 155 at 4; Tr. Vol. XXXVI at 7584-85, 7624).
The Corrunission will determine whether to approve any such application based solely upon the record of that proceeding; however, we note that Ohio policy supports
APP. 328 14-1297-EL-SSO -96- innovation through the implementation of smart grid programs and advanced metering infrasttuctare. R.C. 4928.02(D). Further, modernizing the grid in the Companies' service territories is also consistent with efforts to make the grid more reliable and cost effective for consumers. Further, advanced metering associated with grid modernization will promote competition by facilitating the offering by competitive suppliers of innovative products to meet customers' needs. We encourage the Companies to ensure that the proposed grid modernization filing considers the futare ttansition to a grid that engages customers and supports flexibility in meeting resource adequacy needs.
V. Modifications and Clarifications to Stipulations
However, before the Commission can find that the Stipulations benefit ratepayers and advance the public interest, a number of additional modificatiorxs and clarifications are necessary based upon the record of this proceeding. The Stipulations benefit the public interest by providing for shareholder funding for low-income customer assistance programs in order to aid those customer sttuggling to make ends meet (Co. Ex. 7 at 30; Tr. Vol. I at 44, 65, 200-01, 205; Tr. Vol. II at 427). Many of these programs have been in place for several years, and the Stipulations extend the funding for eight additional years (Co. Ex. 154 at 17; Co. Ex. 155 at 11). These programs help protect at-risk populations, consistent with R.C. 4928.02(L). However, as discussed above, the Commission is deeply concerned about the allegations raised regardmg the constitaent groups of the Citizens' Coalition given the funding provided to the members of the Citizens' Coalition by the Stipulations. Therefore, we will modify the Stipulations to require the filing of compliance reports, annually or more frequently, regarding the funding provided to both Citizens' Coalition and OPAE for programs to support low- and moderate-income customers. Thereafter, based upon the compliance reports, the Commission may order an independent audit of the funding. If such an independent audit is ordered, the independent auditor will be selected by the Commission, and the costs of the audits will be borne by the Comparues, without recovery from ratepayers. The Companies are directed to work with Staff to determine the appropriate scope and frequency of the compliance reports and/or audits. We note that, with respect to payments to other parties to promote energy efficiency programs, all energy efficiency savings obtained through such programs is thoroughly reviewed the evaluation, measurement and verification (EMV) process by the Companies' independent EMV auditor as well as the Commission's statewide EMV auditor.
With respect to the provisions related to the procurement of additional renewable resources in Ohio, the Commission notes that renewable energy plays an integral role in promoting a reliable and cost-effective grid. The Commission will continue to look to the markets as the primary drivers oi an adequate supply of energy from any source, including renewable energy. Additionally, the Conunission will continue to support
APP. 329 14-1297-EL-SSO -97- bilateral conttacts that lead to the development of renewable projects. The Stipulations provide for a corrunitment to procure 100 MW of renewable energy. The Commission supports the consttuction of new renewables in this state. The state has seen a number of wind-related projects approved for siting through the Power Siting Board, many of which have yet to be consttucted. However, solar projects are not as prevalent. Solar projects would enhance the diversity of available generation options. The Commission first encourages that bilateral conttacting opportunities be explored to provide support for the 100 MW of renewables. To the extent that bilateral opportaruties are not available, we encourage that the cost recovery filing to be made subsequently wita the Commission focus first on enhancing solar opportanities. We also direct that the Comparues demonsttate that bilateral opportanities were explored and that a competitive process was utilized to source and determine ownership of any project to be built. Further, we will modify the Stipulations to eliminate any requirement that the procurement must be related to the enactment of new Federal or state environmental laws or regulations. Moreover, the Commission will nxodiiy the Stipulations to require that FirstEnergy file a report detailing its sttategy to promote fuel diversification and carbon reduction every four years instead of every five years (Co. Ex. 154 at 11-12).
The Commission will modify the ESP and Stipulations to reject the proposed changes to the stipulations reached in the ESP IJ Case regarding MTEP and RTEP charges (Co. Ex. 7 at 17-19). The agreement on how to allocate MTEP and RTEP charges between the Comparues and customers was a fundamental issue in the Combined Stipulations approved by the Commission in the ESP II Case. ESP 11 Case, Opinion and Order at 13. When we adopted this provision, we noted that there was substantial litigation risk at both the state and Federal level, and we accepted tae allocation of that risk proposed by the Combined Stipulations (Id. at 32). We decline to revisit taat issue here.
With respect to Rider GCR, we agree with RESA that the rider should be modified from bypassable to non-bypassable only with the approval of the Commission. Therefore, we will modify the ESP to require FirstEnergy to file an application in a separate proceeding, in the event the threshold point is reached, seeking authority from the Commission to modify Rider GCR.
The Commission also notes that, as the Stipulations provide that "FirstEnergy" will retarn its corporate headquarters and nexus of operations in Akron, Ohio, for the duration of Rider RRS, the Stipulated ESP IV should be clarified such that, if FirstEnergy Corp. should move its corporate headquarters and/or nexus of operations from Akron, Ohio, durmg the period of Rider RRS, the Commission may determine, in its sole discretion, to terminate Rider RRS,
Moreover, the Commission notes that tae application contains a provision, regarding Rider AER, to liirut refunds from out-of-period adjustments (Co. Ex. 1 at 10-11).
APP. 330 14~1297-EL-SSO -98-
While we note that refunds based upon out-of-period adjustments are generally disfavored, such determinations should be made on a case-by-case basis. Accordingly, we will modify the Stipulated ESP IV to sttike that proposed provision.
The Commission also will modify the ESP and the Stipulations to adopt three changes proposed by RESA. First, we will reject the proposed change to add the term "generation" in the supplier tariff provisions related to consolidated billing (Co. Ex. 1 at Attachment 5, 1st Revised Page 3 of 52). We agree that the Compames have failed to adequately support this proposed change. Second, we will also reject FirstEnergy's proposal to eliminate the ability of CRES providers to request non-surrunary, customer usage data. We agree that this proposal is mconsistent with our decision in the recent retail market mvestigation and should be rejected. In re Retail Market Investigation, Case No. 12-3151-EL~COI, Entty on Rehearing (May 21, 2014) at 19. Finally, the Conunission will reject the changes to the supplier tariff related to unaccounted for energy (Co. Ex. 1 at Attachment 5, 1st Revised Page 30 of 52 at Section E). We find that the Companies have failed to adequately support this proposed change. We are willing to cor\sider such a change in a futare separate proceeding, provided that it is adequately supported by record evidence.
Moreover, we will modify the proposed ESP to accept the recommendation of IGS to establish a zero-based rider to unbundle from disttibution rates the costs FirstEnergy incurs to support SSO service and to reflect those costs in the SSO price (IGS Ex. 11 at 17- 18). We agree with the testimony of FirstEnergy Mikkelsen that this proposal may enhance competition in the Compames' service territories (Tr. Vol. XXXVII at 7927-28). In order to implement this rider, FirstEnergy should file an apphcation in a separate proceedmg. In that proceeding, FirstEnergy will bear the burden of demonsttating that the application is just and reasonable, and any interested party may raise any issues regarding the rider. Further, we will determine whetaer to approve any such application based solely upon the record of that proceeding.
As provided by FirstEnergy witaess Mikkelsen during the second portion of the hearing, there are a few corrunercial and industtial rate schedules that will be impacted more significantly by Stipulated ESP IV. Ms. Mikkelsen further indicated that the estimated impacts on these customers may be mitigated if the Commission would determine, for purposes of calendar year 2016, the suiruner billing periods to be July, August, and September, and that the Companies gradually phase out EDR(c) over the first three years of ESP IV. FirstEnergy witaess Mikkelsen added that the Commission could then develop a mutaally agreeable phase-in plan for this group of non-residential customers who are projected to experience more significant rate increases. (Tr. Vol. XXXVl at 7659-7662). We agree a mitigation mechanism should be employed in order to ensure that customers are provided with electticity in a cost-effective manner consistent with our mission. Therefore, we direct FirstEnergy to address these significant rate
APP. 331 14-1297-EL-SSO -99- impacts, accordingly, and collaborate with Staff to develop a phase-in plan to be implemented during ESP IV.
The Commission notes that, following the conclusion of the rehearing period, the filmg of tariffs consistent with this Order and its modifications shall be deemed as acceptance of the Order and its modifications by the Compctnies. Any such acceptance will be subject to rights of appeal in state courts. The Comparues shall file tariffs by May 1, 2016. With its initial filing and annually thereafter, FirstEnergy will provide to Staff customer bill impacts and proposed rate mitigation measures, if necessary.
vi. Consideration of Exelon Indicative Offer
Finally, The Commission notes that Exelon has made a competing indicative offer or proposal in this proceeding (Exelon Ex. IOC at 6-7). We very much appreciate Exelon's efforts to craft a worthwhile proposal; however, setting aside questions raised by FirstEnergy regarding whether the competing proposal represents a firm or binding "offer" by Exelon, we find taat, the proposal is not superior to the Stipulations because the Exelon proposal imposes too many risks on retail ratepayers in the Companies' service territories.
Although Exelon claims substantial savings to consumers for its proposal, the evidence in the record demonsttates that the around-the-clock product proposed by Exelon would require the Companies to take power at the fixed conttact price even if the conttact price exceeded the market price of power. Under proposed Rider RRS, on tae other hand, the Comparues retarn the ability to dispatch the plants only when it is economic to do so. (Tr. Vol. XXXVIII at 8051.) Thus, the fact that tae Companies will be required to take power and sell it into the market even if the around the clock, fixed price exceeds the market price undermines the savings claimed by Exelon.
Further, there is no information in the record regarding whether the proposal would support reliability with the ATSI zone of PJM (Tr. Vol. XXXVIII at 8070). Under the Exelon proposal, the energy and capacity would not be delivered into the ATSI zone of PJM (Tr. Vol. XXXVIII at 92). The evidence demorrsttates that both plants are at a serious risk of closure (Co. Ex. 28 at 2-4; Co. Ex. 143 at 5; Tr. Vol. X at 2184, 2185; Tr. Vol. XI at 2395; Tr. Vol. XXXH at 6541-42; Tr. Vol. XXXIII at 6818). If Sammis or Davis-Besse were to be retired, and such plant retirement caused the ATSI zone to separate from PJM, resulting in higher capacity prices for the ATSI zone, ratepayers, rather than Exelon, would be responsible for the difference between the higher capacity prices in the ATSI zone and the price of capacity delivered by Exelon, for the final five years of the proposal (Tr. Vol. XXXVIII at 8092-94). In addition, the Exelon proposal does not preclude the necessity of ttansmission investments to maintain reliability in the event of plant closures. As
APP. 332 14-1297-EL-SSO -100- previously noted, the cost of these investments to be recovered from ratepayers ranges from $400 milhon to $1.1 billion (Co. Ex. 39 at 8-10; Tr. Vol. XVI at 2385).
Moreover, the proposal by Exelon would do nothing to mitigate the economic impact on the region of the potential closure of Sammis and Davis-Besse. As stated above, Sammis and Davis-Besse have a total economic impact of over $1.1 billion armually (Co. Ex. 36 at 11). Closure of these plants would have a significant impact upon the communities where tae plants are located and upon the region. Accordingly, the Corrunission finds that Exelon's proposal should be rejected.
3. Does the settlement package violate any important regulatory principle or practice?
a. Inttoduction
Initially, the Commission again emphasizes the complexity of the issues in this proceeding as well as the necessity that we balance multiple interests. Moreover, the Commission must be cognizant of the state policies set forth in R.C 4928.02. While we appreciate the issues raised by non-signatory parties, we find that the Stipulations, as modified by tae Commission, protect consumers against rate volatility and price fluctaations by promoting rate stability for all ratepayers in this state, modernize the grid through the deployment of advanced technology and procurement of renewable energy resources, and promote competition by enabling competitive providers to offer innovative products to serve customers' needs, consistent with state policy to ensure the availability to consumers oi adequate, reliable, safe, efficient, nondiscriminatory, and reasonably priced retail electtic service; to encourage irmovation including smart grid programs; to protect at-risk populations; and to facilitate the state's effectiveness in the global economy. R.C. 4928.02 (A), (D), (L) and (N).
b. Economic Stability Plan (Retail Rate Stabilitv Rider^
FirstEnergy, Staff, OEG, Nucor, and MSC represent that the Stipulated ESP IV violates no important regulatory principle or practice. Irutially, FirstEnergy argues that the Economic Stability Program (including Rider RRS) is authorized under Ohio law on the basis that; (1) the Commission has previously ruled that ESP provisions like Rider RRS are authorized under Ohio law in the AEP Ohio ESP II Order and In re Application of Duke, Case No. 14-841-EL-SSO (Duke ESP IIP), Opinion and Order (Apr. 2, 2015); (2) the economic stability program is authorized by R.C 4928.143(B)(2)(d) because it is a term, condition, or charge, it relates to limitations on customer shopping, to bypassability, and
APP. 333 14-1297-EL-SSO -101- to default service, and it would have the effect of stabilizing or providing certainty regarding retail electtic service; and (3) the economic stability program is also authorized under R.C. 4928.143(B)(2)(i) (Tr. Vol. I at 42-44, 96; Co. Ex. 154; Co. Ex. 13 at 7,10-11; Tr. Vol. in at 515, 598-599; Tr. Vol. XXII at 4523; Co. Ex. 155 at 12; Co. Ex. 28 at 6-10; Co. Ex. 42 at 3-4; Co. Ex. 39 at 6-10; Co. Ex. 9 at 6-11). Finally, FttstEnergy and Staff assert that the Stipulated ESP IV does not violate any state policy on the basis that it promotes important regulatory principles and practices, mcluding that it: (1) provides customers with stable and reasonably priced electticity based upon market prices; (2) promotes reliable electtic service; (3) promotes a competitive marketplace and supports the retail market; (4) protects at-risk populations; and (5) furthers Ohio's effectiveness in the global economy (Co. Ex. 7 at 16-17, 28-31; Tr. Vol. II at 427; Co. Ex. 8 at 3; Co. Ex. 15 at 2, 9-10; Sierra Club Ex. 89). Staff adds that the Stipulated ESP IV: (6) promotes energy efficiency and peak demand reduction; (7) promotes carbon reduction; and (8) hastens grid modernization and promotes resource diversity (Co. Ex. 154; Co. Ex. 155).
OEG and Staff assert that the proposed Economic Stability Program is consistent with Ohio's quasi-market regulatory system established by S.B. 221, and echo FirstEnergy's argument that it constitates a financial limitation on shopping and will have the effect of stabilizing rates. OEG adds that the proposed Economic Stability Program is not an anti-competitive subsidy prohibited by R.C. 4928.02(H) (OEG Ex. 1 at 7-8). Fmally, OEG argues that the Commission's approval of the proposed Economic Stability Program would not be preempted by FERC, as the Commission has the ability to approve the proposed program as part of its obligation to ensure the adequacy and reliability of Ohio electtic service; approval would be consistent with Ohio's policy to preserve the Conunission's ability to protect its customers; and there is no evidence taat Rider RRS will dttectly effect either wholesale supply or demand in the PJM system, citing 16 U.S.C 824o(i)(2) and (3) and R.C. 4928.02 (OEG Ex. 1 at 6).
In conttast, OCC/NOAC, NOPEC, Environmental Groups, CMSD, RESA, Power4Schools, P3/EPSA, Dynegy, Exelon, OMAEG, Sierra Club, and the IMM assert in their briefs taat tae settlement package violates important regulatory principles and practices, as set forta in further detail below.
NOPEC, CMSD, Power4Schools, P3/EPSA, Dynegy, Exelon, and Sierra Club argue tiiat the Stipulated ESP IV violates R.C 4928.143 by including Rider RRS in the ESP in violation of R.C. 4928.143(B) and the Supreme Court of Ohio's opinion in In re Application of Columbus Southern Power Co., 128 Ohio St.3d 512, 2011-Ohio-1788, 945 N.E.2d 655, ^ 31- 35, holding that only the rune items enumerated in R.C. 4928.143(B)(2) may be included in an ESP (Co. Ex. 155 at 9). NOPEC, CMSD, Power4Schools, P3/EPSA, Exelon, and Sierra Club explain that Rider RRS does not fall under any of the alternatives listed in R.C. 4928.143(B)(2)(d), as the Commission has rejected the Companies' bypassability rationale; Rider RRS does not relate to default service; and R.C 4928.143(B)(2)(d) lists "limitations on
APP. 334 14-1297-EL-SSO -102-
customer shopping," not financial limitations on the consequences of customer shopping. AEP Ohio ESP III Order. Next, NOPEC, CMSD, P3/EPSA, Exelon, and Sierra Club argue that Rider RRS does not provide stability or certainty. In support, NOPEC cites testimony of OCC/NOPEC witaess Wilson that Rider RRS will likely move in the same dttection of market prices, exacerbating price volatility rather than promoting price stability (OCC/NOPEC Ex. 4 at 13, 50). Finally, NOPEC adds fliat Rider RRS is unlawful because it harms large-scale governmental aggregations by imposing a nonbypassable generation charge in violation of R.C 4928.20(K) (Co. Ex. 13 at 12; Tr. Vol. XXII at 4591; Co. Ex. 1 at 21; Co. Ex. 7 at 31; Tr. Vol. Xlfl at 2871-72).
Next, OCC/NOAC, CMSD, Power4Schools, P3/EPSA, and OMAEG assert that the Economic Stability Program is conttary to the pro-competition policies set forth in Ohio law, including R.C, 4928.02 (OCC Ex. 25 at 11-14, 22-23). OCC/NOAC specify that authorization of tae proposed program would not; ensure the availability of reasonably priced retail electtic service; ensure the diversity of electticity supplies and suppliers; ensure tae avoidance of anticompetitive subsidies; and ensure facilitation of the state's effectiveness in the global economy (Co. Ex. 33; OCC/NOPEC Ex. 9 at 7; OCC Ex. 29; OCC/NOPEC Ex. 1 at 10-12, 23, 29; Tr. Vol. XXX at 6206; IGS Ex. 11). CMSD argues that, further, it is conttary to Commission precedent regarding the benefits of market-based pricing, and state policy embodied in the Ofiio Uniform Depository Act, which, in pertinent part, prohibits risky investments in conttacts where the retarn on investment is not tied to the conttact, but is measured based on the performance of some other asset or index. OMAEG adds that the Stipulated ESP IV violates regulatory principles by: (1) thwarting competition and deterring new entty; (2) harming interstate conunerce and out- of-state mvestment; (3) establishing an opaque system of income ttansfers and cross- subsidies among consumers; (4) distorting economic mcentives of pricing mechanisms; (5) denying consumer protections; and (6) undermining and violating previous Commission orders, namely, AEP Ohio ESP III Order (OMAEG Ex. 26A at 8; Dynegy Ex. 1 at 6-7; OCC/NOPEC Ex. 1 at 18). In the same vein, IMM asserts that Rider RRS would constitate a subsidy inconsistent with the competitive regulatory paradigm established in the wholesale power market in which Ohio participates, by providing incentives for non competitive offers, citing the testimony of IMM witaess Bowring in support (IMM Ex. 2 at 2,4-5,7).
P3/EPSA, Dynegy, and Exelon argue that Rider RRS would violate R.C. 4928.03, as it would require shopping customers to pay for affiliated generation and, thus, merge competitive services with regulated services (Tr. Vol. II at 344; Co, Ex. 156; Co, Ex. 13 at 4- 5). P3/EPSA and Exelon further contend that Rider RRS would violate R.C. 4905.22 because it would constitate an unreasonable charge.
Environmental Groups argue that Corrunission approval of a "backroom affiliate deal" is inconsistent with applicable regulatory principles or practices. In support.
APP. 335 14-1297-EL-SSO -103-
Environmental Groups contend that Rider RRS conttavenes legal protections against abuse of affiliate power set forth in R.C 4928.17(A)(3) and 4928.02, and Ohio Adm.Code 4901:l-37-04(A)(3). RESA and Exelon echo this argument regarding R.C. 4928.17 and OMAEG echoes this argument regarding R.C. 4928.02.
OCC/NOAC, NOPEC, CMSD, OMAEG, Power4Schools, P3/EPSA, and Sierra Club assert that the Federal Power Act preempts the Commission ttom implementing the Economic Stability Program. OCC/NOAC, NOPEC, OMAEG, P3/EPSA, and Sierra Club specify that FERC has exclusive jurisdiction over wholesale energy ttansactions as a matter of federal law, and the Commission lacks jurisdiction to approve Rider RRS, as it would set wholesale prices, causing the Commission's jurisdiction to be both field preempted and conflict preempted (Co. Ex. 33 at 2). NOPEC adds that the Corrunission's approval of such a program would violate the Supremacy Clause and the dormant Commerce Clause of the United States Constitation. Sierra Club specifies that Commission approval of Rider RRS would inttude on FERC's and PJM's regulation of wholesale markets by nullifying price signals by creating a subsidy; creatmg an incentive for FirstEnergy to present a "zero offer" to maximize the revenue offset to customers; and directly harming the effectiveness of PJM's recent capacity market reforms that are intended to increase reliability (RESA Ex. 6 at 2; IMM Ex. 2 at 5). In the same vem, NOPEC argues that Rider RRS undermines the PJM capacity market by permitting the Companies to develop offer sttategies that will harm their captive customers and by providmg FES a disincentive to retire plants and an incentive to over-invest in the PPA units (OCC/NOPEC Ex. 1 at 9-13). RESA joins the argument that Rider RRS will cause harm to competitive markets and Ohio's regulatory framework (RESA Ex. 6 at 2).
OCC/NOAC further assert that the Commission should not rule on whether to approve the proposed Economic Stability Program until FERC rules on its legality, noting that EPSA, among other parties, filed a complaint with FERC requesting review of FttstEnergy's affiliate agreement with its generating affiliate.^' NOPEC joins this argument in its reply brief. CMSD adds that, if the Corrunission does not address this issue, customers will be exposed to sigruficant fmancial risk, as it is well-settled that neither the Commission nor courts can order a refund of previously approved rates that are subsequently invalidated pursuant to Keco Industries v. Cincinnati & Suburban Bell Tel. Co., 166 Ohio St. 254, 257 (1957). OMAEG points out that, further, the Stipulated ESP IV specifically prohibits the refund to customers of dollars collected, even if a court finds Rider RRS to be unlawful (Co. Ex. 154 at 9). CMSD adds that Commission approval of the Economic Stability Program would stand as an obstacle to the accomplishment and execution of the full purposes and objectives of the federal policy embodied in PJM's market-based wholesale pricing model and that there is a significant risk that PJM will
^' Elec. Power Supply Assn., et al. v. FirstEnergy Solutions Corp., et al, Federal Energy Regulatory Comm. No. EL-16-34-000 (EPSA Complaint Case).
APP. 336 14-1297-EL-SSO -104- apply mitigation measures if the proposed program is approved (OCC/NOPEC Ex. 1 at 12-17).
Finally, OCC/NOAC and Power4Schools contend that the proposed Economic Stability Program violates R.C. 4928.38, which provides that it is unlawful for the Conunission to collect additional ttansition costs or equivalent revenues from customers.
In its reply brief, FirstEnergy responds that Rider RRS is authorized by R.C. 4928.143(B)(2)(d), emphasizing that the Comrrussion has already determined that retail stability riders supported by purchase power agreements are authorized by this statate in the AEP Ohio ESP III Order and the Duke ESP III Order. Further, in response to arguments that the statate addresses only physical limitations on customer shopping, FirstEnergy argues that the statate addresses only limitations on customer shopping, without specification taat such a limitation must be physical. Thus, FirstEnergy contends that a financial limitation satisfies the statate. Additionally, in response to parties' arguments that Rider RRS will not stabilize rates or provide certainty, FirstEnergy asserts that the Commission already considered and rejected these arguments in the AEP Ohio ESP III Order and Duke ESP 111 Order. In its reply brief. Sierra Club asserts that FirstEnergy should not rely on the fact that the Commission made these determinations in the AEP Ohio ESP III Order and Duke ESP III Order, as these issues were brought up on rehearing in those cases, the Conunission granted rehearing, and the Commission has not yet issued entties on rehearing. Thus, Sierra Club asserts these issues remain pendmg. Additionally, m its reply brief,, RESA asserts that FttstEnergy's argument that Rider RRS is a limitation on customer shopping is inconsistent with its prior assertions throughout this proceeding that Rider RRS will not have an adverse impact on the CRES market or limit a customer's ability to shop (Co. Ex. 1 at 9; Tr. Vol. 1 at 39,108; Tr. Vol. II at 342; Co. Ex. 154 at 18).
FirstEnergy further argues in its reply brief that the Economic Stability Program is not an anticompetitive subsidy prohibited by statate, argumg that revenues from Rider RRS wUl not be used to subsidize any generation service, but will provide customers with long-term rate stability. FirstEnergy adds that Rider RRS does not conflict with R.C 4928.03 or S.B. 3, as argued by some parties. FirstEnergy initially asserts that R.C. 4928.03 has no relevance here because Rider RRS is not a competitive retail electtic generation service. Next, FirstEnergy contends that Rider RRS does not conflict with S.B. 3, as Ohio's current quasi-market regulatory scheme permits and encourages hedges to protect customers against market volatility. FirstEnergy goes on to claim that Rider RRS also does not violate the "just and reasonable" language in R.C 4905.22 as claimed by some parties, asserting that R.C. 4905.22 does not apply to a retail stability charge authorized under R.C. 4928.143(B)(2)(d).
Next, FirstEnergy asserts that Rider RRS does not violate R.C. 4928.38 as alleged by some parties, as tae Comparues are not attempting to recover pre-2001 generation costs
APP. 337 14-1297-EL-SSO 405- through the rider, but are attempting to provide retail price stability to customers. FttstEnergy also points out that the Conunission considered and rejected that argument in the AEP Ohio ESP III Case and Duke ESP III Case. FirstEnergy next addresses NOPEC's argument regarding R.C. 4928.20(K) and harm to large-scale government aggregation customers. FirstEnergy asserts that the statate only requires the Corrunission to promulgate rules and consider the effect on large-scale governmental aggregation, and does not requtte the Commission to ensure no nonbypassable generation charge will be applied to such customers.
Regardmg R.C. 4928.17, FirstEnergy responds that this corporate separation statate merely requires FirstEnergy to have a corporate separation agreement, which it does, and states nothing that prohibits a retail stability rider. Regardmg the Uniform Depository Act, FirstEnergy responds that this argument may be ignored, as nothing in the Act refers to the retail electtic service paid for by schools or other political subdivisions under an ESP.
Next, FirstEnergy and OEG, in their reply briefs, respond to parties' arguments that the Commission's consideration and approval of Rider RRS would be in violation of Federal law. FirstEnergy initially emphasizes that tae Conunission is considermg only Rider RRS and not the PPA, and that the approval of Rider RRS mvolves no wholesale rates, terms, or conditions, but only retail rate tteatment of wholesale costs incurred under the PPA. FirstEnergy and OEG contend that federal law and precedent explicitly leave certain matters to the states, mcluding retail rate stability, resource adequacy, and regulation over generation resources used to serve retail customers, which states may regulate without violating the Federal Power Act. FirstEnergy adds that Rider RRS would also not violate the dormant Commerce Clause, as it invalidates only state actions that constitate regulatory measures designed to benefit in-state economic interests by burdenmg out-of-state competitors, and there is no evidence that Rider RRS was designed for such a purpose. In the same vein, FirstEnergy contends that taere is no reason for the Commission to delay its consideration of Rider RRS pending a FERC decision in the EPSA Complaint Case. FirstEnergy reasons that the ESP IV has been pending before the Commission since 2014 and the Commission holds all necessary information to render a decision. Further, FirstEnergy reasons that the EPSA Complaint Case is on a narrow issue that holds no bearmg on the Stipulated ESP IV.
c. Other Provisions
Regarding Rider DCR, OCC/NOAC and Power4Schools oppose its proposed continuation and the continuation of the base disttibution rate freeze, arguing that this proposal avoids the scrutiny of a base disttibution rate case in violation of prudent regulatory policy (Co. Ex. 154 at 13).
APP. 338 14-1297-EL-SSO -106-
OCC/NOAC, Power4Schools, NOPEC, and OMAEG assert that proposed Rider GDR violates important regulatory practices. OCC/NOAC and Power4Schools argue that proposed Rider GDR is vague, asymmettic, and unauthorized by Ohio law (OCC/NOPEC Ex. 7 at 34). NOPEC joins the argument that proposed Rider GDR is not authorized by law. OMAEG argues that proposed Rider GDR violates Corrunission precedent rejecting a rider request where the rider is prematare and there is a lack of specificity of futare potential costs to be included in the rider, citing AEP Ohio ESP III Order at 62.
OCC/NOAC address the ROE proposed by the Stipulations, arguing that it violates regulatory practices and/or principles because it is imsupported and does not reflect the applicable risk (OCC Ex. 22 at 10,18, 27-32; Co. Ex. 156 at 13). Further, OCC/NOAC add that the grid modernization and resource diversification provisions violate regulatory practices and principles because they lack details (Co. Ex. 154 at 9-10; ELPC Ex. 28 at 15). Finally, OCC/NOAC address the SFV provision in the Stipulated ESP IV, and argue that it violates regulatory policy because it goes beyond the originally filed application to determine an issue that is more properly decided in a full base disttibution case (ELPC Ex. 28 at 5,17-18).
RESA adds that the Stipulated ESP IV violates important regulatory prmciples and practices because: (1) the federal advocacy provision requires the Commission to take action, rather than exercising its own judgmenti (2) the Rider NMB pilot is unduly discriminatory and poorly designed in violation of R.C. 4928.02(A); and (3) the HLF/TOU pilot is unduly discriminatory and unjust in violation of R.C. 4928.02(A) (Co. Ex. 154 at 9; Co. Ex. 3 at 3; RESA Ex. 5 at 7-8, 10, 12; Co. Ex. 4 at 1-2; Tr. Vol. II at 289-291; Tr. Vol. XXXVII at 7788). P3/EPSA join RESA's argument regarding the federal advocacy provision.
Power4Schools addresses the Stipulated ESP IV's proposal that the Companies be permitted to count Legacy MTEP costs toward the Legacy RTEP costs the Companies agreed not to collect from customers as part of the ESP II Case, arguing that this proposal violates that commitment agreed to in the ESP II Case (OCC Ex. 19 at 4-5).
Regarding the Stipulated ESP IV's commitments to provide specified energy efficiency funding, ELPC contends that there is no evidence that the funding v^ll result in cost-effective energy savings, making the Stipulated ESP IV inconsistent with Ohio Adm.Code 4901:1-39-03 and 4901:1-39-04. Next, Envirorunental Groups argue fliat the provisions in the Stipulated ESP IV allowing customers who have opted out of paying under the Companies' EE/PDR programs to continue to receive payments for peak demand reduction violates R.C. 4928.6613. Finally, Environmental Groups assert that granting the Companies' lost-disttibution revenues for their customer action program is inconsistent with Conunission precedent under In re Application of FirstEnergy, Case No.
APP. 339 14-1297-EL-SSO -107-
09-1820-EL-ATA, et al.. Finding and Order (June 30, 2010) at 10, and In re Application of FirstEnergy, Case No. 09-1947-EL-POR, et al.. Opinion and Order (Mar. 23, 2011) at 18.
FirstEnergy, lEU-Ohio, and Nucor, in taeir reply briefs, respond to the Environmental Groups' argument that the Stipulated ESP IV violates R.C. 4928.6613, responding that Rider ELR customers may opt out of the Companies' EE/PDR portfolio plans and continue to receive Rider ELR crechts because taose credits do not arise from the Companies' EE/PDR portfolio plans, but rather from the Stipulated ESP IV itself. Additionally, FirstEnergy contends that the provisions regarding a ttansition to SFV rate design are permitted on the basis that they advance Ohio policy; further, FirstEnergy notes that the provisions do not require FirstEnergy to ttansition to SFV, but rather to file an application for such a rate design, which must be vetted through the Commission's usual process (Co. Ex. 155 at 4; Tr. Vol. XXXVI at 7577-7584).
Next, FirstEnergy responds to parties' arguments regarding the lawfulness of Riders DCR and GDR. FirstEnergy asserts taat R.C. 4928.143(B)(2)(h) expressly permits single issue ratemaking as part oi an ESP. Additionally, FttstEnergy points out that the Conunission previously approved Rider DCR as part of an ESP. ESP II Case; ESP III Case. FirstEnergy also addresses the Envirorunental Groups' argument that the Companies should not be permitted to receive lost-disttibution revenue tied to the Customer Action Program under Commission precedent. FirstEnergy argues that this provision is an integral part of the Stipulated ESP IV that is supported by all signatory parties, and that tae Customer Action Program is an energy efficiency program authorized by R.C. 4928.662 and is contained in the Comparues' Commission-approved EE/PDR Portfolio Plan. In re FirstEnergy, Case No. 12-2190-EL-POR, Finding and Order (Nov. 20, 2014) at 8-9. Next, FirstEnergy addresses parties' objections to the federal advocacy provision, arguing ttiat this provision does not violate state policy and the Commission is well within its powers to accept the recommendation if it believes it is reasonable. Finally, FirstEnergy asserts that the proposed HLF/TOU pilot program is not unduly discriminatory and unjust as alleged by some parties, arguing that eligibility requttements in order to create a homogenous pool are necessary for such a pilot program (Tr. Vol. II at 290-291, 463-467; Co. Ex. 146 at 17).
d. Commission Decision
Initially, the Commission will determme whether the proposed Economic Stability Program, mcluding Rider RRS, may be considered a permissible provision of an ESP, in accordance with R.C. 4928.143(B)(1) or (B)(2). The Commission has the authority to approve, as a component of an ESP, orJy items that are expressly listed in the statate. In re Columbus S. Poioer Co., 128 Ohio St.3d 512, 2011-Ohio-1788, 947 N.E.2d 655. FirstEnergy
APP. 340 14-1297-EL-SSO -108- claims R.C 4928.143(B)(2)(d) as its statatory basis for Rider RRS but also offers R.C. 4928.143(B)(2)(i) as statatory authority for Rider RRS.
Under R.C. 4928.143(B)(2)(d), the Commission can approve, as a component of an ESP, terms, conditions, or charges relating to limitations on customer shopping for retail electtic generation service, bypassability, standby, back-up, or supplemental power service, default service, carrying costs, amortization periods, and accounting or deferrals, including futare recovery of such deferrals, as would have the effect of stabilizing or providmg certainty regarding retail electtic service. Thus, considermg the plain language of the statate, we find that there are three criteria with which Rider RRS must comply. Specifically, an ESP component approved under R.C. 4928.143(B)(2)(d) must fttst be a term, condition, or charge; next, relate to one of the enumerated types of terms, conditions, and charges; and, finally, have the effect of stabilizmg or providing certainty regarding retail electtic service. See AEP Ohio ESP III Order at 20. See also in re AEP Ohio, Case No. 11-348-EL-SSO (AEP Ohio ESP II), Entry on Rehearing (Jan. 30, 2013) at 15-16; In re Dayton Pozoer and Light Co., Case No. 12-426-EL-SSO, et al. {DP&L ESP Case), Opmion and Order (Sept. 4, 2013) at 21-22.
The Conunission finds that the first requirement of R.C. 4928.143(B)(2)(d) is met, as Rider RRS would consist of a charge incurred by customers under ESP IV. Rider RRS, as proposed by the Comparues, would appear as a charge on customer bills, and there is no dispute among the parties on this pomt. Although we have determined that Rider RRS will provide a net credit over the eight years of ESP IV, even the Companies estimate that Rider RRS would result in a net charge to customers in the first two years of ESP IV. Thus, the record indicates that the Rider RRS would, at times, consist of a charge to customers.
With respect to the second criterion of R.C. 4928.143(B)(2)(d), the Rider RRS must relate to at least one of the following: limitations on customer shopping for retail electtic generation service, bypassability, standby, back-up, or supplemental power service, default service, carrying costs, amortization periods, and accounting or deferrals. FirstEnergy contends taat Rider RRS relates to limitations on customer shopping, to bypassability, and to default service.
The Commission finds that R.C. 4928.143(B)(2)(d) authorizes electtic utilities to mclude, in an ESP, terms related to "bypassability" of charges to the extent that such charges have the effect of stabilizing or providing certainty regarding retail electtic service. DP&l ESP Case, Opinion and Order (Sept. 4, 2013) at 21; AEP Ohio ESP III Order at 22. As discussed above, both shopping and SSO customers may benefit from Rider RRS because it would have a stabilizing effect on the price of retail electtic service, irrespective of whether the customer is served by a CRES provider or the SSO. Therefore, we agree with FirstEnergy that Rider RRS, if approved, should be non-bypassable, as authorized by tae second criterion of R.C. 4928.143(B)(2)(d). However, we have ruled that, since nearly
APP. 341 14-1297-EL-SSO -109-
any charge may be bypassable or non-bypassable, "bypassability" alone is insufficient to fully meet the second criterion of R.C. 4928.143(B)(2)(d). AEP Ohio ESP III Order at 22.
Nonetheless, the Commission finds that, consistent with our rulmgs in tae AEP Ohio ESP III Order and the Duke ESP III Order, Rider RRS is a financial limitation on customer shopping for retail electtic generation service. Although the Rider RRS would impose no physical consttamts on shopping, the rider does constitate a financial limitation on shopping that would help to stabilize rates. Under Rider RRS, shopping customers will stal purchase all of their physical generation supply from the market through a CRES provider. Altaough Rider RRS would have no impact on customers' physical generation supply, the consequence of Rider RRS is that the bills of all customers would reflect a price for retail electtic generation service that is based in part on the retail market and in part on the cost of service of Sammis, Davis-Besse, and the OVEC plants. The Commission estimates that Rider RRS will provide a generation credit to customers of $256 million over the term of ESP IV. Effectively, then. Rider RRS would function as a financial resttaint on complete reliance on the retail market ior the pricing of retail electtic generation service. Customers in the Companies' service territories have the ability to choose a competitive supplier pursuant to R.C. 4928.03 and wUl continue to benefit ttom a robust choice in competitive suppliers. In this respect, they are not captive customers. In light of our determination that Rider RRS is a financial limitation on customer shoppmg pursuant to R.C. 4928.143(B)(2)(d), it is urmecessary to reach the argument related to "default service." Accordmgly, we fmd that the second criterion of R.C. 4928.143(B)(2)(d) is satisfied.
Turning next to the third criterion, whether tae Rider RRS would have the effect of stabilizing or providing certainty regarding retail electtic service. We find that the Rider RRS, as a fmancial hedgmg mechamsm, is proposed to have the effect of stabilizing or providing certainty regarding retail electtic service. Rider RRS will act as a form of rate irrsurance. If market prices for energy, capacity and ancillary services rise. Rider RRS will operate to mitigate the increase m market prices. Rider RRS, taerefore, is intended to mitigate, by design, the effects of market volatility, providing customers wita more stable pricing and a measure of protection against substantial increases in market prices. Therefore, since the record reflects that Rider RRS would, in theory, have the effect of stabilizing or providing certainty regarding retail electtic service, we find that the third criterion of R.C 4928.143(B)(2)(d) has been met.
With respect to FirstEnergy's claim that the Economic Stability Program, oi which Rider RRS is part, is an economic development program under R.C. 4928.143(B)(2)(i), tae record is clear that tae plants have a significant economic impact upon the regions in which the plants are located (Co. Ex. 35 at 3; Co. Ex. 36 at 4, 9). FirstEnergy witaess Murley testified that Sammis and Davis-Besse have a total economic impact of over $1.1 billion annually (Co. Ex. 36 at 11). The Commission further notes taat there is nothing in
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R.C 4928.143(B)(2)(i) which limits economic development programs authorized under the statate ttom assisting affiliates of the electtic disttibution utility.
Having determined that the Economic Stability Program and Rider RRS are authorized under R.C. 4928.143(B)(2), the Commission will tarn to the specific claims by opposing parties that specific provisions of the Stipulations violate important regulatory principles and practices.
The Commission is not convinced by the claims of several parties that Rider RRS is anticompetitive. Rider RRS will be non-bypassable and thus will have the same impact on customers' bills on shopping customers as SSO customers (Co. Ex. 13 at 6). Rider RRS creates no advantage to shoppmg and no disincentive to shopping. Likewise, Rider RRS has the same impact on shopping customers irrespective of which CRES provider serves the shopping customer and irrespective of whether the customer is part of an aggregation or served by an individual marketer. The Companies will continue to source all of the SSO load through competitive auctions. Accordingly, we find that Rider RRS is consistent with the state policy to "[e]nsure the availability of unbundled and comparable retail electtic service taat provides consumers with the supplier, price, terms, conditions, and quality options they elect to meet their respective needs." R.C. 4928.02(B).
We are mindful, however, of concerns that tae Companies will enter into bilateral conttacts with an affiliate in order to give the affiliate a competitive advantage. As an initial matter, the Companies' witaesses have consistenfly testified that the Companies intend to liquidate the energy and capacity m PJM's markets and have no intention of entering into bilateral conttacts. Nonetheless, as discussed above, the Commission has imposed safeguards in the annual prudency review process to safeguard against anti competitive behavior by the Companies. Any bilateral conttacts between the Companies and an affiliate will be sttingently reviewed, and no presumption of management prudence will be assumed in a bilateral sale to an affiliate. These protections are more than sufficient to protect against anticompetitive subsidies pursuant to R.C. 4928.02(H).
With respect to issues raised regarding Rider GDR, we disagree taat Rider GDR violates important regulatory principles and practices. No cost will be included in Rider GDR xmless such costs are determined by the Conunission to be just and reasonable in a separate proceeding. As noted above, I^der GDR should be limited to Federal and state government mandates enacted after the filing date of the application in this proceeding, and no generation or ttansrrussion related expenses will be eligible for recovery under Rider GDR. Any interested party will have a full and fair opportanity to participate in such separate proceeding. In addition, OMAEG's reliance upon the AEP Ohio ESP III Order is misplaced. In the AEP Ohio ESP III Order, the Commission noted that AEP Ohio had existmg means to seek recovery of costs, such as a disttibution rate case, over the
APP. 343 14-1297-EL-SSO -Ill- three-year term of the ESP; in this case, the Companies have committed to an eight-year base disttibution rate freeze. AEP Ohio ESP III Order at 62.
With respect to Rider DCR, the Commission is not persuaded by claims by OCC/NOAC and others that costs under Rider DCR fail to receive proper scrutiny. As we have stated previously, Rider DCR is subjected to annual audits which require the Companies to demonsttate what they spent and why the recovery sought is unreasonable. ESP III Case, Opinion and Order at 34. The Conunission has been conducting such audits annually since the inception of Rider DCR. Thus, OCC/NOAC and any otaer party have had, and will continue to have, a full and fair opportanity to raise any issues regarding disttibution investments to be recovered under Rider DCR during the audit process.
The Commission also disagrees with the claim by OCC/NOAC that the provisions of the Stipulation related to SFV rate design are improper because such provisions were not included in tae original application. The provisions related to SFV rate design are specifically authorized by R.C. 4928.143(B)(2)(h), which provides that an ESP may include "a revenue decouplmg mechanism." It does not depart from Commission precedent or practice in proceedmgs under R.C. 4928.143 for intervenors or Staff to reconunend additional provisions for an ESP after the filing of the original application, as Staff, RESA and other intervenors have done throughout this proceedmg, and it does not depart from Commission precedent or practice for parties to reach agreement on such additional provisions. See FirstEnergy ESP II Case, Opimon and Order (Aug. 25, 2010) at 32-33.
OCC/NOAC also contend that the provisions for grid moderruzation and resource diversification violate regulatory prmciples because they lack details. However, the Stipulations merely require the Companies to file, and support, applicatiorrs in separate proceedings for grid modernization and resource diversification. All appropriate details will be addressed m the applications or during the Commission proceedings. Any interested party will have an opportanity to intervene in the separate proceedings and raise any relevant issues, and we will rule on the applications based solely on the evidence m the record of tae separate proceedmg. Accordingly, we find that the provisions of the Stipulations regarding grid modernization and resource diversification are consistent with Ohio policy calling for the development and implementation of flexible regulatory tteatment. R.C. 4928.02(G).
The Envirorunental Groups raise concerns that the energy efficiency programs provided for by the StipulatioriS wiU not be cost-effective in violation of Ohio Adm.Code 4901:1-39-03 and -04. However, nothing in the Stipulations waive the cost-effectiveness requirements of Ohio Adm.Code 4901:1-39-03 and -04, and, as discussed above, the Corrunission expects that the portfolio implemented by the Companies under the Stipulations will contmue to be cost-effective.
APP. 344 14-1297-EL-SSO -112-
RESA claims that two of the pilot programs, the Rider NMB pilot and the HLF/TOU pilot, are unduly discriminatory. We disagree. The natare of any pilot program is to keep the number of participants manageable in order to make some deternunation of the efficacy of the program being tested. Moreover, with respect to the Rider NMB pilot program, the Third Supplemental Stipulation expanded the number of potential participants in the pilot program (Co. Ex. 154 at 17). RESA cites to no evidence in the record that any customers who wish to participate m, and would benefit ttom, the Rider NMB pilot program cannot do so because of the limits on the size of the pilot program. Further, we are not persuaded that the HLF/TOU eligibility requirements are so sttingent to be discriminatory. Instead, we believe that the requirement that potential customers' corporate headquarters be located in this state provides an incentive to large retailers to retain or relocate their corporate headquarters to Ohio, which would have sigruficant economic impacts.
The Commission disagrees with OCC/NOAC taat Rider RRS violates R.C 4928.38, which prohibits the collection of additional ttansition costs. We note that R.C. 4928.39 establishes the criteria for a cost to be considered ttansition costs. Among the criteria is the requttement that costs be "unrecoverable in a competitive market." R.C. 4928.39(C). The record in this proceeding demonsttates that Rider RRS should provide a net credit, not charge, to customers in the amount of $256 million over its eight-year term. We find that the evidence demonsttates that the costs which are included in the Rider RRS calculation are not "unrecoverable in a competitive market" and that, accordmgly, such costs do not meet the definition of ttansition costs.
Fmally, with respect to claims that Rider RRS is preempted by the Federal Power Act, the Commission has determined that Rider RRS is authorized under state law; however, we are an administtative agency with powers specifically granted by the General Assembly and we have no authority to declare a statate unconstitational. Reading v. Puh. Util Comm., 109 Ohio St.3d 193,195, 846 N.E.2d 840 (citing Panhandle E. Pipeline Co. v. Pub. Util Comm., 56 Ohio St.2d 334, 346, 383 N.E.2d 1163 (1978)). Accordmgly we decline to address constitational questions raised by the parties m these proceedings, as under tae specific facts and circumstances presented here, such issues are best reserved for judicial determination. AEP Ohio ESP III Order at 26.
4. ESP versus MRO Test
Additionally, as mdicated earlier, the Commission must also consider the applicable statatory test for approval of an ESP. R.C. 4928.143(C)(1) provides that the Corrunission should approve, or modify and approve, an application for an ESP if it finds that the ESP, including its pricing and all other terms and conditions, including any deferrals and any futare recovery of deferrals, is more favorable in the aggregate as compared to the expected results that would otherwise apply under an MRO, pursuant to
APP. 345 14-1297-EL-SSO -113-
R.C. 4928.142. As noted above, we find that ESP IV, as modified by the Stipulations and by the Commission, will protect consumers against rate volatility and price fluctaations by promoting rate stability for all ratepayers in this state, modernize the grid through the deployment of advanced technology and procurement of renewable energy resources, and promote competition by enabling competitive providers to offer innovative products to serve customers' needs. An MRO contain none of these benefits. Therefore, as discussed below, the Conunission finds that ESP IV, including its pricmg and all other terms and conditions, including any deferrals and any futare recovery of deferrals, is more favorable in the aggregate as compared to the expected results taat would otherwise apply under an MRO.
a. Surrunary oi the Parties' Arguments
i. Appropriate Application of the MRO v. ESP Test
The Companies assert that the Commission should consider both quantitative and qualitative factors in its analysis, citing to Commission and Ohio Supreme Court precedent which allows Commission review of "pricing and all other terms and conditions." AEP Ohio ESP III Order at 94; ESP III Case Order at 56; In re Columbus 5. Power Co., 128 Ohio St. 3d 402, 2011-Ohio-958. Thus, as provided below, the Companies contend that the total benefits of Stipulated ESP IV in the aggregate, including both quantitative and qualitative benefits, demonsttate that it is more favorable in the aggregate when compared to the expected results of the MRO.
NOPEC initially argues that the General Assembly intended, and the Ohio Supreme Court later confirmed, that the Commission is linuted to only consider the quantitative factors listed in R.C. 4928.143(B) in its analysis of a proposed ESP, and thus, the language within R.C. 4928.143(C)(1) must be consttued consistent with that intent. R.C. 1.49; In re Columbus S. Power Co., et al, 128 Ohio St.3d 402, 2011-Ohio-958. Thus, NOPEC states tiaat while a variety of qualitative benefits have been forwarded by the Companies in support of Stipulated ESP IV for purposes of prong two of the three-prong test, these qualitative benefits may not be considered for purposes of the ESP v. MRO test. Accordingly, NOPEC and OCC/NOAC provide that the Commission's determination of whether the proposed Stipulated ESP IV is more favorable in the aggregate than the MRO rests on a determination of whether the identifiable costs of the ESP are greater than the cost of an MRO. Additionally, as only the items hsted in R.C. 4928.143(B) may be included for the Commission's consideration of an ESP, NOPEC also argues that the implementation of Rider GDR should be disallowed since no foreseeable costs to be recovered through this rider have been presented (OCC Ex. 18 at 23). NOPEC also disagrees with the Companies' decision to omit the costs associated with Rider DCR as part of the ESP v. MRO test, noting that OCC/NOPEC witaess Kahal demonsttated that the revenues associated with Rider DCR were a quantifiable cost of the ESP and that they should be considered since
APP. 346 14-1297-EL-SSO -114- the "expected results" of R.C. 4928.142 do not contemplate consideration of tae results of a disttibution rate case. Power4Schools also contends that orUy quantitative benefits should be considered, and thus, the Commission should fmd the ESP to be less favorable than an MRO. P3/EPSA and RESA assert that the Companies have failed to meet their burden to show that the ESP would be more beneficial than an MRO, stating Stipulated ESP IV does not contain an explicit evaluation of this test, and instead, relies on conclusory arguments that this is the case. (Co. Ex. 154 at 18; Co. Ex. 155 at 10-14.)
In its reply brief, FirstEnergy asserts that NOPEC's discussion of legislative history is inappropriate because R.C 4928.143(C)(1) is not ambiguous, and, further, emphasizes that the Commission has repeatedly held that qualitative factors must be considered. Additionally, FirstEnergy points out that the statate discusses not only "pricing" but also refers to "all other terms and conditions." Thus, FirstEnergy contends that NOPEC's focus solely on pricing conflicts with the plain meaning of the statate.
ii. Ouantitative Benefits and Analysis
FttstEnergy claims that the ESP is estimated to be more favorable than the expected results of the MRO by $612.1^^ on a nommal basis, or $260 million on a NPV basis (Co. Ex. 155 at 12; Co. Ex. 156 at 4-6). More specifically, and as discussed above, the Companies assert that this quantitative benefit is a combination of the Economic Stability Program as well as economic development and low-income funding. The Companies elected to omit the costs of Rider DCR m this analysis, posited on the fact that the Companies would utilize a CBP to procure generation under either Stipulated ESP IV or an MRO; thus, there would be no quantifiable difference relating to this pricing between either the two scenarios. Additionally, FirstEnergy reiterates its earlier arguments regarding the quantitative benefits associated with Stipulated ESP IV.
OCC/NOAC argue that the Compames' proposed Stipulated ESP IV is quantitatively more costly to customers than an MRO over its eight-year term, noting that the combined analyses of OCC/NOPEC witaesses Wilson and Kahal demor^sttated that the actaal cost of the ESP over that of an MRO would range from $3.26 to $3.35 billion (OCC/NOPEC Ex. 11 at 16, 26-27; OCC/NOPEC Ex. 7 at 8). Exelon, RESA, NOPEC, and OMAEG also provide that the only number taat should be considered for purposes of this test is the Companies' projected credit arising under Rider RRS, smce there is no indication that tae other payments to be paid under Stipulated ESP IV could not otherwise be made under an MRO (Tr. Vol. XIII at 596). While OCC/NOAC initially contends that Rider DCR will not result in a financial "wash," as proffered by FirstEnergy witaess
^^ The Companies derive this number by adding their projected net benefit attributed to Rider RRS, $561 million, and the additional $51.1 milhon in quantitative benefits in the form of shareholder funding for economic development, low-income customers, and a customer advisory agency.
APP. 347 14-1297-EL-SSO -115-
Fanelli, OCC/NOAC, NOPEC, and RESA argue the alleged qualitative benefits arising from Rider DCR will not actaally accrue to customers and, mstead, will cause customers to pay more than they otaerwise would be required to pay under a disttibution rate case (Co. Ex. 50 at 7; OCC Ex. 18 at 17; OCC/NOPEC Ex. 8 at 30; OCC/NOPEC Ex. 11 at 22-23). Additionally, Exelon states the evidence in the record shows the speculative natare of this projection, while also noting that the Companies failed to conduct, or even consider, a CBP in order to ensure customers pay the least amount for the purported benefits under Rider RRS (Tr. Vol. XXXVl at 7736; Exelon Ex. 4 at 3; Exelon Ex. 1 at 20.) Envhonmental Groups also state that the Commission lacks any reassurances, such as a competitive procurement or some objective benchmark price, which would allow it to adequately evaluate whether the PPA is just and reasonable or more favorable in the aggregate taan an MRO. Based on OCC/NOPEC witaess Kahal's analysis, and furtaer supported by Exelon's offer, NOPEC also contends that Rider RRS should be quantified as costing ratepayers $2.97 billion (OCC/NOPEC Ex. 11 at 18). OMAEG notes that whUe the Companies made changes to its claimed quantitative analysis to account for the shortened eight-year term of Rider RRS and updated ROE of 10.38 percent, they failed to update their energy, capacity, nataral gas, and CO2 price forecasts, which were more than 17 months old (Tr. Vol. XXXVI at 7513). OMAEG argues this outdated information cannot be considered reasonable by tae Conunission, especiaUy when otaer parties in this proceeding have provided more recently updated forecasts that allude to an entirely different outlook for consumers (Tr. Vol. XXXVIII at 8118-19; OCC/NOPEC Ex. 9 at 12-13). Additionally, OMAEG asserts that the Comparues failed to provide any costs associated with the riders and programs contained in the Third Supplemental Stipulation in thett bill impact analyses, even though these provisions may result in sigruficant additional costs to customers who are not eligible for such programs or do not receive the specific benefits (Co. Ex. 154 at 9-15).
In its reply brief, FirstEnergy responds to arguments questiorung the net benefit to customers by maintaining that, according to its projections. Rider RRS has a net benefit to customers of $561 million. FirstEnergy dismisses the testimony otaerv\'ise by other parties' witaesses, asserting that the Companies put forward the orily reliable forecasts and all other projections were based on either unsupported ad hoc and erroneous rationalizations or demonsttably unreliable methodology.
Next, FirstEnergy responds to parties' arguments regarding whether Rider DCR should be included in calculation of the quantitative impact. FirstEnergy mamtains that Rider DCR does not have a quantitative impact on the ESP v. MRO test, as Conunission precedent considers recovery of disttibution capital costs through Rider DCR to be equivalent to the recovery of similar costs through a disttibution rate case. ESP III Case Order at 56. Further, FttstEnergy responds to parties' arguments that low-income funding conunitments should not be counted as a quantitative benefit because similar commitments could be made by the Companies under an MRO. FirstEnergy urges the Corrunission to reject these arguments on the grounds that whether the Companies
APP. 348 14-1297-EL-SSO -116- theoretically could make such funding commitments under an MRO is irrelevant, as FirstEnergy witaess Mikkelsen explained these funding commitments are specifically being made as part of the proposed ESP and would not exist otherwise (Tr. Vol. XXXVI at 77^5-77^6). Additionally, FirstEnergy points out that there is no Commission precedent showing that any such commitments could be required as part of a disttibution rate case.
Next, FirstEnergy responds to parties' arguments that the costs associated with Riders GDR and ELR, as well as the HLF/TOU rate, EE programs, battery technology, renewable resources, and grid moderruzation should be included as part of the costs oi an MRO. FirstEnergy notes that the Commission has previously not mcluded in the ESP v. MRO calculation the costs of riders that are mere placeholders, such as Rider GDR. AEP Ohio ESP III Order at 94. Regarding Rider ELR and the HLF/TOU rate, FirstEnergy points out that FirstEnergy witaess Mikkelsen testified that these provisions have a net zero quantitative impact across the Comparues' customers (Tr. Vol. XXXVII at 7799-7800). Regarding EE programs, FirstEnergy maintains these also should not be counted, as the Compames are required to meet state benchmarks, meaning such costs would arise whether under an ESP or MRO. Finally, regarding battery technology, renewable resources, and grid moderruzation initiatives, the Companies' point to FirstEnergy witaess Mikkelsen's testimony that it is premature to assume there will be any costs associated with taese provisions to consider, as each one is contingent upon futare, independent Commission approval.
iii. Oualitative Benefits and Analysis
The Comparues further assert that Stipulated ESP IV includes a variety of qualitative benefits, which promote rate stability, economic development, retail competition, customer optionality, grid modernization, resource diversification, low- income customer assistance, continued investment in the delivery system, and system reliability. The Comparues have concluded that these benefits would not be available under an MRO. (Co. Ex. 155 at 13, Co. Ex. Co. Ex. 8 at 11; Co. Ex. 50 at 8-9.) As discussed earlier, the Companies state that several provisions previously approved in the ESP III Case will continue to be utilized in Stipulated ESP IV, includmg the continuation of the base disttibution rate tteeze, the procurement of non-shopping load through a CBP, the continuation of Riders DCR, ELR, and EDR(h), and the continued support of economic development and low-income programs through various funding initiatives. Additionally, FirstEnergy reiterates its earlier arguments regarding the qualitative benefits evaluated above in the ttaditional three-prong test.
Though many parties have argued that qualitative benefits should not even be considered for purposes of the ESP v. MRO test, they also argue that in the event the Corrunission could or would consider them, they would be significantiy outweighed by the quantifiable costs attributable to Stipulated ESP IV. P3/EPSA, Power4Schools, and
APP. 349 14-1297-EL-SSO -117-
RESA indicated taat there has been an overreliance on the qualitative benefits to shadow the fact that the quantitative benefits will likely not accrue to the Companies' customers (Tr. Vol. XXXVl 7736-37). NOPEC and Power4Schools also state that even if the Conunission was statatorily authorized to consider qualitative factors during its evaluation of the MRO v. ESP test, it would be unlawful to consider qualitative factors that fall outside of the provisions oi R.C. 4928.143(B) and unreasonable for such qualitative benefits, such as benefits furthering the state policies codified in R.C 4928.02 or the benefits of proposed Riders DCR and GDR, to supersede the quantitative analysis required by R.C 4928.143(C)(1). Furthermore, OMAEG, OCC, NOAC, and Power4Schools assert tae Companies have failed to show that the qualitative benefits of Stipulated ESP IV are more favorable than an MRO, initially noting that the projected costs of Rider RRS during the eight-year term outweigh any claimed benefits, such as rate stability or reliable electtic service (OCC/NOPEC Ex. 4 at 49-52; OCC/NOPEC Ex. 8 at 8). Specifically, OMAEG contends that the costs atttibuted to Rider RRS would greatly outweigh any incremental armual rate mcrease customers would experience otherwise, while adding that there would be no change in reliability if the Plants and OVEC entitiement units were to continue to operate as they do today but such a decision might have significant opportanity costs such as foregone new generation consttuction (OCC/NOPEC Ex. 9 at 12; Tr. Vol. XIII at 2797-99). In addition, OMAEG argues that the projected economic development benefits are flawed and the Companies' analysis fafls to accurately reflect the impact of Rider RRS on the costs to customers and the resulting economic development in this region, noting that the Companies should not be able to claim these projected benefits if they cannot definitively state taat the Plants and OVEC entitlement units are currently operating economically (Co. Ex. 141 at 6; OCC/NOPEC Ex. 11 at 20-21). OMAEG concludes by arguing that while the Companies assert the provisions contained in Stipulated ESP IV will provide additional qualitative benefits, these provisions will only benefit a handful of customers to the dettiment of the majority. In addition, many parties reiterated their concerns regarding the various purported benefits in the second prong analysis of the ttaditional three-prong test.
In its reply brief, FirstEnergy responds to parties' arguments that the Commission should not consider various qualitative benefits by pointing out that the Commission has previously found that an ESP provides qualitative benefits when it; (1) includes energy efficiency programs; (2) promotes economic development; (3) ensures system reliability; and, (4) facilitates rate stability. ESP II Case Order at 44; ESP III Case Order at 56. FirstEnergy urges the Commission not to depart from its precedent and argues that the opposing parties have offered no justification for any departare.
In conttast, Exelon disputes FirstEnergy's assertion of the proffered qualitative benefits, contending that any economic development benefits are largely unknown and that envirorunental benefits should also not be considered as there is no indication tae plants will close if Rider RRS is not approved. Further, Exelon asserts that any continued
APP. 350 14-1297-EL-SSO -118- benefits of the Companies' ESP III Case and new provisiorrs proposed in the Stipulated ESP IV will be outweighed by the cost of Rider RRS. In its reply brief, OCC/NOAC reiterate their prior arguments and emphasize again their belief that FttstEnergy's purported qualitative benefits, including Rider RRS, are illusory and do not benefit customers. OCC/NOAC also assert that FirstEnergy's discussion of the disttibution rate freeze as a qualitative benefit for customers is actaally harmful for customers as there will be no detailed rate-case type of Comrrussion review during the freeze.
b. Commission Conclusion
The Commission finds that the record in taese proceedings demonsttates that the proposed ESP IV is more favorable in the aggregate than the expected results of an MRO under R.C. 4928.142. Under the proposed ESP IV, the generation rates to be charged SSO customers will continue to be established through a CBP; therefore, generation rates in the ESP IV should be equivalent to the results which would be obtained under R.C. 4928.142. However, the evidence in the record demonsttates that there are quantitative and qualitative additional benefits contained in the Stipulations that make the proposed ESP IV more favorable in the aggregate taan the expected results under R.C. 4928.142. We note that these numerous additional benefits will be realized by customers in the Companies' service territories, thus, furthering our policy objectives as enumerated in R.C. 4928.02. These benefits include protection of consumers against rate volatility and price fluctaations by promoting rate stability for all ratepayers in this state, modernization of the grid through the deployment of advanced technology and procurement of renewable energy resources, and promotion of competition by enabling competitive providers to offer iruiovative products to serve customers' needs. Further, we note that, considering the term of ESP IV, the requttements of the Third Supplemental Stipulation and R.C 4928.143(E) wUl apply to ESP IV (Co. Ex. 154 at 18).
Initially, tae Commission finds that the proposed ESP IV is more favorable quantitatively than an MRO. As discussed above, the record m this case indicates that Rider RRS will generate $256 miUion in net revenue over the eight-year term oi ESP IV. As stated above, we are not persuaded by OCC/NOPEC witaess Wilson's claims that Rider RRS will cost customers billions of dollars; OCC and NOPEC rely upon the assumption that prices for nataral gas, electticity and oil will remain below 2013 prices (in real dollars) through 2030 and beyond. Further, we are unconvinced by Mr. Wilson's claim that Rider RRS will exacerbate price volatility by movmg in the same direction as the market. On the conttary, the evidence in the record demonsttates that Rider RRS will promote rate stability by providing a credit if and when energy prices increase, in furtherance of Ohio policy set forth in R.C 4928.02(A).
In addition, the Stipulations provide for additional quantitative benefits in the form of shareholder funding for economic development, low-mcome customers and a customer
APP. 351 14-1297-EL-SSO -119- advisory agency (Co. Ex. 155 at 11-12). This shareholder funding totals $51.1 miUion over the term oi ESP IV (Co. Ex. 155 at 12). We also note taat the low-income funding furthers state policy by protecting at-risk populatioris as provided by R.C 4928.02(L).
With respect to whether Rider DCR should be included in the quantitative analysis, the Commission previously has determmed taat Rider DCR allows the Companies to earn a retarn on and of plant in service associated with disttibution, subttansmission, and general and intangible plant which was not included in the rate base of the Comparues' last disttibution rate case. Pursuant to R.C 4909.15, the Commission is required to determme, in a disttibution rate case, the valuation, as of the date certain, of property used and useful in rendering public utility service. Thus, we concluded that, to the extent that the Companies have made capital investments since the last disttibution rate case, those investments wUl be recovered to an equal extent, through either Rider DCR or through disttibution rates, provided that the property is used and useful in the provision of disttibution service. Accordingly, over the long term, the Companies will recover the equivalent of the same costs, and, for purposes of the ESP v. MRO Test, the costs of Rider DCR and the costs of a potential disttibution rate case should be considered substantially equal and removed ttom the ESP v. MRO analysis. ESP III Case, Opinion and Order (Jul. 18, 2013) at 55-56; Entty on Rehearing (Jan 30, 2013) at 22-23.
Therefore, we find that, on a quantitative basis, the proposed ESP IV is more favorable than an MRO by $307.1 million, representing the sum of the predicted $256 in net revenue predicted for Rider RRS and $51.1 million m committed shareholder funding, over the eight years of ESP IV.
Further, we find that the proposed ESP IV is more favorable qualitatively taan an MRO. We find taat the additional qualitative benefits of an ESP, which would not be provided for in an MRO, mclude: (1) continuation of the disttibution rate increase freeze untU June 1, 2024 to provide rate certainty, predictability, and stability for customers (Co. Ex 154 at 13); (2) continuation of multiple rate options and programs to preserve and enhance rate options for various customers provided in previous ESPs (Co. Ex. 154 at 14- 15); (3) establishment of a goal to reduce CO2 emissions by FttstEnergy Corp with periodic reporting requirements (Co. Ex. 154 at 11; Co. Ex. 155 at 13); (4) reactivation and expansion of energy efficiency programs previously suspended by the Companies, with a goal of saving 800,000 MWh of energy armually (Co. Ex. 154 at 11-12); and (5) programs to promote the use of energy efficiency programs by smaU businesses pursuant to state policy set forth in R.C 4928.02(M) (Co. Ex. 155 at 5). In addition, the Stipulations require the Companies to file applications to; (1) modernize disttibution infrasttuctare through the fUing of a business plan for the deployment of smart grid technology and advanced metering infrasttuctare in accordance with Ohio policy set forth in R.C. 4828.02(D) (Co. Ex. 154 at 9-10); (2) promote resource diversity by investing in utility scale battery technology and, potentially, by prociiring additional renewable energy resources (Co. Ex.
APP. 352 14-1297-EL-SSO -120-
154 at 11-12; Co. Ex. 155 at 13); and (3) ttansition to a SFV rate design which balances the elimination of dismcentives for the Companies to promote energy efficiency and conservation programs with the promotion of the principle of cost causation (Co. Ex. 154 atl2-13;Co. Ex. 155 at 13).
Therefore, based upon the evidence in the record in this proceeding, the Commission finds that the ESP IV, including its pricing and all other terms and conditions, including any deferrals and any futare recovery of deferrals, is more favorable in the aggregate as compared to the expected results that would otherw^ise apply under an MRO pursuant to R.C. 4928,142. Accordingly, we find that the Stipulations, as modified, should be adopted. We also note that oux findmg in this section that the ESP IV is more favorable in the aggregate than the expected results that would otherwise apply under and MRO also addresses arguments by several parties that the Stipulations violate important regulatory prmciples by failing the ESP v. MRO test.
FINDINGS OF FACT AND CONCLUSIONS OF LAW:
(1) The Companies are public utilities as defined in R.C. 4905.02 and, as such, are subject to the jurisdiction of this Commission.
(2) On August 4, 2014, FirstEnergy filed an application for an SSO m accordance with R.C. 4928.141.
(3) Stipulations were filed on December 22, 2014, as modified by errata filed on January 21, 2015; on May 28, 2015; on June 4, 2015; and, on December 1, 2015.
(4) The signatory parties to the Stipulated ESP IV are the Compames, AEP Ohio, OEG, Akron, COSE, Citizens' Coalition, Nucor, MSC, AICUO, IBEW 245, Kroger, EnerNOC, Inc., OPAE, IGS, and the Commission's Staff.
(5) The evidentiary hearing in this proceeding was held from August 31, 2015, until October 29, 2015, and from January 14, 2016, until January 22, 2016.
(6) Pursuant to published notice, public hearings were held in Akron on January 12, 2015; in Toledo on January 15, 2015; and in Cleveland on January 20, 2015.
(7) The Companies' application was filed pursuant to R.C 4928.143, which authorizes the electtic utilities to file an ESP as their SSO.
APP. 353 14-1297-EL-SSO -121-
(8) The Commission finds that the Stipulated ESP IV, as modified, meets the three criteria for adoption of stipulations, is reasonable, and should be adopted.
(9) The proposed Stipulated ESP IV, including its pricing and all other terms and conditiorts, including deferrals and futare recovery of deferrals is more favorable in the aggregate as compared to the expected results that would otherwise apply under R.C 4928.142.
ORDER:
It is, therefore:
ORDERED, That Noble Solutions' motion to mtervene out-of-time is denied as set forth herem. It is, further,
ORDERED, That Oregon's motion for leave to file an amicus brief is granted as set forth herein. It is, further,
ORDERED, That tae applications for interlocutory appeal are denied as set forth herein. It is, further,
ORDERED, That the rulmgs of the attorney examiners are affirmed as set forth herein. It is, further,
ORDERED, That the motions to sttike portions of the initial and reply briefs are granted, m part, and denied, in part, as set forth herein. It is, further,
ORDERED, That the pending motior^s for protective order are granted as set forta herein. It is, furtaer,
ORDERED, That the previously granted motions for protective order are extended as set forth herein. It is, further,
ORDERED, That the Stipulated ESP IV, as modified by the Commission, be adopted and approved. It is, further,
ORDERED, That the Companies file proposed tariffs consistent with the Stipulated ESP IV as modified. It is, further.
APP. 354 14-1297-EL-SSO -122-
ORDERED, That the Comparues take all steps necessary to implement the Stipulated ESP IV. It is, further.
ORDERED, That a copy of this Opinion and Order be served upon aU parties of record.
THE PUBLIC UTILITIES COMMISSION OF OHIO
Andre T. Porter, Chairman
M. Beth Trombold (6ffv>«>irM'i^) ^ :^ /r^ Asim Z. Haque Thqmas Wf Johnson
G AP/MWC/MJ A/vrm
Entered m the Journal MAR 3 1 2016
Barcy F. McNeal Secretary
APP. 355 BEFORE
THE PUBLIC UTILITIES COMMISSION OF OHIO
In the Matter of the Application of Ohio Edison Company, The Cleveland Electtic Illuminating Company, and The Toledo Edison Company for Authority to Provide Case No. 14-1297-EL-SSO for a Standard Service Offer Pursuant to R.C 4928.143 in the Form of an Electric Security Plan.
CONCURRING OPINION OF COMMISSIONER ASIM Z. HAOUE
As these cases have been pending before the Commission for a considerable period of time, and due to the concern expressed by the consumers of this great State (along with interest shown by spectators nationally), I feel compelled to write separately to explain my decisions today. I also want to take this opportanity to provide my thoughts about the current status of the electtic industty here in Ohio. My hope is that this opinion will be insightful to those looking for more guidance on how and why these decisions were made, the issues that face the electtic industty today, and our collective path forward.
I. THE PPA DECISIONS In adjudging these cases over the past two plus years, so many questions have been posed by the general public and those on the periphery of these cases. Why did the utilities bring these cases? Why shoidd the Commission evaluate them when it has committed the State to competitive markets? Are the PPAs a good deal for consumers? Are the utilities asking consumers to subsidize plants that are no longer competitive in the market? Does the PUCO (and the State of Ohio) care about the environment? These are all fair questions to ask.
We must always remember, however, that the Commission serves a quasi-judicial function, and the cases we evaluate have legal standards of review that should create the frame for our analysis. I am, by formal training and by inherent natare, a lawyer. I understand policy well enough. But to me, when it comes to actaally deciding cases, the technical arguments, the law, the testimony, the cross-examination, the overall record, and the briefing, must prevaU.
From a legal perspective, I analyzed these cases differently than in our first American Electtic Power (AEP) PPA-related decision. In re Ohio Power Co., Case No. 13-2385-EL-SSO, et al.. Opinion and Order (Feb. 25, 2015), whereby the Commission found a PPA construct to be legal, but did not allow for a generating unit to actaally be placed in the rider. The key difference here, legally, is that AEP (and FirstEnergy) filed a settlement stipulation with the Commission. As a result, while the legal standard of review still requires that the utilities bear the burden of proof, the ttue test for legality in these cases is the three-part stipulation
APP. 356 14~1297-EL-SSO -2- test established by this Commission and upheld by the Supreme Court of Ohio. That test reads as follows;
(1) Is the settlement a product of serious bargaining among capable, knowledgeable parties?
(2) Does the settiement, as a package, benefit ratepayers and the public interest?
(3) Does the settlement package violate any important regulatory principle or practice?
Admittedly, the plain language of this test leaves some room for Commission interpretation. Over the course of my next term, I hope to add some docttinal principles to this test that futare Commissions can rely upon ior reference. I will in fact attempt to do some of this here.
A. The Three Part Stipulation Test
1. Serious Bargaining Among Capable, Knowledgeable Parties
First, is the stipulation a product of serious bargaining among capable, knowledgeable parties? I agree v^'^ith the conclusions set forth in both Opinions and Orders, but let me add a bit more. As to whether the parties are capable and knowledgeable, the Commission should look to the quality of the parties that have signed the stipulation. Quantity of parties, in my mind, is meaningless.
The Commission is well-acquainted with the parties that typically intervene in major proceedings before the Conunission, and the various interests they represent. The Commission is also well- aware that if a party intervenes and signs a stipulation, but is not a typical intervenor, whether that party has a symbolic and meaningful representation in that particular case. Again, it is qualihj oi the parties that is determinative, not quantity. In the cases at hand, this quality bar was reached by both AEP and FirstEnergy.
Let me also provide some feedback on the concept of side agreements and whether they impact the first part of the stipulation test. I am not a ttemendous fan of these side agreements, and I worry about their proliferation in these types of proceedings. There were two side agreements executed in these cases that I want to mention. One side agreement was between AEP and lEU-Ohio. The other side agreement was between FirstEnergy and IGS Energy. The AEP/IEU side agreement settles major pieces of litigation between the parties, and the only component of the side agreement that overtly touches the PPA case is lEU's agreement not to oppose the AEP stipulation. This, in my mind, would not impact the first part of the stipulation test. AEP and lEU can agree to settle their claims whenever
APP. 357 14-1297-EL-SSO -3- they choose, and for whatever monetary or non-monetary terms they agree upon. The agreement was properly disclosed pursuant to the law, and again, I do not find that this agreement impacts the serious bargaining among knowledgeable, capable parties.
The FirstEnergy and IGS Energy side agreement was also properly disclosed, but that agreement requires, essentiaUy, that the Corrunission consider a futare adjustment to our oversight of default service pricing tlirough a futare filing. My preference is that something like this would have been included in the actual stipulation. At the same time, 1 am aware of the tight timeframe that the Commission placed on the stipulation hearings, and my notion is that the parties perceived it to be administtatively cleaner (which it is) to execute their side agreement rather than file an amended stipulation since the parties agreed on terms during the actaal stipulation hearing. I understand these circumstances, the agreement was properly disclosed under the law, but my preference is that a side agreement term that requires eventaal Commission action or oversight be placed within the actual confines of the stipulation to ensure that serious bargaining is occurring among knowledgeable parties. Ultimately, my concern about this particular side agreement, under these circumstances, does not yield a failure of the first part of the stipulation test
2. As a Package, Benefits Ratepayers and the Public Interest
i. Introduction
This is hard. There is no other way to say it. Whether these stipulations, as a package, benefit ratepayers and the public interest is the pivot point for these stipulations. It is through this part of the stipulation test that some of the broader questions articulated above can be addressed. But first, let me provide some commentary on the plain language of the second part of the stipulation test. To me, it is clear who ratepayers are. Ratepayers encompass those persons or entities that pay for utility service in the service territory of the stipulating utility. This could range from a single residential consumer that lives in a small apartment, to a large auto manufacturer that consumes massive amounts of electticity all day and through the night in order to keep the manufacturing line moving. All are ratepayers within a utility's given service territory.
Defining the public interest is harder. It would seem to me that the public should mostly consist of the same definitional set that I established above for ratepayers. However, it could encompass more. It could encompass those who are less fortunate and who do not have a domicile. It could encompass those who live outside of the service territory of the subject utility but still within the State (i.e. a decision made in the FirstEnergy service territory that impacts persons or entities located in the Duke service territory), and it could even encompass those persons and entities that do not take service from a utility regulated by the Commission (e.g, persons or entities that take service from municipally owned utilities and co-operatives). Thus, public interest is broader than ratepayers, and has the
APP. 358 14-1297-EL-SSO -4- potential to include persons and entities beyond those who pay rates within the subject utility's service territory.
ii. PPA Rider Charges and Credits
First, let's talk about the rate impacts of the PPA rider in the AEP and FirstEnergy service territories. There were projections for the riders presented in both cases, and all of the projections presented had their merits. Here's what I think I know from these projections. I think that, based upon the projections and the evidence in the record, there is general consensus that the PPA riders will result in a charge to consumers for at least the first 2-3 years of the riders. Because the Commission feels somewhat certain of tliis, we have attempted to build in certain consumer protections to ensure that bills do not increase beyond a certain hmit.
Beyond those first few years, it is unclear whether the PPA riders will result in more charges to ratepayers, or if the riders will result in credits being applied to the bills of ratepayers. The utilities believe that the riders will create bill credits. The Ohio Consumers' Counsel and others believe that the riders will continue to create charges. The expert witaesses in the case have presented divergent data points that yielded very different projections. However, I've seen so many dynamic changes in the market since I've taken office that it's hard for me to be convinced that any expert can ttuly project with accuracy beyond a few years out. I've seen market changes due to weather (e.g. polar vortex), scientific and technological irmovation (e.g. shale extraction and more cost-effective renewable development), market fixes (e.g. PJM's capacity performance product), envirorunental considerations (e.g. US EPA environmental regulations), and there are so many more drivers that could impact the market.
Here's what I can say. After a period of charges, I expect to see credits from the PPA riders. I'm not going to give definitive timelines, but that is my expectation. If this mechanism is ttuly a hedge, wherein consumers will pay when market prices are low, but will be credited money back when market prices are high, then what exactly is the point of the hedge if ratepayers never experience the credits? If ratepayers never experience the credits, then the PPA rider mechanism would then act as a somewhat illusory insurance policy.
Let me also argue the utilities' side of this. Let us say that after 2-3 years of Rider PPA charges, environmental regulations are promulgated that serve to prohibit fracking, or serve to limit the ease of interstate ttansport of nataral gas, or some other unforeseen circumstance that would serve to drive up the price of natural gas beyond its historically low price of the present. If that happens, the operating costs of our nataral gas-fired generation fleet wiU increase, thereby increasing market prices. Again, the PPA riders work contta to the market. If market prices rise, then the PPA riders produce credits to
APP. 359 14-1297-EL-SSO -5- ratepayers, and of course the flip is also true. If market prices increase sharply for these reasons associated with the nataral gas fleet, or for any other reason, then the credits that the utilities provide to ratepayers could offset increased market prices. It is certainly a possibility.
Because predictions of market prices beyond a few years are speculative, we must monitor the riders to ensure that ratepayers are purchasing the hedge that has been marketed to them. This should not be perceived as a blank check, and consumers should not be tteated like a ttust account. It's not right. At the same time, consumers, you have the potential to benefit from this if market prices increase. I know that experts opposing PPAs are saying noio that there is no way that this will happen. Please read my commentary on wholesale markets below, and understand that the energy industty is very dynamic with many, many moving parts that have the potential to impact these markets and make them unpredictable.
iii. The Rest of the Stipulation Packages
It is exttemely important to note that cost is not the only factor that this Commission is to weigh in determining whether the stipulations benefit ratepayers and are in the public interest. In In re Application of Columbus Southern Poioer Company, 129 Ohio St.3d 46 (2011), the Supreme Court of Ohio addressed this issue of whether the PUCO could consider more than cost in determining whether a stipulation benefits ratepayers and is in the public interest. In that case, lEU-Ohio challenged AEP's peak demand reduction plan stipulation, presenting what it believed to be a more cost-effective approach to prove that AEP's stipulation did not benefit ratepayers and was not in the public interest. The Supreme Court of Ohio held that, "While cost is surely a relevant concern to be balanced... it is not the only concern, and the commission is entitled to consider more." (emphasis added at 51).
Here, I think the public benefits from a few major categories of terms agreed to in the stipulations, especially the grid modernization and clean generation technologies provisions. Many states have opened dockets and are undertaking "utUity 2.0" or "utility of the futare" grid modernization endeavors. The State of Ohio is due for this conversation. For some time now, I've wondered how we could possibly persuade the electric utilities to have conversations with us about the futare of their industties: how they expect to incorporate next generation (and often third party) technologies into the distribution grid, how they expect to cater to millermial consumers who want more control and understanding over how and what they consume, how to better incorporate clean technologies into everything that they do, etc. These conversations could yield revolutionary endeavors that would surely benefit the public interest. The stark reality is that until these PPA cases were resolved, no such conversations would occur.
APP. 360 14-1297-EL-SSO -6-
AIso, clean generation technologies are advanced in these stipulations with renewable, energy efficiency and even battery storage provisions. In fact, a major envirorunental advocate, the Sierra Club, signed onto the AEP stipulation. It would be foolhardy for me not to recognize the ttemendous amount of public sentiment expressed over the past two years associated with these cases and their environmental ramifications. The environmental community surely will not be pleased that the Commission is approving PPA riders for coal plants and a nuclear plant, but at the same time, the Commission recognizes the importance of cleaner generation technologies by approving certain endeavors in these Opinions and Orders. Again, I do not believe that there would have been a path forward for such commitments without these stipulations.
There are more stipulated terms to discuss that elicited the signatares (or non- opposition) of a number of very important parties in these proceedings. Our largest consumers will be able to take advantage of utility demand response programs. Economic development opportanities are created. Our competitive retailers will be given the opportanity to advance endeavors that could serve to enhance the retaU marketplace. And there is more. Surely, it is fair to ask how much all of this will cost. Much of these costs will be determined in future proceedings before the Commission, and so we wiU find out if the perceived present benefits are actaaUy worth the costs. That question, however, sheds light on the very difficult balance between a current financial impact to ratepayers, and futare benefits (and even savings) for those same ratepayers after this initial investment. I save this conundrum for another day, however.
In summary, whUe it is unclear what the net impact of the PPA riders will be over the next eight years, the concept itself has merit as it could serve as a hedge against marketplace volatility. At the same time, from purely a monetary perspective, we must ensure that constant and large charges do not become the norm, as this would mitigate the conceptual benefit that the hedge has to offer. The other benefits in the stipulation packages, eliciting the signatare of parties in these proceedings, push the stipulations just beyond the pivot point, allowing for a finding that these stipulations pass this second part of the stipulation test.
3. Violate any Important Regulatory Principle or Practice
This third part of the stipulation test, again, allows for some Commission discretion. What is a regulatory principle and a regulatory practice, and even then, which of these principles and practices are important? Do these principles and practices encompass more than the law set forth in the Ohio Revised Code and the rules set forth in the Ohio Administtative Code? Would these principles and practices encompass the current policy positions of the State and perhaps the Chairman of the PUCO? Do these principles and practices encompass generally accepted regulatory norms adopted by a majority of state utility commissions, the National Association of Regulatory Utility Conunissioners, the
APP. 361 14-1297-EL-SSO -7-
Mid-Atlantic Cortference of Regulatory Utility Commissioners, the National Regulatory Research Institate, etc.?
In trying to provide some guidance here, I am of the opinion that, at the very least, the stipulation cannot violate a statute of the Ohio Revised Code or a rule of the Ohio Administrative Code. For this reason, I concur with the language set forth in the Opinions and Orders stating that the third part of the stipulation test has been satisfied. The Commission spent much of 2014 and early 2015 mired in the quandary of whether the PPA mechanism was legal under Ohio law, and more specifically, the ESP statute. The Comnussion's conclusion on that issue in the AEP ESP III case has been made. I do not wish to revisit that decision or its justification here.
1 would, however, like to provide some commentary on the factors set forth by the Commission in AEP ESP III that were meant to serve as evaluative criterion for the Commission in determining whether to grant or deny futare PPA requests. The plain language leading into those factors reads in a more permissive, than mandatory marmer. That is, the Commission can take those factors into account, but it doesn't necessarily have to. If these cases were not presented to us as stipulations, I would have looked more to those factors as guide posts in my decision-making. However, again, the presentation of these cases as stipulations very much changed my legal standard of review, and thus, my analysis. To note, I do not believe that either company successfully proved that the PPA units are needed to preserve reliability. Based upon the legal standard of review though, this failure to meet one of the Commission's permissive factors is not fatal.
II. The Current Status of the Industry
My time on the Commission thus far has been one of ultimate flux in the electtic industty. I sometimes cannot believe both the fortane and misfortane in my timing. As I was coming onto the Commission, the Commission was completing its vision of ttansitioning utilities to fuU competition via the most recent Dayton Power & Light (DP&L) ESP. Now, states and their electtic utUities are ttying to determine how to best plan for the modernized "utility 2.0" futare grid, in tandem with demands for cleaner energy, more thoughtful consumer engagement, and of course, having to deal with market dynamics that are favoring some assets and disfavoring others. 1 pen this portion of my concurrence not for purposes of legacy though. As I have been appointed to another term, my intent is the diamettic opposite. I pen this portion of my concurrence to try and provide the utility community with a glimpse of how I presently view the industty and its various stakeholders and interests. From here, and based upon these thoughts, my hope is that we can chart a clear path for this industry, together.
APP. 362 14-1297-EL-SSO -8-
A. Competition
I begin with the concept of competition. There has been plenty of rhetoric espoused stating that the granting of PPAs wiU destroy competition in the State of Ohio. I will address this concern, but an important distinction needs to first be made. There is a difference between loholesale competition and retail competition. Wholesale competition involves the generators of electticity competing to sell the power that they produce into a marketplace for the best possible price. Retail competition involves entities that purchase this power from the wholesale marketplace, and then resell that power to consumers.
In the State of Ohio, wholesale competitors include the generation companies affiliated with AEP, FirstEnergy, DP&L, Dynegy (who last year purchased the generation fleet owned by Duke Energy Ohio's generation affiliate) and other independent power producers in the State. Generation owned by municipals and co-ops (whom the PUCO do not regulate) also partake in wholesale competitive markets. Retail competitors include companies like Direct Energy, IGS Energy, Constellation, Just Energy, the retail affiliates of the aforementioned four electtic companies and many, many more. I will address retail competition first, followed by wholesale competition.
1. Retail Competition
The statas of retail competition in the State of Ohio is sttong, and wiU continue to be sttong going forward. Nothing in these Opinions and Orders should be construed as me being unsupportive of retail competition. Retailers have become the ttue innovators in the State. They are bringing home energy management products, disttibuted generation, innovative pricing and so much more to their customers. I am supportive and very appreciative of our retailers' efforts to continue to innovate and make customers' lives better.
In analyzing the PPA riders, the mechanisms contemplated could hurt the retail market in a few ways that we must be cognizant of. The first way is if there is confusion about what the Commission has done here. Again, retail competition is working, and it should not be harmed by law or policy based upon a misunderstanding of the Commission's decisions today. The second way is if either the AEP-Ohio or FirstEnergy (the distribution companies) sell their power purchased via the PPAs to their retail affUiates (AEP Retail and FirstEnergy Solutions) via bilateral contract. Per the Opinions and Orders, no presumption of prudency will exist here.
Retail competition is thriving. These companies are innovators. I want to continue to see them thrive and we need to ensure that the potential harms that could arise from these decisions never come to fruition.
APP. 363 14-1297-EL-SSO • -9-
2. Wholesale Competition
As I have already stated, my eventaal decisions in these cases were made by analyzing the stipulations against the three part test. My decisions were based upon the concept of the PPAs being utilized as a retail hedge and rooted in state law. Although our decisions do not rely on Federal or wholesale issues, I want to utilize this "industry statas" section to provide some observations on wholesale market operation, specifically the PJM wholesale market.
I am a believer in wholesale markets for reasons associated with the discipline of economics. Clearly though, state goverrunents have been expressing some recent ttepidation with the markets. There are more states than Ohio that are exercising, or contemplating to exercise their retail jurisdictional authority associated with existing generation (mostly nuclear), or have attempted to incent new generation. Why? What is the root cause of this? 1 am not entirely sure. Conceptaally for the markets, what I think would be essential is that ttust and confidence exist in the markets from not only the actaal market participants, but in this case, those who are forced to deal with the coUateral damage associated with market operation.
State goverrunents are the entities that invariably manage wholesale market collateral damage because they are the most directly accountable to the consumers and job creators in their respective States. I have said this publicly on a few occasions. If the states, who are the most directly accountable to consumers for the impacts of wholesale markets (even though they do not plan or operate them) start to feel pressure, whether from their consumers, utihties, interest groups, etc., and this pressure is either supplemented by, or helps to bolster a lack of ttust and confidence in the markets themselves, then states will contemplate exercising their given legal authority associated with their in-state generation.
When prices were high during the polar vortex, consumers and businesses in the State of Ohio called the PUCO and state goverrunent offices to express their displeasure. They don't know who PJM is. They don't know who FERC is. When a coal plant in Appalachia is shut down and hundreds are losing their livelihoods, these families send letters to the PUCO and state government offices to tell us of their hardships. They don't know who PJM is. They don't know who FERC is. Again, states feel accountable for the impacts of markets that are not in their conttol.
That's not to say that there aren't solutions. I have had the professional pleasure of interacting with the executives at PJM as well as FERC Commissioners. They are forthright and brilliant people in their own right, and they have very challenging jobs. They have, in my experience, also been very receptive to the concerns of the states. But again, state goverrunent behavior is expressing some trepidation which will need to be addressed. The
APP. 364 14-1297-EL-SSO -10- below thoughts/concerns are a start. These are mainly byproduct questions from these PPA cases:
• Are the markets prepared if, for whatever the reason, we see a spike in nataral gas prices, especially with the continued shedding of plants from the coal and nuclear generation fleets?
• How close are we to technically reliable and cost-effective utility scale renewables, and are they adequate replacements for the coal and nuclear fleets?
• The nuclear fleet appears to be in the most difficult position, with retirements occurring or being threatened in other states. With nuclear continuing to be a large chunk of generating capacity in PJM, do we need to tteat them differently in the wholesale markets in order to preserve them?
• Is the demise of the coal fleet overblown? That is, will there continue to be a large coal fleet that clears wholesale markets sans environmental (carbon) reform?
• If envirorunental (carbon) reform finally goes through, whether it be the Clean Power Plan or other reform, and the nuclear fleet continues to sttuggle, and renewables aren't ready, what is your plan to ensure a reliable grid?
Perhaps these questions seem preposterous to the reader. Perhaps the answers to these questions are obvious. Perhaps each of these questions can be answered by stating simply that the markets will account for and take care of all of these potential scenarios. Perhaps the policy underpinnings of my questions, concerns about cost and reliabihty, are not appropriate to ask when dealing with markets. If market prices are high, then that's the market. If power is scarce, then that's the market. Admittedly, if you had my job though, and had to think about consumers big and small just ttying to "make it" on a day-to-day basis here in my State, a State in which I have lived aU over and have always called home, you may understand my concern.
B. Our Electtic Utilities
The Commission and our electtic utilities need to work as partners going forward. These cases were filed two or so years ago, and the Commission has been playing defense ever since. Going forward, we need to have a conversation about your futare. How can we work to better the lives of consumers in the State of Ohio while also ensuring that you maintain your economic viability? My hope is that we will have this important conversation within the confines of our grid modernization dockets and beyond. We need to work as partners going forward for the betterment of the State.
APP. 365 14-1297-EL-SSO -11-
C. The Environmental Community
In my eyes, you have officially arrived here at the Commission. When 1 first started litigating at the Commission some five years ago, I think the perception of your participation is that you were more fringe advocacy parties that would not likely gain traction in large rate cases. Now, unequivocally, you have a seat at the table, and you deserve to be praised for your advocacy and ascension.
My only request is that your advocacy of social principle is firmly grounded in regulatory reality. It is not technically feasible, nor is it presently cost-effective to simply replace our coal, nuclear and gas fleets with renewables and energy efficiency. Perhaps it could happen, but not nearly in the irtunediate futare. As I have stated numerous times when speaking about the Clean Power Plan, cleaner air and a cleaner envirorunent are very fine policy objectives. We must be inteUigent and intellectaally honest in how we get there from a State regulatory perspective.
D. The Coal Fleet
Coal has a rich history here in Ohio. It has supported Ohio communities and families. It has helped preserve reliability of the grid and the cost-effectiveness of power. I continue to be engaged at a national level to help tty and find solutions for coal. Clearly, because of its envirorunental attributes, coal does not hold the same favor that it once did. This, combined with the price of nataral gas, makes for a very challenging market environment for coal.
Cleaner coal solutioris like carbon capture and other forms of carbon management are discussed ad nauseum in Washington, but there appears to be some relative consensus that these technologies, at present, are cost prohibitive. Further, based upon current market dynamics, I wonder if their cost effectiveness may arrive too late for the existing coal fleet.
I have become familiar with the research of Dr. L.S. Fan and his chemical looping work at The Ohio State University. These types of research endeavors could revolutionize the coal industry. As a State regulator, I don't know that I can do much more to move research endeavors to market other than to say "I support you." I think, however, that lending whatever support we can to such research endeavors makes all the sense in the world. I continue to search for solutior\s for this industry, and I am very hopeful that solutions present themselves.
E. Merchant Generators
We are very grateful to have you here, and these decisions should in no way be viewed as a condemnation of your operations here in the State. Through the nataral
APP. 366 14-1297-EL-SSO -12- demographics of the State, existing infrasttuctare and our "one-stop" power siting shop, my hope is that merchant generators will continue to feel that investment in Ohio is a profitable endeavor.
F. The Path Forward
Regulation is far from perfect When one considers all of the moving parts, especially in the electric industry, it is extremely hard to fathom how it could be. Markets are dynamic. Industries evolve based upon technological irmovation. Industry players change priorities based upon share prices, new Boards, and new CEOs. Social movements take shape and influence policy. Lawmakers and other regulators impact what you can and cannot do. The regulators themselves are swapped in and out, and they evolve during the course of their terms. How, then, can electric industry stakeholders in the State of Ohio have some semblance of certainty in regulation?
I feel, at least, that there are a few principles that I will always rely upon when making decisions and charting policy paths. I have quoted the mission of the PUCO extensively in my past decision-making. Outside of the law, it is all that exists to guide us. Now that I have been in this seat for close to three years, I am going to express some autonomy and add a few more principles to the mission that will help guide my second term.
Safe, reliable and cost-effective. These principles are articulated in the mission of the PUCO, and are the core principles to rely upon in safeguarding the industry. The Commission will continue to enforce and seek to make better its reliability and safety measures. The tremendous work that the staff of the Commission does to ensure safety and reliability, and the cooperation that our utilities provide should not be forgotten. It is a heavy, heavy responsibility. I have addressed cost-effectiveness earlier in this concurrence. Note that the principle is cost-effective and not cheapest. As in life, sometimes you have to pay for great service, and sometimes you have to invest on the front-end to save on the back-end. I am always concerned about costs. I am concerned about what our most indigent consumers can pay, and I am concerned if our job creators are paying too much. It is a very challenging balance, but a balance nonetheless that we must endeavor to create.
Innovative. I now view this as synonymous with "competitive" in the retail space. If a retaUer is being innovative, then it is also being competitive. If a retailer's only offer to consumers is a smaU discount off of the price to compare, that retailer is not being irmovative, and thus the retailer is not being competitive. I hope to see more and more retail innovation as I progress through my second term. I also hope to see innovation expressed in our grid modernization dockets. Again, these dockets have ttemendous potential.
APP. 367 14-1297~EL-SSO -13-
Clean. We must acknowledge the clean movement. Failing to do so runs afoul of what appears to be overwhelming consumer sentiment. Recall though that we have to balance this principle against the principles of reliability and cost-effectiveness. Again, environmental advocates have a seat at the table, but we have to work always towards immediately practical solutions. This is not to say, again, that I do not believe in our historical baseload generation either. We must support clean solutions for coal, and must also realize that ttying to push the baseload fleets out of the market sooner than our grid can account for may be very harmful.
Safe - Reliable - Cost-Effective - Innovative - Clean
These are principles that can guide our path forward. These are big cases, but there is still, and there always will be, much work to be done.
Asim Z. Haque, Commissioner
AZH/vrm
Entered in the Journal MAR 3 1 2016
Barcy F. McNeal Secretary
APP. 368 BEFORE
THE PUBLIC UTILITIES COMMISSION OF OHIO
In the Matter of the Application of Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison Company for Authority to Provide Case No. 14-1297-EL-SSO for a Standard Service Offer Pursuant to R.C. 4928.143 in the Form of an Electtic Security Plan.
CONCURRING OPINION OF COMMISSIONER M. BETH TROMBOLD
I write separately from my colleagues because I feel it is important to emphasize the expectation on which today's Opinion and Order is based.
The energy market is dynamic and complicated, and the issues raised in this proceeding are difficult and not given to simple solutions. The application in this case was submitted by the Companies in mid-2014. For over 18 months, the Commission has worked diligently to decide the case in a manner consistent with Ohio law while balancing many interests and providing extensive due process.
Every Ohioan relies on public utility companies for the critical services they provide; therefore, we want those companies to be financially sound and stable. We have also worked long and hard in Ohio to establish a robust competitive electtic marketplace to the benefit of consumers and growing businesses. Importantly, Ohio consumers want safe, reliable electticity at affordable rates as weU as innovative products and services that meet their needs and interests. To be sure, it's all a very delicate balance.
In the case before us today, the Commission must consider whether the Stipulated ESP IV, as a package, benefits ratepayers and the public interest. The analysis made by the Commission in reaching this conclusion is articulated in the Opinion and Order. In short, the Commission concludes that Ohio consumers will benefit from several items in the Stipulated ESP IV such as provisions that will result in grid modernization and more renewables. These provisions will enable the Commission to advance important conversations with our utilities about the futare of the electtic industty and incorporating "next generation technologies" into our electtic disttibution grid.
In addition, the Stipulated ESP IV continues utility demand response programs important to the viability of our large industtial companies, and creates pilot prograrx\s necessary for our competitive retail suppliers to advance Ohio's retail marketplace.
APP. 369 14~l297-EL-SSO -2-
The Purchase Power Agreement (PPA) included in the Stipulated ESP IV has been discussed at great length in this docket and elsewhere.
One of the challenges of utility regulation is that it is based on forecasts, and forecasts are just that: a prediction about an uncertain futare. We all know there have been changes in the market in recent years caused by the weather, the economy, technological irmovations, and environmental considerations that have resulted in market prices no one predicted despite our best attempts to forecast them.
The PPA mechanism proposed by the Companies is designed to operate as a financial hedge against such price volatility, wherein consumers pay more when market prices are low but pay less when market prices are high. Based on the forecasts submitted by the Companies and evidence in the record, it is my clear expectation, just as it is Commissioner Haque's, that the PPA rider approved today wiU result in a credit (i.e. benefit) to ratepayers over the next eight years (Co. Ex. 155 at 11-12; OCC/NOPEC Ex. 9 at 12; Tr. Vol XXII at 4384-86).
M. Beth Trombold, Conunissioner
MBT/vrm
Entered in the Journal MAR 3 1 2016
Barcy F. McNeal Secretary
APP. 370 BEFORE
THE PUBLIC UTILITIES COMMISSION OF OHIO
In the Matter of the Application Seeking Approval of Ohio Power Company's Proposal to Enter into an Affiliate Pov\^er Case No. 14-1693-EL-RDR Purchase Agreement for Inclusion in the Power Purchase Agreement Rider.
In the Matter of the Application of Ohio Power Company for Approval of Certain Case No. 14-1694-EL-AAM Accounting Authority.
OPINION AND ORDER
APP. 371 14-1693-EL-RDR -ii- 14-1694-EL-AAM
Table of Contents
APPEARANCES: 1 I. INTRODUCTION 4 IL HISTORY OF THE PROCEEDINGS 5 IIL PROCEDURAL MATTERS 8 A. Motions for Protective Order 8 B. Motions and Interlocutory Appeal Regarding Procedural Schedule 9 C. Untimely Motions for Intervention 11 1. PJM 11 2. Noble 12 D. Motions for Leave to File Amicus Brief 14 E. Evidentiary Rulings 16 F. Motions to Stay 18 IV. DISCUSSION 21 A. Summary of the Application 21 B. Summary of the Stipulation 23 C Consideration of the Stipulation 48 1. Is the settlement a product of serious bargaining among capable, knowledgeable parties? 49 a. Summary of Parties' Positions 49 b. Commission Decision 51 2. Does the settlement, as a package, benefit ratepayers and the public interest? 53 a. Introduction 53 b. Summary of Signatory Parties' Positions 54 c. Summary of Non-Signatory Parties' Positions 59 d. Comnussion's Factors 67 i. Summary of Signatory Parties' Positions 67 ii. Summary of Non-Signatory Parties' Positions 69 e. Recommended Modifications to the Stipulation 73 i. Summary of PJM's Position 73 ii. Summary of OEG's Position 75 iii. Summary of Non-Signatory Parties' Positions 76 f. Commission Decision 77 i. PPA Rider Projections 78 ii. PPA Rider Rate Impact Mechanism 81 iii. Benefits of the Stipulation 82 iv. Commission's Factors 86 V. Annual Prudency Review %7
APP. 372 14-1693-EL-RDR ~iii- 14-1694-EL-AAM
vi. Other Modifications and Clarifications 90 3. Does the settlement package violate any important regulatory principle or practice? 92 a. Introduction 92 b.. Statutory Authority 92 c. State Policy 95 d. IRP Program 97 e. Allocation of Costs and Credits 99 f. Corporate Separation 100 g. Transition Revenues 102 h. Preemption 102 i. Commission Decision 103 4. ESP/MROTest 104 V. CONCLUSION 106 FINDINGS OF FACT AND CONCLUSIONS OF LAW: 106 ORDER: 107
APP. 373 14-1693-EL-RDR -1- 14_1694-EL-AAM
The Commission, having considered the record in these proceedings^ hereby issues its Opiruon and Order, modifying and adopting the joint stipulation and recommendation submitted by the signatory parties.
APPEARANCES:
Steven T. Nourse, Matthew J. Satterwhite, and Matthew S. McKenzie, American Electric Power Service Corporation, One Riverside Plaza, 29th Floor, Columbus, Ohio 43215-2373, Porter, Wright, Morris & Arthur, LLP, by Dartiel R. Conway, 41 South High Street, Suites 2800-3200, Columbus, Ohio 43215, and Ice Miller LLP, by Christopher L. Miller, 250 West Street, Columbus, Ohio 43215, on behalf of Ohio Power Company.
Mike DeWine, Ohio Attorney General, by Steven L. Beelei and Werner L. Margard, Assistant Attorneys General, 180 East Broad Street, Colunrtbus, Ohio 43215-3793, on behalf of the Staff of the Public Utilities Commission of Ohio.
Bruce J. Weston, Ohio Consumers' Counsel, by William }. Michael, ]odi }. Bair, and Kevin F. Moore, Assistant Consumers' Counsel, 10 West Broad Street, Suite 1800, Columbus, Ohio 43215-3485, and Bricker & Eckler LLP, by Dane Stinson, 100 South Third Street, Columbus, Ohio 43215, on behalf of the residentiai utility consumers of Ohio Power Company.
Boehm, Kurtz & Lowry, by David F. Boehm, Michael L. Kurtz, Kurt J. Boehm, and Jody Kyler Cohn, 36 East Seventh Street, Suite 1510, Cincinnati, Ohio 45202, on behalf of Ohio Energy Group.
McNees, Wallace & Nurick, LLC, by Samuel C. Randazzo, Frank P. Darr, and Matthew R. Pritchard, 21 East State Street, 17th Floor, Columbus, Ohio 43215, on behalf of Industrial Energy Users-Ohio.
Carpenter, Lipps & Leland, LLP, by Kimberly W. Bojko, Danielle M. Ghiloni, and Ryan P. O'Rourke, 280 North High Street, Suite 1300, Columbus, Ohio 43215, on behalf of Ohio Manufacturers' Association Energy Group.
Taft, Stettinius & Hollister, LLP, by Celia M. Kilgard, 65 East State Street, Suite 1000, Columbus, Ohio 43215, on behalf of The Kroger Company.
Spilman, Thomas & Battle, PLLC, by Lisa M. Hawrot, 1233 Main Street, Suite 4000, Wheeling, West Virginia 26003, Carrie M. Harris, 310 First Street, Suite 1100, P.O. Box 90, Roanoke, Virginia 24002-0090, and Derrick Price Williamson, 1100 Bent Creek Boulevard, Suite 101, Mechanicsburg, Pennsylvania 17050, on behalf of Wal-Mart Stores East, LP, and Sam's East, Inc.
APP. 374 14-1693-EL-RDR -2- 14-1694-EL-AAM
Bricker &: Eckler LLP, by Thomas J. O'Brien, 100 South Third Street, Columbus, Ohio 43215-4291, and Richard L. Sites, 155 East Broad Street, 3rd Floor, Columbus, Ohio 43215-3620, on behalf of Ohio Hospital Association.
Jeffrey W. Mayes, 2621 Van Buren Avenue, Suite 160, Eagleville, Pennsylvarua 19403, and Williams, Allwein & Moser, LLC, by Todd M. Williams, Two Maritime Plaza, 3rd Floor, Toledo, Ohio 43604, on behalf of Monitoring Analytics, LLC.
Mark A. Hayden, Jacob A. McDermott, and Scott J. Casto, FirstEnergy Service Company, 76 South Main Street, Akron, Ohio 44308, and Calfee, Halter & Griswold LLP, by James F. Lang and N. Trevor Alexander, 1405 East Sixth Street, Cleveland, Ohio 44114, on behalf of FirstEnergy Solutions Corp.
Vorys, Sater, Seymour & Pease, LLP, by M. Howard Petricoff, Michael J. Settineri, and Gretchen L. Petrucci, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, and Kravitz, Brown & Dortch, LLC, by Michael D. Dortch and Richard R. Parsons, 65 East State Street, Suite 200, Columbus, Ohio 43215, on behalf of Dynegy, Inc.
Thompson Hine LLP, by Kurt P. Helfrich, Scott Campbell, Stephanie M. Chmiel, and Michael Austin, 41 South High Street, Suite 1700, Columbus, Ohio 43215-6101, on behalf of Buckeye Power, Inc.
Joseph Oliker, 6100 Emerald Parkway, Dublin, Ohio 43016, on behalf of Interstate Gas Supply, Inc.
Eckert, Seamans, Cherin & Mellott, LLC, by Gerit F. Hull, 1717 Pennsylvania A-venue, NW, 12th Floor, Washington, D.C. 20006, and Jennifer L, Spinosi, 21 East State Street, 19th Floor, Columbus, Ohio 43215, on behalf of Direct Energy Services, LLC, Direct Energy Business, LLC, and Direct Energy Business Marketing, LLC.
Vorys, Sater, Seymour &: Pease, LLP, by M. Howard Petricoff, Michael J. Settineri, and Gretchen L. Petrucci, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, on behalf of Constellation NewEnergy, Inc. and Exelon Generation Company, LLC.
Vorys, Sater, Seymour & Pease, LLP, by M. Howard Petricoff, Michael J. Settineri, and Gretchen L. Petrucci, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, on behalf of Retail Energy Supply Association.
Vorys, Sater, Seymour &: Pease, LLP, by M. Howard Petricoff, Michael J. Settineri, and Gretchen L. Petrucci, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, on behalf of PJM Power Providers Group and Electric Power Supply Association.
APP. 375 14-1693-EL-RDR -3- 14-1694-EL-AAM
Dickinson Wright PLLC, by Terrence O'Donnell and Raymond D. Sailer, 150 East Gay Street, Suite 2400, Columbus, Ohio 43215, on behalf of Mid-Atlantic Renewable Energy Coalition.
David C Rinebolt and Colleen L. Mooney, 231 West Lima Street, Findlay, Ohio 45839-1793, on behalf of Ohio Partners for Affordable Energy.
Michael R. Smalz, Ohio Poverty Law Center, 555 Buttles Avenue, Columbus, Ohio 43215-1137, on behalf of Appalachian Peace and Justice Network.
Kristin A. Henry and Tony G. Mendoza, 85 Second Street, 2nd Floor, San Francisco, California 94105-3459, Shannon Fisk, Earthjustice, 1617 John F. Kennedy Boulevard, Suite 1675, Philadelphia, Permsylvania 19103, Michael C. Soules, Earthjustice, 1625 Massachusetts Avenue NW, Suite 702, Washington, D.C. 20036, Olson, Bzdok & Howard, P.C., by Christopher M. Bzdok, 420 East Front Street, Traverse City, Michigan 49686, and Richard Sahli Law Office, LLC, by Richard C Sahli, 981 Pinewood Lane, Columbus, Ohio 43230-3662, on behalf of Sierra Club.
Trent Dougherty, 1207 Grandview Avenue, Suite 201, Columbus, Ohio 43212-3449, on behalf of Ohio Environmental Council and Environmental Defense Fund.
Madeline Fleisher, 21 West Broad Street, Suite 500, Columbus, Ohio 43215, and Justin Vickers, 35 East Wacker Drive, Suite 1600, Chicago, Illinois 60601, on behalf of Environmental Law & Policv Center.
Carpenter, Lipps & Leland, LLP, by Joel E. Sechier, 280 North High Street, Suite 1300, Columbus, Ohio 43215, and Gregory J. Poulos, 471 East Broad Street, Suite 1520, Columbus, Ohio 43215, on behalf of EnerNOC, Inc.
Kevin R. Schmidt, 88 East Broad Street, Suite 1770, Columbus, Ohio 43215, on behalf of Energy Professionals of Ohio.
APP. 376 14-1693-EL-RDR ^- 14-1694-EL-AAM
OPINION:
I. INTRODUCTION
It has long been the mission of the Commission to ensure consumers are provided electricity in a reliable, cost-effective, and safe manner. This mission requires the complex task of balancing the interests of Ohio's public utilities companies, other vital businesses, and hard-working citizens.
These principles remain the same today, but the challenges confronting electric utilities continue to evolve. Apparent from the participation in these dockets, electric utilities, customers, suppliers, and many others are concerned about those challenges. They are also interested in the many opportunities to meet them through integrating technology, assuring a diverse mix of resources, and providing the infrastructure and incentives for customers to be engaged in how they consume electricity.
Thousands of pages of testimony and briefs, as well as letters and emails, have been filed with the Commission in these proceedings. Lawyers, expert witnesses, and other staff listened and litigated in hearing rooms at the Commission for countless days. The record before us also contains input from diverse interests, including, but not limited to, customers - residential, commercial and industrial, both large and small; competitive suppliers of retail electric services; and electric generation providers in Ohio and beyond.
Although it bears no weight in the decision of this Commission, we must note that we do not check our sense of the real world at the door. The subject of these proceedings has become part of a larger public dialogue about the provision of electricity service in our state and beyond.
We also note that the Opinion and Order in these proceedings is being released simultaneously with the Opinion and Order in In re Ohio Edison Co., The Cleveland Elec. Ilium. Co., and The Toledo Edison Co., Case No. 14-1297-EL-SSO. While these decisions are similar in that they involve retail rate stability, we emphasize the decisions involve different companies and different types of cases. The current proceedings pertain to only a retail rate stability rider while the other pertains to an entire electric security plan (ESP). In addition, the cases involve stipulations with different terms and different signatory parties. Consequently, neither the format nor the substance of the decisions is identical.
APP. 377 14-1693-EL-RDR -5- 14-1694-EL-AAM
The role of the Conunission is to decide these cases in a maimer consistent with the law while balancing many interests. This Opinion and Order describes the positions of numerous parties not only to summarize the complexity of the record, but to demonstrate the depth of stakeholder concern and the myriad of suggestions made to assist the Commission in our decision.
It is against this backdrop that we issue this Opinion and Order.
II. HISTORY OF THE PROCEEDINGS
Ohio Power Company d/b/a AEP Ohio (AEP Ohio or the Company) is a public utility as defined in R.C. 4905.02 and an electric distribution utility (EDU) as defined in R.C. 4928.01(A)(6), and, as such, is subject to the jurisdiction of this Commission. R.C. 4928.141 provides that an EDU shall provide consumers within its certified territory a standard service offer (SSO) of all competitive retail electric services (CRES) necessary to maintain essential electric services to customers, including a firm supply of electric generation services. The SSO may be either a market rate offer (MRO) in accordance with R.C. 4928.142 or an ESP in accordance with R.C. 4928.143.
In Case No. 13-2385-EL-SSO, et al., the Commission modified and approved AEP Ohio's application for an ESP for the period of June 1, 2015, through May 31, 2018, pursuant to R.C 4928.143. In re Ohio Power Co., Case No. 13-2385-EL-SSO, et al. {ESP 3 Case), Opinion and Order (Feb. 25, 2015), Second Entry on Rehearing (May 28, 2015). Among other matters, the Commission concluded that AEP Ohio's proposed power purchase agreement (PPA) rider, which would have flowed through to customers the net impact of the Company's contractual entitlement associated with the Ohio Valley Electric Corporation (OVEC), satisfied the requirements of R.C. 4928.143(B)(2)(d) and, therefore, was a permissible provision of an ESP. The Commission stated, however, that it was not persuaded, based on the evidence of record, that AEP Ohio's PPA rider proposal would provide customers with sufficient benefit from the rider's financial hedging mechanism or any other benefit that would be commensurate with the rider's potential cost. Noting that a properly conceived PPA rider proposal may provide significant customer benefits, the Commission authorized AEP Ohio to establish a placeholder PPA rider, at an initial rate oi zero, for the term of the ESP, with the Company being required to justify any future request for cost recovery. Finally, the Conmiission deterauned that all of the implementation details with respect to the placeholder PPA rider would be determined in a future proceeding, following the filing of a proposal by AEP Ohio that addresses a number of specific factors, which the Commission will consider, but not be bound by, in its evaluation of the Company's filing. In addition, the Commission indicated that AEP Ohio's PPA rider proposal must address several other issues specified by the Commission. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 20-22, 25-26.
APP. 378 14-1693-EL-RDR -6- 14-1694-EL-AAM
On October 3, 2014, in the above-captioned proceedings, AEP Ohio filed an application seeking approval of a proposal to enter into a new affiliate PPA with AEP Generation Resources, Inc. (AEPGR).^ Following the issuance of the Conmiission's Opinion and Order in the ESP 3 Case, AEP Ohio filed, on May 15, 2015, an amended application and supporting testimony, again seeking approval to enter into a new affiliate PPA with AEPGR and also requesting authority to include the net impacts of both the affiliate PPA and the Company's OVEC contractual entitlement in the placeholder PPA rider approved in the ESP 3 Case. AEP Ohio explained that the amended application supersedes and replaces the Company's original application filed on October 3, 2014. AEP Ohio further explained that the primary purposes of the amended application are to include the OVEC contractual entitlement in the pending PPA rider proposal, along with the proposed affiliate PPA with AEPGR; address the factors and requirements set forth by the Commission in the ESP 3 Case; and update the Company's supporting testimony to reflect a current analysis of the amended proposal.
By Entry issued August 7, 2015, the procedural schedule in these matters was established, including an intervention deadline of August 21, 2015. The following parties were granted intervention by Entry issued September 15, 2015: FirstEnergy Solutions Corp. (FES); Industrial Energy Users-Ohio (lEU-Ohio); Ohio Energy Group (OEG); The Kroger Company (Kroger); Sierra Club; Buckeye Power, Inc. (Buckeye); Mid-Atlantic Renewable Enevgy Coalition (MAREC); Ohio Advanced Energy Economy (OAEE); Wal- Mart Stores East, LP and Sam's East, Inc. (jointly, Walmart); Ohio Environmental Council (OEC); Monitoring Analytics, LLC (Market Monitor or IMM); Ohio Hospital Association (OHA); Energy Professionals of Ohio (EPO); Envirorunental Defense Fund (EDF); Ohio Manufacturers' Association Energy Group (OMAEG); Retail Energy Supply Association (RESA); Ohio Consumers' Counsel (OCC); Direct Energy' Services, LLC, Direct Energy Business, LLC, and Direct Energy Business Marketing, LLC (collectively. Direct Energy); Interstate Gas Supply, Inc. (IGS); PJM Power Providers Group (P3); Electric Power Supply Association (EPSA); Ohio Partners for Affordable Energy (OPAE); Dynegy, Inc. (Dynegy); Appalachian Peace and Justice Network (APJN); Environmental Law & Policy Center (ELPC); Constellation NewEnergy, Inc. and Exelon Generation Company, LLC (jointly, Exelon); and EnerNOC, Inc. (EnerNOC). OAEE filed a notice of withdrawal from these proceedings on September 18, 2015.
A prehearing conference was held, as scheduled, on September 22, 2015. The evidentiary hearing on the amended application commenced on September 28, 2015, and concluded on November 3, 2015. At the evidentiary hearing, AEP Ohio offered the direct testimony of 11 witnesses in support of the Company's application, while two witnesses offered rebuttal testimony on behalf of the Company. Additionally, 25 witnesses testified on behalf of various intervenors and one witness testified on behalf of Staff. At the
AEP Ohio ai\d AEPGK are both subsidiaries of American Electric Power Company, Inc. (AEP).
APP. 379 14-1693-EL-RDR -7- 14-1694-EL-AAM conclusion of the evidentiary hearing, a briefing schedule was established, with initial and reply briefs due to be filed by the parties on November 24, 2015, and December 9, 2015, respectively. By Entry dated November 19, 2015, the attorney examiner granted Staff's motion for an extension of the briefing schedule, such that initial and reply briefs were to be filed by December 22, 2015, and January 8, 2016, respectively.
On December 14, 2015, a joint stipulation and recommendation (stipulation) was filed by AEP Ohio, Staff, OEG, OHA, MAREC, OPAE, Buckeye, Sierra Club, FES, Direct Energy, and IGS (collectively, signatory parties). lEU-Ohio filed a letter on December 22, 2015, noting that it does not oppose the stipulation.
By Entry issued December 15, 2015, the attorney examiner established a procedural schedule, including a hearing date of January 4, 2016, in order to assist the Conmrission in its review of the stipulation. The attorney examiner also determined that the briefing schedule should be held in abeyance until otherwise ordered. The evidentiary hearing on the stipulation commenced, as scheduled, on January 4, 2016, and concluded on January 8, 2016. During the evidentiary hearing, AEP Ohio offered the testimony of William A. Allen in support of the stipulation. Testimony in opposition to the stipulation was offered by 11 witnesses: four witnesses for OCC (Noah C. Dormady, Robert B. Fortney, Michael P. Haugh, and James F. Wilson); two witnesses for OMAEG (Edward W. Hill and JohnSeryak); one witness for Dynegy (Dean EUis); one witness for P3 and EPSA (A- Joseph Cavicchi); one witness for ELPC, OEC, and EDF (Karl R. Rabago); one witness for RESA (Stephen E. Bennett); and one witness for the Market Monitor (Joseph E. Bowring). An untimely motion for limited intervention filed by PJM Interconnection, LLC (PJM) on December 28, 2015, was denied by oral ruling during the hearing on January 6, 2016, and as addressed in a subsequent Entry dated January 7, 2016, which invited PJM to file an amicus brief as a non-part}^ An untimely motion to intervene was also filed by Noble Americas Energy Solutions LLC (Noble) on January 12, 2016. On January 22, 2016, Advanced Power Services (APS), Carroll County Energy LLC (CCE), and South Field Energy LLC (South Field) filed a joint motion requesting leave to file a joint amicus brief. Oregon Clean Energy, LLC (Oregon) filed a similar motion on February 1, 2016.
In accordance with the briefing schedule established at the conclusion of the evidentiary hearing on the stipulation, initial and reply briefs were filed by the parties on February 1, 2016, and February 8, 2016, respectively. PJM filed an amicus brief on February 1, 2016. In addition to the briefs, numerous written comments were filed by residential, commercial, and industrial customers; local governments and school districts; community organizations; and other interested stakeholders in response to AEP Ohio's amended application and the stipulation. The majority of the written comments filed in the dockets convey opposition to the PPA rider proposal, although considerable support for the proposal has also been expressed to the Commission.
APP. 380 14-1693-EL-RDR -8- 14-1694-EL-AAM
III. PROCEDURAL MATTERS
A. Motions for Protective Order
On September 11, 2015, OCC, Sierra, and P3/EPSA filed motions for protective order with respect to the confidential versions of the direct testimony of Sarah E. Jackson (OCC Ex. 14), James F. Wilson (OCC Ex. 16), Paul L. Chernick (Sierra Club Ex. 39), and A. Joseph Cavicchi (P3/EPSA Ex. 9). On September 18, 2015, AEP Ohio filed a motion for protective order seeking protection of the confidential versiorxs of the direct testimony of these witnesses. AEP Ohio contends that the redacted testimony, along with certain exhibits and attachments that were included with the testimony, constitutes competitively sensitive and proprietary trade secret information. Specifically, AEP Ohio notes that the redactions pertain to several generating units owned, or partially owned, by AEPGR and the Company's portion of the OVEC assets, as well as information regarding forecasts of future wholesale market energy, capacity, and fuel prices and forecasted costs, including projected costs associated with environmental compliance. AEP Ohio asserts that the information is the product of original research and development by the Company and AEPGR, has been kept confidential, and, as a result, retains substantial economic value to the Company and AEPGR by being kept confidential. According to AEP Ohio, public disclosure would enable third parties to gain information about the costs and operations of the generation units and forecast prices that may impair the Company's ability to sell their output at the best price and weaken the benefits of the proposed PPA, thereby harming the Company and its customers, as well as AEPGR.
On December 28, 2015, OCC and P3/EPSA filed motions for protective order regarding the confidential versions of the direct testin\ony of James F. Wilson (OCC Ex. 35), Robert B. Fortney (OCC Ex. 32), and A. Joseph Cavicchi (P3/EPSA Ex. 13 and 13A), in opposition to the stipulation. On December 30, 2015, AEP Ohio filed a motion for protective order seeking protection of the confidential versions of the direct testimony of these witnesses. According to AEP Ohio, the redacted testimony, along with certain exhibits and attachments that were included with the testimony, constitutes competitively sensitive and proprietary trade secret information for the same reasons noted above.
On February 1, 2016, P3/EPSA filed a motion for protective order with respect to excerpts of its joint initial brief that refer to information contained within the confidential portion of the hearing transcript (Volume III). On February 10, 2016, AEP Ohio filed a motion for protective order, seeking to protect certain trade secret information found in the excerpts in P3/EPSA's initial brief, as well as the confidential portions of the hearing trarrscript (Volumes XXI and XXII), for the same reasons set forth in the Company's earlier motions.
APP. 381 14-1693-EL-RDR -9- 14-1694-EL-AAM
On March 2, 2016, AEP Ohio filed a motion for protective order, along with a request for expedited ruling, which seeks to protect certain trade secret information in Company Exhibits 28-33 and 55; Sierra Club Exhibits 6-7,14, and 39; OMAEG Exhibits 7-9; OCC Exhibit 18; ELPC Exhibits 5-6; lEU-Ohio Exhibit 8; IGS Exhibit 1; the confidential portions of certain hearing transcripts (Volumes IV, V, and XI); and any other designated confidential information not encompassed by a prior motion for protective order or a ruling by the attorney examiners. AEP Ohio asserts that the information constitutes confidential trade secret information for the same reasons addressed in its earlier motions. No memoranda contra were filed with respect to any of the motions for protective order.
The Commission finds that the information that is the subject of the motions for protective order filed by AEP Ohio, OCC, Sierra Club, and P3/ESPA constitutes confidential and proprietary trade secret information. We, therefore, find that the motions for protective order filed by AEP Ohio, OCC, Sierra Club, and P3/EPSA are reasonable and should be granted. Pursuant to Ohio Adm.Code 490l-l-24(F), Company Exhibits 28- 33 and 55; Sierra Club Exhibits 6-7, 14, and 39; OMAEG Exhibits 7-9; OCC Exhibit 18; ELPC Exhibits 5-6; lEU-Ohio Exhibit 8; IGS Exhibit 1; the confidential portions of the hearing transcripts (Volumes III, IV, V, XI, XXI and XXII); the confidential versions of the direct testimony of OCC witnesses Jackson, Wilson, and Fortney, Sierra Club witness Chernick, and P3/ESPA witness Cavicchi; and P3/EPSA's initial brief shall be granted protective treatment for 24 months from the date of this Opinion and Order. Any request to extend the protective order must be filed at least 45 days in advance of the expiration date.
B. Motions and Interlocutory Appeal Regarding Procedural Schedule
In their briefs, RESA, Exelon, P3, and EPSA argue that the Commission failed to adhere to due process requirements during the second phase of these proceedings following the filing of the stipulation. Specifically, RESA, Exelon, P3, and EPSA contend that the established procedural schedule, including the deadlines for discovery, testimony, and briefs, as well as the hearing date, was insufficient and prejudicial to the parties, particularly given the significant importance of these proceedings and the overlapping schedule established in the pending ESP case for Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison Company (collectively, FirstEnergy), Case No. 14-1297-EL-SSO (FirstEnergy ESP Case). RESA, Exelon, P3, and EPSA note that a joint request to modify the procedural schedule and a related interlocutory appeal were filed by some of the opposing parties but were not ruled upon by the Commission, while requests made during the hearing on the stipulation to continue the hearing date and extend the briefing deadlines were summarily denied. RESA, Exelon, P3, and EPSA conclude that the procedural schedule did not afford the parties a fair and ample opportunity to prepare for the second phase of the proceedings, in violation of their due process rights. (RESA/Exelon Br. at 59-62; P3/EPSA Br. at 78-81.) OMAEG also
APP. 382 14-1693-EL-RDR -10- 14-1694-EL-AAM argues that the Commission should have continued both the initial evidentiary hearing and the hearing on the stipulation, particularly given the overlap with the FirstEnergy ESP Case, and that, by declining to do so, the Commission put a severe strain on the parties' resources, narrowed the scope of their ample discovery rights, and limited their ability to thoroughly and adequately prepare for these proceedings, in contravention of their due process rights (OMAEG Br. at 12-14).
AEP Ohio replies that all parties were afforded due process through many days of hearing and voluminous discovery and that there is no evidence that any party has been prejudiced by the procedural schedule (Co. Reply Br. at 122-124).
As RESA, Exelon, P3, and EPSA acknowledge, the procedural schedule for these cases is fully within the Commission's discretion and not subject to a statutory deadline. The Commission is vested with broad discretion to manage its dockets, including the discretion to decide how, in light of its internal organization and docket considerations, it may best proceed to manage and expedite the orderly flow of its business, avoid undue delay, and eliminate unnecessary duplication of effort. Duff v. Pub. Util. Comm., 56 Ohio St.2d 367, 379, 384 N.E.2d 264 (1978); Toledo Coalition for Safe Energy v. Pub. Util. Comm., 69 Ohio St.2d 559, 560, 433 N.E.2d 212 (1982). Likewise, the decision to deny a continuance or to set a specific deadline for filing briefs rests in the Commission's discretion. City of Akron v. Pub. Util. Comm., 5 Ohio St.2d 237, 241, 215 N.E.2d 366 (1966). The Commission finds that the schedule established in these proceedings, including the deadlines for discovery, testimony, and briefs, as well as the dates for both evidentiary hearings, provided the intervenors with a fair and full opportunity to address the issues raised in AEP Ohio's application, as amended, and the stipulation. The Commission, therefore, finds that all requests for an extension of the procedural schedule should be denied and that the attorney examiners properly proceeded with both evidentiary hearings over the objections of certain parties.
In reaching this decision, we note that AEP Ohio filed its initial application in the present cases on October 3, 2014, and its amended application on May 15, 2015, while the original application proposing a PPA rider in the ESP 3 Case was filed more than two years ago on December 20, 2013; the Company responded to over 1,100 data requests, as well as supplemented over 70 data requests upon filing its amended application (Co. Ex. 52 at 11); and there were approximately five weeks of properly noticed evidentiary hearings on the amended application and the stipulation, during which the parties were afforded the opportunity to offer testimony and cross-examine witnesses, followed by the opportunity to present their arguments through initial and reply briefs. Regarding the overlap with the FirstEnergy ESP Case, we note that, in hght of the sheer volume of the Commission's open dockets, it is inevitable that there are multiple proceedings occurring at any given time before the Commission. Although the Commission may, at times, elect to amend the procedural schedule in a pending case to accommodate the schedule in another
APP. 383 14-1693-EL-RDR -11- 14-1694-EL-AAM proceeding, the fact remains that there are cases, such as the present proceedings and the FirstEnergy ESP Case, that are of such significant import, as RESA, Exelon, P3, and EPSA acknowledge, that they must be heard and decided in an expeditious manner and without delay. The record reflects that the attorney examiners were cognizant of the fact that the hearings in both proceedings were occurring at the same time and, in fact, took steps to ensure that the parties were able to participate fully in both proceedings {see, e.g., Tr. VII at 1838-1839). Further, as the parties and their attorneys have demonstrated here and in the FirstEnergy ESP Case, they are clearly competent and knowledgeable with respect to the matters addressed in the amended application and the stipulation, as well as capable of litigating more than one case at the same time. In short, we find that ample due process was provided to all parties and that no party has been prejudiced by the procedural schedule established in these proceedings.
Finally, regarding ELPC's interlocutory appeal, which was filed on December 23, 2015, the Commission notes that the appeal was purportedly taken from the attorney examiners' constructive denial of a joint motion to extend the procedural schedule, as filed on December 16, 2015. We find that ELPC's interlocutory appeal is procedurally improper and should be denied, because it was not filed in response to a ruling issued under Ohio Adm.Code 4901-1-14 or an oral ruling issued during a public hearing or prehearing conference, as required by Ohio Adm.Code 4901-1-15, and is otherwise without merit for the reasons set forth above.
C. Untimely Motions for Intervention
1. PTM
In its brief, OMAEG contends that PJM's request to intervene and file testimony in the^e proceedings should have been granted to enable PJM to develop the record and to assist the Commission in understanding Section III.A.S.a of the stipulation, which addresses oversight of the bidding of the PPA units into the PJM wholesale markets. OMAEG requests that the Commission accept PJM's pre-filed testimony as evidence in the record. (OMAEG Br. at 14-16.)
Noting that PJM has not challenged the denial of its untimely motion to intervene in these proceedings, AEP Ohio asserts that it is inappropriate for OMAEG to challenge a decision affecting another entity's request for intervention, particularly where the affected entity itself has not done so. AEP Ohio adds that PJM did not demonstrate extraordinary circumstances for its untimely request and, in any event, PJM was offered the opportunity to file an amicus brief. (Co. Reply Br. at 124-125.)
As noted above, by Entry dated January 7, 2016, the attorney examiner denied PJM's untimely motion for intervention, which was filed on December 28, 2015.
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Specifically, the Entry noted that PJM did not demonstrate extraordinary circumstances in support of its request to intervene months after the intervention deadline of August 21, 2015, and following the widely publicized and lengthy initial hearing. Additionally, the Entry noted that PJM does not have a unique interest in these proceedings that is not adequately represented by other parties, including the Market Monitor and several wholesale power provider organizations, and that PJM cannot claim that it lacked notice that Commission oversight of AEP Ohio's bidding process would be at issue in these proceedings, given the fact that the Company was directed, in the ESP 3 Case, to include provisions for rigorous Commission oversight of any proposed PPA, including periodic substantive review and audit, and in light of the fact that Company witness Vegas squarely addressed this issue in his initial testimony filed on May 15, 2015, in these proceedings (Co. Ex. 1 at 5). The Entry further noted that, in cases where a stipulation is filed following the deadline for motions to intervene, the Commission has established that the filing of a stipulation that may resolve issues differently than initially proposed, or that expands the issues, does not, alone, constitute extraordinary circumstances warranting untimely intervention. In re Dayton Power & Light Co., Case No. 02-2779-EL-ATA, et al. (DP&L Case), Opinion and Order (Sept. 2, 2003) at 8-9; In re Ohio Power Co. and Columbus Southern Power Co., Case No. 10-2376-EL-UNC, et al.. Opinion and Order (Dec. 14, 2011) at 9-10. Finally, the Entry emphasized that the Commission and Staff regularly rely upon PJM in an open, informal, and collaborative dialogue to exchange data and information regarding its reliabilit}^, transmission planning, and market operation functions, which has assisted the Commission in developing more effective policy outcomes and should continue in the future unhindered by uimecessary litigation. Although PJM's motion for intervention was denied, PJM was invited to file an amicus brief, as a non-party, solely to provide the Commission with information on its operations and clarification of Section III.A.5.a of the stipulation, which PJM filed on February 1, 2016.
The Commission finds that the attorney examiner's decision to deny PJM's untimely request for intervention should be affirmed for the reasons set forth in the Entry dated January 7, 2016, and as summarized above. Further, PJM has not challenged the attorney exairuner's ruling and OMAEG has failed to show that it was prejudiced by the ruling, particularly given that numerous other parties provided substantial testimony with respect to Section III.A.S.a of the stipulation, while PJM was invited to provide, and did provide, its perspective to the Commission through the filing of an amicus brief. We, therefore, deny OMAEG's request to admit PJM's pre-filed testimony into the record and also find that AEP Ohio's motion to strike the testimony, which was filed on December 31, 2015, should be denied as moot.
2. Noble
On January 12, 2016, Noble filed an untimely motion to inter\^ene. Noble is a certified power marketer that sells CRES to mercantile customers in Ohio. Noble is a
APP. 385 14-1693-EL-RDR -13- 14-1694-EL-AAM member of RESA, which is an intervener in these matters. Noble states that, recently, as a result of negotiations surrounding the stipulation filed in these cases, Noble's interest unforeseeably diverged from those of RESA and some of RESA's members. Noble states that, as a result of these extraordinary circumstances, it seeks untimely intervention in these proceedings in accordance with R.C. 4903.221 and Ohio Adm.Code 4901-1-11(F). Noble asserts that it maintains a real and substantial interest in the proceedings and may experience negative economic impacts if the stipulation is approved. Noble notes that other RESA members. Direct Energy and IGS, are signatory parties to the stipulation. Noble accepts the record in these cases as it existed on the date its motion for intervention was filed. On February 8, 2016, Noble filed a reply brief.
On January 18, 2016, AEP Ohio filed a memorandum contra Noble's motion to intervene. AEP Ohio asserts that Noble's motion to intervene should be denied as untimely and unjustified since the deadline for intervention passed several months ago. AEP Ohio states that RESA has represented the interest of its members, including Noble, throughout these proceedings and during the settlement negotiations. AEP Ohio states that Noble, like other RESA members, could have timely filed for intervention to represent its interest directiy. Thus, AEP Ohio avers that Noble's notion of an unforeseeable divergence of interest is inaccurate and contrived. AEP Ohio notes that RESA continues to oppose the stipulation and, as noted in Noble's motion, opposes the same provisions as Noble. In AEP Ohio's opinion. Noble fails to explain why its perspective is any different from other numerous parties opposing the stipulation, including RESA. AEP Ohio contends that Noble's intervention in these matters at this late stage would be unfair and prejudicial to the parties, but particularly to the Company and signatory parties. On February 16, 2016, AEP Ohio filed a motion to strike Noble's reply brief filed on February 8, 2016. Noble filed an untimely memorandum contra the motion to strike on March 7, 2016, and AEP Ohio filed a letter in response on March 9, 2016.
Pursuant to R.C 4903.221, the Commission may, in its discretion, grant a motion to intervene filed after the specified deadline for intervention has passed for "good cause shown." Accordingly, Ohio Adm.Code 4901-1-11(F) provides that an untimely motion to intervene will orUy be granted under "extraordinary circumstances." The established intervention deadline in these matters was August 21, 2015. Noble filed its request for intervention on January 12, 2016, or 144 days after the intervention deadline and after the hearing on the amended PPA application and the hearing on the stipulation had concluded.
Noble offers that its interest unforeseeably diverged from those of RESA and certain RESA members during the course of negotiations on the stipulation. The Commission finds Noble's situation to be foreseeable. Noble, like other RESA members. Direct Energy and IGS, could have sought intervention in these matters to protect its interest directly rather than relying on RESA. As discussed above, the Commission has determined that
APP. 386 14-1693-EL-RDR -14- 14-1694-EL-AAM the filing of a stipulation that may resolve issues differently than initially proposed, or that expands the issues, does not, alone, constitute extraordinary circumstances justifying untimely intervention. DP&L Case, Opinion and Order (Sept. 2, 2003) at 8-9; In re Ohio Power Co. and Columbus Southern Power Co., Case No. 10-2376-EL-UNC, et al.. Opinion and Order (Dec. 14, 2011) at 9-10. In its analysis in the DP&L Case, the Commission reasoned that it should be no surprise to anyone that a case may be resolved by the proposal of a stipulation, which often encompass a variety of issues, and the mere fact that a stipulation may resolve issues differently than initially proposed does not afford an entity the right to intervene beyond the deadline.^ DP&L Case at 8-9.
Further, the Commission notes that RESA witness Bennett offered testimony in opposition to the stipulation and opposes the same provisions Noble discusses in its motion (Tr. XXII at 5582-5583). Noble offers no other reason why its interests may be different from RESA. Thus, we find that Noble has failed to set forth extraordinary circumstances that justify its late intervention. The Commission has frequently denied untimely motions to intervene where no extraordinary circumstances were presented. See, e.g.. In re Ohio Power Co. and Columbus Southern Power Co., Case No. 10-2376-EL-UNC, et al.. Opinion and Order (Dec. 14, 2011) at 9; In re FirstEnergy, Case No. 11-5201-EL-RDR, Opinion and Order (Aug. 7, 2013) at 7-8; In re Greenwich Windpark, Case No. 13-990-EL- BGN, Opinion, Order, and Certiticate (Aug. 25, 2014) at 3-4. For these reasons, the Conmiission denies Noble's untimely request for intervention and, therefore, also strikes Noble's reply brief filed on February 8, 2016.
D. Motions for Leave to File Amicus Brief
On January 22, 2016, as renewed on February 1, 2016, APS, CCE, and South Field filed a joint motion for leave to file a joint amicus brief. APS is an energy development company with two projects in Ohio - one project, CCE, is under construction and the other project. South Field, is in the development stage. The Ohio Power Siting Board (Board) granted CCE a certificate to construct an approximate^ 750 megawatt (MW) combined cycle, natural gas electric generation facility in Carroll County, Ohio, at a cost of $899 rraUion.3 South Field has an application currentiy pending before the Board for a certificate to construct a 1,100 MW combined cycle, natural gas electric generation facility to be located in Columbiana County, Ohio, at a projected cost of over $1 billion.^ On February 1, 2016, APS, CCE, and South Field filed their joint amicus brief.
^ Ultimately, however, the Commission did grant the untimely request for intervention in the DP&'L Case on the basis that the intervener did not receive notice of certain procedures required by a proposed rule relating to the end of the market development period. DP&L Case at 9. 3 In re CCE, Case No. a3-1752-EL-BGN, Opinion, Order, and Certificate (Mar. 9, 2015). ^ In re South Field, Case No. 15-1716-EL~BGN, is an application currently pending before the Board.
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On February 1, 2016, Oregon filed a motion for leave to file an amicus brief. Oregon attached its brief to the motion. The Board issued Oregon a certificate to construct an 800 MW natural gas fueled, combined cycle electric generation facility, in Lucas County, Ohio, at a cost of more than $860 million, with construction expected to commence in 2016.5
Oregon and APS, CCE, and South Field (collectively. Generation Developers) assert that, as developers of unsubsidized new generation facilities of significant size, they bring a unique perspective of the implications of AEP Ohio's PPA application, as modified by the stipulation, which is not offered by any other party to these proceedings. The Generation Developers submit the implications and policy ramifications have only come to light with the filing of the stipulation and Staff's change in its position from opposing AEP Ohio's PPA application to a signatory on the stipulation. Accordingly, the Generation Developers argue the policy implications were not foreseeable in the initial phase of these proceedings. The Generation Developers reason that submission of aiiucus briefs, to be filed consistent with the briefing schedule, will contribute to the full development of the issues and will not unduly prejudice any party. The Generation Developers proffer that the public interest perspective favors granting their requests for leave to file amicus briefs.
On January 27, 2016, AEP Ohio filed a memorandum contra the motion filed by APS, CCE, and South Field for leave to file a joint amicus brief. AEP Ohio did not file a memorandum contra Oregon's motion but addressed the arguments in Oregon's brief in the Company's reply brief. In its memorandum contra, AEP Ohio argues that APS, CCE, and South Field have not demonstrated any real or substantial interest in these proceedings that is not adequately represented by existing parties or stated any reason why they did not seek to participate in a timely manner. AEP Ohio argues that APS, CCE, and South Field were aware of the proceedings prior to January 2016, as they are represented by the same law firm as other intervenors in these matters. The Company asserts that granting the request to allow APS, CCE, and South Field to file a joint amicus brief will unduly prejudice AEP Ohio and the signatory parties.
The Commission has previously found that the decision whether to accept briefs from amici curiae must be based on the individual case at bar and the issues proposed to be addressed by the movant. In re Duke Energy Ohio, Inc., Case No. 12-1685-GA-AIR, et al.. Opinion and Order (Nov. 13, 2013) at 5-6. In this instance, the Commission finds that permitting the Generation Developers to file amicus briefs will not prejudice any part)^ and will assist the Commission in its consideration of the issues. We specifically note that AEP Ohio has addressed the arguments of the Generation Developers in its memorandum
In re Oregon Clean Energy Center, C&se No. 12-2959-EL-BGN, Opinion, Order, and Certificate (May 1, 2013).
APP. 388 14-1693-EL-RDR -16- 14-1694-EL-AAM contra and in its reply brief. Therefore, the Commission finds that the Generation Developers' motions for leave to file amicus briefs are reasonable under the circumstances and should be granted. Although the Commission is allowing the Generation Developers to file amicus briefs, the Generation Developers will not be considered, either collectively or individually, parties to these proceedings, including for purposes of rehearing and appeal, which is consistent with our decision regarding PJM.
E. Evidentiary Rulings
OCC and APJN argue that the Commission should reverse, pursuant to Ohio Adm.Code 4901-1-15(F), certain rulings of the attorney examiners that occurred during the evidentiary hearings. Specifically, OCC and APJN assert that the settlement discussion confidentiality privilege was applied in a blanket fashion that the Ohio Supreme Court has rejected and was well beyond legal bounds, as Ohio Adm.Code 4901-1-26(E) does not require the exclusion of any evidence otherwise discoverable merely because it is presented in the course of compromise negotiations, or require exclusion when the evidence is offered for another valid purpose. OCC and APJN assert that the information that OCC sought to obtain through cross-examination was for the valid purpose of determining whether the Commission's three-part test for consideration of stipulations has been satisfied in the present proceedings. OCC and APJN add that the manner in which the privilege was applied was prejudicial to the non-signatory parties and deprived the Commission of an accurate and complete record. Accordingly, OCC and APJN request that the evidentiary hearing be reopened to allow non-signatory parties to cross-examine witnesses on matters related to the three-part test, consistent with the proper bounds of the settlement discussion confidentiality privilege. (OCC/APJN Br. at 163-167.)
Next, OCC and APJN contend that it was likewise prejudicial to the non-signatory parties for the attorney examiners to quash subpoenas served by OCC on certain signatory parties (i.e.. Sierra Club, Direct Energy, and IGS) to appear and testify during the evidentiary hearing. OCC and APJN argue that the ruling will undermine parties' ability to subpoena important witnesses, which is contrary to their purpose; will allow the signatory parties to determine who files testimony in support of the stipulation, thereby enabling other signatory parties to evade questioning, even where they are not similarly situated; and will effectively prohibit non-signatory parties from conducting any meaningful discovery, as written discovery responses from signatory parties that do not testify will not be part of the evidentiary record. For these reasons, OCC and APJN request that the evidentiary hearing be reopened to allow non-signatory parties to cross- examine the subpoenaed signatory parties. (OCC/APJN Br. at 168-170.) AEP Ohio responds that OCC/APJN's challenge to the evidentiary ruling of the attorney examiners is untimely and misguided. AEP Ohio emphasizes that, in full compliance with the Commission's rules, testimony was presented by Company witness Allen and that OCC had the opportunity to examine him regarding the stipulation. According to AEP Ohio,
APP. 389 14-1693-EL-RDR -17- 14-1694-EL-AAM
requiring parties to a stipulation to produce hearing witnesses merely because they signed a stipulation would establish a poor precedent and have a chilling effect on settlement discussions. (Co. Reply Br. at 120-122.)
Finally, OCC and APJN claim that AEP Ohio witness Allen should not have been permitted to testify about the alleged economic analysis attached to his pre-filed testimony, because he was not qualified to do so. OCC and APJN emphasize that, although Mr. Allen acknowledged that he is not an economist or an expert regarding the economic base model used in the analysis, his testimony was admitted into the record, despite motions to strike raised by OCC and others. OCC and APJN, therefore, request that Mr. Allen's testimony be excluded from the record. (OCC/APJN Br, at 170.)
The Commission finds that the evidentiary rulings of the attorney examiners should be affirmed. First, regarding the confidentiality of settlement discussions, Ohio Adm.Code 4901-1-26(E) provides that evidence of furnishing or offering or promising to furnish, or accepting or offering or promising to accept, a valuable consideration in compromising or attempting to compromise a disputed matter in a Commission proceeding is not admissible to prove liability for or invalidity of the dispute and that evidence of conduct or statements made in compromise negotiations is likewise not admissible. The rule also provides that the exclusion of evidence is not required when the evidence is offered for another valid purpose, which OCC and APJN claim is the case here, as they sought to elicit information on cross-examination relevant to the three-part test used by the Commission to evaluate stipulations. Contrary to OCC/APJN's claims, however, the non-signatory parties were not precluded from asking questions regarding the occurrence of settlement meetings, the individuals in attendance, or other aspects of the bargaining process; questions about the specific provisions in the stipulation or how the)^ may impact ratepayers or the pubhc interest; or questions about the stipulation's effect on important regulatory principles or practices. Rather, as the record reflects, the non-signatory parties were permitted a full and fair opportunity to cross-examine AEP Ohio witness Allen regarding the three-part test during the evidentiary hearing. Mr. Allen was repeatedly directed by the attorney examiner, over objections from AEP Ohio's counsel, to answer questions posed by the non-signatory parties, without divulging the specific details of the settlement negotiations. (See, e.g., Tr. XIX at 4688, 4695.)
Regarding the subpoenas served by OCC on Sierra Club, Direct Energ}', and IGS, the Commission affirms the attorney examiner's ruling to quash the subpoenas (Tr. XXII at 5658-5659). Ohio Adm.Code 4901-1-25 provides that a subpoena may be quashed if it is unreasonable or oppressive. Here, we agree that it would be urrreasonable to establish a precedent, in cases involving a contested stipulation, under which a non-signatory party could compel the testimony of a signatory party witness, or a signatory party could compel the testimony of a non-signatory party witness, seeking to determine the basis for a party's decision to either join or not join the stipulation. We find that such a precedent
APP. 390 14-1693-EL-RDR -18- 14-1694-EL-AAM would have a chilling effect on settlement negotiations in Commission proceedings. Additionally, with respect to testimony in support of a stipulation, Ohio Adm.Code 4901- 1-30(D) requires only that at least one signatory party file or provide supporting testimony. OCC and APJN, in effect, seek to amend the rule. As it stands now, the rule appropriately requires the signatory parties, consistent with their evidentiary burden to support the stipulation, to determine whether testimony from multiple witnesses is necessary or whether the testimony of one witness is sufficient to demonstrate that the stipulation is reasonable and satisfies the Commission's three-part test.
With regard to the economic analysis attached to Mr. Allen's testimony and the attorney examiner's rulings denying several parties' motions to strike the testimony (Tr. VII at 1770-1771, 2060), we note that the Commission has considerable discretion regarding the qualifications of an expert. City of Akron v. Pub. Util. Comm., 5 Ohio St.2d 237, 242, 215 N.E.2d 366 (1966). Mr. Allen's testimony sets forth his significant educational and professional qualifications (Co. Ex. 10 at 1-2) and, although he is not himself an economist, Mr. Allen testified that he directed an economist at American Electric Power Service Corporation (AEPSC) to run the economic model at his request and that he had input into the actual process of running the model, including gathering the necessary data and discussing how to account for various factors (Tr. VII at 1780-1784). In light of his extensive experience as AEPSC's Managing Director oi Regulatory Case Management and his advanced business degree, we find that Mr. Allen is clearly familiar with regulatory filings and was sufficiently knowledgeable to sponsor the results of the model that were attached to his testimony (Co. Ex. 10 at 1-2; Tr. VII at 1800,1805). We, therefore, find that OCC/APJN's claims are without merit and that the attorney examiner's rulings denying the motions to strike Mr. Allen's testimony should be affirmed.
F. Motions to Stay
On March 21, 2016, OCQ APJN, and OMAEG filed a motion to stay these proceedings, pending a ruling on a complaint before the Federal Energy Regulatory Commission (FERC), which was filed by EPSA, RESA, Dynegy, and others on January 27, 2016, in regard to AEP Ohio's proposed affiliate PPA.^ 'oCC, APJN, and OMAEG note that the Supreme Court of Ohio has recognized that there is an apparent unfairness when a decision of the Commission is determined to be unlawful, but customers receive no refund of the charges that have already been collected, due to the prohibition on retroactive ratemaking. OCC, APJN, and OMAEG assert that a stay of these proceedings would avoid such unjust results.
Although OCC, APJN, and OMAEG acknowledge that the Commission has stated that there is no controlling precedent establishing the conditions under which it will sta)^
6 FERC Docket No. EU6-33-000.
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an order, OCC, APJN, and OMAEG point out that the Commission has favored the following four-factor test: whether there has been a strong showing that the movant is likely to prevail on the merits; whether the party seeking the stay has shown that it would suffer irreparable harm absent the stay; where the public interest lies; and whether the stay would cause substantial harm to other parties. In re Commission's Investigation Into the Modification of Intrastate Access Charges, Case No. 00-127-TP-COI, Entry on Rehearing (Feb. 20, 2003) at 5, citing MCI Telecommunications Corp. v. Pub. Util Comm., 31 Ohio St.3d 604, 606, 510 N.E.2d S06 (1987). In support of their motion for a stay of these proceedings, OCC, APJN, and OMAEG argue that they have satisfied the four factors considered by the Commission in determining whether to stay an order. Specifically, OCC, APJN, and OMAEG claim that there is a strong likelihood that the complainants will prevail at FERC on the merits; the collection of unlawful PPA rider charges during the pendency of the complaint would likely cause irreparable harm to AEP Ohio's customers; a stay would further the public interest by providing relief to customers burdened by the state of the economy; and a stay would not cause substantial harm to the Company, given that the PPA rider is revenue neutral to the Company.
AEP Ohio filed a memorandum contra the motion to stay these proceedings on March 23, 2016. According to AEP Ohio, the motion is another strategy of OCC, APJN, and OMAEG to defeat the Company's PPA rider proposal through unnecessary delay. AEP Ohio also contends that the complaint pending before FERC does not provide any grounds to delay the Commission's decision on the stipulation. In particular, AEP Ohio argues that the Commission's decision on the retail rate treatment of the affiliate PPA is not dependent on the pending complaint; the Commission should issue its decision before FERC rules on the complaint; and the complaint provides no basis to delay a decision regarding the OVEC entitlement or the other commitments in the stipulation. Finally, AEP Ohio asserts that neither the four-factor test nor an}' other precedent justifies a stay before the Commission issues an order and, in any event, the motion to stay filed by OCC, APJN, and OMAEG does not satisfy any part of the test. AEP Ohio maintains that it would be improper for the Commission to make findings regarding the likelihood of success of a complaint pending before FERC; potential rate impacts are insufficient to establish irreparable harm; a stay would not further the public interest; and a stay would, in fact, cause great harm to the Company and its parent, AEP. On March 30, 2016, OCC, APJN, and OMAEG filed a reply to AEP Ohio's memorandum contra their motion to stay, which reiterated the arguments raised in the motion.
On March 29, 2016, Noble filed a motion to stay the proceedings^ noting that it fully supports and joins in the motion filed by OCC, APJN, and OMAEG. In support of its motion. Noble argues that AEP Ohio's PPA rider proposal will irretrievably harm the wholesale and retail markets for generation in Ohio. On March 30, 2016, AEP Ohio filed correspondence in response to Noble's motion. AEP Ohio asserts that the motion should
APP. 392 14-1693-EL-RDR -20- 14-1694-EL-AAM be denied for the same reasons included in its memorandum contra the motion to stay filed by OCC, APJN, and OMAEG.
Initially, the Conunission finds that the motions to stay the proceedings, as filed by Noble and OCC, APJN, and OMAEG, are procedurally improper. In support of their request, OCC, APJN, and OMAEG rely solely on the four-factor test. However, as OCC, APJN, and OMAEG acknowledge, the four-factor test has traditionally been used by the Commission to determine whether to stay an order pending appeal. Here, OCC, APJN, and OMAEG, as well as Noble, filed their motions in advance of the Commission's issuance of this Opinion and Order. Noble, OCC, APJN, and OMAEG have essentially requested that the Commission refrain from issuing an order in these proceedings, pending a ruling by FERC on the complaint before it. As discussed above, the Commission has broad discretion to manage its dockets, including how to manage and expedite the orderly flow of its business and avoid undue delay. Duff v. Pub. Util. Comm., 56 Ohio St.2d 367, 379, 384 N.E.2d 264 (1978); Toledo Coalition for Safe Energy v. Pub. Util. Comm., 69 Ohio St.2d 559, 560, 433 N.E.2d 212 (1982). AEP Ohio's amended application has been pending for nearly a year, while the Commission has held two evidentiary hearings and reviewed a voluminous record and post-hearing briefs. As stated above, we find it necessary to decide these proceedings in an expeditious manner and without delay.
We find that Noble, OCC, APJN, and OMAEG's attempts to hamper our discretion, aside from the procedural irregularities, should also be rejected on substantive grounds. Even if we assume that the motion should be considered under the four-factor test, given that we hereby issue our Opiruon and Order, OCC, APJN, and OMAEG have misapplied the test and otherwise failed to satisfy its criteria. Focusing instead on EPSA's likelihood of success before FERC, OCC, APJN, and OMAEG have not shown or even addressed whether they, as the movants, are likely to prevail on the merits, consistent with the first part of the test, through an appeal to the Ohio Supreme Court. With respect to the second factor, the Commission has previously found that potential rate impacts are insufficient to establish irreparable harm. See, e.g.. In re Duke Energy Ohio, Inc., Case No. 12-1685-GA- AIR, et al., Entry (Feb. 19, 2014) at 3-4, 6; In re Columbus Southern Poioer Co. and Ohio Power Co., Case No. 08-917-EL-SSO, et al., Enti-y (Mar. 30, 2009) at 2, 3. Addressing the third factor, OCC, APJN, and OMAEG have again cited potential rate impacts and have not offered any other reason explaining how the public interest favors the extraordinary remedy of a stay. As we find below, the stipulation, as a package, is in the public interest and, therefore, a stay would not be appropriate under the circumstances, as it would delay the significant benefits provided by the stipulation and may cause substantial harm to AEP Ohio's interests. For this same reason, and in light of our denial of Noble's untimely motion to intervene in these proceedings, we find that Noble's motion also lacks merit. Accordingly, the motions to stay the proceedings filed by Noble, OCC, APJN, and OMAEG should be denied.
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IV. DISCUSSION
A. Summary of the Application
In the application, as amended, AEP Ohio requests approval of its proposal to enter into a new affiliate PPA between the Company and AEPGR through which the Company would purchase the output of specific generating units owned wholly by AEPGR or, in part, with Dyneg}^ and The Dayton Power and Light Company (DP&L). AEP Ohio also seeks approval to include the net impacts of the new affiliate PPA in the PPA rider, which the Commission approved on a placeholder basis in the ESP 3 Case. Finally, AEP Ohio requests approval to include, in the PPA rider, the net impacts of the Company's contractual entitlement to a 19.93 percent share of the electrical output of generating units owned by OVEC. As explained in the testimony of AEP Ohio witnesses Vegas and Pearce, the Company proposes to include the following generating units in the PPA rider:
APP. 394 14-1693-EL-RDR -22- 14-1694-EL-AAM
Affiliate PPA Rider Units Plant Location Unit PPA Planned Owner Operator Entitiement Retirement (MW) Year Cardinal Ohio 1 592 2033 AEPGR AEPGR Conesville Ohio 4 339 2033 AEPGR, Dynegy, AEPGR DP&L ConesvUle Ohio 5 405 2036 AEPGR AEPGR Conesville Ohio 6 405 2038 AEPGR AEPGR Stuart Ohio 1 150 2033 AEPGR, Dynegy, DP&L DP&L Stuart Ohio 2 150 2033 AEPGR, D^meg}^ DP&L DP&L Stuart Ohio 3 150 2033 AEPGR, Dynegy, DP&L DP&L Stuart Ohio 4 150 2033 AEPGR, Dynegy, DP&L DP&L Zimmer Ohio 1 330 2051 AEPGR, Dynegy, Dyneg)^ DP&L OVEC PPA Rider Units Plant Location Unit PPA Planned Owner Operator Entitiement Retirement (MW) Year Kyger Ohio 1 40 2040 OVEC OVEC Creek Kyger Ohio 2 40 2040 OVEC OVEC Creek Kyger Ohio 3 40 2040 OVEC OVEC Creek Kyger Ohio 4 40 2040 OVEC OVEC Creek Kyger Ohio 5 40 2040 OVEC OVEC Creek Clifty Creek Indiana 1 40 2040 OVEC OVEC Clifty Creek Indiana 2 40 2040 OVEC OVEC Clifty Creek Indiana 3 _j 40 2040 OVEC OVEC Clifty Creek Indiana 4 40 2040 OVEC OVEC Chfty Creek Indiana 5 40 2040 OVEC OVEC Clifty Creek Indiana 6 40 2040 OVEC OVEC
Additionally, Mr. Vegas testified that the affiUate PPA and the OVEC PPA are designed to stabilize retail rates in AEP Ohio's service area, support economic development in Ohio,
APP. 395 14-1693-EL-RDR -23- 14-1694-EL-AAM protect the reliability of electricity supply, maintain fuel diversity, and protect against the adverse impact of early plant closures on the Ohio economy and the local coimnunities that the plants support. According to Mr. Vegas, the 3,111 MW included in the affitiate PPA and the OVEC PPA, which represents over a third of AEP Ohio's connected retail load, is a significant and reasonable amount of generation to use as a financial hedge to stabilize rates, as required by the Commission in the ESP 3 Case. (Co. Ex. 1 at 12-13; Co. Ex. 2 at 6-7,10; Co. Ex. 13 at 1.)
B. Summary of the Stipulation
As stated previously, a stipulation signed by AEP Ohio, Staff, OEG,^ OHA, MAREC, OPAE, Buckeye, Sierra Club, FES,^ Direct Energy, and IGS was filed on December 14, 2015. The stipulation was intended by the signatory parties to resolve all of the outstanding issues in these proceedings. The signatory parties agree that, for purposes of settlement, the Commission should approve the amended application as filed by AEP Ohio on May 15, 2015, subject to the modifications described in the stipulation.^ (Joint Ex. 1 at 1, 4.) The following is a summary of the stipulation and is not intended to supersede or replace the stipulation:
Additional Terms and Conditions of the PPA Rider (Section lll.A)
Inclusion of a Revised Affiliate PPA in the PPA Rider (Section III.A.l)
The signatory parties agree that it would be prudent for AEP Ohio to sign a revised affiliate PPA, which has been updated as summarized in Attachment A to the stipulation.^^ Consistent with the terms of the PPA rider as approved in the ESP 3 Case and as proposed in the amended application, the signatory parties further agree that the net credits or costs of a revised affiliate PPA should be reflected in AEP Ohio's retail rates by including the revised affiliate PPA in the PPA rider.^^ (Joint Ex. 1 at 4.)
OEG's signature and consent to the stipulation were contingent upon subsequent cUent approval Qoint Ex. 1 at 38). By letter dated December 15, 2015, OEG informed the Commission that OEG had received final client approval and should, therefore, be considered a signatory party on an unconditional basis. FES notes that it has intervened in these proceedings to support the legal and policy determination supporting a Commission-approved PPA rider. FES takes no position with respect to any other issue being settled or litigated in these proceedings. (Joint Ex. 1 at 39.) ^ Sierra Club agrees not to oppose this provision. 10 Sierra Club, Direct Energy, and IGS are not participating in this provision but agree not to oppose it. 11 Sierra Club, Direct Energy, and IGS are not participating in this provision but agree not to oppose it
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Inclusion of OVEC Entitlement in the PPA Rider (Section III. A.2)
The signatory parties agree that the net credits or costs of AEP Ohio's contractual entitlement to a share of the electrical output of generating units owned by OVEC should be reflected in the Company's retail rates by including the OVEC PPA in the PPA rider, as proposed in the Company's amended application.^^ Consistent with page 27 of the Opinion and Order in the ESP 3 Case, AEP Ohio will continue reasonable efforts to explore divestiture of the OVEC asset and report by June 30 annually; however, the signatory parties agree that ongoing inclusion of the OVEC PPA in the PPA rider is not dependent upon a successful divestiture of the OVEC asset. (Joint Ex. 1 at 5.)
Additional PPA Rider Credit Commitment of AEP Ohio (Section III.A.3)
To encourage AEP Ohio to exercise its contractual rights under the revised affiliate PPA to ensure that the PPA units are managed efficiently, cost effectively, and with maximum market profitably, the Company will make the following commitment If, in any of the last four years of the PPA rider, the unadjusted PPA rider results in a charge to customers or a credit to customers that is less than the amount set forth in the table below, AEP Ohio agrees to provide an additional credit to customers, not to exceed the amount set forth in the table below:
Planning Year 2020/2021 $10 Million Planning Year 2021/2022 $20 Million Planning Year 2022/2023 $30 MilUon Planning Year 2023/2024 $40 Million
(Joint Ex. 1 at 5.)
In no event will AEP Ohio provide an additional credit that results in customers receiving a net credit (the sum of the unadjusted PPA rider credit and the additional credit) that exceeds the amount set forth in the table above. For example, if the unadjusted PPA rider credit were S5 million in planning year 2020/2021, then AEP Ohio would provide customers an additional credit of $5 million, resulting in a net credit of $10 million. Alternatively, if, in that same planning year, the unadjusted PPA rider charge were $16 million, then AEP Ohio would provide an additional credit of $10 million to customers, resulting in a net charge of $6 million. To further illustrate, if in that same planning year, the unadjusted PPA rider charge were $5 million, then AEP Ohio would provide an additional credit of $10 million, resulting in a net credit of $5 million. (Joint Ex. 1 at 5-6.)
^2 Sierra Club, Direct Energy, and IGS are not participating in this provision but agree not to oppose it.
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The unadjusted PPA rider value under this provision (Section III.A.3) that is used to determine the level, if any, of a Company-funded credit for a given year shall be calculated without including the cost of the renewable facilities implemented under Section III.I of the stipulation (Joint Ex. 1 at 6).
PPA Rider Mechanism (Section ni.A.4)
The signatory parties agree that the PPA rider will be set based on armual forecasted values subject to quarterly true-ups to reflect actual values, with the initial rider rate being based on a $4 million credit for 2016 (annualized) subject to reconciliation. Consistent with the amended application and supporting testimony, AEP Ohio would flow all revenues and costs relating to the affiliate PPA and the OVEC PPA through the PPA rider. PPA rider credits and charges will be allocated to rate classes/voltage levels (Residential; GS Non-Demand; Secondary; Primary; Sub/Tran; and Lighting) schedules based upon their PJM five monthly coincident peak demands for the prior year. PPA rider costs/credits will be billed to customers through a per kilowatt hour (kWh) charge for each rate class/voltage level. (Joint Ex. 1 at 6.)
Other Contingencies for Continuation of the PPA Rider Recovery (Section III.A.5')
The signatory parties agree that, based on the following conditions and presuming an extension of the ESP 3 term through May 31, 2024, PPA rider recovery will extend through May 31, 2024 (Joint Ex. 1 at 7).
Rigorous Review of the PPA Rider (Section III. A.5.a)
AEP Ohio agrees to participate in armual compliance reviews before the Commission to ensure that actions taken by the Company when selling the, output from generation units included in the PPA rider into the PJM market were not unreasonable. AEP Ohio, not its customers, would be responsible for the adjustments made to the PPA rider based on actions deemed unreasonable by the Conunission, including any costs (after proper consideration of such costs and netting of any bonus payments) associated with performance requirements in PJM's markets. Any determination that the costs and revenues included in the PPA rider are unreasonable shall be made in light of the facts and circumstances known at the time such costs were committed and market revenues wexe received. In addition, the calculation of the PPA rider will be based on the sale of power into PJM. (Joint Ex. 1 at 7.)
Full Information Sharing (Section ni.A.5.b)
AEPGR fleet information on any cost component will be provided pursuant to a reasonable Staff request (as determined by the Commission) as it conducts a
APP. 398 14-1693-EL-RDR -26- 14-1694-EL-AAM reasonableness review of a specific cost component for the generation units included in the affiliate PPA. Staff shall treat any and all such information, regardless of its content, as if it is highly sensitive, proprietary, trade secret information, and critical energy infrastructure information.^^ In addition, as permitted by law, such information shall not be subject to a public information request and shall be protected indefinitely. (Joint Ex. 1 at 7-8.)
Commission Option to Terminate upon Unit Sale (Section III. A.5.c')
AEP Ohio's retail rate recovery from the purchase of wholesale generation from a PPA urut may be extinguished upon the sale or transfer to a non-affiliate of any generation units that are included in the purchase power agreement,^^ if the Commission decides to exclude that unit from the PPA rider based on the circumstances of such transfer or sale.^^ The Commission may also determine that such unit should be maintained in the PPA rider, (Joint Ex. 1 at 8.)
Commitment Reporting (Section III.A.5.d)
AEP Ohio will file an annual compliance report with the Commission by December 31, 2016, and for the remainder of the extended ESP term, confirming that the commitments in Section III of the stipulation are being met (Joint Ex. 1 at 8).
Future Modifications to the Revised Affiliate PPA (Section III.A.6^
The signatory parties agree that, by adopting the stipulation, the Conunission will make no finding as to the prudence of any future modification to a revised affiliate PPA, and the Commission will reserve the right to review the prudence of AEP Ohio agreeing to any such future modification as part of its ongoing oversight of retail rates. AEP Ohio agrees that it will request a Commission determination of the prudence of any future modification to the affiliate PPA. In addition, AEP Ohio would agree to make a voluntary filing to obtain a Commission prudence determination prior to changing depreciation rates under the affiliate PPA. AEP Ohio, not its customers, would be responsible for any
13 Sierra Club is not participating in ttiis provision but agrees not to oppose it. 14 For example, AEP has indicated that it will maintain separate accounting and may decide to transfer the affiliate PPA units into a separate subsidiary in order to facilitate the PPA transaction, which would not trigger operation of Section III.A.S.c. For purposes of this provision and the entire stipulation, an "affihate" of AEP Ohio does not include utility operating companies. 15 Changes among the current owners in the ownership structure of the jointly-owned units, either in whole or in part, while maintaining a comparable level of capacity for the generation station and while avoiding adverse economic impacts for retail customers, shall not be considered a sale for purposes of this provision. Further, if AEP Ohio is successful in divesting the OVEC asset, that outcome will not trigger operation of Section IILA.B.c. Finally, the renewable projects relating to Section III.I will not trigger operation of Section III.A.D.C.
APP. 399 14-1693-EL-RDR -27- 14-1694-EL-AAM increased costs associated with changing depreciation rates if the Commission determines such changes are not prudent. (Joint Ex. 1 at 8-9.)
Federal Advocacy (Section III.B)
AEP Ohio^^ will make the following additional commitments in order to continue to proactively and cooperatively work to improve the PJM markets and advance initiatives that ultimately will benefit retail customers in Ohio (Joint Ex. 1 at 9).
1. Through May 31, 2024, AEP Ohio will advocate in good faith before PJM and FERC for market enhancements such as a longer-term capacity product, and any other market improvements. Before making any such filing, AEP Ohio will inform Staff of its position and the rationale behind it. (Joint Ex. 1 at 9.)
2. Beginning June 1, 2016, and continuing through May 31, 2024, AEP Ohio will provide a public, annual update to the Commission on the state of wholesale electricity markets from the Company's perspective (Joint Ex. 1 at 9).
3. In the event that PJM has not obtained approval for a longer-term capacit}^ product to address state resource adequacy needs by September 1, 2017, the Commission will solicit comments from interested parties no later than October 30, 2017, addressing the state's long-term resource adequacy needs (Joint Ex. 1 at 9).
Extension of ESP 3 Term Through May 31, 2024 (Section III.C)
AEP Ohio will file a separate application with the Commission requesting that its current ESP be extended through the term of the affiliate PPA - that is, until May 31, 2024. AEP Ohio will file this separate application by April 30, 2016. Among other appropriate proposals to be developed as part of the application, AEP Ohio will include the following provisions and features in its application. (Joint Ex. 1 at 10.)
1. A proposal for extension of riders and tariffs relating to the expanded ESP term, including, but not limited to, the terms and conditions for extension of the distribution investment rider (DIR) (Joint Ex. 1 at 10).
2. Any additional funding commitments relating to the expanded ESP term (Joint Ex. 1 at 10).
3. A proposal to extend the competitive bidding process for SSO procurement, including the schedule, auction products, and related matters (Joint Ex. 1 at 10).
^^ The federal advocacy commitments are those of AEP Ohio and not of any other signatory party.
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4. An analysis and proposal relating to the significantly excessive earnings test (SEET) for the extended ESP term (Joint Ex. 1 at 10).
5. An analysis of the statutory MRO comparison test (Joint Ex. 1 at 10).
6. The additional issues under the ESP statute relating to the expanded ESP term (Joint Ex. 1 at 10).
In addition to the foregoing general matters to be addressed in the application to extend the ESP term, AEP Ohio agrees to propose and the signatory parties agree to advocate for approval of (and the non-opposing parties agree to either support or not oppose) the following items as agreed to in the stipulation (Joint Ex. 1 at 10).
7. A provision to extend the interruptible power (IRP) tariff and credit for the full expanded ESP term (i.e., through May 31, 2024) for the current IRP tariff customers as well as 250 MW of additional interruptible load of the signatory parties' members that qualify under the tariff as well as members of non-opposing parties. Further, 150 MW of the additional interruptible load shall be reserved for new businesses locating in the service territory of AEP Ohio. If 100 MW of additional interruptible load subscribes to the IRP tariff during the 12 months immediately following approval of the stipulation, then the IRP tariff shall be increased by an additional 25 MW available to the signatory parties' members. AEP Ohio will also include a provision to increase the IRP credit to $9/kilowatt (kW)-month starting in June 2018 and throughout the remainder of the extended ESP term for any customers that are participating during that time period. The IRP tariff proposal will be updated to reflect the terms of this paragraph including that it will be available to both SSO and shopping customers. (Joint Ex. 1 at 10-11.)
8. A provision to include an automaker credit provision to support increased utilization or expansion of automaker facilities in AEP Ohio's service territory. The automaker credit provision will provide a $lO/megawatt hour credit for all kWh corisumption above the customer's baseline consumption. The baseline will be established based upon the customer's calendar year 2009 annual usage. Total credits under this provision shall not exceed $500,000 armually. Recovery of these credits will be through the economic development rider (EDR). (Joint Ex. 1 at 11.)
9. A provision giving GS-3 and GS-4 customers v^tith interval metering capability the opportunity to opt in to a pilot mechanism under the new basic transmission cost rider (BTCR) based on each eligible customer's single annual transmission coincident peak demand (Joint Ex. 1 at 11).
10. This section of the stipulation is reserved for future use (Joint Ex. 1 at 11).
APP. 401 14-1693-EL-RDR -29- 14-1694-EL-AAM
11. The signatory parties agree that nothing in the stipulation constitutes an amendment of AEP Ohio's existing energy^ efficiency and peak demand reduction (EE/PDR) plan for purposes of the uncodified provisions enacted in 2014 by Senate Bill 310 (S.B. 310) and that nothing in the stipulation affects a customer's opt-out right under R.C 4928.6612, as that provision was enacted in 2014 by S.B. 310. IRP tariff customers may opt out of the opportunity and ability to obtain direct benefits from AEP Ohio's EE/PDR plan as provided in S.B. 310. No account properly identified in the customer's verified notice under R.C. 4928.6612 shall be subject to any cost recovery mechanism under R.C. 4928.66 or eligible to participate in, or directly benefit from, programs arising from EDU portfolio plans approved by the Commission. (Joint Ex. 1 at 11-12.)
12. AEP Ohio will file and advocate for a pilot program that establishes a bypassable competition incentive rider (CIR) as an addition to the SSO non-shopping rate above the auction price with the purpose of incenting shopping and recognizing that there may be costs associated with providing retail electric service that are not reflected in SSO bypassable rates.^^ The total collected from the CIR will then be refunded to all distribution customers through a new rider established in the 2016 ESP amendment case. (Joint Ex. 1 at 12.)
a. AEP Ohio and the signatory parties will meet to determine the charge to include based on a mills per kWh. This will be included in the 2016 ESP amendment case. If the signatory parties cannot agree on an appropriate charge. Staff will choose the final level for inclusion in AEP Ohio's ESP extension filing. (Joint Ex. 1 at 12.)
b. AEP Ohio will file and support approval of a pilot rider to credit the amount collected from the CIR bypassable pilot rider in the 2016 ESP amendment. The rider will provide a credit for all distribution customers using the same rate design associated with the PPA rider. (Joint Ex. 1 at 12.)
c. The charge from the CIR would take effect concurrent with the implementation of the SSO credit rider upon final order of the ESP extension proceeding. Unless otherwise amended by the Commission, the CIR pilot adder shall be in effect through the term of the affiliate PPA recovery sought in the agreement or until new disttibution base rates are put into effect. AEP Ohio will provide an analysis as part of its next distribution rate case to show all of the actual costs required to provide
17 OPAE is not participating in this provision but agrees not to oppose it in this docket.
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SSO generation service that are included in the Company's cost of service study. (Joint Ex. 1 at 12-13.)
13. Aside from the above-listed items, AEP Ohio agrees not to propose any changes relating to the current ESP term (i.e., through May 31, 2018) for the riders and tariffs approved in the Opinion and Order in the ESP 3 Case. In addition, AEP Ohio agrees not to renew proposals for riders or tariffs that were rejected in the Opinion and Order in the ESP 3 Case for both the current ESP term and the extended ESP term (i.e., through May 31, 2024). (Joint Ex. 1 at 13.)
Additional AEP Ohio Conunitments (Section III.D)
1. AEP Ohio will make a shareholder-funded donation of $500,000 to a research and development program for clean energy technology at an Ohio public higher educational institution (Joint Ex. 1 at 13).
2. In a manner that is consistent with AEP Ohio's existing EE/PDR plan and while staying within the currently approved funding levels, AEP Ohio will work with OHA on an annual energy efficiency program targeted at OHA members in the Company's territory. The intent will be to partner with OHA over the term of the affiliate PPA, to encourage and increase OHA members' participation in AEP Ohio's cost effective energ\^ efficiency programs at their facilities. (Joint Ex. 1 at 13.)
a. Provide $400,000 in EE/PDR funding per year through the term of the affiliate PPA, to the OHA to promote and obtain significant participation and energy/demand savings through AEP Ohio's EE/PDR programs amongst its members including Energy Star benchmarking, hospital energy audits, education related to energ}^ efficiency and demand reduction, meetings with hospital facility directors and members of hospital c-suites, and presentations that champion energy efficiency, hospital resilience, and energy-related actions to mitigate climate change, and related issues (Joint Ex. 1 at 13-14).
b. AEP Ohio and OHA will work together to develop and automate Energy Star benchmarking for OHA members in AEP Ohio's certified territory, which will support a broader offering to other customer segments (Joint Ex. 1 at 14).
c. Provide up to $600,000 per year through the term of the affiliate PPA, in additional incentives from EE/PDR funding for contributior^ to qualifying EE/PDR projects under the AEP Ohio program. OHA and AEP Ohio will collaborate to determine the level of funding from this
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pool of dollars to contribute to projects throughout the year to provide an extra incentive for OHA members to implement EE/PDR projects under the AEP Ohio plan. Consideration for the additional incentives should include the size of the facility with a preference for smaller OHA members that have below average Energy Star scores. (Joint Ex. 1 at 14.)
d. AEP Ohio will prioritize circuits with OHA members for any Volt-Var Optimization deployments over the term of the affiliate PPA, when determining the implementation plan. AEP will work with OHA to determine which circuits will be prioritized taking into account the benefit to the circuit in comparison to others and construction/staging considerations. (Joint Ex. 1 at 14.)
e. AEP Ohio will commit to update all Alternative Feed Service rates for OHA members to a uniform $2.50 per kW month (Joint Ex. 1 at 15).
f. AEP Ohio, in collaboration with OHA, will provide a Continuous Energy Improvement program for rural hospitals in AEP Ohio's certified territory with the goal of improving each participating hospital's energy efficiency (Joint Ex. 1 at 15).
OHA's partnership and rights to administer the programs and receive funding under this clause will be contingent upon continued approval and existence of an AEP Ohio EE/PDR plan, approved funding, and any other necessary mechanism to ensure the continued recovery of net lost distribution revenues. OHA will support the approval of budgets and components of the EE/PDR rider, including shared savings at least at their current levels in future filings. (Joint Ex. 1 at 15.)
3. In a manner that is consistent with AEP Ohio's existing EE/PDR plan and while staying within the currently approved funding levels, OPAE will receive $200,000 in 2016 to provide direct assistance with the approved Communit}^ Assistance Program (CAP) within the Company's EE/PDR plan as follows:
a. Design and manage bulk purchasing of refrigerators and other energy efficiency measures where feasible;
b. Provide software and manage temporary data reporting for CAP through March 2016, or until the AEP Ohio Energy Efficiency Customer Platform (EECP) data system is in place;
c.' Provide monitors to administer quality assurance/quality conttol of the CAP; and
APP. 404 14-1693-EL-RDR -32- 14-1694-EL-AAM
d. Manage the training of community action agencies on the AEP Ohio EECP data system used for CAP and other meetings and training initiatives as necessary including the annual Weatherize Ohio conference.
For 2017, OPAE will manage and administer the CAP within AEP Ohio's EE/PDR plan. The program will have an annual budget up to $8,000,000. OPAE will receive a five percent management fee. In addition to overall management of the program, OPAE will continue to provide quality assurance/quality control of the CAP. (Joint Ex. 1 at 15-16.)
OPAE's partnership and rights to administer the program and receive funding under this clause will be contingent upon continued approval and existence of an AEP Ohio EE/PDR plan, approved cost recovery, and any other necessary mechanism to ensure the continued recovery of net lost distribution revenues. OPAE will support the approval of budgets and components of the EE/PDR rider, including shared savings at least at their current levels in future filings. (Joint Ex. 1 at 16.)
4. Upon approval of the stipulation, 50 percent of the EE/PDR rider costs for ttansmission and sub-ttansmission voltage customers will be ttansferred to the EDR through May 31, 2024 (Joint Ex. 1 at 16).
5. Upon approval of the stipulation, 50 percent of the IRP credits from the EE/PDR rider will be ttansferred to the EDR, to more accurately reflect the economic development benefits of these credits charged for demand-metered customers (Joint Ex. 1 at 16).
6. AEP will maintain a nexus of operations (including employees) in Ohio relating to operation and support for the PPA units for the duration of the PPA rider. AEP intends to maintain its corporate headquarters in Columbus, Ohio for the term of the PPA rider. (Joint Ex. 1 at 16.)
7. AEP Ohio agrees to work with Staff and the signatory parties to determine the parameters of a two-year pilot supplier consolidated billing program for any CRES provider that is a signatory party. The purpose of the pilot will be to provide the industry with data and information on the practicality of a supplier consolidated billing implementation in the Ohio electric choice market. (Joint Ex. 1 at 16-17.)
a. The participating CRES provider will agree to assume all EDU bill requirement administtative code rules and work with Staff and the EDU on consumer safeguards, including Ohio Adm.Code Chapter 4901:1-21 (without waiver unless recommended by Staff) (Joint Ex. 1 at 17).
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b. Participating CRES providers agree to provide Staff and the EDU with any and all information related to the pilot (Joint Ex. 1 at 17).
c. Staff, AEP Ohio, and participating CRES providers will meet to determine a methodology to govern the implementation, including, but not limited to, the method of ttansfer and payment to the EDU of customer charges, as well as credit and collection procedures and purchase of receivables without recourse (Joint Ex. 1 at 17).
d. The methodology to govern the pilot shall be established no later than six months from a final order approving a stipulation in these proceedings (Joint Ex. 1 at 17).
e. Due to the nature of a pilot program, the supplier consolidated billing pilot will be limited to 5,000 customers per CRES provider signatory party for the first six months of active implementation (Joint Ex. 1 at 17).
i. Based upon biannual review and appioval by Staff, AEP Ohio, and participating CRES provider signatory parties, the customer participation cap shall be incrementally increased by 5^000 customers each six months not to exceed 20,000 customers for any individual CRES signatory party over the two-year term of the pilot program (Joint Ex. 1 at 17).
ii. Existing customers may remain on the supplier consolidated billing program upon completion of the two-year term of the pilot until otherwise ordered by the Commission (Joint Ex. 1 at 18).
iii. The signatory parties retain the right to petition the Commission to expand the pilot cap or terms pending Commission consideration of future consolidated billing orders (Joint Ex. 1 at 18).
f. Costs related to AEP Ohio's implementation of the pilot supplier consolidated billing program will be shared 50 percent by the CRES provider signatory parties. AEP Ohio's 50 percent share will be eligible for recovery in a future rate proceeding. Staff will study the costs needed to implement the pilot and include an analysis of the type of costs needed to expand the program and how that should be allocated among the providers. (Joint Ex. 1 at 18.)
g. Participating CRES suppliers shall have the ability to bill under the pilot supplier consolidated billing program no later than one year from
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approval of the final Opinion and Order approving a stipulation in these proceedings (Joint Ex. 1 at 18).
h. Participating CRES suppliers shall not prohibit a customer from returning to the EDU consohdated billing (Joint Ex. 1 at 18).
i. Participating CRES suppliers shall not charge a late payment fee greater than the EDU's tariffed late payment fee (Joint Ex. 1 at 18).
j. By the conclusion of the two-year pilot program, Staff shall file a report on the program that shall include recommendations on the program, which may include expansion or retirement (Joint Ex. 1 at 18).
k. Any participating CRES supplier's competitively sensitive information acquired by AEP and Staff under the pilot supplier consolidated billing program shall be afforded the appropriate confidential treatment (Joint Ex. 1 at 19).
8. AEP Ohio will file a proposal for a pilot program in the comments due on January 6, 2016, in Case No. 12-3151-EL-COI. The proposal will be to establish a pilot program in the AEP Ohio service territory providing an EDU third-party agent call transfer process to educate and enroll interested customers moving and initiating service and to establish a procedure for the offering of a standard discount rate providing a guaranteed discount off the price to compare without early termination fees. (Joint Ex. 1 at 19.)
9. With respect to Conesville Units 5 and 6, AEP Ohio and its affiliates make the following commitments (Joint Ex. 1 at 19).
a. By July 1, 2016, AEP Ohio will make a cost recovery filing supporting the conversion of Conesville Units 5 and 6 to natural gas co-firing. These units will be converted by December 31, 2017, subject to approval for cost recovery for AEP Ohio through the PPA rider and any other regulatory approvals. AEP Ohio agrees to use its best efforts to seek Commission approval for cost recovery of co-firing Conesville Units 5 and 6. If the Commission's cost recovery decision is not issued until after January 31, 2017 (the lead time needed for construction), the completion deadline may change commensurately based on the timing of the Commission's actual cost recovery approval decision. (Joint Ex. 1 at 19.)
b. For the period from completion of the co-firing project through December 31, 2029, AEP Ohio and its affiliate owner shall limit the coal heat input to
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no more than 28,737,180 milhon British Thermal Units (MMBTU) per year (annualized for any partial years) combined for both units Conesville 5 and 6. This annual MMBTU limit is 37.5 percent of the unit's design level. AEP Ohio and its affiliates commit that the units will maximize usage of natural gas when it is available and economic. (Joint Ex. 1 at 19- 20.)
c. Conesville Unit 6 will retire, refuel, or repower to 100 percent natural gas by December 31, 2029. If PJM pursues a Rehability Must Run (RMR) arrangement or equivalent mechanism for continued operation of the unit due to the transmission reliability impacts of the retiring of the unit, AEP Ohio and its affiliate will retire, refuel, or repower the unit at the end of such RMR arrangement or equivalent mechanism. Except as provided in Sections III.A.6 (potential depreciation rate change) and IIl.D.lO (Conesville co-firing costs),^^ no costs to retire, refuel, or repower Conesville Unit 6 shall be recovered through the PPA rider. (Joint Ex. 1 at 20.)
d. Conesville Unit 5 will retire, refuel, or repower to 100 percent natural gas by December 31, 2029. If PJM pursues a RMR arrangement or equivalent mechanism for continued operation of the unit due to the ttansmission reliability impacts of the retiring of the unit, AEP Ohio and its affiliate will retire, refuel, or repower the unit at the end of such RMR arrangement or equivalent mechanism. Except as provided in Sections III.A.6 (potential depreciation rate change) and IIl.D.lO (Conesville co- firing costs),^^ no costs to retire, refuel, or repower Conesville Unit 5 shall be recovered through the PPA rider. (Joint Ex. 1 at 20.)
10. AEP Ohio and its affiliates will retire, refuel, or repower Cardinal Unit 1 to 100 percent natural gas by December 31, 2030.^^ If PJM pursues a RMR arrangement or equivalent mechanism for continued operation of the unit due to the ttansmission reliability impacts of the retiring of the unit, AEP Ohio and its affiliate will retire, refuel, or repower the unit at the end of such RMR arrangement or equivalent mechanism. Except as provided in Section ni.A.6 (potential depreciation rate change), no costs to retire, refuel.
^S Through the testimony of AEP Ohio witness Allen on January 6, 2016 (Tr. XX at 4940), as well as letter filed by the Company on January 7, 2016, the Company explained that the reference here to Section IIl.D.lO should actually be to Section III.D.9. ^^ Through the testimony of AEP Ohio witness Allen on January 6, 2016 (Tr. XX at 4940), as well as letter filed by the Company on January 7, 2016, the Company explained that the reference here to Section in.D.W should actually be to Section m.D.9. 20 Buckeye is not participating in Sections IIl.D.lO to III.D.12 of the stipulation.
APP. 408 14-1693-EL-RDR -36- 14-1694-EL-AAM or repower Cardinal Unit 1 shall be recovered through the PPA rider. (Joint Ex. 1 at 20- 21.)
11. With respect to Conesville Units 5 and 6 and Cardinal Unit 1, AEP Ohio and its affiliates make the following commitments. AEP Ohio will open a docket at the Commission no later than December 31, 2024, which it will update annually, known as the "Retirement Readiness" docket. The purpose of the docket will be to identify and timely remove any barriers to retiring, refueling, or repowering Conesville Units 5 and 6 and Cardinal Unit 1 by the dates set forth above. Elements of the "Retirement Readiness" docket will include the following. (Joint Ex. 1 at 21.)
a. AEP Ohio or an independent third party will perform a unit-by-unit load flow analysis by December 31, 2024, to identify any transmission upgrades and/or non-transmission alternatives to allow Cardinal Unit 1, Conesville Unit 5, and Conesville Unit 6 to retire, refuel, or repower on the dates set forth above without negative impacts to reliabilit)' or the need for RMR agreements. Such analysis will: (1) take off-line only Cardinal Unit 1, Conesville Units 5 and 6, and all units that have notified PJM of their intentions to retire on or before December 31, 2029; (2) include new generation that has a signed intercoimection agreement and is scheduled to go into service on or before December 31, 2029; and (3) include ttansmission upgrades that have been approved by the PJM board and have an expected completion date by December 31, 2029. Such analysis will include at least one scenario in which retiring capacity is replaced with 25 percent demand response, 25 percent renewables, and 50 percent non-coal new generation. (Joint Ex. 1 at 21.)
b. By December 31, 2024, AEP Ohio or an independent third party will identify specific transmission upgrades and/or non-ttansmission alternatives that would completely alleviate any identified reliability concerns. AEP Ohio will analyze non-ttansmission solutions to any reliability problems projected to result from the retirement of the units, including energy efficiency, demand response, and disttibuted generation resources. (Joint Ex. 1 at 22.)
c. AEP Ohio or an independent third party will set forth a plan by December 31, 2024, to timely implement the specific ttansmission upgrades and/or non-ttansmission alternatives that would address the reliability concerns, so that each unit can be retired, refueled, or repowered by the dates set forth above. AEP Ohio will include in its implementation plan all cost-effective non-ttansmission solutions identified through this analysis. AEP Ohio will armually update this
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docket to inform the Commission of its progress in implementing its plan. A report documenting the results of such analysis and setting forth a plan for implementing each ttansmission upgrade and non- ttansmission alternative by the retire, refuel, or repower date shall be filed with the Conunission at least four years before the retire, refuel, or repower date for each unit. AEP Ohio agrees to take reasonable steps to implement any necessary ttansmission upgrades or non-ttansmission alternatives, so that each unit can be retired, refueled, or repowered by the dates set forth above. (Joint Ex. 1 at 22.)
d. No ttansmission upgrade costs or non-ttansmission alternative costs associated with the commitments set forth in this section (Section III.D.12) shall be recovered through the PPA rider. The signatory parties retain the right to challenge any proposed transmission upgrades or non- ttansmission alternatives. (Joint Ex. 1 at 22-23.)
12. With respect to the co-owned PPA units (Conesville Unit 4, Zimmer Unit 1, Stuart Units 1 through 4, and the OVEC units), AEP Ohio and its affiliates make the following commitments. AEP Ohio will open a docket at the Commission no later than March 30, 2017, which it will update annually, known as the "Generation Transition" docket. The purpose of the docket will be to identify and remove any remaining barriers to retiring, repowering, or refueling the co-owned units. Elements of the "Generation Transition" docket will include the following. (Joint Ex. 1 at 23.)
a. AEP Ohio will annually report and document in this docket the steps that it and its affiliates have taken to secure retiring, repowering, or refueling to 100 percent natural gas the remaining PPA units with the joint owners (Joint Ex. 1 at 23).
b. If AEP Ohio is not able to get all of the remaining co-owners to commit to retiring, refueling, or repowering the co-owned PPA units in a plan to be submitted by January 1, 2024, AEP will report and document in this docket the steps that it has taken to consolidate ownership interests so that the co-owned units are exclusively owned by a single entity (Joint Ex. Iat23).
c. AEP Ohio or an independent third party will perform a unit-by-unit load flow analysis by December 31, 2020, to identify any ttansmission upgrades and/or non-ttansmission alternatives to: (a) allow Conesville Unit 4, Zimmer Unit 1, Stuart Units 1 through 4, and the OVEC units to retire before their currently planned retirement dates without negative impacts to reliability or the need for RMR agreements; and to
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(b) minimally impact the local communities where coal plants are located by evaluating targeted investments in demand-side energy savings programs, renewables, and other alternative technologies. Such analysis will: (1) take off-line only Conesville Unit 4, Zimmer Unit 1, Stuart Units 1 through 4, the OVEC units, and all units that have notified PJM of their intentions to retire using the same retirement scenarios for the co-owned units outiined below; (2) include new generation that has a signed interconnection agreement and is scheduled to go into sendee using the same retirement scenarios for the co-owned units outlined below; and (3) include ttansmission upgrades that have been approved by the PJM board and have an expected completion date using the same retirement scenarios for the co-owned units outlined below. Such analysis will include at least one scenario is which retiring capacih? is replaced with 25 percent demand response, 25 percent renewables, and 50 percent non- coal new generation. This analysis will be filed as a part of the annual update in 2021 and will include scenarios for retirement of 5 years and 10 years before the currently-plaimed retirement date; for units currently scheduled to operate beyond 2039, the analysis will include scenarios for retirement of 15 years and 20 years before the currently-expected retirement date. (Joint Ex. 1 at 23-24.)
d. AEP Ohio or an independent third party will identify by June 1, 2021, specific ttansmission upgrades and/or non-ttansmission alternatives that would completely alleviate any identified reliability concerns. AEP Ohio must analyze non-ttansmission solutions to any reliabilit}' problems projected to result from retirement of each unit, including energy efficiency, demand response, and disttibuted generation resources. (Joint Ex. 1 at 24.)
e. AEP Ohio will have an independent third party perform an analysis about how to bring or encourage companies to establish renewable energy companies with headquarters and manufacturing plants in Ohio and how to ttansition the current power plant workforce to such job opportunities. AEP Ohio will file this in the 2018 annual update filing. (Joint Ex. 1 at 24-25.)
f. AEP Ohio will publish figures for its current and historic property tax payments to municipalities or local government entities that host the co- owned units, and will conduct a study analyzing how that revenue might be replaced post-retirement (Joint Ex. 1 at 25).
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g. AEP Ohio will publish its current and historic employment figures at the co-owned units, and will conduct a study anatyzing the expected impact to employment from retirement of the co-owned units, and how those jobs might be replaced or relocated (Joint Ex. 1 at 25).
h. AEP Ohio and its affiliates commit to continue to pursue ttansfer or sale of its conttactual entitlement at OVEC and other jointly-owned PPA units. AEP Ohio and its affiliates will periodically file a status report with the Commission on these ttansfers or sales. Nothing in the stipulation limits the right of AEP Ohio or its affiliates to sell any PPA unit, provided that any such sale would be made subject to the commitments made in the stipulation by AEP Ohio and its affiliates and in the bilateral agreement between AEPGR and Sierra Club executed on December 14, 2015. (Joint Ex. 1 at 25.)
i. AEP Ohio will use best efforts to develop a plan with joint owners to retire, repower, or refuel the jointly-owned PPA units, which will be filed in the "Generation Transition" docket no later than June 1, 2024. This plan will incorporate scenarios listed above for potential early retirement (5 years and 10 years and, as applicable, 15 years and 20 years). If the co- owners are not willing to commit to early retirement, repowering, or refueling, AEP will use best efforts to consolidate ownership so that it can further explore potential early retirement scenarios. (Joint Ex. 1 at 25-26.)
j. Except as provided in Section III.A.6 (potential depreciation rate change), no costs to retire, refuel, or repower the co-owned PPA units shall be recovered through the PPA rider. No ttansmission upgrade costs or non- ttansmission alternative costs associated with the commitments set forth in this section (Section III.D.13) shall be recovered through the PPA rider. The signatory parties retain the right to challenge any proposed ttansmission upgrades or non-ttarrsmission alternatives. (Joint Ex. 1 at 26.)
13. In Case No. 13-1939-EL-RDR, AEP Ohio will propose - ti^ough settiement efforts to commence within 90 days of adoption of the stipulation and through a filing in that docket if settlement is not achieved after another 60 days - and use best efforts to pursue approvals for each of the following (Joint Ex. 1 at 26).
a. A proposal to deploy 160 circuits of Volt/VAR Optimization (versus today's potential plan of 80 circuits if the gridSMART stipulation is finalized and approved). Recovery of costs will be through the gridSMART Phase II Rider with no shared savings and no incentive
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return on equity (ROE). More specifically, savings associated with Volt/VAR Optimization will not be counted toward the calculation used to determine the level of shared savings under the current EE/ PDR plan or for purposes of ttiggering the shared savings mechanism but may be counted toward the Company's overall achievement of EE/PDR above and beyond the agreed upon savings benchmarks in Section III.D.16.^^ (Joint Ex. 1 at 26-27.)
b. A provision to file a cost/benefit study for a full deployment of Volt/VAR Optimization equipment on all of its disttibution circuits and substations, including Volt-Amp Reactive power and Conservation Voltage Reduction technology. The cost/benefit study shall be broken down bv disttibution circuit and substation, to determine the total amount of investment that would be cost-effective, (Joint Ex. 1 at 27.)
c. When AEP Ohio files the cost/benefit study, it will also include a proposal for seeking cost recovery of deployment of all cost-effective Volt/VAR technology. AEP Ohio agrees not to seek any additional incentive for installing the equipment or shared savings for any resulting energy savings. If the filing is approved, AEP Ohio agrees to deploy the equipment in a timely manner. (Joint Ex. 1 at 27.)
d. AEP Ohio shall keep the equipment operational during the useful life of the equipment and shall file annual reports with the Commission stating the amount of energy reductions, peak demand reduction, and monetary savings and greenhouse gas emission reductions resulting from this equipment (Joint Ex. 1 at 27).
e. AEP Ohio and Staff agree that they will support Sierra Club's full intervention in Case No. 13-1939-EL-RDR, if the Commission adopts the stipulation without material modification (Joint Ex. 1 at 27).
f. AEP Ohio will use its best efforts to seek approval for the energy and peak demand reductions to be used as a compliance tool under the Clean Power Plan (CPP) (Joint Ex. 1 at 27).
^1 Through the testimony of AEP Ohio witness Allen on January 6, 2016 (Tr. XX at 4938-4939), as well as letter filed by the Company on January 7, 2016, the Company explained that the reference here to Section III.D.16 should actually be to Section III.D.IS.
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14. AEP Ohio agrees, within 90 days of a Commission order adopting the stipulation, to form a working group in conjunction with Staff and other interested parties, to discuss a pilot program for future descending clock default supply auctions where, after the auction is completed but before the market clearing price is announced, energ}^ efficiency providers would be able to competitively bid to supply energy efficiency projects (Joint Ex. 1 at 27-28).
15. AEP Ohio agrees to develop and submit for Commission approval a 2017-2019 EE/PDR plan designed to achieve an energy savings goal of 1.33 percent annually and a demand reduction goal of 0.75 percent annually of baseline energy and demand, respectively, by the end of the plan period. As part of that filing, AEP Ohio agrees to continue its current practice of bidding eligible peak demand reduction achievements into PJM capacity auctions for the 2017-2019 EE/PDR plan, with any capacity revenues shared consistent with existing Commission policy (80 percent to customers and 20 percent retained by the Company). These commitments regarding the 2017-2019 EE/PDR plan filing are contingent upon approval of the 2017-2019 AEP Ohio EE/PDR plan, including funding and any other necessary mechanism to ensure the continued recovery of net lost disttibution revenues. Sierra Club agrees to support the approval of budgets necessary to reach these goals and components of the EE/PDR rider, including shared savings at current approved levels. Nothing in this paragraph affects a customer's opt-out right under R.C. 4928.6612, as that provision was enacted in 2014 by S.B. 310. (Joint Ex. 1 at 28.)
Carbon Emission Reduction Plan (Section IILE)
By December 31, 2016, AEP Ohio will file a carbon emission reduction plan indicating how the Company and its affiliates intend to promote fuel diversification and carbon emission reduction, including an analysis of the economic impact of any proposals for the Commission's consideration. AEP Ohio will incorporate AEP's activities and plans relating to carbon reduction into the filed carbon emission reduction plan. For example, AEP's goals for ttansforrrung its generation fleet (while maintaining 6 percent nuclear generation) include: (1) reducing reliance on coal/lignite generation from 74 percent in 2005 to 48 percent by 2026; (2) increasing natural gas generation from 17 percent in 2005 to 25 percent by 2026; (3) increasing hydro/wind/solar/pumped storage from 3 percent in 2005 to 15 percent in 2026; and (4) increasing energy efficiency/demand response from less than 1 percent in 2005 to 6 percent in 2026. Reliance on resources with higher carbon emissions may be replaced with renewable resources, energy efficiency, and other advanced technologies, including batteries. (Joint Ex. 1 at 28-29.)
Fuel Diversification (Section III.F)
AEP Ohio will implement programs to promote fuel diversity and carbon emission reductions to address potential environmental regulations in the future, including an
APP. 414 14-1693-EL-RDR -42- 14-1694-EL-AAM analysis of the economic impact of any proposals for the Commission's consideration. AEP Ohio will explore programs including the conversion of fuel sources at the PPA units, energy efficiency plans, the closure of the PPA units, and the siting of renewable energy generation. Any programs implemented by AEP Ohio will be subject to the assurance of recovery for prudently incurred costs. (Joint Ex. 1 at 29.)
Grid Modernization (Section IILG)
AEP Ohio will explore avenues to empower consumers through grid modernization initiatives that promote customer choice in Ohio. As part of its June 1, 2016 grid modernization business plan, AEP Ohio will highlight future initiatives, including, but not limited to, the following options:
i. Installing advanced metering infrasttucture.
ii. Investing in Disttibution Automation Circuit Reconfiguration.
iii. Pursuing Volt-VAR Optimization.
iv. Removing obstacles for disttibuted generation.
V. Consulting with Staff on net-metering tariffs.
(Joint Ex. 1 at 29-30.)
AEP Ohio's June 1, 2016 plan will include, but not be limited to, data sharing provisions, subject to customer consent, and full smart grid/meter deployment timelines. AEP Ohio will work with the signatory parties prior to filing the plan. (Joint Ex. 1 at 30.)
Battery Technology (Section III.H)
Contingent on battery resources being eligible for inclusion in rate base in conjunction with the provision of disttibution services, AEP Ohio will include such battery resources in future filings before the Commission (Joint Ex. 1 at 30).
Environmental and Renewable Energy Projects (Section III.P)
1. AEP Ohio and its affiliates will develop a total of at least 500 MW nameplate capacity of wind energy projects in Ohio as follows (Joint Ex. 1 at 30).
a. The indi"^adual projects will be proposed over the course of the next four years, following adoption of the stipulation (Joint Ex. 1 at 30).
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b. AEP Ohio will file EL-RDR applications under the PPA rider to initiate approval for retail cost recovery associated with each project. AEP Ohio agrees to use its best efforts to seek Commission approval for these filings. (Joint Ex. 1 at 30.)
c. AEP affiliates will have the right, based on commercially reasonable terms, to initially own up to 50 percent of such projects on an aggregate net basis based on installed capacity. Ownership details will be established for each project individually. Such projects will be competitively bid. AEP will consult with Staff regarding the process by which projects are selected for advancement. The request for proposal process will be commenced within 45 days of a Commission order adopting the stipulation. Subject to timely regulatory approvals, the projects will coirunence consttuction by the deadline for eligibility of benefits available under the CPP. The projects are not contingent on the CPP taking effect. (Joint Ex. 1 at 30-31.)
d. AEP Ohio will be the buyer of a long-term PPA (i.e., 10 years or longer) for each project, including all capacity, energy, ancillaries, and renewable energy credits produced by the project. Capacity, energy, and ancillary services for all projects will be liquidated into the PJM markets with resulting revenues being credited to retail customers. Renewable energy credits not reserved for compliance will be liquidated into the markets with resulting revenues being credited to retail customers. (Joint Ex. 1 at 31.)
e. The commitment is premised upon AEP Ohio receiving full cost recovery (based on a PPA sttucture) through the PPA rider with details (except for the rate design provided for below) to be determined as part of the separate EL-RDR filing.^ In reviewing such applications, the Commission will consider, among other relevant matters, the economics and proposed PPA price associated with each project, as compared to other available market prices for such projects. (Joint Ex. 1 at 31.)
f. The wind energy projects will be completed by 2021 subject to timely regulatory approvals (Joint Ex. 1 at 31).
^2 Except as explicitly indicated, nothing in this section shall be interpreted to limit the rights of the signatory parties to fully participate or take positions (for or against) in EL-RDR proceedings relating to the terms of any individual project.
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2. AEP Ohio will develop a total of at least 400 MW nameplate capacity for a solar energy project(s) in Ohio, subject to Commission approval and cost recovery (based on a PPA sttucture) through the PPA rider with details (except for the rate design provided for below) to be determined as part of the separate EL-RDR filing. The same approach and parameters described above in Sections Ill.I.l.a through Ill.I.l.e of the stipulation will apply to the solar project(s). In lieu of Section ni.I.l.f that is applicable to the wind energy projects, AEP Ohio and its affiliates will commit to use best efforts to complete the solar energy projects by 2021. In addition, preference will be given to solar projects that are sited in Appalachian Ohio, create permanent manufacturing jobs in Appalachian Ohio, and commit to hiring Ohio military veterans. (Joint Ex. 1 at 31-32.)
3. The rate design to be used for recovery of any net costs or flow through of any net credits associated with both the wind and solar renewable energy projects described above in Sections III.I.l and III.I.2 shall be a uniform per kWh charge for all monthly consumption up to 833,000 kWh per customer account. This rate design shall apply for the life of the projects. (Joint Ex. 1 at 32.)
4. MAREC and its members will support Commission approval of, and full cost recovery for, the wind projects described in the stipulation. AEP Ohio and MAREC will collaborate on siting policy advocacy and advocacy for a reasonable renewable portfolio standard post-S.B. 310 freeze. AEP Ohio agrees to advocate for a reasonable energy efficiency portfolio standard post-S.B. 310 freeze. (Joint Ex. 1 at 32.)
Transition Provision (Section III.D
1. Regarding termination and ttansition of the ESP under R.C. 4928.143(E), the signatory parties agree that the following ordering ttansition must occur under the fourth- year test required by R.C 4928.143(E) (Joint Ex. 1 at 32).
a. Termination shall only be ordered following: (i) the Commission's test of the plan, which shall include consideration of the prospective quantitative and qualitative effects of the remaining term, including the impact of termination on the financial health of AEP OJiio; and (ii) a finding that the results of the test conclude that the remaining term of the ESP is no longer more favorable than an MRO and a finding that the remaining term of the ESP is substantially likely to result in significantly excessive earnings for the Company (Joint Ex. 1 at 33).
b. Termination shall not affect the continued cost recovery under the PPA rider or the DIR (Joint Ex. 1 at 33).
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c. Any additional credits funded by AEP Ohio under Section III.A.3 of the stipulation shall be reflected in the Company's earnings for purposes of the SEET and the MRO test under R.C. 4928.143 (Joint Ex. 1 at 33).
The Three-Part Test for Commission Approval (Section IILKJ
The signatory parties agree^s that the stipulation satisfies the three-part test ttaditionally used by the Commission to consider stipulations. Specifically, the signatory- parties agree that: (a) the stipulation is a product of serious bargaining among capable, knowledgeable parties representing diverse interests; (b) the stipulation does not violate any important regulatory principle or practice; and (c) the stipulation, as a whole, benefits customers and the public interest. (Joint Ex. 1 at 33.)
MRO Test Results (Section III.L)
The signatory parties agree that the stipulation preserves and advances the positive results of the MRO versus ESP test under R.C. 4928.143(C) as found in the Opinion and Order in the ESP 3 Case'^^ (Joint Ex. 1 at 34).
Procedural Matters (Section IV)
A. Recognizing the value of a timely ruling by the Commission to achieve the benefits described in the modified application, the signatory parties urge the Commission to render a decision adopting the stipulation no later than February 10, 2016, in order to capture some of the anticipated financial benefits relating to typically colder months with higher energy prices in early 2016 (Joint Ex. 1 at 34).
B. AEP Ohio will file testimony in support of the stipulation pursuant to the procedural schedule established by the Commission (Joint Ex. 1 at 34).
C Except for enforcement purposes or to establish that the terms of the stipulation are lawful, neither the stipulation nor the information and data contained in the stipulation or attached to the stipulation shall be cited as a precedent in any future proceeding for or against any signatory party, if the Commission approves the stipulation. Nor shall the acceptance of any provision within the settlement agreement be cited by any party or the Commission in any forum so as to imply or state that any signatory party agrees with any specific provision of the settlement. More specifically, no specific element or item contained in or supporting the stipulation shall be consttued or applied to atttibute the results set forth in the stipulation as the results that any signatory party might
^ Sierra Club, Direct Energy, and IGS agree not to oppose this provision. 2"^ Sierra Club is not participating in this provision but agrees not to oppose it.
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support or seek, but for the stipulation in these proceedings or in any other proceeding. The stipulation contains a combination oi outcomes that reflects an overall compromise involving a balance of competing positions, and it does not necessarily reflect the position that one or more of the signatory parties would have taken on any individual issue. Rather the stipulation represents a package that, taken as a whole, is acceptable for the purposes of resolving all contested issues without resorting to litigation. The signatory parties believe that the stipulation, taken as a whole, represents a reasonable compromise of varying interests. (Joint Ex. 1 at 34-35.)
D. If a court of competent jurisdiction invalidates the application of the PPA rider proposal in whole or in part, AEP Ohio will permit any part of the stipulation that has not been invalidated to continue while a good faith effort is made by the signatory parties to restore the invalidated provision to its equivalent value. The signatory parties agree to work in good faith, on an expedited basis not to exceed 60 days, to cure any court- determined deficiency. AEP Ohio will then file (or jointly file with the signatory parties) the modification to the PPA rider, or its successor provision, for expedited approval by the Commission, which approval shall not be withheld if the modified PPA rider, or its successor provision, provides a reasonable remedy to cure the deficiency. AEP Ohio's agreement to permit the stipulated provisions to go into effect in this manner is contingent upon the signatory parties supporting the modified PPA rider, or its successor provision. A signatory party may choose to oppose and express any concerns with the modified PPA rider, or its successor provision, to the Commission; however, if such concerns are not accepted by the Commission, then any signatory party that opposed the modified PPA rider, or its successor provision, will forfeit its stipulated provision(s). This commitment on severability is not intended and shall not be consttued to affect the prohibition against retroactive ratemaking. No amounts collected shall be refunded as a result of this severability provision. (Joint Ex. 1 at 35.)
E. The signatory parties will support the stipulation if the stipulation is contested,25 and no signatory party will oppose an application for rehearing designed to defend the terms of the stipulation (Joint Ex. 1 at 36).
F. The stipulation and AEP Ohio's ongoing commitments under the stipulation presume and are conditioned on an outcome of the rehearing issues pending in the ESP 3 Case and any appeals that affirm the continued existence of the PPA rider and that facilitate the application to extend the ESP 3 term consistent with the terms of the stipulation (Joint Ex. 1 at 36).
G. The stipulation is conditioned upon adoption of the stipulation by the Commission in its entirety and without material modification. Lf the Commission rejects
2^ Sierra Club, Direct Energy, and IGS are not obligated to support the stipulation.
APP. 419 14-1693-EL-RDR -47- 14-1694-EL-AAM or materially modifies all or any part of the stipulation, any signatory party shall have the right within 30 days of issuance of the Comrrussion's order to apply for rehearing. The signatory parties agree that they will not oppose or argue against any other party's application for rehearing that seeks to uphold the original urunodified stipulation. If the Conunission does not adopt the stipulation without material modification upon any rehearing ruling, then within 30 days of such Commission rehearing ruling any signatory party may terminate and withdraw from the stipulation by filing a notice with the Commission. If the Commission does not act upon the application(s) for rehearing in support of the stipulation as filed within 45 days of the filing of the application(s) for rehearing, then any signatory party may terminate its signatory part}-' status by filing a notice with the Commission of its withdrawal from the stipulation, (Joint Ex. 1 at 36.)
H. Unless the signatory party exercises its right to terminate its signatory party status or withdraw as described above, each signatory party agrees to and will support the reasonableness of the stipulation before the Commission, and to cause its counsel to do the same, and in any appeal that it participates in from the Commission's adoption and/or enforcement of the stipulation. ^6 The signatory parties also agree to urge the Commission to accept and approve the terms of the stipulation as promptly as possible.^^ (Joint Ex. 1 at 37.)
I. As set forth in Section III.C of the stipulation, AEP Ohio agrees to file a separate application with the Commission seeking to extend its current ESP to May 31, 2024. AEP Ohio further agrees to include in that application, among other appropriate proposals to be developed, certain provisions and features specified in Section III.C of the stipulation. If the Commission denies AEP Ohio's request to include in its extended ESP any of the provisions and features specified in Section III.C, any adversely affected signatory part}' agrees to work in good faith with the Company to develop new provisions to restore or replace the invalidated provision to its equivalent value and jointly request approval of any new agreed to provisions by the Commission. If such signator}' parties are unable to reach agreement, each of those signatory parties may petition the Commission for appropriate relief limited to the equivalent value of the specific provision that is not included in AEP Ohio's extended ESP. (Joint Ex. 1 at 37.)
J. The parties agree that specific performance is an appropriate remedy for enforcement of the stipulation. The signatory parties acknowledge and agree that specific performance is the only appropriate remedy for any breach of the stipulation, and under
•^^ Whether or not Sierra Club exercises its right to terminate its signatory party status or withdraw as described above. Sierra Club and its counsel are not obligated to support the reasonableness of the stipulation before the Commission. Sierra Club and its counsel agree not to oppose the stipulation before the Commission. ^" Sierra Club agrees not to oppose this provision.
APP. 420 14-1693-EL-RDR -48- 14-1694-EL-AAM no circumstances shall monetary damages be allowed for any breach of the stipulation. In the event any action should be necessary to enforce the terms and conditions of the stipulation, each party shall bear its own attorneys' fees and costs, including the fees and costs of enforcing any judgment. The signatory parties shall receive written notice within 30 days of any alleged breach of the stipulation or its discovery. Upon receipt of any written notice of breach, the signatory party has 30 days to cure the alleged breach. If after 30 days the alleged breach has not been cured to the satisfaction of the signatory party alleging the breach, the signatory party alleging a breach of the stipulation may seek specific performance at the Commission, consistent with this paragraph. (Joint Ex. 1 at 37- 38.)
C Consideration of the Stipulation
As happens in many cases before the Commission, certain parties filed a stipulation, which they specifically describe as the culmination of discussions and accommodation of diverse interests. Ohio Adm.Code 4901-1-30 authorizes parties to Commission proceedings to enter into a stipulation. Although not binding upon the Commission, the terms of such an agreement are accorded substantial weight. Consumers' Counsel v. Pub. Util. Comm., 64 Ohio St.3d 123,125, 592 N.E.2d 1370 (1992), citing Akron v. Puh. Util. Comm., 55 Ohio St.2d 155,157, 378 N.E.2d 480 (1978). This concept is particularly valid where the stipulation is unopposed by any party and resolves all issues presented in the proceeding in which it is offered.
The standard of review for considering the reasonableness of a stipulation has been discussed in a number of prior Commission proceedings. See, e.g., In re Cincinnati Gas & Elec. Co., Case No. 91-410-EL-AIR, Order on Remand (Apr. 14, 1994); In re Western Reserve Telephone Co., Case No. 93-230-TP-ALT, Opinion and Order (Mai. 30, 1994); In re Ohio Edison Co., Case No. 91-698-EL-FOR, et al.. Opinion and Order (Dec. 30, 1993); In re Cleveland Elec. Ilium. Co., Case No. 88-170-EL-AIR, Opinion and Order (Jan. 30,1989); In re Restatement of Accounts and Records, Case No. 84-1187-EL-UNC, Opinion and Order (Nov. 26,1985). The ultimate issue for our consideration is whether the agreement, which embodies considerable time and effort by the signatory parties, is reasonable and should be adopted. In considering the reasonableness of a stipulation, the Commission has used the following criteria:
(1) Is the settlement a product of serious bargaining among capable, knowledgeable parties?
(2) Does the settlement, as a package, benefit ratepayers and the public interest?
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(3) Does the settlement package violate any important regulatory principle or practice?
The Supreme Court of Ohio has endorsed the Commission's analysis using these criteria to resolve cases in a manner economical to ratepayers and public utilities. Indus. Energy Consumers of Ohio Power Co. v. Pub. Util. Comm., 68 Ohio St.3d 559, 629 N.E.2d 423 (1994), citing Consumers' Counsel at 126. The Court stated in that case that the Commission may place substantial weight on the terms of a stipulation, even though the stipulation does not bind the Commission.
As an initial matter, several of the non-signatory parties argue that the stipulation should not be held to the same standard as previously used by the Commission, as many of the components are not germane to the proposed PPA rider and are unrelated to the scope of these proceedings (OCC/APJN Br. at 13-16, 55; ELPC/EDF/OEC Br. at 52-54). However, under the three-prong test, the Commission alwa5^s carefulh^ reviews all terms and conditions of the proposed stipulation, in order to determine whether the stipulation is in the public interest. In making this determination, we exercise our independent judgment, based upon our statutory authority', the evidentiary record, and the Cormnission's specialized expertise and discretion. Monongahela Poioer Co. v. Pub. Util Comm., 104 Ohio St.3d 571, 2004-Ohio-6896, 820 N.E.2d 921,1| 29.
1. Is the settlement a product of serious bargaining among capable, knowledgeable parties?
a. Summary of Parties' Positions
Addressing the first part of the Commission's three-part test, AEP Ohio witness Allen testified that the stipulation is the product of serious bargaining among capable, knowledgeable parties. In support of his position, Mr. Allen explained that he attended settlement meetings held at the offices of the Commission, as well as several meetings with individual parties, which resulted in the stipulation. Mr. Allen further explained that the signatory parties represent a variety of diverse interests, including entities advocating on behalf of low-income customers, commercial customers, industtial customers, competitive retail electtic suppliers, electtic generators, and en^aronmental interests. According to Mr. Allen, the stipulation is the result of a lengthy process of negotiation involving experienced counsel representing members of many stakeholder groups. Specifically, Mr. Allen noted that the parties met with AEP Ohio to discuss areas of potential settlement prior to commencement of the evidentiary hearing on September 28, 2015, and, following the conclusion of the hearing and the extension of the briefing schedule, continued their settlement meetings and communications over a period of several weeks before the stipulation was filed on December 14, 2015. Mr. Allen added that the parties involved in the negotiations were capable and knowledgeable with respect to the issues in these
APP. 422 14-1693-EL-RDR -50- 14-1694-EL-AAM proceedings, particularly in light of the full evidentiary hearing that occurred prior to the last phase of negotiations and the more than 1,100 data request responses served by AEP Ohio. (Co. Ex. 52 at 1-2,10-11,)
Parties opposing the stipulation aver the stipulation cannot meet the first criterion of the test used to evaluate the reasonableness of a stipulation, in light of two side agreements - one agreement between Sierra Club and AEPGR (Sierra Club/AEPGR Agreement) and the other agreement between lEU-Ohio and AEP Ohio (lEU-Ohio/AEP Ohio Agreement). Opposing intervenors primarily cite the lEU-Ohio/ AEP Ohio Agreement. OMAEG and Dynegy state that the terms of the lEU-Ohio/AEP Ohio Agreement were not disclosed to any party during negotiations and that the agreement was only disclosed to all parties, signatory and non-signatory, through discovery after the stipulation was filed with the Commission. Accordingly, parties opposing the stipulation argue the integrity of AEP Ohio's negotiations with other signatory and non-signatory parties has been called into question such that the first component of the test carmot be met. Consumers' Counsel v. Pub, UtiL Comm., Ill Ohio St.3d 300, 2006-Ohio-5789, 856 N.E.2d 213,11 86. (OMAEG Br. at 21-22; Dynegy Br. at 21-24.)
OCC/APJN and OMAEG contend the stipulation cannot comply with the first criterion of the three-part test, as the stipulation fails to include specific details of how AEP Ohio will comply with various provisions of the stipulation, the cost of each provision, primarily co-firing, retiring, and refueling of PPA units, and the rate impacts of each provision. Further, several opposing parties contend various provisions of the stipulation involve issues that do not directiy relate to the PPA rider and evidence a lack of serious bargaining. In addition, OCC and APJN argue that the first prong of the test incorporates a diversity of interest component that this stipulation does not meet. (OCC/ APJN Br. at 13, 32-42, 47-54; OMAEG Br. at 20-23.)
In response, AEP Ohio submits that, unlike the underlying case on which the opposing intervenors rely, lEU-Ohio is not a signatory part}^ to the stipulation. Consumers' Counsel at ^ S6. AEP Ohio emphasizes the lEU-Ohio/AEP Ohio Agreement requires lEU-Ohio to dismiss, withdraw, or limit its participation in several proceedings pending before the Commission and the Ohio Supreme Court, in addition to agreeing not to oppose the PPA stipulation. AEP Ohio notes the lEU-Ohio/AEP Ohio Agreement was provided in discovery and emphasizes the December 22, 2015 letter filed by lEU-Ohio in these dockets acknowledged the existence of the agreement. AEP Ohio argues that there is no basis to find that any party relied upon lEU-Ohio's agreement not to oppose the stipulation or was otherwise prejudiced by the lEU-Ohio/AEP Ohio Agreement. Thus, AEP Ohio contends the arguments asserting the agreement violates the first prong of the test to evaluate the stipulation are without merit. AEP Ohio notes that each of the provisions for which opposing intervenors claim there is insufficient information was the
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subject of a discovery response and could have been explored with Company witness Allen who testified in support of the stipulation. (Co. Reply Br. at 18-29.)
b. Commission Decision
The Commission acknowledges the existence of a side agreement can be relevant to a determination of whether serious bargaining occurred in the negotiation of a stipulation. Consumers' Counsel at % 86. The Sierra Club/AEPGR Agreement was specifically referenced in the stipulation and essentially memorializes the commitments to pursue co- firing or conversion of specified PPA units (OMAEG Ex. 26; Joint Ex. 1 at 25). Therefore, the existence of the Sierra Club/AEPGR Agreement should have been obvious to all parties and the agreement was also provided in the course of discovery. The lEU- Ohio/AEP Ohio Agreement was not referenced in the stipulation and, therefore, the parties may not have known about the agreement. OMAEG and Dynegy state that the terms of the lEU-Ohio/AEP Ohio Agreement were not disclosed to any part)^ during negotiations, although Company witness Allen testified some parties were aware of the lEU-Ohio/AEP Ohio Agreement (Tr. XIX at 4814). In the lEU-Ohio/AEP Ohio Agreement, lEU-Ohio agrees to not oppose the stipulation filed in these cases and agrees to withdraw from several other proceedings pending before the Commission and the Ohio Supreme Court, among other things (OMAEG Ex. 27; P3/EPSA Ex. 11).
The Commission notes that, in Consumers' Counsel v. Pub. Util. Comm., the side agreement was between signatory parties and the side agreement was requested but not provided in discovery. Consumers' Counsel at ^ 86. In this instance, the lEU-Ohio/AEP Ohio Agreement was acknowledged in the letter filed by lEU-Ohio on December 22, 2015, and the lEU-Ohio/AEP Ohio agreement was provided to all parties in the course of discovery (P3/EPSA Ex. 11; OMAEG Ex. 27). Further, AEP Ohio witness Allen testifled that some but not all of the parties were aware of the lEU-Ohio/AEP Ohio Agreement before the stipulation was signed (Tr. XIX at 4814). Most importantly, the Commission notes the lEU-Ohio/AEP Ohio Agreement does not require lEU-Ohio to support or endorse the stipulation and lEU-Ohio is not a signatory party to the stipulation. As such, there is no indication that lEU-Ohio's agreement not to oppose the stipulation unduly influenced another party to these proceedings to sign or not to sign the stipulation. The Commission also emphasizes both the Sierra Club/AEPGR Agreement and the lEU- Ohio/AEP Ohio Agreement were provided in the course of discovery, consistent with R.C. 4928.145 (OMAEG Ex. 26; Co. Ex. 53; P3/EPSA Ex. 11; Tr. XXI at 5186-5188). Further, the Sierra Club/AEPGR Agreement and the lEU-Ohio/AEP Ohio Agreement have not been submitted to the Commission for approval and the Commission will not enforce the terms of the agreements. Thus, in this instance, the Contmission finds the side agreements do not adversely affect whether serious bargaining occurred.
APP. 424 14-1693-EL-RDR -52- 14-1694-EL-AAM
The evidence of record conclusively demonsttates the participation of signatory and non-signatory parties in the negotiation sessions and demonsttates the knowledge and experience of the parties. The Commission also notes the parties participating in these cases are represented by experienced counsel familiar with Commission proceedings. The stipulation was negotiated after weeks of hearings on the Company's amended PPA application where numerous witnesses for AEP Ohio, various intervenors, and Staff offered testimony and were subject to cross-examination. (Co. Ex. 52 at 11; Tr. XXI at 5410- 5411, 5419-5423.)
The Commission finds that it is not necessary that specific details of compliance, costs, and rate impacts for every commitment AEP Ohio agreed to undertake in the stipulation be known, at this time, for the stipulation to comply with the first prong of the test. The value of various provisions in the stipulation exists in AEP Ohio's corrunitment to make an application or filing with the Commission, or another signatory party's agreement to take certain actions, where there is otherwise no legal obligation to do so. Throughout the stipulation, AEP Ohio has agreed to develop the necessary details and file an application with the Commission for review and consideration. The stipulation cannot circumvent the authority of the Conunission and, therefore, we find it reasonable for the stipulation to include provisions where the parties commit to the filing of an application for review by the Commission.
The Commission finds that the stipulation is the product of serious bargaining among capable, knowledgeable parties. All of the parties, including OCC, APJN, OMAEG, and Dynegy, were invited to attend multiple meetings to discuss settlement proposals, and were offered an opportunity to discuss the terms to be included in the stipulation. As AEP Ohio witness Allen testified, the parties in these cases routinely participate in rate matters before the Commission, are capable and knowledgeable with respect to regulatory matters, and are represented by experienced counsel.. Additionally, conttary to OCC/APJN's position, the signatory parties represent a wide variety of diverse interests. Although OCC and APJN did not ultimately sign the stipulation, the interests of residential customers were represented during the settlement negotiations. (Co. Ex. 52 at 1-2,10-11; Tr. XXI at 5419-5421.)
The three-prong test utilized by the Comrrussion and recognized by the Ohio Supreme Court does not incorporate the diversity of interest component, as presented by OCC and APJN. We reject OCC/APJN's attempt to revise the test to evaluate stipulations based on the diversity of signatory parties (OCC Ex. 36 at 2; OCC Ex. 33 at 3). OCC also seeks to hold itself out as the only party speaking for the interests of residential consumers. The Conunission has repeatedly determined that we will not require any single party, including OCC, to agree to a stipulation, in order to meet the first prong of the three-prong test. In re Vectren Energy Delivery of Ohio, Inc., Case No. 13-1571-GA-ALT, Opinion and Order (Feb. 19, 2014) at 10; In re FirstEnergy, Case No. 12-1230-EL-SSO,
APP. 425 14-1693-EL-RDR -53- 14-1694-EL-AAM
Opinion and Order (July 18, 2012) at 26, citing Dominion Retail, Inc. v. The Dayton Poioer and Light Co., Case No. 03-2405-EL-CSS, et al.. Opinion and Order (Feb. 2, 2005) at 18, Entty on Rehearing (Mar. 23, 2005) at 7-8.
However, no particular customer class may be intentionally excluded from negotiations. The Ohio Supreme Court has previously expressed grave concern regarding the adoption of a partial stipulation where the stipulation arose from settlement talks from which an entire customer class was intentionally excluded. Time Warner AxS v. Pub. Util. Comm., 75 Ohio St.3d 229, 233, 661 N.E.2d 1097 (1996). The record in these proceedings demonsttates that representatives of each of the customer classes, including the residential class, participated in the settlement negotiations (Co. Ex. 52 at 1-2,10-11; Tr. at XXI at 5419- 5423). There is no evidence in the record that an entire class of customers was excluded from the settlement negotiations. Furthermore, we note that OPAE is a signatory party to the stipulation. OPAE has described itself to the Commission as a "nonprofit organization representing the interest of over 60 nonprofits providing energy assistance to low income families throughout the state of Ohio" with the purpose "to promote affordable energ}^ policies and preserve access to essential energy services for all Ohioans." In addition, the Commission notes that OPAE members operate bill assistance, weatherization, energy efficiency, and consumer education programs throughout Ohio.^s On that basis, the Commission reasons that OPAE's ultimate clientele is primarily low and moderate-income residential consumers. Further, the Commission has previously considered OPAE an advocate on behalf of low and moderate-income customers. See, e.g., In re FirstEnergy, Case No. 12-1230-EL-SSO, Opinion and Order (July 18, 2012) at 26. Opposing intervenors have failed to offer any reason that the Commission should not regard OPAE in the same marmer in these proceedings. Accordingly, we find that, based upon the record before the Commission, considering that all provisions of the stipulation and the other agreements among certain parties were fully and adequately disclosed, the stipulation is the product of serious bargaining among capable, knowledgeable parties.
2. Does the settlement, as a package, benefit ratepayers and the public interest?
a. Inttoduction
According to the second prong of our three-prong test, the Commission must determine whether the settlement, as a package, benefits ratepayers and the public interest. Although the non-signatory parties have raised numerous concerns regarding the stipulation, we are persuaded that the stipulation, as a package, benefits ratepayers and the public interest. As discussed below, the evidence in the record demonsttates that the
2S In re Commission Revim of Ohio Adm.Code Chapters 4901:1-27 and 4901:1-18, Case No. 03-8S8-AU-ORD, Joint Comments (June 12, 2003) at 4; In re Ohio Department of Development, Case No. 08-658-EL-UNC, Motion to Intervene (July 9, 2008) at 3.
APP. 426 14-1693-EL-RDR -54- 14-1694-EL-AAM stipulation, as modified, contains consumer protections that will protect consumers against rate volatility and price fluctuations by promoting retail rate stability for all ratepayers in this state, modernize the grid through the deployment of advanced technology and procurement of renewable energy resources, and promote retail competition by enabling competitive providers to offer innovative products to serve customers' needs.
b. Summary of Signatory Parties' Positions ^^— ^^— |l *^ v' With respect to the second part of the three-part test, AEP Ohio witness Allen testified that the settlement, as a package, benefits ratepayers and the public interest. Specifically, Mr. Allen explained that the stipulation is designed to provide adequate, safe, reliable, and predictably priced electtic service and to support economic development and job retention in the state of Ohio. Noting that the affiliate PPA and the PPA rider were initially proposed by AEP Ohio to promote retail rate stability and economic development, Mr. Allen testified that, as part of the stipulation, the Company has now proposed a revised affiliate PPA that includes a lower fixed ROE, producing customer savings of $S6 million, and a shorter conttact term, resulting in reduced uncertaint)^ Mr. Allen added that the stipulation includes credits to customers that could amount to up to $100 million during the last four years of the PPA. Finally, Mr. Allen noted that other customer benefits provided by the stipulation include a significant extension of the term of AEP Ohio's current ESP; commitments to advocate at the federal level; proposals to include enhancements to the competitive retail market in Ohio; commitments to enhance energy efficiency programs; commitments to reduce the carbon emissions of power plants in Ohio; commitments to seek to expand wind and solar energy resources by 900 MW in Ohio; and commitments to explore grid modernization. (Co. Ex. 52 at 1,13-14.)
In terms of the estimated impact of the stipulation on customer rates, Mr. Allen testified that, upon implementation, the stipulation is projected to increase residential customer rates by approximately $0.62 per month, or 0.5 percent, for a typical customer using 1,000 kWh per month, with the rates for all other customer classes estimated to either decline or increase by less than 1 percent. Mr. Allen noted that, in combination with AEP Ohio's recently implemented ESP, a residential customer using 1,000 kWh per month will experience a decrease on average of approximately $9 per month as compared to March 1, 2015. Mr. Allen also noted that, over the term of the PPA, customers are forecasted to receive $721 million in net credits from the PPA rider. (Co. Ex. 52 at 14-15, Ex. WAA-2.)
In its brief, AEP Ohio argues that the stipulation satisfies the second part of the three-part test for several reasons. First, AEP Ohio asserts that the evidence reflects that customers are expected to sufficiently benefit from the PPA rider's financial hedging mechanism, with a net financial benefit expected for the period covered by the Company's
APP. 427 14-1693-EL-RDR -55- 14-1694-EL-AAM projections. Specifically, AEP Ohio notes that the record demonsttates that there is a reasonable expectation of a long-term financial benefit from the PPA rider, as supported by the Company's four different scenarios reflecting a range of impacts that load volatilit}' can have on the rider's revenues and costs: a weather normalized load case; a case with a five percent increase in load, compared to the weather normalized case; a case with a five percent decrease in load, compared to the weather normalized case; and a case with an average of a five percent increase and five percent decrease in load for each year. AEP Ohio explains that the five percent higher load and lower load cases were presented to demonsttate the true hedge value of the PPA rider by showing that weather and other load variability factors can have an asynunetric impact on electtic prices, such that, as compared to a given weather normalized case, load shifts up tend to increase prices more so than the price decreases that may result when load shifts down. According to AEP Ohio, its analysis shows that, if load increases due to a sttengthening economy or weather volatility, as experienced during the recent polar vortex, both shopping and SSO customers will be exposed in an asymmettic manner to the resulting higher wholesale prices, which the PPA rider will then partially offset. AEP Ohio concludes that the five percent higher and lower load cases demonsttate the upward potential for customer benefit, while the average net credit calculation of $721 million is a reasonable value to rely upon over the study period as a likely overall result. AEP Ohio also asserts that the PPA rider will protect customers from price volatility and supplement the benefits derived from the staggering and laddering of SSO auctions, which may mask the impact on customers of rising market prices but carmot offset the impacts in the same way as the PPA rider. In sum, AEP Ohio emphasizes that the PPA rider will benefit customers by using a diversified portfolio, sourced from 20 generation units, to provide a cost-based hedge against market prices, which provides a more balanced approach than relying solely on market-based pricing. (Co. Br. at 73-79, 91-98; Co. Reply Br. at 62-65, 74-79.)
AEP Ohio also points out that the use of forwards prices by OCC and other intervenors to project the PPA rider's impact is flawed in a number of ways. In particular, AEP Ohio argues that forwards prices are not a forecast of future spot market prices and do not have any connection to what future spot market prices might actually be; the market for electtic energy forwards is illiquid, except in the short term, and, therefore, cannot provide a sound basis for a long-term forecast; forwards prices do not account for long-term factors such as the impact of the CPP on energy prices in the future; and forwards prices are not available for the latter part of the PPA term. In response to criticism that AEP Ohio used outdated data for its own PPA rider projections, the Company emphasizes that, conttary to certain parties' claims, the 2015 fundamentals forecast was not finalized, released, and available for use when the amended application was filed and that it was, therefore, reasonable for the Company to proceed with the amended application based on the 2013 fundamentals forecast, which Company witness Bletzacker testified is within a band of credibility. Further, AEP Ohio asserts that the load projectioris used in the 2013 fundamentals forecast are reliable and properly account for
APP. 428 14-1693-EL-RDR -56- 14-1694-EL-AAM factors like the CPP and energy efficiency measures, conttary to arguments raised by certain intervenors. (Co. Reply Br. at 65-72.)
Next, AEP Ohio emphasizes that the stipulation provides significant customer benefits, including its modifications to the PPA rider proposal and the combination of both the OVEC PPA and the affiliate PPA in the rider to provide a significant financial hedge for all customers; the additional PPA rider credits of up to $100 million to ensure efficient operations and maximize revenues; the initial $4 million annualized credit and the rider's improved rate design; and the regulatory approvals and reporting commitments, which provide additional protections for customers. AEP Ohio notes that the difference between the amended application's initial variable ROE of 11.24 percent and the stipulation's fixed ROE of 10.38 percent for the shortened term of the PPA proposal yields savings of $86 million for retail customers. AEP Ohio cites the stipulation's commitments regarding the proposed extended ESP filing as additional benefits, particularly the provisions addressing the automaker credit and the CIR pilot program, which are benefits that would not otherwise exist in the absence of the stipulation. Next, AEP Ohio points out that there are numerous provisions regarding grid modernization, carbon reduction and fuel diversification, and battery technology and Volt/VAR Optimization that provide important environmental, energy efficiency, demand reduction, and customer choice benefits that will help ttansform the Company into a utility of the future through significant resource investment in Ohio's energy future and empowerment of customer choice. (Co. Br. at 99-109; Co. Reply Br. at 72-74.)
Further, AEP Ohio notes that it has undertaken certain obligations that uniquely address environmental and renewable energ}' issues and significantly move forward advanced energy development in Ohio, while providing added benefits to the Company's customers, creatively advancing energ)' policy within the state, and facilitating opportunities to positively impact the environment. In particular, AEP Ohio emphasizes that the stipulation addresses the Company's commitment to deploy coordinated conversions of certain coal burning operational units to natural gas or, alternatively, retire or repurpose the coal units over a responsible and reasonable timeframe, which will advance carbon reduction and reduce other environmental impacts of coal use, as well as the Company's commitment to develop a total of at least 500 MW of nameplate capacity of wind energy projects and 400 MW of nameplate capacity of solar energy projects, which would become part of the portfolio of renewable assets within Ohio used to address CPP requirements. Further, AEP Ohio asserts that several provisions of the stipulation promote retail competition and additional customer shopping, including the CIR pilot program, pilot supplier consolidated billing program, and a pilot related to customer enrollments; address beneficial EE/PDR commitments; and provide commitments to proactively and cooperatively work to improve the PJM markets. Again, AEP Ohio emphasizes that many of these provisions provide significant benefits that can only be achieved as a result of the stipulation, while the environmental, renewable energy
APP. 429 14-1693-EL-RDR -57- 14-1694~EL-AAM resource, and energ)^ efficiency provisions have the added benefit of facilitating the state's compliance with the CPP by providing clarity regarding future planning and preserving numerous options for meeting carbon emission targets. (Co. Br. at 109-131; Co. Reply Br. at 80-83.)
OEG emphasizes that the stipulation, as a package, includes several beneficial modifications to AEP Ohio's amended application that are in the public interest. Specifically, OEG notes that the stipulation shortens the PPA term and protects customers from paying retirement-related costs associated with the PPA units; reduces the ROE received by AEPGR from a potential maximum of 15.90 percent to a fixed 10.38 percent, which reduces potential PPA costs by $67.3 million armually, or $539 million over the PPA term; adds a guaranteed $100 million customer credit in the last four years of the PPA; establishes a reasonable cost allocation and rate design for the PPA rider; commits AEPGR to full information sharing with Staff; limits the circumstances under which the PPA's liquidated damages provision would apply and substantially reduces the potential amount of liquidated damages that customers would pay if the provision is ttiggered; and expands the Commission's authorit}' over the PPA rider by expressly recognizing that the Commission can exclude or retain a PPA unit from the rider upon its sale or ttansfer, review the prudence of any future modifications to the PPA, and review the prudence of any depreciation rate changes under the PPA. OEG asserts that these provisions benefit customers by significantly reducing the potential adverse rate impacts associated with AEP Ohio's PPA proposal and expressly recognizing the Commission's authority to engage in rigorous oversight of the PPA and PPA rider. (OEG Br. at 3-6.)
Additionally, OEG contends that the supplemental provisions in the stipulation are aimed at achieving environmental, economic, energy choice, and reliabilit)^ benefits for retail customers and the state and are, therefore, in the public interest. OEG adds that the total package of supplemental provisions in the stipulation is reasonable, particularly given that the Commission will have the opportunity to review and determine whether to approve many of the provisions in subsequent proceedings. Finally, OEG notes that the stipulation provides a preview of several beneficial components of AEP Ohio's next ESP filing, which OEG believes should ultimately be adopted by the Commission in the next ESP proceeding, including the extension and limited expansion of the IRP tariff and the increase in the IRP credit, establishment of the automaker credit to encourage increased production or expansion at automaker facilities, and the ttansmission pilot program that would allocated costs under the BTCR consistent with principles of cost causation. (OEG Br. at 6-11.)
Staff argues that the stipulation must be evaluated as a package and, as such, it includes a number of significant benefits that further the public interest. Staff also emphasizes that the stipulation will ensure that the PPA urtits are managed efficientiy and bid competitively in the PJM markets, while supporting economic development and job
APP. 430 14-1693-EL-RDR -58- 14-1694-EL-AAM retention in the state and facilitating the provision of adequate, safe, and reliable electtic service. With respect to arguments that AEP Ohio will lack incentive to maximize revenues. Staff points out that the Company must work cooperatively with AEPGR to contain costs and that the Company's actions will be subject to the Commission's oversight. With respect to provisions of the stipulation that are not related to the PPA proposal. Staff notes that such provisions seek to provide significant value for ratepayers, such as by aiding low-income families and ensuring reliable electtic service at hospitals, and, in any event, will be subject to subsequent Commission review, which will provide parties with proper due process at that time. (Staff Br. at 7-13; Staff Reply Br. at 4-5, 8,10, 11-12,14-16.)
IGS and Direct Energy assert that the provisions of the stipulation related to the guaranteed discount rate referral program, CIR, supplier consolidated billing program, and grid modernization and expansion of advanced metering will conttibute to the development of the competitive market, enhance customer education regarding retail electtic choice, promote comparable and unbundled rate sttuctures, increase the availability of innovative products and services, and result in direct savings to customers (IGS/Direct Energy Br. at 4-9; IGS/Direct Energy Reply Br. at 5-9). MAREC emphasizes that the provision in the stipulation requiring AEP Ohio to develop at least 500 MW nameplate capacity of wind energy projects in Ohio would provide cost savings to customers through federal renewable energy production and investment tax credits, as well as provide substantial economic benefits through new jobs and local tax payments (MAREC Br. at 2-4).
Buckeye notes that it supports AEP Ohio's PPA proposal, because it advances rate stability by providing a hedge against market volatility and furthering fuel supply diversity, promotes electtic system reliabilit}^ by providing long-term cost support for important coal-fired baseload plants in Ohio, and is economically beneficial to the state by more than $550 milhon annually. Buckeye emphasizes that permitting a portion of AEP Ohio's and AEPGR's generation portfolios to be dedicated to the Company's customers on a ttaditional cost-of-service basis, while relying on the market to serve the remaining portion, is a superior alternative to complete reliance on volatile markets and one that is consistent with Buckeye's own business model, particularly where the goal is to ensure that a sufficient and diverse portfolio of generation resources is in place to meet the requirements of Ohio consumers for reliable and affordable electtic service. Buckeye adds that it prefers to continue its successful joint operation of the Cardinal Station with a partner like AEPGR that has a similar business model and long-term investment philosophy. Further, Buckeye argues that, if the Commission does not approve the PPA proposal, and if AEP Ohio and AEPGR immediately sell or retire their interests in OVEC and the Cardinal Station, the sale or retirement may result in a misalignment of interests between Buckeye and the new owners of the Cardinal Station and OVEC, causing Buckeye to incur sttanded costs related to its significant unamortized investments in the Cardinal
APP. 431 14-1693-EL-RDR -59- 14-1694-EL-AAM
Station and OVEC, respectively; increased costs to Buckeye associated with the termination of AEPGR's operation and maintenance of the Cardinal Station and OVEC units and the provision of back-up power to Buckeye under the Cardinal Station Agreement (CSA); and increased ttansmission costs to Buckeye and its members with no increase in ttansmission reliability. (Buckeye Br. at 6-19.)
OHA asserts that the stipulation sttikes a fair and reasonable balance between the interests of the shareholders of AEP Ohio's parent company and its Ohio customers, because, in exchange for financial stability for the PPA units, the Company's customers will receive the benefits of faster progress towards a cleaner and more energ}^ efficient environment. As specific customer benefits, OHA emphasizes the stipulation's inclusion of provisions addressing AEP Ohio's commitments to file a carbon reduction plan and a grid modernization proposal, including the deplo3?"ment of Volt/VAR Optimization technologies; to retire, refuel, or repower certain PPA units; to develop at least 900 MW of renewable enerev resources; and to enable OHA to continue its work with members on the implementation of cost-effective energ)'. efficiency measures and the reduction of the carbon footprint of hospitals in the Company's service territory. (OHA Reply Br. at 2-3.)
c. Summary of Non-Signatory Parties' Positions
The Market Monitor asserts that the PPA rider should not be approved for a number of reasons. First, the Market Monitor contends that the PPA rider improperly shifts costs and risks from shareholders to customers and distorts competitive incentives in the PJM capacity market. Next, the Market Monitor points out that it is not in the interest of Ohio customers to assume the risks and bear the costs associated with the PPA rider units, given that AEP Ohio does not believe that the units are profitable or expect that market conditions will make them profitable in the future. The Market Monitor also argues that the new PJM capacity market design increases the performance incentives for capacity resources; however, under AEP Ohio's PPA proposal, customers would bear the risks associated with the PPA units' performance and the Company would not have the same incentives to manage the performance of the units, because customers would pay any penalties. (IMM Br. at 2-5.)
Further, the Market Monitor maintains that the PPA rider would create subsidies that are analogous to subsidies that were found to be inconsistent with competition in the PJM wholesale power market design. PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467 (4th Cir. 2014) (Nazarian); PPL EnergyPlus, LLC v. Solomon, 766 F.3d 241 (3d Cir. 2014) (Solomon). Specifically, the Market Monitor notes that the PPA rider would create sttong incentives for AEP Ohio to offer its capacity at less than the competitive offer level, which would have price suppressive effects on the wholesale power markets and make it difficult for other generating units without subsidies to compete or build new generation. Additionally, the Market Monitor asserts that the market paradigm is the preferred
APP. 432 14-1693-EL-RDR -60- 14-1694-EL-AAM approach for providing reliable wholesale power at the lowest possible cost and that the PPA rider is not consistent with the competitive retail and wholesale market design that exists in Ohio. Finally, the Market Monitor notes that PJM and FERC may address the threat posed by the PPA rider through market rule changes, in particular by expanding the minimum offer price rule (MOPR) to include all new and existing generating units that receive subsidies and preventing such units from being offered into the capacity market at less than an unsubsidized competitive offer level. The Market Monitor points out, however, that if AEP Ohio were thereby required to offer the PPA units at the competitive level and the units do not clear in the capacity market, there would be no market revenues and customers would receive no offset to the costs that they would be required to pay under the PPA rider. (IMM Br. at 5-9; IMM Reply Br. at 15-17.)
Dyneg}' also argues that AEP Ohio's PPA proposal, as modified by the stipulation, will distort the wholesale markets and negatively impact the retail market in Ohio. In particular, Dynegy contends that the general wholesale power market concept requires a market design that results in the appropriate incentives and that AEP Ohio's PPA proposal is inconsistent with the market paradigm; the wholesale PJM market has been delivering long-term energy pricing stability, which would be threatened by a return to regulation in Ohio; the PPA proposal is inconsistent with competition in the PJM wholesale power market and will create sttong incentives for the Company to offer the capacity at less than a competitive offer level; and the distortion of wholesale markets results in retail market uncertainty and puts new generating siting at risk. Dyneg\^ further argues that the PPA proposal would also enable AEPGR to unfairly compete against Dynegy and other wholesale merchant generators for years and that Dynegy^'s ownership relationship with AEPGR with respect to the jointiy owned units will be impacted as a result of the PPA, as AEPGR will have a disincentive to make sttategic decisions intended to maximize the profitability of the units. (Dynegy Br. at 8-21.)
Further, Dynegy maintains that the stipulation fails the second part of the three-part test for several other reasons, Dynegy argues that the annual PPA rider credit or charge is an amount that cannot be accurately estimated and will vary significantly from year to year, resulting in unknown market risk for ratepayers that is not justified by any provision of the stipulation; the risk to the competitive markets and the development of new generation in Ohio is not in the public interest; and the risk to ratepayers and the markets is not worth the illusory claim of rate stability, with the quarterly reconciliation process resulting in significant swings in rates, or the other purported benefits of the stipulation that are not related to the PPA rider, which constitute favor ttading and should not be considered by the Commission. Dynegy also contends that neither AEPGR nor OVEC intends to close its plants; additional generation is being developed in Ohio; AEP Ohio has exaggerated the level of wholesale market volatility; and the Company should not be allowed to return the PPA units to a hybrid cost-of-service model at the expense of ratepayers and other merchant generators, which must depend solely on the markets to
APP. 433 14-1693-EL-RDR -61- 14-1694-EL-AAM provide revenue and are harmed when subsidies suppress market prices below adequate or reasonable levels. (Dynegy Br. at 25-32; Dynegy Reply Br. at 5-14.)
RESA, Exelon, P3, and EPSA contend that the PPA proposal in the stipulation is conttary to the second part of the tliree-part test for several reasons. First, RESA, Exelon, P3, and EPSA claim that the PPA proposal was crafted as a subsidy for the PPA plants^ because AEP is advocating for the affiliate PPA as part of its overall business sttategy in pursuit of its own financial interests; only affiliate plants that allegedly are at economic risk were considered for the proposal; the proposal is intended to provide an affiliate with a guaranteed income stteam and profit margin for years; and the proposal will shift market risk, environmental compliance risk, and the risk associated with Capacity Performance penalties from shareholders to ratepayers. RESA, Exelon, P3, and EPSA emphasize that numerous witnesses representing a diverse group of stakeholders testified that the PPA proposal shifts risks to ratepayers and constitutes a subsidy, which AEP Ohio did not refute. (RESA/Exelon Br. at 9-19; P3/EPSA Br. at 53-55.)
Additionally, RESA, Exelon, P3, and EPSA argue that the Commission should continue to support the development of competitive markets, whereas the PPA proposal would move Ohio back toward re-regulation, discourage bidders from participating in the SSO auctions, and deter the development of new gas-fired generation that would be in competition with the subsidized PPA plants. Claiming that AEP Ohio has no prospect of providing ratepayers with a financial hedge, RESA and Exelon also contend that the evidence establishes that AEP Ohio's current retail rates have historically been stable and are likely to decline due to the recent drop in the price of natural gas, which is not reflected in the Company's forecasts. RESA and Exelon urge the Commission to find that the evidence does not demonsttate that the PPA proposal will have the effect of stabilizing rates, as the PPA rider could be either a charge or a credit under AEP Ohio's four projections, which would cause customers' generation charges to fluctuate more than at present. RESA, Exelon, P3, and EPSA also point out that the OVEC portion of the PPA proposal is the same proposal that the Commission rejected, in the ESP 3 Case, on the basis that it was not shown to have the effect of stabilizing retail rates. (RESA/Exelon Br. at 19- 28, 32-36; P3/EPSA Br. at 30-31, 47, 56; P3/EPSA Reply Br. at 31.)
In their reply brief, RESA and Exelon argue that customers do not want or need a Commission-imposed hedge. In particular, RESA and Exelon contend that the SSO auctions are successful, with staggering and laddering resulting in stable rates; CRES offers are not volatile, offer fixed rate conttacts, and have exhibited a downward ttend; and there is sttong opposition to the PPA proposal among diverse customer groups, while the few proponents of the proposal received monetary perks in exchange for their signatures on the stipulation. RESA and Exelon further contend that the PPA rider captures wholesale market volatility and ttansfers it to retail rates. For their part, P3 and EPSA argue that AEP Ohio's threat that the PPA units may close is a political bluff, given
APP. 434 14-1693-EL-RDR -62- 14-1694-EL-AAM that the amended application states that the units may be sold rather than closed; the Company's own witnesses admitted that there is no intention to close the units; and the co-owned units cannot be unilaterally closed by one owTier. (RESA/Exelon Reply Br. at 2- 11,18-19; P3/ESPA Reply Br. at 9-16.)
With respect to the non-PPA terms of the stipulation, RESA and Exelon assert that the Commission's approval of the stipulation, including AEP Ohio's commitments to put forth certain proposals in future proceedings, would be inappropriate, as it covild be consttued as an obligation on the part of the Conimission to approve the programs in those future proceedings. In regard to the provisions addressing the development of wind and solar projects in Ohio and the retiring, refueling, or repowering of certain generating units, RESA and Exelon maintain that the risk associated with these proposals would unreasonably be placed on ratepayers rather than AEP Ohio or shareholders. (RESA/Exelon Br. at 52-55.)
P3 and EPSA contend that multiple terms of the stipulation are simply monetary inducements offered by AEP Ohio in exchange for certain signatory parties' support or non-opposition with respect to the PPA proposal. Other provisions, according to P3 and EPSA, provide minimal benefits, if any, and do not outweigh the concerns associated with the PPA proposal. Finally, P3 and EPSA claim that numerous other provisions are urureasonable or unlawful, as they purport to bind the Conunission (Commission's solicitation of comments addressing the state's long-term resource adequacy needs), are vague (BTCR pilot), discriminate in favor of the signatory parties (CIR and supplier consolidated billing pilot), impermissibly seek to modify the current ESP outside of an ESP case (automaker credit, partial transfer of IRP and EE/PDR costs to the EDR, and ttansition provisions), and inappropriately require cost recover)' through the PPA rider beyond the current ESP and the contemplated extended term for projects that have not been proposed to the Commission (conversion of certain units to natural gas co-firing), (P3/EPSA Br. at 69-76; P3/EPSA Reply Br. at 23-26.)
According to OCC and APJN, AEP Ohio did not sustain its burden to prove that the stipulation is in the public interest, because there is too much ambiguity and uncertainty in the stipulation's terms, such as the resulting rate impact of many of its provisions, and the Company's own estimates reflect that residential customers would pay more under the stipulation than the)' would if only the PPA rider proposal were approved.^^ OCC and APJN also assert that the stipulation's purported benefits are overstated and that the PPA rider as a hedging mechanism is not necessary for customers, will result in increased rate volatility, and is subject to the same considerable uncertainty and potential for consumer
•^^ In their joint initial and reply briefs, OCC and APJN refer to the second part of the three-part test for stipulations as the third part, and vice versa. In summarizing OCC/APJN's arguments herein, we refer to the second and third parts of the test in the proper way.
APP. 435 14-1693-EL-RDR -63- 14-1694-EL-AAM harm that confronted the Commission in the ESP 3 Case. (OCC/APJN Br. at 31-45, 103- 105,154-157; OCC/APJN Reply Br. at 16-19.)
Next, OCC and APJN argue that OCC's own testimony justifies rejection of the stipulation. Specifically, OCC and APJN note that the stipulation's proposed conversion of certain units to gas co-firing lacks sufficient details regarding the cost to consumers; the CIR constitutes an artificial increase to the SSO; cash or cash equivalents were provided to induce certain signatory parties to sign the stipulation, with the costs of these pro\tisions to be recovered from all customers; the development of 900 MW of wind and solar capacity will come at a hefty price for consumers; and the rate design of the PPA rider and the ttansfer of certain costs from the EE/PDR rider to the EDR will not result in reasonable pricing for residential customers. Also, OCC and APJN contend that the PPA proposal would harm customers for numerous reasons. OCC and APJN specifically note that the overall cost of the PPA rider, which is projected by OCC to be at least $1.9 billion (or $1.5 billion on a net present value basis), is substantial; the owners of the PPA units would have no incentive to manage costs or maximize revenues; and the PJM energ)' and capacity markets would be adversely affected through bidding sttategies that could harm AEP Ohio's captive customers. In response to AEP Ohio's criticism of OCC witness Wilson's cost projections, which are based on futures prices, OCC and APJN argue that futures prices are reliable, because they reflect a consensus of market participants' expectations of prices in the coming months and years, including their expectations and forecasts of supply, demand, and price. OCC and APJN add that there is sufficient liquidity in electtic energy forwards and that futures prices incorporate market participants' expectations regarding all relevant supply and demand factors, including the impact of the CPP or other carbon emissions requirements, conttary to AEP Ohio's claims, OCC and APJN also caution that the impact to customers could be much worse than OCC's $1.9 billion projection, which presumes a revenue stteam to offset the PPA units' costs, although there is considerable potential, in light of PJM's recommendations addressed below, that the units are offered into the market at cost but do not clear, resulting in no revenue offset. Further, OCC and APJN argue that the stipulation should not be considered a package under the three-part test, because the stipulation's terms do not have a sufficient nexus to each other and to the application. (OCC/APJN Br. at 45-53, 55-69,101-103,106-112; OCC/APJN Reply Br. at 8-11,16-19, 21-27, 33.)
OMAEG argues that the stipulation will harm ratepayers and the public interest, because, with respect to the PPA proposal, the losses incurred in the operation of the plants covered by the PPA will be passed on to all electticity users in AEP Ohio's service territory, while there could be substantial harm to the competitive markets through price suppressi^'e effects and the deterrence of nev\^ entty. Noting that AEP Ohio has failed to show that the PPA proposal was prompted at the behest of retail customers or that there is significant volatility at the retail level, OMAEG adds that the proposal fails to provide rate stability to customers, as it is based on unreliable and outdated forecasts and utilizes a
APP. 436 14-1693-EL-RDR -64- 14-1694-EL-AAM quarterly reconciliation process. Regarding the non-PPA related provisions, OMAEG contends that the costs associated with the negotiated rate discounts, subsidies, and energy efficienc}' corrmiitments will not be borne b}' AEP Ohio, but instead ^^till be passed on to ratepayers that do not directly benefit. Specifically, OMAEG cites the provisions within the stipulation addressing the conversion of Conesville Units 5 and 6, the supplier consolidated billing program, renewable resources and energ)' efficiency measures, programs involving OPAE and OHA, and the expansion of the IRP tariff as provisions that are intended to benefit the narrow interests of the signatory parties to the dettiment of other customers or groups, or ratepayers as a whole. (OMAEG Br. at 23-25, 54-61; OMAEG Reply Br. at 13-16, 21-22.)
Asserting that the PPA proposal is more burden than benefit, Walmart argues that the revised affiliate PPA improperly shifts risk from an unregulated affiliate to AEP Ohio's customers. Walmart also contends that the PPA proposal will inflict extensive costs on customers, including significant penalties if a unit is removed from the PPA; is based on outdated projections that overstate the potential revenue benefits of the PPA; and lacks an evidentiary basis for anything other than speculative customer benefits. Additionally, Walmart maintains that the PPA proposal provides AEP Ohio and AEPGR with cost recovery tteatment that is ttaditionally afforded to vertically integrated utilities, without providing the Company's customers with the protections of regulator}' oversight, given that the Commission would have no authority to modify the PPA, once it is approved, and would instead be limited to an after-the-fact review of the Company's actions. (Walmart Br. at 3-10.)
Kroger contends that the revised affiliate PPA does not benefit ratepayers and is conttary to the public interest, because it would force customers to subsidize AEPGR's generation units for years. According to Kroger, if AEPGR were confident in AEP Ohio's projections for the PPA rider, it would accept the burden of potential short-term losses in order to reap the projected long-term gains. Kroger believes that the PPA rider is likely to result in a net negative proposition for customers for a number of years. Kroger also notes that, even with the stipulation's proposed risk sharing mechanism, customers would unfairly assume the complete risk of losses in the early years of the PPA, which are projected to be the least favorable for customers. (Kroger Br. at 2-4; Kroger Reply Br. at 1.)
According to ELPC, OEC, and EDF, AEP Ohio has failed to show that the PPA rider or the stipulation as a whole will benefit ratepayers or the public interest. Initially, ELPC, OEC, and EDF assert that the PPA rider poses a significant risk of high costs to ratepayers and that AEP Ohio's projected rate impact should not be relied upon by the Commission, as it is based on an outdated market price forecast from 2013 that likely overestimates future energy prices. ELPC, OEC, and EDF add that the 2013 forecast is inconsistent with both AEP Ohio's 2015 market price forecast, which predicts on-peak energy and natural gas prices that are significantly lower, as well as current market expectations, which reflect
APP. 437 14-1693-EL-RDR -65- 14-1694-EL-AAM energy and natural gas prices that are even lower than the 2015 forecast. ELPC, OEC, and EDF assert that the evidence indicates that the PPA proposal, as amended by the stipulation, may result in $1.6 to $1.9 billion in costs for customers, including hundreds of millions in costs over the next few years when the parties' forecasts offer the greatest certainty. ELPC, OEC, and EDF further assert that AEP Ohio's projections are inherently flawed. In particular, ELPC, OEC, and EDF claim that the 2013 market price forecast is based on assumed load levels that are higher than are actually likely to occur, in light of energy efficiency measures that will be implemented to comply with the CPP and the stipulation, as well as the requirements of R.C. 4928.66. They further claim that the 2013 forecast is inconsistent with AEP Ohio's own view of forecasted customer energy usage, as confirmed by the Company's long-term forecast reports filed with the Commission in 2013 and 2015, which indicate that total load projections have dropped by more than four percent for each year from 2015 through 2023. Finally, ELPC, OEC, and EDF point out that the 2013 market price forecast does not reflect the significant potential for Capacity Performance penalties. (ELPC/OEC/EDF Br. at 16-27.)
Regarding AEP Ohio's continued reliance on the 2013 market price forecast, ELPC, OEC, and EDF note that the Company incorporated a number of updates to its PPA rider projections over the course of these proceedings to account for new information, such as capacity price auction results, and offered no evidence that it could not re-run its dispatch model based on the 2015 market price forecast, particularly in connection with its filing of amended rider projections in December 2015 to account for the stipulation's modifications. ELPC, OEC, and EDF also note that AEP Ohio criticized intervenor forecasts of its prior PPA rider proposal, as put forth in the ESP 3 Case, for failing to utilize up-to-date information, including the most recent available price forecasts. Further, ELPC, OEC, and EDF point out that FERC and other state commissions have rejected utilities' attempts to rely on outdated information. ELPC, OEC, and EDF conclude that the Commission cannot reasonably rely on AEP Ohio's PPA rider projections, in light of the significant record evidence showing a downward ttend in market prices that the Company itself believes will persist over the term of the proposed PPA rider. (ELPC/OEC/EDF Reply Br. at 10- 15.)
Additionally, ELPC, OEC, and EDF argue that the costs associated with the PPA units are likely to be higher than projected, because AEP Ohio omitted projected compliance costs or even any quantitative description of potential costs for several environmental regulations that are likely to affect the units by 2024, as well as provided incomplete cost estimates for other applicable pending or current environmental regulations, which could directly offset the net PPA revenues flowing to customers and also render the units less econoirdc in the PJM supply stack, reducing their potential market revenues. ELPC, OEC, and EDF also maintain that AEP Ohio's failure to conduct a competitive procurement process or otherwise weigh the potential costs of alternative hedging mechanisms, including energy efficiency measures, undermines the
APP. 438 14-1693-EL-RDR -66- 14-1694-EL-AAM reasonableness of the PPA proposal and provides no basis for the Commission to determine that the PPA with AEPGR is a prudent affiliate deal for the alleged customer benefits that it will provide. (ELPC/OEC/EDF Br. at 27-38; ELPC/OEC/EDF Reply Br. at 15-17.)
Further, ELPC, OEC, and EDF contend that AEP Ohio has not demonsttated that the PPA rider offers customer benefits that outweigh the expected costs, specifically noting that the Company has not shown that retail customers are exposed to significant or unwanted short-term price volatility that is not already mitigated through fixed price conttacts or the staggering and laddering of SSO auctions, or that the PPA rider would provide an effective hedge. According to ELPC, OEC, and EDF, neither has AEP Ohio offered any evidence, other than its flawed 2013 market price forecast, that market prices are expected to steeply rise over the next eight years, exposing retail customers to long- term price volatiiit)', or that customers lack tools to address such volatilit}', such as energ}' efficiency measures and installation of behind-the-metei generation. ELPC, OEC, and EDF emphasize that AEP Ohio has not shown that the PPA rider will benefit customers by conttolling the alleged long-term retail price volatilit}' that the Company claims is not sufficiently mitigated by existing mechanisms. ELPC, OEC, and EDF add that, if the PPA rider is approved, energy efficiency and demand response resources, which typically benefit customers by lowering wholesale market prices through reduced peak loads, may come to harm customers by lowering the revenues received by the PPA units, which would present a dilemma in the Commission's consideration of future EE/PDR programs. (ELPC/OEC/EDF Br. at 38-46; ELPC/OEC/EDF Reply Br. at 17-18.)
Finally, ELPC, OEC, and EDF argue that AEP Ohio's contention that the PPA units are likely to retire, due to low PJM energy and capacity prices, is contradicted by the record, which reflects that PJM's new Capacity Performance requirements have increased capacity prices significantly; there is no e^adence that reliability in PJM is at risk, with significant amounts of new generation being developed, and exceeding retirements, in Ohio and throughout PJM; the Company's projected ttansrrussion costs, which would occur in the event of the PPA units' retirement, are irrettievably flawed, as they are based on the unrealistic assumptions that all of the PPA units will retire in 2019 at the same time and simultaneously with the retirement of 11,800 MW of other generation in PJM, due to the CPP, but with no new generation factored in to replace it; the Company's analysis of the economic development benefits associated with the PPA rider is incomplete, because it does not address the effect of plant retirements on electtic prices as the Commission required in the ESP 3 Case; and the non-PPA related provisions in the stipulation do not merit any significant weight in the Commission's determination of the stipulation's benefits, as many of the provisions only require the Commission to make a future filing with no guarantee of a beneficial outcome, while other provisions bind the Commission in significant ways or involve benefits that would occur even without the stipulation. (ELPC/OEC/EDF Br. at 46-54.)
APP. 439 14-1693-EL-RDR -67- 14-1694-EL-AAM
In its reply brief, lEU-Ohio asserts that the arguments of ELPC, OEC, EDF, and OMAEG regarding the IRP provisions of the stipulation are premature at this point, given that the merits of the provisions are not before the Commission in these proceedings. lEU-Ohio adds that, in any event, the arguments of ELPC, OEC, and EDF should be rejected because they are incorrect and would reduce customer incentives to make demand response available to AEP Ohio for the benefit of system reliability, while OMAEG's arguments are internally conttadictory and unsupported. lEU-Ohio points out that OMAEG claims that non-signatory parties should have access to the expanded IRP program, but also contends, without record support, that the proposed expansion of the program would be too costly. (lEU-Ohio Reply Br. at 3-8.)
d. Commission's Factors
In the ESP 3 Case, the Commission authorized AEP Ohio, pursuant to R.C. 4928.143(B)(2)(d), to establish a zero placeholder PPA rider and enumerated a number of factors to be considered in the evaluation of any future PPA rider filing seeking cost recovery. Specifically, the Commission directed AEP Ohio to address, at a minimum, the financial need of the generating planti the necessit)' of the generating facility, in light of future reliability concerns, including supply diversity; a description of how the generating plant is compliant with all pertinent environmental regulations and its plan for compliance with pending environmental regulations; and the impact that a closure of the generating plant would have on electtic prices and the resulting effect on economic development within the state. The Commission further directed AEP Ohio, in its PPA rider proposal, to provide for rigorous Commission oversight of the rider, including a proposed process for a periodic substantive review and auditi commit to full information sharing with the Commission and its Staff; include an alternative plan to allocate the rider's financial risk between both the Company and its ratepayers; and include a severability provision. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 25-26.
i. Sununarv of Signator)' Parties' Positions
In addressing the second part of the three-part test, AEP Ohio argues that its PPA proposal satisfies the factors enumerated by the Commission in the ESP 3 Case. Initially, regarding the financial need of the generating plant, AEP Ohio asserts that its forecasts show that the PPA units have a financial need, at least in the near term, given that near- term PJM capacity market revenues remain far below the fixed costs of the PPA units, even after expected Capacity Performance payments are incorporated. AEP Ohio adds that participation by demand response resources in PJM capacity auctions means additional uncertainty regarding capacity pricing outcomes, while low short-term capacity and energy market prices have increased the risk of premature retirement of the PPA units. AEP Ohio maintains that the financial challenge and resulting need that the PPA units face is due to depressed wholesale market pricing in the western part of PJM, coupled with
APP. 440 14-1693-EL-RDR -68^ 14-1694-EL-AAM both short- and long-term pricing volatility, and that the PPA rider is designed to allow the continued capital investment necessary to the long-term operation of the units. Regarding the second factor, AEP Ohio contends that it has demonsttated that the PPA units will play a vital role in promoting reliability and fuel diversity in the state. Specifically, AEP Ohio maintains that coal should remain a critical component of fuel diversification efforts and that the retirement of coal-fired units, which have the ability to store fuel on site and thus maintain reliability during adverse weather conditions, would increase energy market volatility, result in an over-reliance on natural gas facility generation including proposed projects that may not ultimately be placed in ser^tice, and necessitate costly ttansmission system upgrades. (Co. Br. at 32-43; Co. Reply Br. at 29-36.)
Next, AEP Ohio argues that it has demonsttated that the PPA units are already equipped with the envirorunental conttols necessary to comply with six major existing and pending environmental regulations or that there are budgetary estimates for future compliance included within the financial analysis provided as part of the PPA rider's cost estimates, including, with respect to the CPP, a reasonable projected cost of S15 per mettic ton for carbon dioxide emissions starting in 2022. Regarding the fourth factor, AEP Ohio contends that approval of the PPA proposal will provide substantial economic benefits by supporting economic development in Ohio and protecting against the adverse impact of early plant closures on the state's economy and the local communities that are supported by the plants through direct benefits of more than 1,600 jobs, $121 million in annual payroll income, and $11.5 million in annual property taxes, with the ongoing value of the PPA units' operation estimated at $650 miUion. AEP Ohio adds that closure of the PPA units would substantially impact Ohio's economy because new generation with equivalent capacity is not being consttucted in the state. (Co. Br. at 43-58; Co. Reply Br. at 36-50.)
In terms of the Commission's oversight of the PPA rider, AEP Ohio asserts that its PPA proposal fully satisfies the requirement by affording the- Commission many opportunities for rigorous oversight and substantive review of the PPA units' costs and revenues. AEP Ohio notes that, in the present proceedings, the Commission will determine whether the proposed PPA is beneficial for ratepayers and, therefore, whether it is prudent for the Company to sign the PPA, incur legacy costs, and pass any net PPA costs or credits through to customers via the PPA rider; thereafter, the Commission will continue to exercise ongoing oversight and review of PPA costs through the Company's proposed audit process, which will involve both accounting review of previously approved PPA costs and managerial review of the Company's decisions regarding newly incurred PPA costs, as well as a review of PPA revenues and the Company's actions in selling the output of the PPA units, including review of any Capacity Performance bonuses or penalties. AEP Ohio emphasizes that it has committed to seeking the Conunission's pre-approval regarding the prudency of significant capital expenditures or other major decisions such as unit closure. In terms of timing, AEP Ohio proposes that the Commission would review PPA rider revenues in the audit for the year in which the
APP. 441 14-1693-EL-RDR -69- 14-1694-EL-AAM revenues were included in the rider, while costs would be reviewed in the audit for the year in which the costs were incurred. Further, AEP Ohio asserts that the information sharing commitment in the stipulation, combined with the Company's prior commitments to share the PPA units' cost and revenue data with the Commission, fulfill the requirement for full information sharing with the Commission and Staff. (Co. Br. at 58-69; Co. Reply Br. at 50-56.)
With respect to allocation of the PPA rider's financial risk, AEP Ohio asserts that the rigorous re^tiew of costs being passed through the PPA rider exposes the Company, not its customers, to the risk of disallowance, while the stipulation's $100 million credit obligation and reduced ROE are other risks assumed by the Company or AEPGR. Finally, AEP Ohio notes that the stipulation includes a severability provision to ensure that the ESP would continue in orderly fashion in the event that a court invalidates the PPA rider. (Co. Br. at 69-72; Co. Reply Br. at 56-61.)
Staff notes that, although it does not believe that AEP Ohio's amended application satisfies the Commission's conditions set forth in the ESP 3 Case, the stipulation addresses many of Staff's concerns. Specifically, Staff explains that the stipulation, among other things, provides for a shortened PPA term, lower ROE, rigorous Commission review of the PPA rider, full information sharing, severability provision, and a sharing mechanism to allocate the rider's risk between AEP Ohio and ratepayers. (Staff Br. at 17-21.) OEG asserts that AEP Ohio's PPA proposal, as modified by the stipulation, is compliant with the Commission's requirements from the ESP 3 Case (OEG Br. at 18-19).
Buckeye asserts that AEP Ohio's amended application, as modified by the stipulation, satisfies the Commission's criteria. Buckeye also notes that it is not opposed to reasonable modifications to AEP Ohio's PPA proposal that address the concerns of the Commission or the other parties, as long as the Company does not oppose the modifications. Buckeye argues, however, that the obligations of AEP Ohio and AEPGR to Bucke5^e, as a joint owner of the generating units in question, that exist under the Inter- Company Power Agreement (ICPA) and the CSA should not be abridged in any circumstance as a result of these proceedings, with any conflicts between obligations under the ICPA and CSA and obligations under the stipulation resolved in favor of the ICPA and CSA. For that reason. Buckeye states that it has excluded itself from the provisions of the stipulation that relate to its status as a joint owner of the Cardinal Station and OVEC, in order to reserve its rights and remedies under the ICPA and CSA. (Buckeye Br. at 19-22.)
ii. Sunnmary of Non-Signatory Parties' Positions
The Market Monitor argues that AEP Ohio has failed to demonsttate any actual financial need of the PPA units; has not shown that the units are needed for resource
APP. 442 14-1693-EL-RDR -70- 14-1694-EL-AAM diversity or reliability or explained why customers are not better off with the lowest cost market based prices for capacity; has not proved that subsidization of the units is needed to provide stable electtic prices or to promote economic development; and has failed to show that the PPA proposal will not interfere with Ohio's compliance with the CPP or other environmental regulations (IMM Reply Br. at 3-5, 8-12).
RESA, Exelon, P3, and EPSA contend that AEP Ohio has not satisfied most of the Commission's criteria, particularly by neglecting to present any evidence addressing several factors in relation to the OVEC units. With respect to financial need of the PPA generating plants, RESA, Exelon, P3, and EPSA assert that there is no evidence of the financial history for any of the plants, although the evidence does reflect that AEPGR is performing profitabh', the PPA plants are not going to close, and the plants cleared in PJM's recent capacit)' auction and are, thus, committed to operating for several more years. Regarding the necessit)' of the PPA units in light of future reliabilit}' needs, RESA, Exelon, P3, and EPSA argue that AEP Ohio failed to address this criterion with respect to the OVEC entitlement and presented a flawed reliabilit}' analysis that considered the affiliate PPA units as a group rather than individually, as instructed by the Commission, RESA and Exelon add that AEP Ohio's PPA proposal will not alter its current supply mix and, because there is no plan to close the plants, reliability and supply diversity are not issues to be considered. P3 and EPSA emphasize that the co-owned status of the PPA plants weighs against an}' concern for premature closure. Further, RESA, Exelon, P3, and EPSA maintain that AEP Ohio failed to establish the impact that a closure of each PPA plant would have on electtic prices and the resulting effect on economic development in the state. According to P3 and EPSA, AEP Ohio also failed to propose an appropriate plan for allocating the PPA rider's financial risk between the Company and ratepayers. Finally, RESA, Exelon, P3, and EPSA contend that, under AEP Ohio's PPA proposal as amended b}' the stipulation, the Comimission's oversight will not be rigorous and information sharing will be minimal and ineflective. (RESA/Exelon Br. at 38-45; P3/EPSA Br. at 32-33, 35-45, 47-51; P3/EPSA Br. at 16-23.)
With respect to the financial need of the generating plant, OMAEG claims that, as an initial matter, the Commission lacks authority to consider the issue because market forces determine financial need. OMAEG adds that, in any event, AEP Ohio cannot show a legitimate financial need and instead faults PJM's capacity market design and claims that the PPA units need subsidies in the near term in order to remain competitive pending an anticipated rise in energy costs. OMAEG points out that concerns regarding the PJM capacity market consttuct were recently addressed through FERC's adoption of PJM's Capacity Performance proposal, which has resulted in increased clearing prices. OMAEG also emphasizes that AEP Ohio's statements regarding the financial need of the PPA units are inconsistent with its corporate parent's position that the plants are well-positioned from a cost and operational perspective to participate in the competitive market. Turning to the issue of reliability and fuel diversity, OMAEG asserts that there is sufficient resource
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adequacy in the PJM region, given that PJM exceeded its target reserve margin by 4.1 percent in the most recent base residual auction, and that the Commission should rely on PJM's expertise to alleviate any perceived concerns regarding the future reliability of the electtic grid in Ohio. Regardless, OMAEG contends that there is no realistic prospect that the PPA units will soon retire. OMAEG also emphasizes that no notice of any impending retirement has been provided to PJM as would be required; AEP Ohio has overstated its retirement claims by failing to account for the fact of co-ownership in its flawed $1.6 billion ttansmission upgrade estimate; and RMR arrangements, new generation assets, energy efficiency projects, and disttibuted generation can be used to mitigate system impacts and capacit}' shortialls caused by a closure. Noting that fuel diversity is another matter within PJM's purview, OMAEG argues that, in any event, replacement of the coal-fired PPA units with more efficient gas-fired units would actually enhance the diversity of Ohio's generation mix. OMAEG concludes that AEP Ohio cannot demonsttate that the PPA units are necessary in light of reliability concerns. (OMAEG Br. at 25-34; OMAEG Reply Br. at 6-8,11-12.)
Addressing envirorunental compliance costs, OMAEG argues that ratepayers should not be required to bear the risks associated with such costs. Noting that the increasingly sttingent envirorunental conttols imposed by the CPP will significantly increase the PPA units' compliance costs in the future, OMAEG asserts that AEP Ohio's PPA proposal does not safeguard ratepa}'"ers against unjust and unreasonable charges or protect the state's effectiveness in the global economy. In terms of the economic impact from a plant closure, OMAEG argues that extending the life of aging and expensive coal plants would raise the price of electticit}' and harm economic development in the state. Specifically, OMAEG maintains that AEP Ohio's forecasts are flawed and should not be relied upon by the Commission, because they are inherently speculative and inconsistent with the Company's claim that the PPA units are at risk; overstate expected energy market revenues, as reflected in the Company's 2015 fundamentals forecast and forwards prices, and also projected load and capacit)' prices; and are used selectively by the Company, Additionally, OMAEG offers that requiring customers to pay for the operating risks associated with the PPA plants, including any costs incurred when a unit does not run, environmental compliance costs, legacy costs, retirement costs, and the termination fee provided for under the affiliate PPA, will likely increase the overall cost of the PPA proposal above OCC witness Wilson's projection. Noting that there are other tools to address market volatility, OMAEG also contends that the PPA rider does not resemble an insurance product, contrary to AEP Ohio's claims, and that it will not act as a significant financial hedge. Finally, OMAEG asserts that AEP Ohio's economic development analysis is flawed and insufficient to sustain the Company's burden of proof; the significant costs projected for the PPA rider will harm economic development in the state, particularly in the energy-intensive manufacturing sector; and the Company has overstated the economic benefits associated with keeping the PPA units afloat, but understated the economic value
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to be gained by the entty of cleaner, more efficient natural gas generating units. (OMAEG Br. at 34-49; OMAEG Reply Br. at 18-20.)
Regarding the other considerations identified by the Commission in the ESP 3 Case, OMAEG points out that AEP Ohio proposes a process for review and audit of the PPA rider that would exclude participation by intervenors; fails to memorialize any information sharing with the Commission or Staff in either PPA and seeks to protect any provided information with the utmost level of confidentiality; and places the PPA rider's risks solely on ratepayers, although they are least able to manage the risks of owning and operating the PPA plants (OMAEG Br. at 49-54; OMAEG Reply Br. at 8-10).
OCC and APJN also assert that AEP Ohio has failed to prove the financial disttess of any generating unit, given that recent earnings statements and investor presentations reflect that AEP's assets are increasing substantially in value and the PPA units are positioned to compete in the generation markets; AEP Ohio has the financial capability to cover any projected short-term investment that is required at the outset of the PPA; and the Company's own forecasts corifirm that, even without the PPA rider, AEI^R could operate the PPA units profitably. OCC and APJN add that there are market-based alternatives to the PPA rider, such as privately secured financing and bilateral conttacts with specific commercial and industrial customers that could benefit from more stable pricing, while the proposed ROE is unjust, unreasonable, unprecedented, and should be no higher than AEPGR's average cost of debt. With respect to the second factor, OCC and APJN argue that PJM, rather than the Commission, is responsible for electtic generation reliability, OCC and APJN add that even AEP Ohio acknowledges that PJM is capable of ensuring resource adequacy; there is no indication that any of the PPA units will close without the PPA, which should be dictated by market forces in any event; the PPA proposal will not conttibute to supply diversity, while the market is already working to diversify Ohio's portfolio mix through the consttuction of new generation; and the Company's analysis of the ttansmission cost impact in the event of plant closures is not credible, as it does not account for new generation, includes a substantial amount of non- PPA urtit retirements, and does not specify the impact of the PPA units' retirement on the ttansmission system. (OCC/APJN Br. at 69-80,112-124; OCC/APJN Reply Br. at 19-20, 34- 35.)
Turning to the third factor, OCC and APJN claim that AEP Ohio has not shown, and cannot show due to significant uncertainty surrounding the CPP and other environmental regulations, that the PPA units are compliant with current environmental regulations or that they will comply with pending environmental regulations, while OCC's testimony reflects that customers will likely pay much more for envhonmental compliance measures than what the Company projects for the period of 2015 through 2024. Next, OCC and APJN assert that, while AEP Ohio has provided some analysis on the economic impact of plant closures using a number of faulty assumptions and the
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outdated economic base model, the Company has not assessed the impact of such closures on electtic prices nor offered a witness that is qualified to render an opinion on the economic analysis required by the Commission. Finally, OCC and APJN contend that AEP Ohio's PPA proposal does not properly allocate the financial risks, which would be placed solely on customers, or provide for rigorous Conunission oversight or information sharing, as the proposal omits transparency and participation by interested parties and could require customers to pay liquidated damages in the event of a disallowance of costs or discontinuance of the PPA rider. (OCC/APJN Br. at 81-94,124-144; OCC/APJN Reply Br. at 20-21, 31-32, 39-44.)
In addition to the Commission's designated factors, OCC and APJN assert that AEP Ohio should also be required to demonsttate compliance with additional factors that address consumer benefits, such as an independent assessment of future price scenarios; the impact of offer sttategies on customers; incentives to conttol costs and make rational retirement decisions; the economic impact of higher retail rates; an analysis of a least-cost combination of new and existing generation and ttansmission assets that would deliver the claimed benefits of the PPA proposal; the cost of achieving price stability through competitive solicitation; and the cost of meeting current and expected environmental regulations with generation and ttansmission alternatives to the PPA proposal (OCC/APJN Br. at 144-154).
e. Recommended Modifications to the Stipulation
i. Summary of PJM's Position
In its amicus brief, PJM asserts that Section III.A.o.a of the stipulation, which addresses the proposed armual compliance reviews of the PPA rider, may impact Ohio's interest in atttacting competitive generation to meet its future economic development needs and the overall competitiveness of the wholesale market in the state, • Noting that it takes no position on the stipulation as a whole, PJM recommends that, if the stipulation is approved, the Commission should clarify that, under Section ni.A.5.a of the stipulation, a reasonable offer behavior for AEP Ohio would be to offer the PPA units into the PJM markets at a level no lower than their "actual costs," as that term is understood by PJM and applied consistent with its tariff and manuals without consideration of the offsetting revenues provided by Ohio retail customers under the stipulation. PJM believes that this clarification is necessary to ensure that the affiliate PPA does not artificially suppress prices in a manner that would hurt the development of new generation in Ohio, Further, PJM recommends that the Commission clarify that the risk associated with Capacity Performance penalties remains with the owner of the PPA units, as the entity that can mitigate the risk, and that AEP Ohio may not seek recovery of any penalties from customers through the PPA rider. (PJM Br. at 4-9.)
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Finally, PJM asserts that arguments that approval of the stipulation is necessary to ensure electtic system reliability in Ohio are misplaced. PJM points out that it is the entity ultimately responsible for reliability of the bulk electtic system in the PJM region; recent retirements of coal-fired generating units have been absorbed through PJM's robust forward capacity market and regional ttansmission planning process and the retired generation has been replaced with newer resources, such that resource adequacy targets have been met and exceeded year after year; there are substantial new plants under consttuction or proposed to be consttucted in Ohio; the RMR provisions of PJM's tariff are another means to ensure reliability, although PJM has infrequently found it necessary to rely upon these provisions, even with the recent retirements; and the Capacity Performance consttuct is intended to guarantee that generators perform as needed. PJM urges the Commission to remain cognizant that electtic system reliability is assured by PJM in a comprehensive fashion and that reliabilit}' assurance does not hinge on the PPA units continuing in service. (PJM Br, at 9-12.)
AEP Ohio responds that it intends to fully comply with all PJM tariff requirements and any other applicable rules in bidding the PPA units' capacity. According to AEP Ohio, although the Commission may review the prudence of AEP Ohio's bidding activity within PJM rules, PJM's recommendation that the Commission effectively impose an additional PJM bidding rule on the Company is improper and ur\fair, given that PJM has not sought to impose a similar requirement on other existing generators that receive cost- based compensation. AEP Ohio adds that decisions about the recovery of Capacity Performance penalties by retail customers is a matter that falls exclusiveh' within the Commission's jurisdiction and that PJM's recommendations improperly reach into retail matters, while seeking to impose a special rule for the PPA proposal that does not apply to other similarly situated market participants. AEP Ohio notes that, unless the Company is responsible for an imprudent decision or action in managing or implementing the PPA terms, a Capacity Performance charge should be tteated as any other cost associated with operation of the units and passed through the wholesale PPA and, ultimately, the retail PPA rider. (Co. Reply Br. at 58-61, 91-93.)
In response to PJM, OEG asserts that the Commission has the requisite authority under the Energy Policy Act of 2005 and R.C. 4928.02(A) to approve the PPA rider as a part of its obligation to ensure the adequacy and reliability of electtic generation in Ohio through fuel diversity. OEG asserts that the PPA proposal will promote fuel diversity by helping maintain the operation of coal-fired generation, a key component of fuel diversity in a region that is becoming more heavily reliant on natural gas generation. Additionally, OEG advocates that the Commission reject PJM's recommendation that AEP Ohio be prohibited from bidding the PPA units into the PJM capacity market as a price taker. OEG points out that PJM's recommendation would unreasonably impose a condition on AEP Ohio's bidding sttategy that PJM does not require of other bidders; would result in less capacity revenue flowing into the PPA rider, as less of the PPA units' capacity would
APP. 447 14-1693-EL-RDR -75- 14-1694-EL-AAM likely clear, which would harm the rider's projected economic benefits; and could be viewed as an attempt by the state to artificially inflate market prices. (OEG Reply Br. at 14-17.)
ii. Summary of OEG's Position
OEG also recommends that the Commission make several express findings to reinforce the terms of the stipulation. Specifically, OEG argues that the Commission should expressly state that no retirement-related costs associated with the PPA units, aside from approved depreciation changes, may be collected from retail customers; should expressly clarify that any subsequent rejection of the PPA or the PPA-related stipulation provisions by a state or federal court will not ttigger the PPA's Hquidated damages provision; should reserve the right to reevaluate, modify, or terminate the PPA rider, without ttiggering the liquidated damages provision, if the MOPR is applied to the PPA units during the PPA term; should expressly find that there is no definitive evidence demonsttating that approval of the PPA rider would distort the PJM wholesale markets; and should expressly find, in anticipation of arguments that the PPA is conttary to FERC standards for affiliate ttansactions, that the costs of the PPA are projected to be below market over the term of the PPA. (OEG Br. at 19-22.) P3 and EPSA respond that the Conunission should not adopt OEG's recommended findings. Specifically, P3 and EPSA note that any finding by the Commission that there will be no wholesale market distortion would be conttary to the positions taken by PJM, the Market Monitor, and other witnesses that work and compete in the wholesale markets; and that the Conunission should not find that the costs of the AEPGR PPA will be below market, because AEP Ohio has not offered any type of guarantee or commitment u'ith respect to its PPA rider projections, (P3/EPSA Reply Br, at 32-36.)
AEP Ohio asserts that OEG's three proposed clarifications are inappropriate, because they attempt to modify the stipulation. Further, AEP Ohio notes that OEG's two proposed findings in support of the stipulation are reasonable, if the Commission also expressly states that the PPA rider is aimed at retail ratemaking, and as long as the Commission does not apply FERC's standards for affiliate ttansactions, in making the findings. Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC *\\ 61,382 (1991) (Edgar). Finally, AEP Ohio requests that the Commission reiterate its long-held opinion that there is retail competition in Ohio and that the Company's customers are not captive, while also making clear that, in approving the stipulation, the Commission is affirmatively finding that the PPA proposal accords with all Ohio corporate separation laws and regulations and that the evidence in the record of these proceedings conttadicts the affiliate abuse concerns raised by various intervenors. AEP Ohio notes that FERC has ttaditionally deferred to similar findings by the Commission in evaluating affiliate ttansactions. (Co. Reply Br. at 125-131.)
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iii. Summary of Non-Signatory Parties' Positions
P3 and EPSA recommend that, if the PPA proposal is approved, AEP Ohio should be required to use its best efforts to maximize revenues from the sale of the energy, capacity, and ancillary services from the PPA units into the PJM markets or through bilateral conttacts, in order to offset ratepayers' obligations under the PPA rider. P3 and EPSA also suggest that, as a proper risk sharing mechanism, a cap on the potential charges that customers will incur under the PPA rider should be required. (P3/EPSA Br. at 76-78; P3/EPSA Reply Br. at 20-21, 31.) RESA and Exelon argue that, if the PPA proposal is approved, the Commission should impose appropriate incentives, aside from the stipulation's SlOO million credit commitment, to ensure that ratepayers are not exposed to substantial risk when PPA costs exceed revenues, such as through requirements that at no time will the annual PPA rider exceed a ceiling amount and that the aggregate rider credit at the end of the term must be at least equal to any rider charges plus carrying charges (RESA/Exelon Reply Br. at 19-24). Kroger requests that, if the Commission approves the PPA proposal, the rate design of the PPA rider be modified, such that the rider's costs would be recovered on a demand basis for demand metered customers instead of through an energy charge (Kroger Br. at 4-5; Kroger Reply Br. at 1-2).
Walmart argues that, if the Commission approves the PPA proposal, the Commission should reject the stipulation's ROE of 10.38 percent and instead adopt an ROE in the range of 9.69 percent to 9.99 percent. In support of its argument, Walmart asserts that AEP Ohio failed to offer any evidentiary basis for the ROE of 10.38 percent proposed in the stipulation, which Walmart finds, in any event, unreasonable when compared to the average ROE of 9.86 percent approved for similarly situated utilities across the nation since 2012. Walmart adds that the proposed ROE is higher than what was adopted by the Commission in AEP Ohio's most recent disttibution rate case; does not reflect the declining ttend in authorized ROEs; and does not account for the reduction in risk from the guaranteed cost recovery under the PPA proposal. (Walmart Br. at 10-14.) Noting that it would be inappropriate to include an ROE in the affiliate PPA, OCC and APJN reconunend that, if the PPA rider proposal with an ROE is nevertheless approved, the ROE be set no higher than AEPGR's average cost of debt, both long-term and short- term (OCC/APJN Reply Br. at 34-35),
OMAEG recommends that, if the Commission approves the stipulation's provision regarding the expansion of the IRP tariff and credit, the Commission should afford the opportunity to all eligible customers rather than limit it to members of signatory and non- opposing parties; should retain the current level of credit payments as to minimize the cost burden on other customers; and require AEP Ohio to bid the interruptible load as a capacity resource into PJM's capacity auctions, with any revenues received from bidding the interruptible load into the capacity market used to offset the cost of providing the IRP program. Additionally, OMAEG contends that the stipulation's severability provision
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should be modified, because it unreasonably precludes any collected amounts from being refunded, even if a court determines that the PPA rider is unlawful. OMAEG requests that the Commission sttike the provision or, alternatively, direct that any amounts recovered through the PPA rider be made subject to refund. (OMAEG Br. at 60-61; OMAEG Reply Br, at 20-21.) OCC and APJN also criticize the severability provision's failure to provide for a refund of any charges that are subsequently deemed unlawful (OCC/APJN Br. at 45).
AEP Ohio responds that, if the PPA rider is approved and goes into effect, and operation of the PPA units is conducted in reliance upon that approval, it is appropriate that the financial results provided by the rider are not rettospectively unwound. With respect to the IRP, AEP Ohio notes that the stipulation only commits the Company to proposing changes to the IRP tariff and that OMAEG can raise its arguments in the ESP extension proceeding. (Co. Reply Br. at 117-118.)
f. Commission Decision
The Commission again emphasizes the importance of our mission in assuring all customers access to reliable, safe, and cost-effective services, as well as the difficulty of balancing numerous important interests in deciding these sensitive and complex issues. The Commission has thoroughly considered the arguments raised by the parties, PJM, and the Generation Developers, as well as the recommended modifications to the stipulation, and we find that the stipulation, as modified below, meets the second part of the three- part test. Based upon our review, we find that the record in these proceedings demonsttates a projected net credit to customers of $37 million over the current ESP term through May 31, 2018, or $214 miUion through May 31, 2024, under the term of the PPA rider. Further, we find that the stipulatiom as modified, will protect consumers against rate volatility and price fluctuations by promoting retail rate stabilit)' for all ratepayers in this state, modernize the grid through the deplo)'ment of advanced technolog}' and procurement of renewable energy resources, and promote retail competition by enabling competitive providers to offer irmovative products to serve customers' needs.
As an initial matter, the Commission notes that the second part of the test specifically requires that we evaluate the stipulation as a package. In prior cases, the Commission has considered and approved stipulations that address a wide variety of issues, often resolving several pending proceedings at the same time, and specifically emphasizing that the stipulation must be viewed as a package foi purposes of the second part of the three-part test. Set, e.g.. In re Ohio Power Co., Case No. 94-996-EL-AIR, et al. Opinion and Order (Mar. 23, 1995) at 20-21; In re Columbus Southern Power Co. and Ohio Power Co., Case No. 99-1729-EL-ETP, et al.. Opinion and Order (Sept. 28, 2000) at 44; DP&L Case, Opinion and Order (Sept. 2, 2003) at 29. We have repeatedly found value in the parties' resolution of pending matters through a stipulation package, as an efficient and cost-effective means of bringing their issues before the Commission, while also, at times.
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avoiding the considerable time and expense associated with the litigation of a fully contested case. See, e.g.. In re FirstEnergy, Case No. 12-1230-EL-SSO, Opinion and Order (July 18, 2012) at 42; In re Columbus Southern Poioer Co. and Ohio Poiver Co., Case No. 11- 5568-EL-POR, et al.. Opinion and Order (Mar. 21, 2012) at 17. We, therefore, reaffttm that the stipulation offered by the signatory parties in these proceedings must be viewed as a whole.
i. PPA Rider Projections
In addressing the second part of the three-part test, the non-signatory parties primarily raise concerns with the projected rate impact of the PPA proposal. Although, as discussed below, the Commission finds that rate stability is an important consideration, we agree that a rate stability proposal, such as the PPA rider, must not impose unreasonable costs on customers and, again, under the second part of the three-part test, we are charged with reviewing the stipulation to determine whether it benefits ratepayers. During the course of these proceedings, the Commission was presented with several different PPA rider scenarios based on differing data inputs and assumptions, all of which are predictions of future conditions. The Commission's first task, therefore, is to evaluate the parties' projections, in order to determine a reasonable overall estimate of the PPA rider's net credit or charge based on the evidence of record.
In support of the amended application, AEP Ohio witness Pearce developed forecasts of revenues and costs based on various data, including Company witness Bletzacker's long-term forecast of PJM wholesale power prices and Company witness Hawkins' capital sttucture and ROE. Specifically, Dr, Pearce used PLEXOS, which is an hourly production cost model used to forecast the dispatch of units in the PJM power market, to determine the market revenues and variable costs of production for the generating units based on a generation forecast for. each. unit. The model utilizes assumptions for each unit's cost of energy, scheduled maintenance outages, and forced outages, along with forecasted market prices of energy, which were provided by Mr. Bletzacker, to determine forecasted generation output, costs, and energy revenues for each unit. In order to incorporate changes necessitated by the stipulation, AEP Ohio witness Allen modified Dr. Pearce's analysis by updating the period of analysis to January 1, 2016, through May 31, 2024, reducing the ROE from the initial formula rate of 11.24 percent to a fixed 10.38 percent, and incorporating the results of PJM's recent Capacity Performance auctions for the 2016/17, 2017/18, and 2018/19 delivery years. As noted above, AEP Ohio presented four scenarios, which are intended to demonsttate the effect of variation in load due to severe weather or economic factors, including the asymmettic impact that such factors have on electtic prices, where increases in load tend to increase prices more so than load reductions decrease prices. (Co. Ex. 2 at 11-20, Ex. KDP-2; Co. Ex. 52 at Ex. WAA-2; Tr. II at 543; Tr. XVII at 4388, 4405-4406; Tr. XVIfl at 4568-4569,4574-4575.)
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Based on the analysis of AEP Ohio witnesses Pearce, Bletzacker, and Alien, the Company asserts that a net credit of $721 milhon is the best evidence of the projected benefit of the PPA rider during the term of the rider, with a net credit of $209 million projected over the current ESP term, while the stipulation recommends an initial rider rate based on a $4 million armualized credit for 2016, which is consistent with the Company's weather normalized case that predicts a net credit of $37 million for the existing ESP period, or $214 million over the term of the rider (Co, Ex. 52 at 15, Ex. WAA-2; Joint Ex. 1 at 6).^o xhe non-signatory parties reach a different conclusion, with OCC estimating that the PPA rider would result in a net cost of at least $1.9 billion over the term of the rider and $580 million over the current ESP term (OCC Ex. 34 at 5).
The Commission finds, however, that OCC's PPA rider projection is fundamentally flawed for a number of reasons. OCC witness Wilson's projection, which is derived from AEP Ohio's five percent lower load case, uses Company witness Pearce's analysis in terms of the expected costs of the PPA units, but incorporates forwards electtic energy prices in place of the Company's hourly energy prices, thus modif}ang the projected revenues. Mr, Wilson's criticism of Dr. Pearce's analysis, therefore, is essentially based on his belief that forwards conttacts are a preferable means of estimating future energy prices. Forwards prices, however, are not a forecast of future spot market prices and they should not be relied upon as a basis for long-term forecasts of energy prices. Further, unlike AEP Ohio's fundamentals forecast, the futures prices used by Mr. Wilson do not account for factors such as the impact of future carbon emission regulations, which is another reason that they are not an accurate predictor of future energy prices. Finally, there is a lack of futures market liquidity, other than in the immediate near term, as the record clearly reflects. Over the roughly eight-year term of the PPA, there are simply too few fonA.^ards conttacts that can be used to form a reliable projection of the PPA rider's impact. As AEP Ohio emphasizes, Mr. Wilson appears to acknowledge this fact. For months beyond October 2020, for wh^ch there were no AEP-Da}'ton Hub Day Ahead forwards prices, Mr. Wilson used the monthly forwards prices for the period of November 2019 through October 2020 as proxies for the period of November 2020 through December 2024. We do not find it reasonable to rely on an analysis that merely recycles the monthly futures prices for November 2019 through October 2020 across the final four years, approximately, of the PPA.31 (Co. Ex. 45-48; Co. Ex. 50 at 1-6; OCC Ex. 15 at 51-52;^OCC Ex. 34 at 9-10; Tr. V at 1470; Tr. XV at 3817-3819; Tr. XXII at 5488-5489, 5494.)
^^ The parties' PPA rider projections are stated in nominal doUars. In summarizing the parties' projections for the current ESP term, the Commission has used the entire projected credit or charge for 2016 and 2017, as well as the projected credit or charge for the first five months ol 2018. '^^ Aside from AEP Ohio's projections, OCC witness Wilson offered the only projection of the PPA rider's impact under the stipulation. During the hearing on AEP Ohio's amended apphcation, Sierra Club witness Chernick and IGS witness Leanza offered testimony that, like Mr. Wilson's projection, reUes heavily on futures contracts (Sierra Club Ex. 37 at 24-33; Sierra Club Ex. 40 at 4-5; IGS Ex. 7 at 4-5, 6-7). Further, as Sierra Club and IGS are signatory parties, the testimony of Mr. Chernick and Mr. Leanza was
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AEP Ohio witnesses Pearce, Bletzacker, and Allen, however, have provided a thorough analysis of the PPA rider's estimated impact, which incorporates the only actual forecast of long-term energy prices in the record. Despite the non-signatory parties' critical assessment of AEP Ohio's projections, the Commission is not persuaded by their arguments and the fact remains that no other party has presented a full projection of energy prices and the net revenues under the PPA rider. As noted above, even OCC witness Wilson's projection is based, in large part, on the analysis of AEP Ohio's witnesses. Additionally, although several parties argue that the 2013 fundamentals forecast used by AEP Ohio is outdated and that the Company should have updated its projections using the 2015 fundamentals forecast, the U.S. Energy Information Administtation (EIA) noted in its Annual Energy Outlook (AEO) for 2015 that the projected electticity prices for the Reference case, oi'er the long term, actually increased in comparison to the Reference case in the AEO for 2014. Specifically, EIA found that:
In the AEO2015 Reference case delivered natural gas prices to electticity generators are lower than in the AEO2014 Reference case in the first few years of the projection but higher throughout most of the 2020s. From 2020 to 2030, the generation cost of component of end-use electticit}' prices is, on average, 4% higher in AEO2015 than in AEO2014.'
(Co. Ex. 18 at E-7.) Therefore, it is possible that, even if Mr. Bletzacker had used an updated fundamentals forecast, higher electticit)' prices may have resulted in AEP Ohio's PPA rider projections beconaing more favorable to customers rather than less favorable.
Accordingly, based upon the evidence in the record, the Commission finds that AEP Ohio's PPA rider analysis is reliable and should be used to determine an estimate of the rider's net impact. In particular, we find that AEP Ohio's weather normalized case, which was used by the signatory parties as the basis for recommending the PPA rider's annualized initial $4 million credit for 2016, is a reasonable and conservative projection. We, therefore, conclude that the PPA rider is reasonably estimated to provide a net credit of $37 million over the current ESP term, or $214 million over the PPA rider term, for AEP Ohio's ratepayers (Co. Ex. 52 at Ex. WAA-2).
In the ESP 3 Case, the Commission was not persuaded, based on the record, that AEP Ohio's PPA rider proposal in that case, which included only the OVEC entitlement, would provide customers with sufficient benefit from the rider's financial hedging mechanism or any other benefit commensurate with the rider's potential cost. ESP 3 Case,
not updated following the filing of the stipulation. Accordingly, we give their testtmony no weight in determining a reasonable estimate of the PPA rider's impact.
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Opinion and Order (Feb. 25, 2015) at 25. In the present proceedings, AEP Ohio has offered a PPA proposal that includes the OVEC entitlement as well as the output from the proposed affiliate PPA, which, as addressed further below, has substantial value as a financial hedge and rate stability mecharusm that is based approximately 30 percent on the cost of service of the PPA units and 70 percent on the retail market, and which has been further improved through the signatory parties' modifications to the proposal in the stipulation. To the extent that the $214 million net credit projected under AEP Ohio's weather normalized case is realized over the PPA rider term, the PPA rider will provide a direct financial benefit, along with a valuable hedging mechanism, to ratepayers. Additionally, as discussed in greater detail below, the stipulation provides numerous other customer benefits. We, therefore, find that the stipulation's PPA proposal is in the public interest and that it should be approved, as modified below, through May 31, 2024.
Finally, the Commission notes that, in the event that AEP Ohio's extended ESP application is approved. Section IIl.J of the stipulation (Joint Ex, 1 at 32-33) and R.C 4928.143(E) apply. Again, we base our decision approving the PPA rider today on AEP Ohio's projection that is predicted to result in a net credit of S214 million.
ii. PPA Rider Rate Impact Mechanism
The Commission acknowledges that the projections presented in these cases are simply predictions of future market prices and costs; thus, even the most reliable projections may be proven wrong in the future, particularly over an eight-year timeframe. Therefore, in order to protect customers against rate volatilit)" and price fluctuations and to provide additional rate stability for customers, the Conunission will modify the stipulation to include a mechanism to limit the rate impacts of the PPA rider, consistent with the testimony of Staff witness Choueiki (Staff Ex. 1 at 19) and RESA witness Bennett (RESA Ex. 1 at 10). This mechanism will be asymmettical; there will be no limit on the net credits that may be provided to customers under the PPA rider.
We direct AEP Ohio to limit customer rate increases related to the PPA rider at five percent of the June 1, 2015 SSO rate plan bill schedules for the remainder of the current ESP period through May 31, 2018. The five percent limit shall be determined not by overall customer rate classes, but on an individual customer-by-customer basis. The customer rate impact mechanism applies only to the PPA rider. Any rate changes that arise as a result of past proceedings, including any disttibution-related proceedings, or in subsequent proceedings, are not factored in the five percent limit. The calculation of customer rate increases related to the PPA rider shall not include any cost associated with the renewable energy projects implemented under Section III.I of the stipulation. Further, the five percent limit shall be normalized for equivalent usage to ensure that at no point any individual customer's bill impact related to the PPA rider shall exceed five percent. Any revenue reduction resulting from the implementation of the customer rate impact
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mechanism shall be reflected in the calculation of the PPA rider's over/under-recoven- balance for recovery in AEP Ohio's next quarterly update filing.
The Conunission notes that AEP Ohio voluntarily included the PPA rider as part of its ESP and chose to file an ESP to fulfill the obligation to provide SSO service under R.C. 4928.141. Further, AEP Ohio has the option, under R.C 4928.143, to reject any Conunission modifications to the ESP and withdraw its application for an ESP. Therefore, if AEP Ohio proceeds with the PPA rider by filing tariffs and finalizing a PPA with AEPGR based upon the term sheet, we will consttue such actions as the voluntary acceptance of the mechanism limiting the rate impacts of the PPA rider. However, it is our intent that the mechanism be consttued as part of the PPA rider for purposes of the severability clause in the stipulation, and if the mechanism is rejected by a court of competent jurisdiction, that the PPA rider continue as described in the severability clause.
The Commission also notes that our approval of the PPA rider, as a retail hedge, is based upon retail ratemaking authority under state law, which does not conflict with or erode federal laws or the responsibilit}' of FERC to regulate electricity at wholesale. Charges at wholesale are exclusively within the jurisdiction of FERC Here, the Commission specifies the reasonable amount to pay at retail. AEP Ohio is under no requirement by this Commission or FERC to enter into the arrangements proposed under the PPA proposal. With regard to any potential conttact, AEP Ohio is aware, prior to the execution of the conttact, of the Commission's modifications to the stipulation. Regarding AEP Ohio's conttactual entitlement to a 19.93 percent share of the electtical output of the OVEC generating units, the Conunission does not direct or mandate a conttact for any amount of the entitlement at wholesale. Rather, our approval of the PPA rider is limited to an authorization of an amount to pay at retail. Penn. Power Co. v. Pennsylvania Pub. Util. Comm., 127 Pa.Commw. 97, 561 A.2d 43 (1989); Pike County Light and Power Co. v. Pennsylvania Puh. Util Comm., 77 Pa. Commw. 268, 465 A.2d 735 (1983).
iii. Benefits of the Stipulation
Having determined that the best projection or forecast, based upon the record, of the credit to be produced by the PPA rider is $214 milHon over the term of the rider, we will turn to other factors to be considered in determining whether the rider is in the public interest. The Commission finds, based on the record evidence, that the stipulation will provide numerous benefits for customers that are in the public interest and consistent with the policy of the state, as set forth in R.C. 4928.02. With respect to the provisions related to the procurement of additional renewable energy resources in Ohio (Joint Ex. 1 at 30-32; Co. Ex. 52 at 14), the Commission notes that renewable energy plays an integral role in promoting a reliable and cost-effective grid. The Conunission will continue to look to the markets as the primary drivers of an adequate supply of energy from any source, including renewable energy. Additionally, the Commission will continue to support
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bilateral conttacts that lead to the development of renewable projects. The stipulation provides for a commitment to procure 500 MW of wind capacity and 400 MW of solar capacity. The Commission supports the consttuction of new renewables in this state. The state has previously seen a number of wind-related projects approved for siting through the Board, many of which have yet to be consttucted. However, solar projects are not as prevalent. Solar projects would enhance the diversity of available generation optioris. The Commission first encourages that bilateral conttacting opportunities be explored to provide support for the consttuction of renewables. To the extent that bilateral opporturuties are not available, the Commission will entertain and review a cost recovery filing, first focusing on enhancing solar opportunities. We also direct AEP Ohio to demonsttate that bilateral opportunities were explored and that a competitive process was utilized to source and determine ownership of any project to be built.
With respect to the PPA proposal, we find that customers will benefit from the PPA rider as a financial hedging mechanism. The PPA rider will supplement the benefits derived from the staggering and laddering of the SSO auctions and protect retail customers from price volatilit}' in the market. The record reflects that the PPA rider will provide added rate stability during periods of extteme weather, when the rider can be expected to offset severe price spikes. The different scenarios reflected in AEP Ohio's projection of the PPA rider's impact demonstrate the effect of variation in load due to severe weather or economic factors, including the asymmettic impact that such factors have on electtic prices, where increases in load tend to increase prices more so than load reductions decrease prices. If load increases due to weather or economic conditions, shopping and SSO customers will be exposed to the resulting higher wholesale prices, which the PPA rider will partially offset. The 3,111 MW of capacity under the affiliate PPA and the OVEC PPA is a significant amount that will provide value as a financial hedging mechanism that supports stable retail rates. Although certain non-signatory parties argue that customers do not want or need a.hedge.to stabilize their,rates,, rate, stability is an essential component of AEP Ohio's ESP, as we recognized in the ESP 3 Case, and R.C 4928.143(B)(2)(d) expressly authorizes the Commission to establish a rate stability mechanism. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 25. The PPA rider provides the benefit of a more balanced approach than relying exclusively on the market, through a diversified portfolio with a cost-based hedge, sourced from 20 generating units representing roughly a third of AEP Ohio's coruiected load, that protects against volatile market prices. (Co. Ex. 1 at 8-10; Co. Ex. 2 at 11-21, Ex. KDP-2; Co. Ex. 6 at 5; Co. Ex. 10 at 7-S, Ex. WAA-2; Co. Ex. 51 at 2-3, 4-5, 7-S, Ex. WAA-R3; Co. Ex. 52 at 13-14, Ex. WAA-2; MAREC Ex. 1 at 6-7; Tr. XVII at 4385-4388, 4405-4406; Tr. XVIII at 4574-4575; Tr. XX at 4978.)
In addition to the benefit of rate stability, the PPA proposal will facilitate generation fuel supply diversit}' and work to offset the price volatility impact that any single fuel source may have on electtic rates. Fuel source diversity is a matter of great importance to
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the Commission, and the PPA proposal will help to ensure that a diverse fuel source mix is maintained in Ohio. (Co. Ex. 1 at 8-10, 23; Co. Ex. 2 at 16-17, 22-24; Co. Ex. 6 at 12-13; Co. Ex. 11 at 3-4; Co. Ex. 52 at 14.) As previously acknowledged by the Commission, there is also considerable uncertainty with respect to pending environmental regulations, and the PPA proposal will afford the state flexibility in complying with any future requirements of the CPP, by providing greater fuel source diversit}' (Co. Ex. 4 at 15-19). ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 24, Second Entty on Rehearing (May 28, 2015) at 4-6. Further, the PPA proposal will guarantee that the PPA units continue to provide jobs and other economic benefits to the region, v\'hile avoiding the potential for increased ttansmission costs that may result from premature retirements (Co. Ex. 1 at 10, 13-15, 25- 26; Co. Ex. 5 at 11; Co. Ex. 7 at 4-5, 6-10; Co. Ex. 10 at 11-13; Co. Ex. 52 at 13-14).
Additionally, the stipulation's modifications to the PPA proposal put forth in AEP Ohio's amended application, including the changes to the affiliate PPA outlined in Attachment A to the stipulation, will also benefit customers. Specificall}', the stipulation reduces the ROE for the affiliate PPA from an initial variable rate of 11.24 percent (with a range up to 15.9 percent) to a fixed 10.38 percent, resulting in savings of $86 million, and shortens the term of the PPA to approximately 8 years. The stipulation also provides that AEP Ohio will fund credits to ratepayers of up to SlOO million over the last four years of the PPA term, if the actual revenues under the PPA rider are at a level that would otherwise impose a charge or provide a credit that is less than the amount of the credit commitment. This provision of the stipulation, therefore, also adds value for ratepayers, as a means to ensure that the PPA rider operates to the benefit of customers, as expected, and to incent AEP Ohio to make certain that the PPA units are managed efficientiy. (Joint Ex. 1 at 5, Att. A; Co. Ex. 2 at Ex. KDP-1; Co. Ex. 8 at 6-7; Co. Ex. 52 at 14, Ex. WAA-2.)
Aside from the stipulation's enhancements to the PPA proposal, the stipulation also includes numerous commitments by AEP Ohio to offer proposals in future proceedings that are intended to promote economic development and retail competition, facilitate energy efficiency measures, reduce carbon emissions, expand the development of renewable resources, and pursue grid modernization in the state. Initially, the Commission notes that, because these proposals are subject to further review in future proceedings, our recognition of the benefits of the proposals should not be consttued as a predetermination of the outcome of those future proceedings, which will be decided based upon the record in each case. Rather, at this point in time, we find value for customers in AEP Ohio's commitment to bring these proposals before the Commission for further consideration (Tr. XIX at 4870).
With respect to specific customer benefits, the Commission notes that the automaker credit is intended to encourage economic development by creating an incentive for automakers to use or locate their manufacturing facilities within the state. AEP Ohio has also committed to filing, by December 31, 2016,, a carbon reduction plan for promoting
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both fuel diversification and carbon emission reductions, as well as filing, by June 1, 2016, a grid modernization business plan that will include initiatives related to advanced metering infrasttucture installation, investment in disttibution automation circuit reconfigurations, Volt/VAR Optimization, removing obstacles to disttibuted generation, and net metering tariffs. As we have previously stated, there is significant long-term value and benefit for customers with the implementation of advanced metering infrasttucture, disttibution automation, and other smart grid technologies. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 51-52. Regarding Volt/VAR Optimization in particular, AEP Ohio has committed to propose, through settlement efforts in Case No. 13-1939-EL-RDR, to deploy 160 circuits of Volt/VAR Optimization, rather than the 80 circuits proposed in that case, and to include a future proposal to deploy all cost-effective Volt/VAR technology, while also agreeing not to count the savings associated with the Volt/VAR Optimization toward ttiggering the shared savings mecharusm, although the energy savings would be applied toward the Company's overall EE/PDR achievement above and beyond the savings benchmarks agreed upon in the stipulation. (Joint Ex. 1 at 11, 26-27, 28, 29-30; Co. Ex. 52 at 14; Tr. XIX at 4863-4865; Tr. XX at 4932; ELPC Ex. 18.)
Although the Comrrussion will review and decide whether to approve AEP Ohio's grid modernization business plan in a separate proceeding, we note that, under R.C. 4928.02(D), it is the policy of the state to encourage innovation through the implementation of smart grid programs and advanced metering infrasttucture. The Conunission further notes that the modernization of the grid in AEP Ohio's service territory is also consistent with efforts to make the grid more reliable and cost effective for consumers. We encourage AEP Ohio to ensure that the proposed grid modernization business plan considers the future ttansition to a grid that engages customers and supports flexibilit}' in meeting resource adequacy needs.
Other customer benefits of the stipulation include A.EP Ohio's commitment to conttibute $500,000 in shareholder funding to a public institution of higher education in Ohio for the purpose of advancing clean energy research and development; commitment to propose a supplier consolidated billing pilot program, with half of the costs paid by the CRES signatory parties; several commitments involving increased investment in EE/PDR programs at Ohio hospitals, including Volt/VAR Optimization deployment; and the expansion of the IRP program (Joint Ex. 1 at 10-11, 13-15, 16-17; Co. Ex. 52 at 14; Tr. XVIII at 4540-4541, 4644-4645; Tr. XIX at 4714; Tr. XXII at 5593-5594). Additionally, we find that a number of other provisions of the stipulation are in the public interest, as they will afford the state a considerable degree of flexibility in meeting the carbon reduction requirements that may result from the CPP or other future envirorunental regulations. These include the PPA proposal itself, which supports supply diversity; AEP Ohio's commitment to convert certain generating units to natural gas co-firing or to retire, refuel, or repower to 100 percent natural gas within a specific timeframe; the Company's commitment to propose the development of at least 900 MW of solar and wind resources in Ohio; and
APP. 458 14-1693-EL-RDR -86- 14-1694-EL-AAM various commitments made by the Company to implement energy efficiency and demand response measures. (Joint Ex. 1 at 13-16, 19-28, 30-32; Co. Ex. 52 at 14; Tr. XIX at 4710- 4711.)
iv. Commission's Factors
With respect to the factors enumerated in the ESP 3 Case, the Commission directed AEP Ohio, at a minimum, to address four specific factors, which the Commission would balance, but not be bound by, in deciding whether to approve the Company's request for cost recovery in its filing. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 25. AEP Ohio filed an amended application, in part, to address the Commission's factors, as well as the other requirements set forth by the Commission in the ESP 3 Case, while the stipulation addresses in further detail the directives provided in the ESP 3 Case. Although we address the factors identified in the ESP 3 Case, we also note that our determination of whether to approve the proposed PPA rider is based on our retail ratemaking authority under state law, which does not conflict with the Federal Power Act or FERC's responsibilit}' to regulate electticity at wholesale. While the Commission is sympathetic to concems surrounding potential additional ttarismission costs, resource diversity, and local economic impact, the Commission's decision does not turn on such issues. The Commission has, however, considered the evidence offered by AEP Ohio and the other parties with respect to the factors and requirements from the ESP 3 Case, as part of our analysis of the second part of the three-part test.
AEP Ohio's testimony reflects that near-term capacity market revenues are not sufficient to support necessary capital investment, even with the revenue uplift from the recent Capacity Performance auctions, and have increased the risk of premature retirement of the PPA units (Co. Ex. 1 at 17; Co. Ex. 2 at 31; Co. Ex. 5 at 13-14). The record further reflects that the PPA units will support supply diversity in the state. AEP Ohio's testimony indicates that the continued operation of the coal-fired PPA units will help to protect against a potential over-reliance on natural gas generation facilities and ensure that the region has a diversified fuel source portfolio. (Co. Ex. 1 at 8, 13; Co. Ex. 3 at 6-7.) Regarding compHance with current or pending environmental regulations, AEP Ohio witnesses testified that the PPA units are either already equipped with the environmental conttols necessary to comply with six important environmental regulations, including the CPP, or that there are budgetary estimates for future compliance incorporated within the financial analysis provided as part of the PPA cost estimates (Co. Ex. 4 at 4-5, 20-21; Co. Ex. 5 at 7).
AEP Ohio witnesses also addressed the expected impact of PPA unit closures on economic development and electtic prices within the region, explaining that the continued retirement of generating units would necessitate costly ttansmission upgrades. Noting that the PPA units provide over $650 million in armual economic benefits, they
APP. 459 14-1693-EL-RDR -87- 14-1694-EL-AAM emphasized that the units employ over 1,600 workers and provide $121 million in direct armual payroll income and $11.5 million in armual property taxes, as well as more than 4,000 additional jobs and nearly $244 million of additional income, to the region. (Co. Ex. 1 at 10,13, 25-26; Co, Ex. 7 at 10; Co. Ex. 10 at 11-13, Ex. WAA-3, Ex. WAA-4.) Finally, the other PPA proposal requirements set forth by the Commission in the ESP 3 Case were addressed in AEP Ohio's testimony or in the Company's amended application (Co. Ex. 1 at 27-29; Co. Ex. 10 at 10-11; Co. Ex. 13 at 3-4).
It is apparent from the stipulation that the signatory parties took steps to address the Commission's factors and requirements from the ESP 3 Case, given that the stipulation includes sections regarding review of the PPA rider, information sharing, risk sharing, and severabilit)' (Joint Ex. 1 at 5, 7-9, 35). Although we find, following our consideration of the evidence of record, that the factors and requirements from the ESP 3 Case have been thoroughly addressed by AEP Ohio in its testimony and by the signatory parties in the stipulation, the Commission believes that certain clarifications and modifications to the stipulation are necessary to ensure that the requirements from the ESP 3 Case are satisfied as fully intended by the Commission. Initially, regarding the requirement to include a plan to allocate the PPA rider's financial risk between AEP Ohio and ratepayers, the stipulation's lower fixed ROE and £100 million credit corrunitment, as well as the potential for disallowance of imprudent costs, are not a sufficient plan to allocate the rider's financial risk (Joint Ex. 1 at 5, 7, Att. A). We conclude, however, that, in combination with the other modifications adopted herein by the Commission, there is a proper sharing of financial risk between AEP Ohio and ratepayers, as well as an appropriate balance between legitimate customer concerns about prices and the interests of other stakeholders. We also clarify that AEP Ohio should not seek to recover any portion of the $100 million credit corrunitment from ratepayers in any future Commission proceeding. With respect to the terms of the stipulation's severabilit}' provision, we find that the prohibition on refunds, in the event of an invalidation of the PPA rider proposal, should be removed from the stipulation, as it is a matter for determination by the Commission or reviewing court (Joint Ex. 1 at 35).
V. Armual Prudency Review
The Commission emphasizes that we will conduct an armual prudency review of any retail charges flowing through the PPA rider. Section in.D.5.a addresses armual compliance reviews before the Commission to ensure that actions taken by AEP Ohio when selling the output from generation units included in the PPA rider into the PJM market were not unreasonable (Joint Ex. 1 at 7). In response to the concerns raised by certain intervenors, the Commission finds it necessary, at this point, to provide some clarity as to whether specific actions will be deemed not urueasonable for purposes of retail cost recovery. First, we will modify the stipulation to ensure that AEP Ohio, rather than ratepayers, will bear the burden of any Capacity Performance penalties, which will
APP. 460 14-1693-EL-RDR -88- 14-1694-EL-AAM not be considered prudent expenditures. AEP Ohio, therefore, should not seek to recover, through the PPA rider, any costs associated with Capacity Performance penalties. However, we will further modify the stipulation to provide that all Capacity Performance bonuses will be retained by AEP Ohio. Additionally, the Commission reserves the right to prohibit recovery of any costs related to any unit for any period exceeding 90 days for any forced outage during the term of the PPA rider, unless otherwise recommended by Staff and approved by the Conunission. We also direct that AEP Ohio should not flow through the PPA rider the net costs or revenues associated with AEPGR's obligations or entitlements with respect to Buckeye's Cardinal Units 2 and 3 under the CSA. Our decision is based solely on the record in these proceedings and does not preclude AEP Ohio from filing a supplemental application to include the net effects of Cardinal Units 2 and 3 in the PPA rider. We find that these modifications and clarifications will ensure that the stipulation is in the public interest and that financial risk is properly allocated.
We disagree with claims that the armual prudency review is inadequate or illusory. The aruiual review provided for under the stipulation is intended to address Staff's recommendations (Staff Ex. 1 at 17-18; Co. Ex. 52 at 2), and the Commission has always provided for the periodic review and reconciliation of riders created under an ESP. It is well-established that state commissions can review whether a utility prudently entered into a particular ttansaction in light of the alternatives. Pike County Light and Power Co. v. Pennsylvania Pub. Util. Comm., 77 Pa.Commw. 268, 465 A.2d. 735 (1983). FERC acknowledges the authorit)' of states to review the prudence of ttansactions. Duke Energy Retail Sales, LLC, 127 FERC ^ 61,027 (2009). This authority also has been recognized by federal courts:
Regarding the states' ttaditional power to consider the prudence of a retailer's purchasing decision in setting retail rates, we find no reason why utilities must be permitted to recover costs that are imprudently incurred; those should be borne by the stockholders, not the ratepayers. Although Nantahala underscores that a state cannot independently pass upon the reasonableness of a wholesale rate on file with FERC, it in no way undernunes the long-standing notion that a state commission may legitimately inquire into whether the retailer prudently chose to pay the FERC-approved wholesale rate of one source, as opposed to the lower rate of another source.
Kentucky West Virginia Gas Co. v. Pennsylvania Pub. Util. Comm., 837 F.2d 600, 609 (3d Cir. 1988) {citing Nantahala Poioer & Light Co. v. Thornburg, 476 U.S. 953 (1986)).
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Further, we note that AEP Ohio has consented to this review as an integral part of the PPA rider under the ESP pursuant to R.C. 4928.143, specifically including both the costs of generating power and the ttansactions involving the sale of the power into the PJM market (Joint Ex. 1 at 7). Kentucky West Virginia Gas Co., 837 F.2d at 617 (finding that utility could not complain about process used by Commission to which it had consented).
Some parties have raised the possibility that AEP Ohio would sell the output from the generation units included in the PPA rider to an affiliate at a below-market price. AEP Ohio has made it clear that its intent is to sell the energy, capacity, and ancillary services into the PJM markets and that any sales under a bilateral conttact would be subject to the Commission's review (Tr. XVIII at 4616-4617, 4655-4657; Tr. XIX at 4722-4724, 4735-4736). This is an issue of importance, considering the success of retail shopping. It is the desire of the Commission that such shopping continues. We emphasize that any bilateral ttansaction between AEP Ohio and any affiliate would be sttingently reviewed to ensure that it did not adversely affect retail electtic service competition in this state. The Commission notes that, consistent with Conunission precedent, AEP Ohio will bear the burden of proof in demonsttating the prudency of all costs and sales during the review, as well as that such actions were in the best interest of retail ratepayers; however, no presumption of management prudence will apply to any bilateral sales b}'' the Company to affiliates.
With respect to bidding behavior, the Corrunission is mindful of the issues raised by PJM in its brief. The Commission appreciates the continued investments in generation in our region by merchant generators. The Conamission notes that PJM could impose the very same bidding standards on all bidders, or all similarly-situated bidders, in PJM auctions rather than only on the plants at issue in these proceedings. We are not persuaded that the PPA plants should be held to different standards than other generation plants, particularly those in states that already provide for full cost recovery of generation plants. Retail cost recovery may be disallowed as a result of the annual prudency review if the output from the units was not bid in a manner that is consistent with participation in a broader competitive marketplace comprised of sellers attempting to maximize revenues. As noted above, AEP Ohio will bear the burden of proof in demonsttating that bidding behavior is prudent and in the best interest of retail ratepayers.
Regarding the process for ongoing Staff review and annual audits of the PPA rider, the Corrunission expects that the process will be carried out in a manner that is consistent with the process for AEP Ohio's prior fuel adjustment clause (FAC) mechanism. Accordingly, with respect to AEP Ohio's quarterly PPA rider filings, which should include appropriate work papers. Staff should review each such filing for completeness, computational accuracy, and consistency with any prior Commission determinations regarding the adjustments. If Staff raises no issues prior to the billing cycle during which the quarterly adjustments are to become effective, the adjusted PPA rider rates shall
APP. 462 14-1693-EL-RDR -90- 14-1694-EL-AAM become effective for that billing cycle. The PPA rider, however, remains subject to adjustment during the annual audit and reconciliation, through which Staff, or another auditor selected by the Corrunission, will review the accuracy and appropriateness oi the rider's accounting and the prudency of AEP Ohio's decisions and actions as set forth in the stipulation. In order to facilitate the audit of AEP Ohio's PPA rider filings, the Company should open a new case each year in which the Company should file its quarterly PPA rider adjustments and in which the audit report for that year should also be filed. The quarterly PPA rider adjustments should be filed on or before March 1, June 1, September 1, and December 1 of each year, unless otherwise agreed upon by Staff and AEP Ohio. AEP Ohio and Staff should work together to determine the specific content and format for the quarterly PPA rider filings. We also note that, as with AEP Ohio's FAC mechanism, interested stakeholders may seek to intervene and participate in the armual audit process, consistent with any established procedural schedule.
The stipulation provides that the PPA rider rate would be based initially on an armualized $4 million credit for 2016, subject to reconciliation (Joint Ex. 1 at 6). We find that this provision should be modified, such that the PPA rider rate remains at its current rate of zero through May 31, 2016. AEP Ohio is, therefore, authorized to flow the net effects of the OVEC PPA and the affiliate PPA through the PPA rider, begirming on June 1, 2016. As part of AEP Ohio's first quarterly adjustment filing that occurs on or before September 1, 2016, the Company should include a ttue-up to reflect actual values and an updated forecast of the PPA rider's projected impact, which should be based on the most recent data available to the Company. With its initial filing and aruiually thereafter, AEP Ohio will provide to Staff customer bill impacts and proposed rate mitigation measures, if necessary. With respect to legacy costs, the Commission directs AEP Ohio to provide to Staff audited accounting information establishing the amount of legacy costs. Further, the Commission directs the auditor in the first annual audit to verify the information provided by AEP Ohio to sen.'e as a baseline for future audits.
vi. Other Modifications and Clarifications
In response to the parties' arguments and recommendations, the Commission finds that a number of additional modifications and clarifications are necessary. As .J recorrunended by OEG, the Commission finds that any subsequent rejection of the PPA or the PPA-related stipulation provisions by a state or federal court should not be deemed to ttigger the PPA's liquidated damages provision (Joint Ex. 1 at Att. A). We also reserve the right to reevaluate or modify the PPA rider, without ttiggering the liquidated damages provision, if there is a change to PJM's tariffs or rules that prohibits the PPA units from being bid into PJM auctions. Finally, notwithstanding our approval of the PPA rider, we direct that AEP Ohio should not seek to recover, from ratepayers, the costs associated with any conversion, whether considered co-firing, refueling, or repowering, or the costs associated with the retirement, of the PPA uruts, through the PPA rider or any other cost
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recovery mechanism as recovery of such costs would not be consistent with the statutory framework set forth in R.C. 4928.143 or any other provision of R.C Chapter 4928. The stipulation's cost recovery provisions found in Sections III.D.9, IIl.D.lO, and III.D.12, except as pertaining to ttansmission upgrade costs or non-ttansmission alternative costs, should be modified accordingly (Joint Ex. 1 at 19-21, 26). Any potential depreciation rate changes remain subject to a prudence determination by the Commission, pursuant to Section ni.A.6 of the stipulation (Joint Ex. 1 at 9).
The Commission does not agree that certain provisions in the stipulation are nothing more than monetary inducements offered by AEP Ohio in exchange for the support of the signatory parties. The stipulation's provisions directing specific payments to OHA and OPAE require these parties, on behalf of Ohio hospitals and low-income customers, respectively, to take a number of steps to implement specific energy efficiency programs, and, as discussed above, energy efficiency measures provide significant customer benefits (Joint Ex. 1 at 13-16). The payments are, therefore, to be made in exchange for specific services and programs that add value to the stipulation as a package. The Corrunission acknowledges our prior admonition that direct payments to intervenors of a refund of prior payments are sttongly disfavored. In re Columbus Southein Pozoer Co. and Ohio Power Co., Case No. 05-376-EL-UNC, Order on Remand (Feb. 11, 2015) at 11-12. Although we do not agree that the payments to OHA and OPAE are analogous to the refunds provided to specific intervenors in that case, the Commission does find that it is appropriate to direct AEP Ohio, working in conjunction with OHA and OPAE, to file annual or more frequent compliance reports, with the initial report filed no later than December 31, 2016, confirming that the parties' conunitments set forth in the stipulation are being met. Thereafter, based upon the compliance reports, the Commission may order an independent audit of the funding. If such an independent audit is ordered, the independent auditor will be selected by the Commission, and the costs of the audits will be borne by A-EP Ohio, without recovery from ratepayers. AEP Ohio is directed to work with Staff to determine the appropriate scope and frequency of the compliance reports and audits. We note that, with respect to pa}^ments to other parties to promote energy efficiency programs, all energy efficiency savings obtained through such programs are thoroughly reviewed through the evaluation, measurement, and verification (EMV) process by AEP Ohio's independent EMV auditor, as well as the Commission's statewide EMV auditor.
As final matters, we note that provisions of the stipulation that purport to bind the Corrunission in the manner in vvhich it conducts its business, handles its dockets, or renders its decisions remain within the Commission's discretion. These include provisions addressing the Commission's tteatment of confidential information (Joint Ex. 1 at 7-8), the Commission's solicitation of conunents regarding long-term resource adequacy needs in the state (Joint Ex. 1 at 9), the Commission's consideration of renewable energy projects (Joint Ex. 1 at 31, 32), and the Commission's citation of the stipulation as precedent (Joint
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Ex. 1 at 34). Additionally, although the Commission has broad discretion with respect to rate design, we find that the provisions in the stipulation that would ttansfer certain costs from the EE/PDR rider to the EDR (Joint Ex. 1 at 16) are proposals that should be included in AEP Ohio's application to extend the ESP through May 31, 2024. The stipulation also provides that AEP, for the term of the PPA rider, intends to maintain its corporate headquarters in Columbus, Ohio, and will maintain a nexus of operations in the state relating to operation and support of the PPA units (Joint Ex. 1 at 16). We find that the stipulation should be clarified, such that, if AEP does not maintain its corporate headquarters in Columbus, Ohio, or a nexus of operations in the state, during the period of the PPA rider, the Conunission may determine, in its sole discretion, to terminate the rider. With these modifications and clarifications, the Commission finds that the stipulation, as modified, benefits ratepayers and the public interest, in accordance with the second prong of our test for the consideration of stipulations.
3. Does the settlement package violate anv important regulatory principle or practice?
a. Inttoduction
Initially, the Commission again emphasizes the complexity of the issues in these proceedings, as well as the necessity that we balance multiple interests. Moreover, the Commission must be cognizant of the state policies set forth in R.C. 4928.02. While we appreciate the issues raised by non-signatory parties, we find that the stipulation, as modified by the Commission, protects consumers against rate volatility and price fluctuations by promoting retail rate stability for all ratepayers in this state, modernizes the grid through the deployment of advanced technology and procurement of renewable energy resources, and promotes retail competition by enabling competitive providers to offer innovative products to serve customers' needs, consistent with state policy to ensure the availability to consumers of adequate, reliable, safe, efficient, non-discriminatory, and reasonably priced retail electtic service; to encourage innovation, including smart grid programs; to protect at-risk populations; and to facilitate the state's effectiveness in the global economy. R.C. 4928.02(A), (D), (L), and (N).
b. Statutory Authority
Several parties opposing the stipulation reason that the Commission lacks jurisdiction, under Ohio law, to approve the PPA rider and the stipulation, arguing the Commission's jurisdiction is limited to retail rates and services. OCC and APJN argue that it is the core responsibility of FERC, not the Corrunission, to protect consumers by overseeing the wholesale electtic markets. In light of FERC's exclusive federal jurisdiction, opposing intervenors aver that the Commission is without jurisdiction under Ohio law to approve the PPA rider. (OCC/APJN Br. at 16-19; OMAEG Br. at 16-20.)
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Opposing intervenors note that the Conunission determined that the PPA rider is a generation credit or charge. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 22. As such, non-signatory parties assert the Commission lacks the authority to approve the PPA proposal or the stipulation outside of an ESP proceeding and also lacks the authority to extend the PPA rider beyond the current ESP term. (P3/EPSA Br. at 57-60; RESA/Exelon Br. at 28-31.)
The Commission, in accordance with the requirements of R.C. 4928.143(B)(2)(d), approved the PPA rider mechanism in the ESP 3 Case but did not approve the recovery of any PPA costs. After concluding the PPA rider could be a provision of an ESP, the Corrunission ultimately determined that AEP Ohio's PPA proposal, which included only the OVEC entitlement, would not provide retail customers with sufficient benefit from the rider's financial hedging mechanism or any other benefit corrunensurate with.the rider's potential cost. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 21, 25. Recognizing that AEP Ohio had pending before the Commission, in the above-entitled matters, the initial application to incorporate an additional PPA in the PPA rider mechanism, the Comrrussion established the PPA rider as a placeholder, at an initial rate of zero, for the term of the ESP and directed that implementation details would be determined in a future proceeding. ESP 3 Case at 19, 25. The Commission finds that the present PPA proceedings are, therefore, an outcome of the ESP 3 Case, in order to facilitate a more in-depth review of the Company's PPA proposal, and, if approved by the Commission, to populate the rate in the PPA rider. This process is consistent with other ESP proceedings where the Commission has approved zero placeholder riders and subsequently populated the rate of the rider. In re Columbus Southern Power Co. and Ohio Power Co., Case No. 11-346-EL-SSO, et al. (ESP 2 Case), Opinion and Order (Aug. 8, 2012) at 24-25; In re Duke Energy Ohio, Inc., Case No. 08-920-EL-SSO, et al.. Opinion and Order (Dec. 17, 2008) at 17; In re FirstEnergy, Case No. 08-935-EL-SSO, et al.. Second Opinion and Order (Mar. 25, 2009) at 15.
Accordingly, the Commission does not believe it is sttictiy necessary, in these rider proceedings, to reassess the statutor)' basis for the PPA rider. Nonetheless, in response to the parties' arguments, we will affirm that the PPA rider mechanism can be included as a provision of an ESP, based on the record before us. Tongren v. Puh. Util. Comm., 85 Ohio St.3d 87, 706 N.E.2d 1255 (1999). The Commission finds that the PPA rider mechanism, as proposed in the amended application and the stipulation, meets the three requirements set forth in R.C 4928.143(B)(2)(d). See, e.g., ESP 2 Case, Entty on Rehearing (Jan. 30, 2013) at 15-16; In re Dayton Poiver and Light Company, Case No. 12-426-EL-SSO, et al.. Opinion and Order (Sept. 4, 2013) at 21-22. R.C 4928.143(B)(2)(d) dictates that a component of an ESP must be a term, condition, or charge relating to limitations on customer shopping for retail electtic generation service, bypassability, standby, back-up, or supplemental power service, default service, carrying costs, amortization periods, and accounting or deferrals, including future recovery of such deferrals, as would have the effect of stabilizing or providing certainty regarding retail electtic service. The PPA rider, as presented in the
APP. 466 14-1693-EL-RDR -94- 14-1694-EL-AAM amended application and the stipulation, is a credit or charge that would appear on customers' bills (Co. Ex. 52 at Ex. WAA-2). Thus, the Commission concludes that the first requirement of R.C 4928.143(B)(2)(d) is met, as the PPA rider would consist of a charge or credit incurred by customers under the ESP.
To be an element of an ESP, R.C. 4928.143(B)(2)(d) also requires that the PPA mechanism relate to at least one of the following: limitations on customer shopping for retail electtic generation service, bypassabilit}', standby, back-up, or supplemental power service, default service, carrying costs, amortization periods, and accounting or deferrals. The PPA rider, as presented in the amended application and the stipulation, is non- b)'passable and would operate as a financial limitation on customer shopping for retail electtic generation ser\'ice. The effect of the PPA rider is that the bills of all customers would reflect a price for retail electtic generation service that is approximately 30 percent based on the cost of service of the PPA units and 70 percent based on the retail market, thus functioning as a financial hedge against complete reliance on the retail market for the pricing of retail electtic generation service. The PPA mechanism proposed in the amended application and the stipulation includes approximately 3,100 MW of generation, a significantly greater amount than the level of the OVEC entitlement alone, as initially proposed in the ESP 3 Case. (Co. Ex. 2 at 15-19; OEG Ex. 1 at 10; Tr. XVII at 4249, 4378; Tr. XX at 5062.)
Finally, R.C. 4928.143(B)(2)(d) requires that the charge have the effect of stabilizing or providing certainty regarding retail electtic service. The PPA rider proposed in the amended application and the stipulation would operate as a financial hedging mechanism, with the effect of stabilizing or providing certainty regarding retail electtic service. The PPA rider would smooth out fluctuations in market prices, because the rider would rise or fall in a way that is counter cyclical to the wholesale market. The PPA rider, therefore, is intended to mitigate, by design, the effects of market ^'olatilit}', providing customers with more stable retail pricing and a measure of protection against substantial increases in market prices, with quarterly reconciliations to actual costs and revenues. The record reveals that, on a demand or capacity basis, the PPA rider proposed in the amended application and the stipulation would equate to retail electtic rates that are based approximately 30 percent on the cost of service and 70 percent on the market. Thus, the Conunission reasons, consistent with the ESP statute, that the PPA rider mechanism is capable of stabilizing retail electtic rates. (Co. Ex. 1 at 8-10; Co. Ex. 2 at 11-21, Ex. KDP-2; Co. Ex. 6 at 5; Co. Ex. 10 at 7-8, Ex. WAA-2; Co. Ex. 51 at 2-3, 4-5, 7-8, Ex. WAA-R3; Co. Ex. 52 at Ex. WAA-2; OEG Ex. 1 at 10, 13; MAREC Ex. 1 at 6-7; Tr. II at 543; Tr. XVIII at 4568- 4569, 4574; Tr. XX at 4978.)
Consistent with the requirements of R.C. 4928.143(B)(2)(d), the Commission's objective is to ensure sufficient and adequate oversight of the costs to be incurred and the benefits to be received by AEP Ohio's retail customers, both shopping and SSO, through
APP. 467 14-1693-EL-RDR -95- 14-1694-EL-AAM the PPA rider. The record reveals that shopping has been robust in AEP Ohio's service territory, with approximately 51 percent and 52 percent of commercial and industtial customers, respectively, receiving electtic service from a CRES provider, while more than 32 percent of residential ratepayers are shopping customers, as of June 30, 2015 (Co. Ex. 38). CRES rates, as reflected in the retail conttact offers for residential customers, reflect a level of volatility that would be reduced by the PPA rider (Co. Ex. 51 at 3-5). While we find that the PPA rider is a financial limitation on customer shopping pursuant to the requirements of R.C. 4928.143(B)(2)(d), the rider does not prohibit or otherwise curtail customers from securing their electtic service from a CRES provider nor will the rider resttict current CRES customers. Shopping and SSO customers are not captive customers. In other words, customers will continue to have the ability to select a CRES provider or return to the SSO. The PPA mechanism is intended to act merely as a financial hedge for shopping and SSO customers against price changes in the retail market.
c. State Policy
Regarding the third part of the three-part test, AEP Ohio witness Allen testified that the stipulation does not violate any important regulatory principle or practice. Mr. Allen further testified that the stipulation, as a compromise among the diverse group of signatory parties, promotes the state policy provisions set forth in paragraphs (A), (B), (C), (D), (E), (J), (L), and (N) of R.C. 4928.02.' Mr. Allen added that the stipulation advances important regulatory policies and practices by providing a hedge against rising energy prices; promoting competitive service offerings, diversity of suppliers, and advancements in technology for infrasttucture and efficient information access; increasing energy efficiency; and addressing the resolution of other regulatory matters often considered by the Commission. (Co. Ex. 52 at 1,12-13; Co. Br. at 109.)
Several intervenors opposing the PPA rider and the stipulation argue they violate various state policy provisions of R.C. 4928.02. OCC and APJN contend that the stipulation carmot meet the third prong of the test, as the stipulation advocates for the ttansfer of 50 percent of the costs associated with the IRP credits from the EE/PDR rider to the EDR. OCC and APJN claim the ttansfer is not reasonable and would cause harm to residential customers. OCC and APJN reason that, with the ttansfer approved, costs will not be allocated on the principle of cost causation and, therefore, the proposal is not reasonable under R.C 4928.02(A). OCC and APJN also submit approval of the PPA rider would result in the cross-subsidization of generation by disttibution customers, conttary to R.C. 4928.02(H). ELPC, EDF, and OEC argue the PPA rider is inconsistent with the promotion of effective competition in the retail market, as set forth in R.C 4928.02(H). (OCC/APJN Br. at 68-69; ELPC/EDF/OEC Br. at 55.)
AEP Ohio states the continuing porttayal of the PPA rider as conttary to Ohio law and policy by opposing intervenors directly conttadicts the Corrunission's decision in the
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ESP 3 Case and should be rejected again. Staff also submits that the stipulation does not violate any important regulatory principle or practice and promotes the state policies hsted in paragraph (A), (C), (D), (E), (J), (L) and (N) of R.C. 4928.02. The Company advises that the supplier consolidated billing pilot is intended to squarely address the policies advocated in R.C. 4928.02(C) and (E) to encourage customer choice and the IRP tariff is intended to address the policies advocated in R.C 4928.02(N) and to advance economic development in Ohio. The Company notes, in the ESP 3 Case, the Commission determined the PPA rider is a generation-related rider recovering generation-related costs. Elyria Foundry Co. v. Pub. UtiL Comm., 114 Ohio St.3d 305, 2007-Ohio-4164, 871 N.E.2d 11, 1j 50; ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 21, 26. (Co. Br. at 108-109; Co. Reply Br. at 12, 81-82; Stafl Br. at 13-14.)
Pursuant to R.C. 4928.02(A), it is the policy of the state of Ohio to ensure the availability to consumers of adequate, reliable, safe, efficient, non-discriminatory, and reasonably priced retail electtic service. The PPA rider is another mecharusm that may be used to stabilize retail electtic rates and ensure reasonably priced retail electtic service. R.C. 4928.02(H) requires the Commission to ensure effective competition in the provision of retail electtic service by avoiding anticompetitive subsidies. The Conunission finds that the PPA rider mechanism, as modified in this Opinion and Order, is consistent with that state policy and the remainder of R.C. 4928.02. The PPA rider mechanism, as adopted herein, will avoid Ohio retail customers' total reliance on market-based pricing and weather exttemes. Accordingly, the Commission believes adoption of the PPA rider continues to be consistent with our obligation under R.C. 4928.02(A) to ensure the availability to consumers of reasonably priced retail electtic service. We reject claims the PPA rider would violate R.C 4928.02(H). Conttary to the arguments of opposing intervenors, the PPA rider mechanism does not facilitate the recovery of generation- related costs through disttibution or ttansmission rates. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 26.
The Commission is not convinced by the claims of several parties that the PPA rider is anticompetitive. Initially, we note that wholesale competition and retail competition are different. Wholesale competition involves generators of power selling energy, capacity, and ancillary services into the PJM market. Retail competition involves CRES suppliers reselling power purchased from the wholesale market to retail consumers.
The PPA rider is non-bypassable and, thus, will have the same impact on shopping customers' bills as on SSO customers' bills. The PPA rider creates no advantage to shopping and no disadvantage to shopping. Likewise, the PPA rider has the same impact on a shopping customer irrespective of which CRES provider serves the customer and irrespective of whether the customer is part of an aggregation or served individually by a CRES provider. Further, AEP Ohio will continue to source all of the SSO load through competitive auctions. Accordingly, we find that the PPA rider is consistent with the state
APP. 469 14-1693-EL-RDR -97- 14-1694-EL-AAM policy to "[ejnsure the availability of unbundled and comparable retail electtic service that provides corisumers with the supplier, price, terms, conditions, and quality' options they elect to meet their respective needs." R.C 4928.02(B).
We are mindful, however, of concerns that AEP Ohio may enter into bilateral conttacts with an affiliate in order to give the affiliate a competitive advantage. As an initial matter, AEP Ohio witness Allen testified that the Company intends to sell the energy and capacity in PJM's markets and does not expect to enter into bilateral conttacts (Tr. XVIII at 4617, 4655-4657; Tr. XIX at 4736). Nonetheless, as discussed above, there are imposed safeguards in the annual prudency review process to protect against anticompetitive behavior by AEP Ohio. Any bilateral conttacts between AEP Ohio and an affiliate will be sttingently reviewed, and no presumption of management prudence will apply to a bilateral sale to an affiliate. These protections are more than sufficient to protect against anticompetitive subsidies under R.C. 4928.02(H).
d. IRP Program
OMAEG argues that, in Section III.C.7 of the stipulation, AEP Ohio proposes to expand the IRP tariff and increase the credit offered to current IRP customers. Under certain conditions, OMAEG argues AEP Ohio proposes to expand the MW available through the IRP to signatory parties and non-opposing parties only, without any record support. OMAEG contends there is no logical reason for AEP Ohio to propose to broaden the IRP tariff eligibility and to increase credits for signatory parties and non-opposing parties. According to OMAEG, non-signatory parties also have the ability to implement demand response programs and making the program available to a select class is anticompetitive. OMAEG also argues that the increase in the credit is significant, at an estimated additional cost to customers of $27.1 million, and inconsistent with the Company's claims in the ESP 3 Case, where AEP Ohio argued the level of interruptible credits should be maintained.^^ (OMAEG Br. at 58-61.)
ELPC, OEC, and EDF assert that Section III.Cll of the stipulation violates R.C. 4928.6613. According to ELPC, OEC, and EDF, R.C. 4928.6611 to 4928.6613 permit certain utility customers to opt out of a utility's EE/PDR portfolio plan and exempt the customer from the associated cost of the utility's EE/PDR programs. Opposing intervenors interpret Section III.Cll of the stipulation to permit IRP customers to opt out of the obligation to pay for the EE/PDR rider but still participate in the interruptible tariff and receive the associated credit. (ELPC/OEC/EDF Br. at 57-58.)
In reply, AEP Ohio declares that there is no conflict between a customer's participation in the IRP tariff and the customer's exercise of the opt-out provision under
32 ESP 3 Case, Second Entry on Rehearing (May 28, 2015) at 8.
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R.C. 4928.6612. According to AEP Ohio, the IRP tariff existed prior to the enactment of S.B. 310 and has remained available to customers taking interruptible service. As to the reallocation of a share of the cost of the credits provided under the IRP tariff to the EDR, as provided in the stipulation, AEP Ohio contends that the portion of the cost of those credits being recovered via the EE/PDR rider has likewise been reduced by the same amount and the mechanism for recovery aligned with the purpose of the tariffs and the credits. AEP Ohio believes it is noteworthy that the IRP credits are not addressed by or funded through the current EE/PDR portfolio plan. (Co. Reply Br. at 114-115.)
In its reply brief, lEU-Ohio notes that a component of the stipulation is AEP Ohio's agreement to file an ESP application by April 30, 2016, to extend its ESP through May 31, 2024. Among the provisions AEP Ohio has agreed to include in the ESP application is a provision to expand the. scope of the IRP tariff and. to increase the credit rate. lEU-Ohio submits that the provisions cited by ELPC/OEC/EDF and OMAEG are also provisions to be included in the ESP application to be filed by AEP Ohio. Accordingly, lEU-Ohio reasons that the provisions of the stipulation that ELPC/OEC/EDF and OMAEG oppose are not ripe for review. Further, lEU-Ohio avers that ELPC/OEC/EDF's premise is incorrect. lEU-Ohio states that the IRP is not part of the EE/PDR plan and notes that, if ELPC/OEC/EDF's arguments were accepted, it would reduce the incentive for customers with demand response capabilities to make those capabilities available to AEP Ohio, causing injury to other customers and likely reducing system reliabilit}'. Similarly, lEU- Ohio argues OMAEG's position is internally contradictory and unsupported by the record. (lEU-Ohio Reply Br. at 2-8.)
The Commission rejects the claims and arguments of ELPC/OEC/EDF and OMAEG. The provisions that opposing intervenors cite are provisions to be included in AEP Ohio's next ESP application, as required by the stipulation, and, for that reason, ELPC/OEC/EDF's and OMAEG's arguments regarding the provisions are premature. The Commission finds that it is not a violation of an important regulatory principle or practice for the stipulation to enumerate provisions to be included in a subsequent filing. Additionally, interested parties will be able to raise their issues in the future proceeding, which the Commission will decide based on the record. Accordingly, we reject the claims of ELPC/OEC/EDF and OMAEG that the IRP provisions of the stipulation violate an important regulatory principle or practice.
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e. Allocation of Costs and Credits
OCC and APJN argue that PPA rider credits and charges should not be allocated based on the PJM five monthly peak demands, which, in OCC/APJN's opinion, unfairly and arbittarily assigns a disproportionate share of the rider's cost to residential customers. OCC and APJN advocate allocation of the PPA rider cost based on a combination of demand and energy, netting the difference between the costs and the sales of the generation products. OCC and APJN also argue that the ttansfer of 50 percent of certain costs associated with the IRP credits from the EE/PDR rider to the EDR would violate the principle of cost causation. (OCC/APJN Br. at 68-69.)
Sirrularly, Kroger argues the PPA rider rate design is not fair to all customers, particularly high load factor customers like Kroger. Kroger notes the predominant costs to be included in the PPA rider are demand related costs and, therefore, argues costs should be allocated to the rate classes and recovered in a similar manner. Kroger asserts the PPA rider's cost allocation is a violation of the principle of cost causation. (Kroger Br. at 4-5.)
The Company averts the opposing parties' criticism of the rate design presented in the stipulation, by noting that the Ohio Supreme Court has recognized the Commission's "considerable discretion in matters of rate design." Indus. Energy Users-Ohio v. Ohio Poiver Co., 140 Ohio St.3d 509, 2014-Ohio-4271, 20 N.E.3d 699, 1| 27, citing Consumers' Counsel v. Puh. Util. Comm., 125 Ohio St.3d 57, 2010-Ohio-134, 926 N.E.2d 261, ^ 20; Citywide Coalition for Util. Reform v. Pub. Util. Comm., 67 Ohio St3d 531, 534, 620 N.E.2d 832 (1993). Conttary to OCC/APJN's opposition to the stipulation's proposal to ttansfer certain costs from the EE/PDR rider to the EDR, AEP Ohio notes that, in the ESP 3 Case, OCC argued just the opposite - that the IRP credits should be collected through the EDR to assure that the costs of those credits are borne by all customers and, otherwise, mercantile customers who are receiving the benefits of the IRP may opt out of the EE/PDR rider. AEP Ohio argues- it is disingenuous for OCC to now argue that the proposed tteatment of IRP credits violates any regulatory principle or practice. The Company argues OCC witness Fortney changed his position as set forth in written testimony and throughout the course of his testimony at hearing. AEP Ohio states it is inappropriate to modify the cost allocation in the stipulation in the absence of any analysis to support OCC's position. (Co. Br. at 152-154; Co. Reply Br. at 118-120.)
Section III.A.4 of the stipulation specifies the rate design for the PPA rider (Joint Ex. 1 at 6). At Sections II1.D.4 and III.D.5 of the stipulation, AEP Ohio stipulates to the ttansfer of certain costs from the EE/PDR rider to the EDR, upon the approval of the stipulation, ultimately revising the rate design (Joint Ex. 1 at 16). The Commission is vested with broad discretion on issues of rate design. Indus. Energy Users-Ohio v. Ohio Power Co., 140 Ohio St.3d 509, 2014-Ohio-4271, 20 N.E.3d 699, T{ 27. We, therefore, reject arguments raised by OCC, APJN, and Kroger regarding the PPA rider's rate design. Further, the
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Commission has previousl}' recognized that the IRP program offers numerous benefits, including the promotion of economic development and the retention of manufacturing jobs. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 40. Accordingly, given the Conunission's considerable discretion with respect to rate design, we find it would not violate an important regulatory principle or practice, if a share of the IRP credits is collected via the EDR, and, in any event, we have directed AEP Ohio to include the stipulation's cost ttansfer provisions in its extended ESP application.
f. Corporate Separation
Several intervenors aver the amended PPA apphcation and the stipulation violate R.C 4928.17, the corporate separation statute. Non-signatory inter\'enors reason that AEP Ohio ttansferred its generation assets to AEPGR and AEPGR engages in sales for resale as a FERC-regulated entity. lnter\'enors opposing the PPA argue that, as shown in the revised affiliate PPA, AEP Ohio would be a" member of the operating corrunittee, along with AEPGR and AEPSC, with oversight of the operations and other significant issues related to the PPA units. Dynegy argues that the PPA proposal essentially puts AEP Ohio back into the generation business, in violation of R.C 4928.17. Further, several intervenors contend the existing code of conduct does not adequately address AEP Ohio's direct involvement with the generation units. According to certain intervenors, the PPA proposal and the stipulation make it clear that the statutorily required separation between competitive and non-competitive sendees will not be maintained and, for that reason alone, the Corrunission cannot approve AEP Ohio's amended PPA application and the stipulation. Dynegy also submits that the stipulation violates AEP Ohio's open access disttibution tariff, which directs that AEP Ohio not tie or otherwise "condition the provision of the Company's regulated services * * * to the taking of any goods and/or services from the Company's afflliates." (RESA/Exelon Br. at 45-49; P3/EPSA Br. at 60-62; Dyneg}'Br. at33-35.)
AEP Ohio notes that a complaint has been filed with FERC and, therefore, believes the Commission should not interfere with FERC's adjudication of the complaint or attempt to apply FERC requirements. However, AEP Ohio submits that opposing parties misrepresent FERC's application of the Edgar standard in AEP Generation Resources, Inc., 145 FERC ^ 61,275 (2013). AEP Ohio argues, conttary to the claims of interveners, that FERC declined to apply the Edgar standard on the basis that the power supply agreement was a short-term agreement for a ttansition period that supports this Commission's resttucturing efforts. Furthermore, AEP Ohio states that, subsequently, FERC granted AEP Ohio a waiver on affiliate sales ttansactions, including the Edgar standard, in FERC Docket No. ER14-593-000, et al., on February 5, 2014. Thus, AEP Ohio reasons it is not required to obtain FERC approval to enter into the revised affiliate PPA as referenced in the stipulation. (Co. Reply Br. at 94-97.)
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AEP Ohio claims that the arguments asserting approval of the PPA rider and stipulation would violate R.C. 4928.17 are fundamentally flawed. AEP Ohio avers that the prefatory language in R.C. 4928.17 makes it clear that the corporate separation mandates do not apply to items authorized in the ESP statute, R.C. 4928.143. According to the Company's interpretation of the statutes, R.C 4928.143(B)(2)(d) permits provisions relating to "limitations on customer shopping for electtic generation service" as part of an ESP. Accordingly, AEP Ohio reasons that interveners' arguments to the conttary corrflict with this explicit exception. Furthermore, AEP Ohio offers that nothing in the ESP statute refers to competitive generation service and none of the services provided by an EDU under the ESP are competitive services, nottA'ithstanding that they include generation, and a non-bypassable stability charge under the ESP statute, like the PPA rider, carmot be considered a charge for competitive service. AEP Ohio also notes that the interveners' corporate separation theory conflicts with R.C. 4928.143(B)(2)(b) and (B)(2)(c), as those provisions contemplate non-bypassable generation charges for all shopping and non- shopping customers relating to newly-built capacity. AEP Ohio argues that opposing intervenors have not established any actual problem or violation with the approved corporate separation plan or the affiliate code of conduct and, should such issues arise, the Company states the Conunission is fully capable of enforcing AEP Ohio's corporate separation plan and the code of conduct rules. (Co. Reply Br. at 110-113.)
As noted in the section of this Opinion and Order addressing issues of preemption, and consistent v-'ith the Conunission's determination in the ESP 3 Case, we will not address the federal constitutional issues put forth by the parties in these proceedings, as we conclude such arguments are best reserved for judicial determination. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 26.
In regard to the claim that the PPA rider and stipulation violate AEP Ohio's code of conduct in its open access disttibution tariff, the Commission finds that the argument overlooks the basic premise that the PPA rider operates as a financial hedge for retail customers, not as a physical hedge. Ohio retail customers will not receive the physical generation from the PPA units. The energy, capacity, and ancillary services from the PPA uruts would be sold into the PJM markets and, after accounting for costs, the net credit or charge would flow through the PPA rider to customers. In this manner, AEP Ohio's regulated services are not linked to the goods or services from AEPGR. The Commission finds that the opposing inter\'enors' claims that the PPA rider and the stipulation would violate the corporate separation requirements of R.C 4928.17 also lack merit. We conclude that R.C. 4928.17 sets forth a number of corporate separation provisions that generally apply to AEP Ohio as an electtic utility. However, the statute mandates certain exceptions, providing that an electtic utility's compliance is required, "[ejxcept as otherwise provided in sections 4928.142 or 4928.143 * * * of the Revised Code." Having determined in these proceedings, as well as the ESP 3 Case, that a PPA rider is authorized
APP. 474 14-1693-EL-RDR -102- 14-1694-EL-AAM pursuant to R.C 4928.143(B)(2)(d), the Commission finds opposing interveners' arguments regarding R.C. 4928.17 misplaced. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 19-26.
g. Transition Revenues
OCC and APJN assert that the PPA rider is in violation of R.C. 4928.38, which prohibits an electtic utility from receiving ttansition revenues, also referred to as sttanded costs, from the start of CRES through the end of the market development period. At this point, OCC and APJN posit that AEP Ohio is required to operate fully on its own in the competitive market. OCC and APJN reason that the PPA rider is based on collecting above market revenues from AEP Ohio's ratepayers, which will ultimately be ttansferred to AEPGR, an unregulated affiliate and owner of the PPA units, to ensure a guaranteed return on and of AEPGR's investment. (OCC/ APJN Br. at 98-100.)
The Company notes that the Corrunission previously rejected OCC/ APJN's ttansition cost argument in the ESP 3 Case and argues that OCC/APJN's claims mischaracterize the PPA rider. AEP Ohio offers that the record in these cases demonsttates that customers are expected to receive a net quantitative benefit over the term of the PPA and there is no legal or factual basis to support the notion that the PPA units are sttanded investments. AEP Ohio asks that the Commission reject this argument again. (Co. Br. at 106-107.)
The Commission disagrees that the PPA rider would permit AEP Ohio to collect untimely ttansition costs in violation of R.C. 4928.38. As we determined in the ESP 3 Case, the PPA rider constitutes a rate stability charge related to limitations on customer shopping for retail electtic generation service and may, therefore, be authorized pursuant to R.C 4928.143(B)(2)(d). ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 26. Nothing in the amended PPA application or the stipulation changes the Commission's position on this issue.
h. Preemption
In various ways, opposing intervenors challenge the Commission's jurisdiction to consider AEP Ohio's amended PPA application and the stipulation. Opposing intervenors contend the Commission's approval of the PPA proposal, as it stands in both the amended PPA application and the stipulation, is field and conflict preempted under the Federal Power Act and would interfere with FERC's exclusive jurisdiction ever the wholesale markets.33 Opposing parties argue that the affiliate PPA, under which AEPGR would sell to AEP Ohio the capacity, energy, and ancillary services generated by the PPA units, is a wholesale ttansaction that falls exclusively under federal jurisdiction. For example, OCC and APJN reason that, because the PPA rider would provide AEP Ohio with a fixed
33 16U.S.C. §824etseq.
APP. 475 14-1693-EL-RDR -103- 14-1694-EL-AAM amount for the energy and capacity sold in the PJM markets, which is a wholesale ttansaction, the Commission is preempted from approving the PPA proposal. OCC and APJN emphasize that the sale would be revenue neuttal to AEP Ohio, meaning that the sale is fixed at the conttact price of the PPA. (OCC/APJN Br. at 16-22.)
ELPC, EDF, and OEC submit that AEP Ohio has failed to meet the requirements of FERC's test for affiliate agreements and corporate separation requirements under R.C 4928.17(A)(3), as well as other standards requiring the Company to demor^ttate that the revised affiliate PPA does not provide anticompetitive advantages or a financial subsidy. Opposing parties note FERC's concern in Edgar with affiliate agreements or ttansactions, where the utility may give unduly favorable terms to an affiliate because higher profits can accrue to conunen shareholders. OMAEG declares that Commission approval of the PPA rider and associated cost recovery usurps FERC's exclusive jurisdiction to regulate the wholesale power market, including the wholesale capacit)' market. According to OMAEG, FERC's jurisdiction includes the reasonableness of wholesale rates and the rules or practices affecting wholesale rates. Accordingly, OMAEG reasons the Commission is preempted under the supremacy clause from approving the PPA proposal and adopting the stipulation, citing Nazarian and Solomon. (OMAEG Br. at 16-20; P3/EPSA Br. at 65-66; ELPC/EDF/OEC Br. at 56-57.)
In the ESP 3 Case, the Commission acknowledged the parties' arguments on the issue of federal preemption. We declined, however, to address constitutional issues, noting that, under the specific facts and circumstances of the proceedings, such issues are best reserved for judicial determination. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 26. Recognizing that, on October 19, 2015, the U.S. Supreme Court granted a petition for a writ of certiorari to review Nazarian^^ and that a complaint has been filed at FERC in regard to these proceedings,35 we continue to find it appropriate to defer questions of constitutionality for determination by the courts. Therefore, to the extent that the facts and circumstances of these cases would require the Commission to address constitutional issues as raised by the parties, we reiterate and confirm that such arguments are best reserved for judicial determination.
i. Commission Decision
The Commission recognizes that opposing intervenors have put forth numerous arguments that several specific provisions of the stipulation violate an important regulatory principle or practice. In accordance with this component of the test, as recognized by the Supreme Court of Ohio, the Commission must determine whether the stipulation package violates any important regulatory principle or practice. In light of our
34 Hughes V. PPL EnergyPlus, LLC, 136 S.Ct. 382 (2015). 35 FERC Docket No. EL16-33-000.
APP. 476 14-1693-EL-RDR -104- 14-1694-EL-AAM consideration of the specific provisions of the stipulation presented as discussed above, the Commission finds that the stipulation, in whole, and as modified herein, dees not violate any important regulatory principle or practice and, therefore, complies with the third criterion of the test for evaluating the reasonableness of stipulations.
4. ESP/MROTest
In its brief, AEP Ohio contends that the PPA rider will constitute an additional quantitative and qualitative benefit of the ESP that can be added to the benefits that the Commission already recognized in finding that the Company's ESP is more favorable than an MRO in the ESP 3 Case. Specifically, AEP Ohio asserts that, even before considering the many qualitative benefits that will flow from approval of the PPA rider, the Company's projections reflect that the rider will provide a net quantitative benefit to customers of more than $209 million over the current ESP term through May 31, 2018. AEP Ohio asserts that, because the net positive impact of the PPA rider will make the ESP that much more favorable in the aggregate than the expected results of an MRO, it is urmecessary for the Commission to conduct another ESP/MRO test, as long as the Commission agrees that the rider is a net benefit for customers. AEP Ohio concludes that it is a simple matter of arithmetic to add the net positive benefits of the PPA rider proposal to the existing net positive results of the ESP/MRO test conducted in the ESP 3 Case. (Co. Br. at 131-133; Co. Reply Br. at 84-86.)
RESA, Exelon, P3, and EPSA argue that the Commission should determine that an ESP/MRO analysis must be conducted in these proceedings and find that there is insufficient evidence as to whether, with AEP Ohio's PPA proposal in place, the Company's current ESP is more favorable in the aggregate than an MRO. RESA, Exelon, P3, and EPSA note that AEP Ohio did not present a formal ESP/MRO analysis addressing quantitative and qualitative factors or the results of a competitive bid process that would demonsttate the market rate. RESA and Exelon assert that OCC witness Wilson's projected net cost over the current ESP term, coupled with AEP Ohio witness Allen's admission that the PPA rider's impact is likely to fall somewhere between the five percent higher and lower load cases, show that, even if the PPA proposal could be quantified in reliable fashion, the ESP would no longer be more favorable than an MRO, particularly in light of the rider's significant unknown risks that outweigh any qualitative benefits of the ESP. P3 and EPSA add that the Conunission does not have the authority to implement the PPA rider for a time period beyond the current ESP 3 term, because the Commission carmot perform the ESP/MRO analysis without a future ESP proposal pending before the Commission. (RESA/Exelon Br. at 36-38; P3/EPSA Br. at 33-34, 45-46, 51-52; RESA/Exelon Reply Br. at 11-16.)
OMAEG asserts that the Commission should evaluate the PPA rider's impact on the ESP/MRO test. OMAEG notes that, based on OCC wimess W^ilson's analysis, the
APP. 477 14-1693-EL-RDR -105- 14-1694-EL-AAM forecasted cost of the PPA rider for the current ESP term is $580 million, which, when factored into the Commission's application of the test in the ESP 3 Case, renders the ESP less favorable than an MRO. (OMAEG Br. at 61.) Claiming that only quantitative factors should be considered under the statutory test, OCC and APJN argue that the PPA proposal must be rejected, because its projected cost of $580 million would cause the ESP to fail the statutory test by $527 million and, in any event, there are significant, unknown costs associated with the stipulation's other provisions, which have not been quantified by AEP Ohio (OCC/APJN Br. at 160-163; OCC/APJN Reply Br. at 35-37).
The Commission notes that, although this is not an ESP case and, therefore, the ESP/MRO test does not apply here, we will nevertheless address the test in the present proceedings, in order to consider and resolve the parties' arguments on this issue. In light of our above finding that the stipulation, including the PPA rider proposal, will result in a net benefit for customers, we agree with AEP Ohio's assertion that the Company's ESP, which is currently approved to continue through May 31, 2018, remains more favorable than the expected outcome uiider an MRO. In the ESP 3 Case, we determined that the ESP, including its pricing and all other terms and conditions, including any deferrals and any future recovery of deferrals, as modified by the Corrunission, is more favorable in the aggregate as compared to the expected results that would otherwise apply under R.C. 4928.142. With respect to the quantitative benefits of the ESP, the Conunission found that the ESP, as modified, results in a total of $53,064,000 in quantifiable benefits over the ESP term that would not be possible under an MRO. ESP 3 Case, Opinion and Order (Feb. 25, 2015) at 94-95, Second Entty on Rehearing (May 28, 2015) at 51-52, 55-57.
AEP Ohio's projection, under the weather normalized case, indicates that the PPA rider is expected to provide a net quantitative benefit to customers of $37 million over the current ESP term through May 31, 2018, or $214 million over the term of the PPA rider (Co. Ex. 52 at Ex. WAA-2). W^ith the stipulation's numerous other quantitative and qualitative benefits,36 as well as our modifications to the stipulation to ensure that ratepayers will benefit from the PPA rider, we do not agree with the non-signatory parties' contention that the PPA proposal in the stipulation upsets the positive results of our previous ESP/MRO analysis. As AEP Ohio correctly asserts, when the net positive benefit of the PPA rider proposal is combined with the existing net positive results of the ESP/MRO test conducted by the Commission in the ESP 3 Case, the result must remain,, as a matter of basic addition, a net benefit, with the ESP becoming that much more favorable in the aggregate than the expected results of an MRO. We, therefore, reject the non- signatory parties' arguments on this issue.
36 The Commission has previously rejected OCC/APJN's argument that only quantitative factors may be considered in the ESP/MRO analysis. See, e.g., ESP 3 Case, Opinion and Order (Feb, 25, 2015) at 94, Second Entry on Rehearing (May 28, 2015) at 56-57; see also In re Columbus Southern Power Co., 128 Ohio St.3d 402, 2011-Ohio-95S, 945 N.E.2d 501.
APP. 478 14-1693-EL-RDR -106- 14-1694-EL-AAM
V. CONCLUSION
Upon consideration of the record in these proceedings, the Commission finds that the stipulation entered into by the signatory parties is reasonable and should be adopted, with the modifications set forth in this Opinion and Order. Accordingly, we further find that the amended application filed by AEP Ohio on May 15, 2015, should be approved as modified by the stipulation and further modified by this Opinion and Order. The Commission notes that, following the conclusion of rehearing, the filing of tariffs consistent with this Opinion and Order, including its modifications to the stipulation, shall be deemed as acceptance of the Order and the modifications by AEP Ohio. Any such acceptance, however, will be subject to rights of appeal under R.C. Chapter 4903. As a final matter, the Commission notes that any argument, request for modification of the stipulation, or pending motion that has not been specifically addressed in this Opinion and Order has been thoroughly considered and should be denied.
FINDINGS OF FACT AND CONCLUSIONS OF LAW:
(1) AEP Ohio is a public utility as defined in R.C 4905.02 and an electtic utilit}' as defined in R.C 4928.01 (A)(11), and, as such, is subject to the jurisdiction of this Commission.
(2) In the ESP 3 Case, the Commission modified and approved AEP Ohio's application for an ESP for the period beginning June 1, 2015, through May 31, 2018, including a placeholder PPA rider.
(3) On October 3, 2014, in the above-captioned proceedings, AEP Ohio filed an application for approval to enter into a new affiliate PPA with AEPGR.
(4) On May 15, 2015, AEP Ohio filed an amended application, again seeking approval of a new affiliate PPA with AEPGR and also requesting authority to include the net impacts of both the affiliate PPA and the Company's OVEC conttactual entitlement in the placeholder PPA rider approved in the ESP 3 Case.
(5) The following parties were granted intervention in these proceedings: FES, lEU-Ohio, OEG, Kroger, Sierra Club, Buckeye, MAREC, OAEE, Walmart, OEC, Market Monitor, OHA, EPO, EDF, OMAEG, RESA, OCC, Direct Energy, IGS, P3, EPSA, OPAE, Dynegy, APJN, ELPC, Exelon, and EnerNOC.
APP. 479 14-1693-EL-RDR -107- 14-1694-EL-AAM
OAEE filed a notice of withdrawal from these proceedings on September 18, 2015.
(6) A procedural conference regarding the PPA application was held on September 22, 2015.
(7) An evidentiary hearing commenced on September 28, 2015, and concluded on November 3, 2015.
(8) On December 14, 2015, a stipulation was filed by AEP Ohio, Staff, OEG, OHA, MAREC OPAE, Buckeye, Sierra Club, FES, Direct Energy, and IGS, which was intended to resolve all of the issues in these cases.
(9) An evidentiary hearing on the stipulation conunenced on January 4, 2016, and concluded on January 8, 2016.
(10) Briefs and reply briefs were filed on February 1, 2016, and February 8, 2016, respectiveh'.
(11) The stipulation meets the criteria used by the Commission to evaluate stipulations, is reasonable, and should be adopted, as modified by this Opinion and Order.
(12) AEP Ohio should be authorized to implement its proposed PPA rider rates, consistent with the stipulation and this Opinion and Order.
ORDER:
It is, therefore,
ORDERED, That the stipulation be adopted and approved, as modified by this Opinion and Order. It is, further,
ORDERED, That the amended application filed by AEP Ohio on May 15, 2015, to establish PPA rider rates be approved and modified, consistent with the terms of the stipulation and this Opinion and Order. It is, further,
ORDERED, That AEP Ohio be authorized to file tariffs, in final form, consistent with the stipulation and this Opinion and Order. AEP Ohio shall file one copy in these case dockets and one copy in its TRF docket, It is, further.
APP. 480 14-1693-EL-RDR -108- 14-1694-EL-AAM
ORDERED, That the effective date of the new tariffs shall be a date not earlier than the date upon which the final tariff pages are filed with the Commission. It is, further,
ORDERED, That AEP Ohio shall notify its customers of the changes to the tariff via bill message or bill insert within 30 days of the effective date of the revised tariff. A copy of this customer notice shall be submitted to the Conunission's Service Monitoring and Enforcement Department, Reliability and Service Analysis Division, at least 10 days prior to its disttibution to customers. It is, further,
ORDERED, That the motions for protective order filed by AEP Ohio, OCC, Sierra Club, and P3/EPSA be granted for 24 months from the date of this Opinion and Order. It is, further,
ORDERED, That various parties' motions for extension of the procedural schedule and ELPC's interlocutory appeal be denied. It is, further,
ORDERED, That Noble's untimely motion to interx'ene in these proceedings be denied. It is, further,
ORDERED, That AEP Ohio's motion to sttike Noble's reply brief be granted. It is, further,
ORDERED, That the motions seeking leave to file amicus briefs filed by the Generation Developers be granted. It is, further,
ORDERED, That OMAEG's and OCC/APJN's requests for reversal of certain procedural rulings be denied. It is, further,
ORDERED, That the motions to stay the proceedings filed by Noble and OCC, APJN, and OMAEG be denied. It is, further,
ORDERED, That AEP Ohio's motion to sttike PJM's testimony be derued as moot. It is, further.
APP. 481 14-1693-EL-RDR -109- 14-1694-EL-AAM
ORDERED, That a copy of this Opinion and Order be served on all parties of record.
THE PUBLIC UTILITIES COMMISSION OF OHIO
Andre T. Porter, Chairman U^^wh M. Beth Trombold \Osy\CAA^
Asim Z. Haque Thoi^as W. Johnson
CowOj^L. SJP/GNS/sc
Entered in the Journal MAR 3 1 2016
Barcy F. McNeal Secretary
APP. 482 BEFORE
THE PUBLIC UTILITIES COMMISSION OF OHIO
In the Matter of the Application Seeking Approval of Ohio Power Company's Proposal to Enter into an Affiliate Power Case No. 14-1693-EL-RDR Purchase Agreement for Inclusion in the Power Purchase Agreement Rider.
In the Matter of the Application of Ohio Power Company for Approval of Certain Case No. 14-1694-EL-AAM Accounting Authority.
CONCURRING OPINION OF COMMISSIONER M. BETH TROMBOLD
I write separately from my colleagues because I feel it is important to emphasize the expectation on which today's Opinion and Order is based.
The energy market is dynamic and complicated, and the issues raised in this proceeding are difficult and not given to simple solutions. The application in this case was submitted by the Company in mid-2014. For over 18 months, the Corrunission has worked diligently to decide the case in a maruier consistent with Ohio law while balancing many interests and providing extensive due process.
Every Ohioan relies on public utility companies for the critical services they provide; therefore, we want those companies to be financially sound and stable. We have also worked long and hard in Ohio to establish a robust competitive electtic marketplace to the benefit of consumers and growing businesses. Importantly, Ohio consumers want safe, reliable electticity at affordable rates as well as iruiovative products and services that meet their needs and interests. To be sure, it's all a very delicate balance.
In the case before us today, the Commission must consider whether the Stipulation, as a package, benefits ratepayers and the public interest. The analysis made by the Corrunission in reaching this conclusion is articulated in the Opinion and Order. In short, the Commission concludes that Ohio consumers will benefit from several items in the Stipulation such as provisions that will result in grid modernization and more renewables. These provisioris will enable the Conunission to advance important conversations with our utilities about the future of the electtic industty and incorporating "next generation technologies" into our electtic disttibution grid.
In addition, the Stipulation continues utility demand response programs important to the viability of our large industtial companies, and creates pilot programs necessary for our competitive retail suppliers to advance Ohio's retail marketplace.
APP. 483 14-1693-EL-RDR -2- 14-1694-EL-AAM
The Purchase Power Agreement (PPA) included in the Stipulation has been discussed at great length in this docket and elsewhere.
One of the challenges of utility regulation is that it is based on forecasts, and forecasts are just that: a prediction about an uncertain future. We all know there have been changes in the market in recent years caused by the weather, the economy, technological innovations, and environmental considerations that have resulted in market prices no one predicted despite our best attempts to forecast them.
The PPA mechanism proposed by the Company is designed to operate as a financial hedge against such price volatilit}', wherein consumers pay more when market prices are low but pay less when market prices are high. Based on the forecasts submitted by the Company and evidence in the record, it is my clear expectation, just as it is Commissioner Haque's, that the PPA rider approved today will result in a credit (i.e. benefit) to ratepayers over the next eight years (Co. Ex. 52, Ex. WAA-2).
M. Beth Trombold, Commissioner
MBT/sc
Entered in the Journal MAR 3 1 2016
Barcy F. McNeal Secretary
APP. 484 BEFORE
THE PUBLIC UTILITIES COMMISSION OF OHIO
In the Matter of the Application Seeking Approval of Ohio Power Company's Proposal to Enter into an Affiliate Power Case No. 14-1693-EL-RDR Purchase Agreement for Inclusion in the Power Purchase Agreement Rider.
In the Matter of the Application of Ohio Power Company for Approval of Certain Case No. 14-1694-EL-AAM Accounting Authority.
CONCURRING OPINION OF COMMISSIONER ASIM Z. HAQUE
As these cases have been pending before the Conunission for a considerable period of time, and due to the concern expressed by the consumers of this great State (along with interest shown by spectators nationally), I feel compelled to write separately to explain my decisions today. I also want to take this opportunity to provide xny thoughts about the current status of the electtic industty here in Ohio. My hope is that this opinion will be insightful to those looking for more guidance on how and why these decisions were made, the issues that face the electric industty today, and our collective path forward.
I. THE PPA DECISIONS In adjudging these cases over the past two plus years, so many questions have been posed by the general public and those on the periphery of these cases. Why did the utilities bring these cases? Why should the Commission evaluate them when it has committed the State to competitive markets? Are the PPAs a good deal for consumers? Are the utilities asking consumers to subsidize plants that are no longer competitive in the market? Does the PUCO (and the State of Ohio) care about the environment? These are all fair questions to ask.
We must always remember, however, that the Commission serves a quasi-judicial function, and the cases we evaluate have legal standards of review that should create the frame for our analysis. I am, by formal ttaining and by inherent nature, a lawyer. I understand policy well enough. But to me, when it comes to actually deciding cases, the technical arguments, the law, the testimony, the cross-examination, the overall record, and the briefing, must prevail.
From a legal perspective, I analyzed these cases differently than in our first American Electtic Power (AEP) PPA-related decision. In re Ohio Power Co., Case No. 13-2385-EL-SSO, et al.. Opinion and Order (Feb. 25, 2015), whereby the Commission found a PPA consttuct to be legal, but did not allow for a generating unit to actually be placed in the rider. The key difference here, legally, is that AEP (and FirstEnergy) filed a settlement stipulation with the
APP. 485 14-1693-EL-RDR -2- 14-1694-EL~AAM
Commission. As a result, while the legal standard of review still requires that the utilities bear the burden of proof, the ttue test for legality in these cases is the three-part stipulation test established by this Commission and upheld by the Supreme Court of Ohio. That test reads as follows:
(1) Is the settlement a product of serious bargaining among capable, knowledgeable parties?
(2) Does the settlement, as a package, benefit ratepayers and the public interest?
(3) Does the settlement package violate any important regulatory principle or practice?
Admittedly, the plain language of this test leaves some room for Conunission interpretation. Over the course of my next term, I hope to add some docttinal principles to this test that future Commissions can rely upon for reference. I will in fact attempt to do some of this here.
A. The Three Part Stipulation Test
1. Serious Bargaining Among Capable, Knowledgeable Parties
First, is the stipulation a product of serious bargaining among capable, knowledgeable parties? I agree with the conclusions set forth in both Opinions and Orders, but let me add a bit more. As to whether the parties are capable and knowledgeable, the Commission should look to the quality of the parties that have signed the stipulation. Quantity oi parties, in my mind, is mearungless.
The Conunission is well-acquainted with the parties that typically intervene in major proceedings before the Commission, and the various interests they represent. The Commission is also well- aware that if a party intervenes and signs a stipulation, but is not a typical intervenor, whether that party has a symbolic and meaningful representation in that particular case. Again, it is quality oi the parties that is determinative, not quantity. In the cases at hand, this quality bar was reached by both AEP and FirstEnergy.
Let me also provide some feedback on the concept of side agreements and whether they impact the first part of the stipulation test. I am not a ttemendous fan of these side agreements, and I worry about their proliferation in these types of proceedings. There were two side agreements executed in these cases that I want to mention. One side agreement was between AEP and lEU-Ohio. The other side agreement was between FirstEnergy and IGS Energy. The AEP/IEU side agreement settles major pieces of litigation between the parties, and the only component of the side agreement that overtly touches the PPA case is
APP. 486 14-1693-EL-RDR -3- 14-1694-EL-AAM lEU's agreement not to oppose the AEP stipulation. This, in my mind, would not impact the first part of the stipulation test. AEP and lEU can agree to settle their claims whenever they choose, and for whatever monetary or non-monetary terms they agree upon. The agreement was properly disclosed pursuant to the law, and again, 1 do not find that this agreement impacts the serious bargaining among knowledgeable, capable parties.
The FirstEnergy and IGS Energy side agreement was also properly disclosed, but that agreement requires, essentially, that the Commission consider a future adjustment to our oversight of default service pricing through a future filing. My preference is that something like this would have been included in the actual stipulation. At the same time, I am aware of the tight timeframe that the Commission placed on the stipulation hearings, and my notion is that the parties perceived it to be administtatively cleaner (which it is) to execute their side agreement rather than file an amended stipulation since the parties agreed on terms during the actual stipulation hearing. 1 understand these circumstances, the agreement was properly disclosed under the law, but my preference is that a side agreement term that requires eventual Corrunission action or oversight be placed within the actual confines of the stipulation to ensure that serious bargairung is occurring among knowledgeable parties. Ultimately, my concern about this particular side agreement, under these circumstances, does not yield a failure of the first part of the stipulation test.
2. As a Package, Benefits Ratepayers and the Public Interest
i. Inttoduction
This is hard. There is no other way to say it. Whether these stipulations, as a package, benefit ratepayers and the public interest is the pivot point for these stipulations. It is through this part of the stipulation test that some of the broader questions articulated above can be addressed. But first, let me provide some commentary on the plain language of the second part of the stipulation test. To me, it is clear who ratepayers axe. Ratepayers encompass those persons or entities that pay for utility service in the service territory of the stipulating utility. This could range from a single residential consumer that lives in a small apartment, to a large auto manufacturer that consumes massive amounts of electticity all day and through the night in order to keep the manufacturing line moving. All are ratepayers within a utility's given service territory.
Defining the public interest is harder. It would seem to me that the public should mostly consist of the same definitional set that I established above for ratepayers. However, it could encompass more. It could encompass those who are less fortunate and who do not have a domicile. It could encompass those who live outside of the service territory of the subject utility but still within the State (i.e. a decision made in the FirstEnergy service territory that impacts persons or entities located in the Duke service territory), and it could even encompass those persons and entities that do not take service from a utility regulated
APP. 487 14-1693-EL-RDR -4- 14-1694-EL-AAM by the Commission (e.g. persorrs or entities that take service from municipally owned utilities and co-operatives). Thus, public interest is broader than ratepayers, and has the potential to include persons and entities beyond those who pay rates within the subject utility's service territory.
ii. PPA Rider Charges and Credits
First, let's talk about the rate impacts of the PPA rider in the AEP and FirstEnergy service territories. There were projections for the riders presented in both cases, and all of the projections presented had their merits. Here's what I think I know from these projections. I think that, based upon the projections and the evidence in the record, there is general consensus that the PPA riders will result in a charge to consumers for at least the first 2-3 years of the riders. Because the Commission feels somewhat certain of this, we have attempted to build in certain consumer protections to ensure that bills do not increase beyond a certain limit.
Beyond those first few years, it is unclear whether the PPA riders will result in more charges to ratepayers, or if the riders will result in credits being applied to the bills of ratepayers. The utilities believe that the riders will create bill credits. The Ohio Consumers' Counsel and others believe that the riders will continue to create charges. The expert witnesses in the case have presented divergent data points that yielded very different projections. However, I've seen so many dynamic changes in the market since I've taken office that it's hard for me to be convinced that any expert can ttuly project with accuracy beyond a few years out. I've seen market changes due to weather (e.g. polar vortex), scientific and technological innovation (e.g. shale exttaction and more cost-effective renewable development), market fixes (e.g. PJM's capacity performance product), environmental considerations (e.g. US EPA environmental regulations), and there are so many more drivers that could impact the market.
Here's what I can say. After a period of charges, I expect to see credits from the PPA riders. I'm not going to give definitive timelines, but that is my expectation. If this mechanism is ttuly a hedge, wherein consumers wiU pay when market prices are low, but will be credited money back when market prices are high, then what exactly is the point of the hedge if ratepayers never experience the credits? If ratepayers never experience the credits, then the PPA rider mechanism would then act as a somewhat illusory insurance policy.
Let me also argue the utilities' side of this. Let us say that after 2-3 years of Rider PPA charges, envirorunental regulations are promulgated that serve to prohibit fracking, or serve to limit the ease of interstate ttansport of natural gas, or some other unforeseen circumstance that would serve to drive up the price of natural gas beyond its historically low price of the preseiU. If that happens, the operating costs of our natural gas-fired
APP. 488 14-1693-EL-RDR -5- 14-1694-EL-AAM generation fleet will increase, thereby increasing market prices. Again, the PPA riders work contta to the market. If market prices rise, then the PPA riders produce credits to ratepayers, and of course the flip is also true. Ji market prices increase sharply for these reasons associated with the natural gas fleet, or for any other reason, then the credits that the utilities provide to ratepayers could offset increased market prices. It is certainly a possibility.
Because predictions of market prices beyond a few years are speculative, we must monitor the riders to ensure that ratepayers are purchasing the hedge that has been marketed to them. This should not be perceived as a blank check, and consumers should not be tteated like a ttust account. It's not right. At the same time, consumers, you have the potential to benefit from this if market prices increase, I know that experts opposing PPAs are saying now that there is no way that this will happen. Please read my commentary on wholesale markets below, and understand that the energy industty is very dynamic with many, many moving parts that have the potential to impact these markets and make them unpredictable.
iii. The Rest of the Stipulation Packages
It is exttemely important to note that cost is not the only factor that this Commission is to weigh in determining whether the stipulations benefit ratepayers and are in the public interest. In In re Application of Columbus Southern Power Company, 129 Ohio St.3d 46 (2011), the Supreme Court of Ohio addressed this issue of whether the PUCO could consider more than cost in determining whether a stipulation benefits ratepayers and is in the public interest, In that case, lEU-Ohio challenged AEP's peak demand reduction plan stipulation, presenting what it believed to be a more cost-effective approach to prove that AEP's stipulation did not benefit ratepayers and was not in the public interest. The Supreme Court of Ohio held that, "While cost is surely a relevant concern to be balanced... it is not the only concern, and the commission is entitled to consider more." (emphasis added at 51).
Here, I think the public benefits from a few major categories of terms agreed to in the stipulations, especially the grid modernization and clean generation technologies provisions. Many states have opened dockets and are undertaking "utility 2.0" or "utility of the future" grid modernization endeavors. The State of Ohio is due for this conversation. For some time now, I've wondered how we could possibly persuade the electtic utilities to have conversations with us about the future of their industties: how they expect to incorporate next generation (and often third party) technologies into the disttibution grid, how they expect to cater to millennial consumers who want more conttol and understanding over how and what they consume, how to better incorporate clean technologies into everything that they do^ etc. These conversations could yield revolutionary endeavors that would surely benefit the public interest. The stark reality is that until these PPA cases were resolved, no such conversations would occur.
APP. 489 14-1693-EL-RDR -6- 14-1694-EL-AAM
Also, clean generation technologies are advanced in these stipulations with renewable, energy efficiency and even battery storage provisions. In fact, a major environmental advocate, the Sierra Club, signed onto the AEP stipulation. It would be foolhardy for me not to recognize the ttemendous amount of public sentiment expressed over the past two years associated with these cases and their environmental ramifications. The environmental community surely will not be pleased that the Corrunission is approving PPA riders for coal plants and a nuclear plant, but at the same time, the Commission recognizes the importance of cleaner generation technologies by approving certain endeavors in these Opinions and Orders. Again, I do not believe that there would have been a path forward for such commitments without these stipulations.
There are more stipulated terms to discuss that elicited the signatures (or non- opposition) of a number of very important parties in these proceedings. Our largest consumers will be able to take advantage of utility demand response programs. Economic development opportunities are created. Our competitive retailers will be given the opportunity to advance endeavors that could serve to enhance the retail marketplace. And there is more. Surely, it is fair to ask how much all of this will cost. Much of these costs will be determined in future proceedings before the Commission, and so we will find out if the perceived present benefits are actually worth the costs. That question, however, sheds light on the very difficult balance between a current financial impact to ratepayers, and future benefits (and even savings) for those same ratepayers after this initial investment. I save this conundrum for another day, however.
In summary, while it is unclear what the net impact of the PPA riders will be over the next eight years, the concept itself has merit as it could serve as a hedge against marketplace volatility. At the same time, from purely a monetary perspective, we must ensure that constant and large charges do not become the norm, as this would mitigate the conceptual benefit that the hedge has to offer. The other benefits in the stipulation packages, eliciting the signature of parties in these proceedings, push the stipulations just beyond the pivot point, allowing for a finding that these stipulations pass this second part of the stipulation test.
3. Violate any Important Regulatory Principle or Practice
This third part of the stipulation test, again, allows for some Commission discretion. What is a regulatory principle and a regulatory practice, and even then^ which of these principles and practices are important? Do these principles and practices encompass more than the law set forth in the Ohio Revised Code and the rules set forth in the Ohio Admiiusttative Code? Would these principles and practices encompass the current policy positions of the State and perhaps the Chairman of the PUCO? Do these principles and practices encompass generally accepted regulatory norms adopted by a majority of state
APP. 490 144693-EL-RDR -7- 14-.1694-EL-AAM utility commissions, the National Association of Regulatory Utility Commissioners, the Mid-Atlantic Conference of Regulatory Utility Cormnissioners, the National Regulatory Research Institute, etc.?
In ttying to provide some guidance here, I am of the opinion that, at the very least, the stipulation cannot violate a statute of the Ohio Revised Code or a rule of the Ohio Administtative Code. For this reason, I concur with the language set forth in the Opinions and Orders stating that the third part of the stipulation test has been satisfied. The Commission spent much of 2014 and early 2015 mired in the quandary of whether the PPA mechanism was legal under Ohio law, and more specifically, the ESP statute. The Commission's conclusion on that issue in the AEP ESP III case has been made. I do not wish to revisit that decision or its justification here.
I would, however, like to provide some commentary on the factors set forth by the Conunission in AEP ESP III that were meant to serve as evaluative criterion for the Conunission in determining whether to grant or deny future PPA requests. The plain language leading into those factors reads in a more permissive, than mandatory manner. That is, the Commission can take those factors into account, but it doesn't necessarily have to. If these cases were not presented to us as stipulations, I would have looked more to those factors as guide posts in my decision-making. However, again, the presentation of these cases as stipulations very much changed my legal standard of review, and thus, my analysis. To note, I do not believe that either company successfully proved that the PPA units are needed to preserve reliability. Based upon the legal standard of review though, this failure to meet one of the Conunission's permissive factors is not fatal.
II. The Current Status of the Industry
My time on the Commission thus far has been one of ultimate flux in the electtic industty. I sometimes cannot believe both the fortune and misfortune in my timing. As I was coming onto the Conunission, the Commission was completing its vision of ttansitioning utihties to full competition via the most recent Dayton Power & Light (DP&L) ESP. Now, states and their electtic utilities are ttying to determine how to best plan for the modernized "utility 2.0" future grid, in tandem with demands for cleaner energy, more thoughtful cor^sumer engagement, and of course, having to deal with market dynamics that are favoring some assets and disfavoring others. 1 pen this portion of my concurrence not for purposes of legacy though. As I have been appointed to another term, my intent is the diamettic opposite. I pen this portion of my concurrence to tty and provide the utility conununity with a glimpse of how 1 presently view the industty and its various stakeholders and interests. From here, and based upon these thoughts, my hope is that we can chart a clear path for this industty, together.
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A. Competition
I begin with the concept of competition. There has been plenty of rhetoric espoused stating that the granting of PPAs will desttoy competition in the State of Ohio. 1 will address this concern, but an important distinction needs to first be made. There is a difference between wholesale competition and retail competition. Wholesale competition involves the generators of electticity competing to sell the power that they produce into a marketplace for the best possible price. Retail competition involves entities that purchase this power from the wholesale marketplace, and then resell that power to consumers.
In the State of Ohio, wholesale competitors include the generation companies affiliated with AEP, FirstEnergy, DP&L, Dynegy (who last year purchased the generation fleet owned by Duke Energy Ohio's generation affiliate) and other independent power producers in the State. Generation owned by municipals and co-ops (whom the PUCO do not regulate) also partake in wholesale competitive markets. Retail competitors include companies like Direct Energy, IGS Energy, Constellation, Just Energy, the retail affiliates of the aforementioned four electtic companies and many, many more. I will address retail competition first, followed by wholesale competition.
1. Retail Competition
The status of retail competition in the State of Ohio is sttong, and will continue to be sttong going forward. Nothing in these Opinions and Orders should be consttued as me being unsupportive of retail competition. Retailers have become the ttue innovators in the State. They are bringing home energy management products, disttibuted generation, irmovative pricing and so much more to their customers. I am supportive and very appreciative of our retailers' efforts to continue to innovate and make customers' lives better.
In analyzing the PPA riders, the mechanisms contemplated could hurt the retail market in a few ways that we must be cognizant of. The first way is if there is confusion about what the Commission has done here. Again, retail competition is working, and it should not be harmed by law or policy based upon a misunderstanding of the Commission's decisions today. The second way is if either the AEP-Ohio or FirstEnergy (the disttibution companies) sell their power purchased via the PPAs to their retail affiliates (AEP Retail and FirstEnergy Solutions) via bilateral conttact. Per the Opinions and Orders, no presumption of prudency will exist here.
Retail competition is thriving. These companies are innovators. I want to continue to see them thrive and we need to ensure that the potential harms that could arise from these decisions never come to fruition.
APP. 492 14-1693-EL-RDR -9- 14-1694-EL-AAM
2. Wholesale Competition
As I have already stated, my eventual decisions in these cases were made by analyzing the stipulations against the three part test. My decisions were based upon the concept of the PPAs being utilized as a retail hedge and rooted in state law. Although our decisions do not rely on Federal or wholesale issues, I want to utilize this "industty status" section to provide some observations on wholesale market operation, specifically the PJM wholesale market.
I am a believer in wholesale markets for reasons associated with the discipline of economics. Clearly though, state governments have been expressing some recent ttepidation with the markets. There are more states than Ohio that cire exercising, or contemplating to exercise their retail jurisdictional authority associated with existing generation (mostly nuclear), or have attempted to incent new generation. Why? What is the root cause of this? I am not entirely sure. Conceptually for the markets, what I think would be essential is that ttust and confidence exist in the markets from not or\ly the actual market participants, but in this case, those who are forced to deal with the collateral damage associated with market operation.
State governments are the entities that invariably manage wholesale market collateral damage because they are the most directly accountable to the consumers and job creators in their respective States. I have said this publicly on a few occasions. If the states, who are the most directly accountable to consumers for the impacts of wholesale markets (even though they do not plan or operate them) start to feel pressure, whether from their consumers, utilities, interest groups, etc., and this pressure is either supplemented by, or helps to bolster a lack of ttust and confidence in the markets themselves, then states will contemplate exercising their given legal authority associated with their in-state generation.
When prices were high during the polar vortex, consumers and businesses in the State of Ohio called the PUCO and state goverrunent offices to express their displeasure. They don't know who PJM is. They don't know who FERC is. When a coal plant in Appalachia is shut down and hundreds are losing their livelihoods, these families send letters to the PUCO and state government offices to tell us of their hardships. They don't know who PJM is. They don't know who FERC is. Again, states feel accountable for the impacts of markets that are not in their conttol.
That's not to say that there aren't solutions. I have had the professional pleasure of interacting with the executives at PJM as well as FERC Commissioners. They are forthright and brilliant people in their own right, and they have very challenging jobs. They have, in my experience, also been very receptive to the concerns of the states. But again, state government behavior is expressing some ttepidation which will need to be addressed. The
APP. 493 14-1693-EL-RDR -10- 14-1694-EL-AAM below thoughts/concerns are a start. These are mainly byproduct questions from these PPA cases:
• Are the markets prepared if, for whatever the reason, we see a spike in natural gas prices, especially with the continued shedding of plants from the coal and nuclear generation fleets?
• How close are we to technically reliable and cost-effective utility scale renewables, and are they adequate replacements for the coal and nuclear fleets?
• The nuclear fleet appears to be in the most difficult position, with retirements occurring or being threatened in other states. With nuclear continuing to be a large chunk of generating capacity in PJM, do we need to tteat them differently in the wholesale markets in order to preserve them?
• Is the demise of the coal fleet overblown? That is, will there continue to be a large coal fleet that clears wholesale markets sans environmental (carbon) reform?
• If environmental (carbon) reform finally goes through, whether it be the Clean Power Plan or other reform, and the nuclear fleet continues to sttuggle, and renewables aren't ready, what is your plan to ensure a reliable grid?
Perhaps these questions seem preposterous to the reader. Perhaps the answers to these questions are obvious. Perhaps each of these questioris can be answered by stating simply that the markets will account for and take care of all of these potential scenarios. Perhaps the policy underpinnings of my questions, concerns about cost and reliability, are not appropriate to ask when dealing with markets. If market prices are high, then that's the market. If power is scarce, then that's the market. Admittedly, if you had my job though, and had to think about corrsumers big and small just ttying to "make it" on a day-to-day basis here in my State, a State in which I have lived all over and have always called home, you may understand my concern.
B. Our Electtic Utilities
The Commission and our electtic utilities need to work as partners going forward. These cases were filed two or so years ago, and the Commission has been playing defense ever since. Going forward, we need to have a conversation about your future. How can we work to better the lives of consumers in the State of Ohio whfle also ensuring that you maintain your economic viability? My hope is that we will have this important conversation within the confines of our grid modernization dockets and beyond. We need to work as partners going forward for the betterment of the State.
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C. The Environmental Community
In my eyes, you have officially arrived here at the Commission. When 1 first started litigating at the Conunission some five years ago, I think the perception of your participation is that you were more fringe advocacy parties that would not likely gain ttaction in large rate cases. Now, unequivocally, you have a seat at the table, and you deserve to be praised for your advocacy and ascension.
My only request is that your advocacy of social principle is firmly grounded in regulatory reality. It is not technically feasible, nor is it presently cost-effective to simply replace our coal, nuclear and gas fleets with renewables and energy efficiency. Perhaps it could happen, but not nearly in the inunediate future. As I have stated numerous times when speaking about the Clean Power Plan, cleaner air and a cleaner environment are very fine policy objectives. We must be intelligent and intellectually honest in how we get there from a State regulatory perspective.
D. The Coal Fleet
Coal has a rich history here in Ohio. It has supported Ohio communities and families. It has helped preserve reliability of the grid and the cost-effectiveness of power. 1 continue to be engaged at a national level to help tty and find solutions for coal. Clearly, because of its environmental atttibutes, coal does not hold the same favor that it once did. This, combined with the price of natural gas, makes for a very challenging market environment for coal.
Cleaner coal solutions like carbon capture and other forms of carbon management are discussed ad nauseum in Washington, but there appears to be some relative consensus that these technologies, at present, are cost prohibitive. Further, based upon current market dynamics, 1 wonder if their cost effectiveness may arrive too late for the existing coal fleet.
I have become familiar with the research of Dr. L.S. Fan and his chemical looping work at The Ohio State University. These types of research endeavors could revolutionize the coal industty. As a State regulator, I don't know that I can do much more to move research endeavors to market other than to say "I support you." I think, however, that lending whatever support we can to such research endeavors makes all the sense in the world. I continue to search for solutioris for this industty, and I am very hopeful that solutions present themselves.
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E. Merchant Generators
We are very grateful to have you here, and these decisions should in no way be viewed as a condemnation of your operations here in the State. Through the natural demographics of the State, existing infrasttucture and our "one-stop" power siting shop, my hope is that merchant generators will continue to feel that investment in Ohio is a profitable endeavor.
F. The Path Forward
Regulation is far from perfect. When one considers all of the moving parts, especially in the electtic industty, it is exttemely hard to fathom how it could be. Markets are dynamic. Industties evolve based upon technological innovation. Industty players change priorities based upon share prices, new Boards, and new CEOs. Social movements take shape and influence policy. Lawmakers and other regulators impact what you can and cannot do. The regulators themselves are swapped in and out, and they evolve during the course of their terms. How, then, can electtic industty stakeholders in the State of Ohio have some semblance of certainty in regulation?
I feel, at least, that there are a few principles that I will always rely upon when making decisions and charting policy paths. I have quoted the mission of the PUCO extensively in my past decision-making. Outside of the law, it is all that exists to guide us. Now that I have been in this seat for close to three years, I am going to express some autonomy and add a few more principles to the mission that will help guide my second term.
Safe, reliable and cost-effective. These principles are articulated in the mission of the PUCO, and are the core principles to rely upon in safeguarding the industty. The Commission will continue to enforce and seek to make better its reliability and safety measures. The ttemendous work that the staff of the Commission does to ensure safety and reliability, and the cooperation that our utilities provide should not be forgotten. It is a heavy, heavy responsibility. I have addressed cost-effectiveness earlier in this concurrence. Note that the principle is cost-effective and not cheapest. As in life, sometimes you have to pay for great service, and sometimes you have to invest on the front-end to save on the back-end. I am always concerned about costs. I am concerned about what our most indigent consumers can pay, and I am concerned if our job creators are paying too much. It is a very challenging balance, but a balance nonetheless that we must endeavor to create.
Innovative. I now view this as synonymous with "competitive" in the retail space. If a retailer is being irmovative, then it is also being competitive. If a retailer's only offer to consumers is a small discount off of the price to compare, that retailer is not being innovative, and thus the retailer is not being competitive. I hope to see more and more
APP. 496 14-1693-EL-RDR -13- 14-1694-EL-AAM retail irmovation as I progress through my second term. I also hope to see innovation expressed in our grid modernization dockets. Again, these dockets have ttemendous potential.
Clean. We must acknowledge the clean movement. Failing to do so runs afoul of what appears to be overwhelming consumer sentiment. Recall though that we have to balance this principle against the principles of reliability and cost-effectiveness. Again, envirorunental advocates have a seat at the table, but we have to work always towards irrunediately practical solutions. This is not to say, again, that I do not believe in our historical baseload generation either. We must support clean solutions for coal, and must also realize that ttying to push the baseload fleets out of the market sooner than our grid can account for may be very harmful.
Safe - Reliable - Cost-Effective - Innovative - Clean
These are principles that can guide our path forward. These are big cases, but there is still, and there always will be, much work to be done.
Asim Z. Haque, Commissioner
AZH/sc
Entered in the Journal
MAR 3 1 2016
Barcy F. McNeal Secretary
APP. 497 4901:1-39-01 Definitions, OH ADC 4901:1-39-01
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-39. Energy Efficiency Programs (Refs & Annos)
OAC 4901:1-39-01
4901:1-39-01 Definitions
Currentness
(A) “Achievable potential” means the reduction in energy usage or peak demand that would likely result from the expected adoption by homes and businesses of the most efficient, cost-effective measures, given effective program design, taking into account remaining barriers to customer adoption of those measures. Barriers may include market, financial, political, regulatory, or attitudinal barriers, or the lack of commercially available product. “Achievable potential” is a subset of “economic potential.”
(B) “Anticipated savings” means the reduction in energy usage or peak demand that will accrue from contractual commitments for program participation made in the reporting period, which measures in such programs are scheduled for installation in the subsequent reporting periods.
(C) “Capital stock” means all devices, equipment, and processes that use or convert energy.
(D) “Coincident peak-demand savings” means the demand savings for energy efficiency measures that are expected to occur during the summer on-peak period which is defined as June through August on weekdays between 3:00 p.m. and 6:00 p.m.
(E) “Commission” means the public utilities commission of Ohio.
(F) “Cost effective” means the measure, program, or portfolio being evaluated that satisfies the total resource cost test.
(G) “Demand response” means a change in customer behavior or a change in customer-owned or operated assets that affects the demand for electricity as a result of price signals or other incentives.
(H) “Economic potential” means the reduction in energy usage or peak demand that would result if all homes and businesses adopted the most efficient and cost-effective measures. Economic potential is a subset of the “technical potential.”
(I) “Electric utility” has the meaning set forth in division (A)(11) of section 4928.01 of the Revised Code.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 498 1 4901:1-39-01 Definitions, OH ADC 4901:1-39-01
(J) “Energy baseline” means the average total kilowatt-hours of distribution service sold to retail customers of the electric utility in the preceding three calendar years as reported in the electric utility's most recent long-term forecast report, pursuant to division (A)(2)(a) of section 4928.66 of the Revised Code. The total kilowatt-hours sold shall equal the total kilowatt-hours delivered by the electric utility.
(K) “Energy benchmark” means the annual level of energy savings that an electric utility must achieve as provided in division (A)(1)(a) of section 4928.66 of the Revised Code.
(L) “Energy efficiency” means reducing the consumption of energy while maintaining or improving the end-use customer's existing level of functionality, or while maintaining or improving the utility system functionality.
(M) “Independent program evaluator” means the person(s) hired by one or more of the electric utilities, at the direction of the commission, to complete the following activities:
(1) Monitor, verify, evaluate, and report on the electric energy savings and peak-demand reductions resulting from utility program and mercantile customer activities.
(2) Determine program and portfolio cost-effectiveness.
(3) Conduct program process evaluations.
(4) Perform due-diligence reviews of evaluations or documentation provided by an electric utility or mercantile customer, as directed by the commission.
Such person shall work at the sole direction of the commission.
(N) “Market transformation” means a lasting structural or behavioral change in the marketplace that increases customer adoption of energy efficiency or peak reduction measures that will be sustained after any program promoting such behavior ceases.
(O) “Measure” means any material, device, technology, operational practice, or educational program that makes it possible to deliver a comparable level and quality of end-use energy service while using less energy or less capacity than would otherwise be required.
(P) “Mercantile customer” has the meaning set forth in division (A)(19) of section 4928.01 of the Revised Code.
(Q) “Nonenergy benefits” mean societal benefits that do not affect the calculation of program cost-effectiveness pursuant to the total resource cost test including but not limited to benefits of low-income customer participation in utility programs; reductions in greenhouse gas emissions, regulated air emissions, water consumption, natural resource depletion to the extent the benefit of such reductions are not fully reflected in cost savings; enhanced system reliability; or advancement of any other state policy enumerated in section 4928.02 of the Revised Code.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 499 2 4901:1-39-01 Definitions, OH ADC 4901:1-39-01
(R) “Peak demand,” when measuring reduction programs, means the average maximum hourly electricity usage during the highest 100 hours on the electric utility's system in a calendar year.
(S) “Peak-demand baseline” means the average peak demand on the electric utility's system in the preceding three calendar years as reported in the electric utility's most recent long-term forecast report, pursuant to division (A)(2)(a) of section 4928.66 of the Revised Code.
(T) “Peak-demand benchmark” means the reduction in peak demand an electric utility's system must achieve as provided in division (A)(1)(b) of section 4928.66 of the Revised Code.
(U) “Person” shall have the meaning set forth in division (A)(24) of section 4928.01 of the Revised Code.
(V) “Program” means a single offering of one or more measures provided to consumers. For example, a weatherization program may include insulation replacement, weather stripping, and window replacement measures.
(W) “Staff” means the staff or authorized representative of the public utilities commission.
(X) “Technical potential” means the reduction in energy usage or peak demand that would result if all homes and businesses adopted the most efficient measures, regardless of cost.
(Y) “Total resource cost test” means an analysis to determine if, for an investment in energy efficiency or peak-demand reduction measure or program, on a life-cycle basis, the present value of the avoided supply costs for the periods of load reduction, valued at marginal cost, are greater than the present value of the monetary costs of the demand-side measure or program borne by both the electric utility and the participants, plus the increase in supply costs for any periods of increased load resulting directly from the measure or program adoption. Supply costs are those costs of supplying energy and/or capacity that are avoided by the investment, including generation, transmission, and distribution to customers. Demand-side measure or program costs include, but are not limited to, the costs for equipment, installation, operation and maintenance, removal of replaced equipment, and program administration, net of any residual benefits and avoided expenses such as the comparable costs for devices that would otherwise have been installed, the salvage value of removed equipment, and any tax credits.
(Z) “Verified savings” means an annual reduction of energy usage or peak demand from an energy efficiency or peak- demand reduction program directly measured or calculated using reasonable statistical and/or engineering methods consistent with approved measurement and verification guidelines.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 500 3 4901:1-39-01 Definitions, OH ADC 4901:1-39-01
Rules and appendices are current through March 31, 2018
4901:1-39-01, OH ADC 4901:1-39-01
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 501 4 4901:1-39-03 Program planning requirements, OH ADC 4901:1-39-03
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-39. Energy Efficiency Programs (Refs & Annos)
OAC 4901:1-39-03
4901:1-39-03 Program planning requirements
Currentness
(A) Assessment of potential. Prior to proposing its comprehensive energy efficiency and peak-demand reduction program portfolio plan, an electric utility shall conduct an assessment of potential energy savings and peak-demand reduction from adoption of energy efficiency and demand-response measures within its certified territory, which will be included in the electric utility's program portfolio filing pursuant to rule 4901:1-39-04 of the Administrative Code. An electric utility may collaborate with other electric utilities to co-fund or conduct such an assessment on a broader geographic basis than its certified territory. However, such an assessment must also disaggregate results on the basis of each electric utility's certified territory. Such assessment shall include, but not be limited to, the following:
(1) Analysis of technical potential. Each electric utility shall survey and characterize the energy-using capital stock located within its certified territory and quantify its actual and projected energy use and peak demand. Based upon the survey and characterization, the electric utility shall conduct an analysis of the technical potential for energy efficiency and peak-demand reduction obtainable from applying alternate measures.
(2) Analysis of economic potential. For each alternate measure identified in its assessment of technical potential, the electric utility shall conduct an assessment of cost-effectiveness using the total resource cost test.
(3) Analysis of achievable potential. For each alternate measure identified in its analysis of economic potential as cost-effective, the electric utility shall conduct an analysis of achievable potential. Such analysis shall consider the ability of the program design to overcome barriers to customer adoption, including, but not limited to, appropriate bundling of measures.
(4) For each measure considered, the electric utility shall describe all attributes relevant to assessing its value, including, but not limited to potential energy savings or peak-demand reduction, cost, and nonenergy benefits.
(B) Program design criteria. When developing programs for inclusion in its program portfolio plan, an electric utility shall consider the following criteria:
(1) Relative cost-effectiveness.
(2) Benefit to all members of a customer class, including nonparticipants.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 502 1 4901:1-39-03 Program planning requirements, OH ADC 4901:1-39-03
(3) Potential for broad participation within the targeted customer class.
(4) Likely magnitude of aggregate energy savings or peak-demand reduction.
(5) Nonenergy benefits.
(6) Equity among customer classes.
(7) Relative advantages or disadvantages of energy efficiency and peak-demand reduction programs for the construction of new facilities, replacement of retiring capital stock, or retrofitting existing capital stock.
(8) Potential to integrate the proposed program with similar programs offered by other utilities, if such integration produces the most cost-effective result and is in the public interest.
(9) The degree to which a program bundles measures so as to avoid lost opportunities to attain energy savings or peak reductions that would not be cost-effective or would be less cost-effective if installed individually.
(10) The degree to which the program design engages the energy efficiency supply chain and leverages partners in program delivery.
(11) The degree to which the program successfully addresses market barriers or market failures.
(12) The degree to which the program leverages knowledge gained from existing program successes and failures.
(13) The degree to which the program promotes market transformation.
(C) Promising measures not selected. Each electric utility shall identify measures considered but not found to be cost- effective or achievable but show promise for future deployment. The electric utility shall identify potential actions that it could undertake to improve the measure's technical potential, economic potential, and achievable potential to enhance the likelihood that the measure would become cost-effective and reasonably achievable.
(D) The electric utility may seek to collaborate or consult with other utilities, regional and municipal governmental organizations, nonprofit organizations, businesses, and other stakeholders to develop programs meeting the requirements of this chapter.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 503 2 4901:1-39-03 Program planning requirements, OH ADC 4901:1-39-03
Rules and appendices are current through March 31, 2018
4901:1-39-03, OH ADC 4901:1-39-03
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 504 3 4901:1-39-04 Program portfolio plan and filing requirements, OH ADC 4901:1-39-04
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-39. Energy Efficiency Programs (Refs & Annos)
OAC 4901:1-39-04
4901:1-39-04 Program portfolio plan and filing requirements
Currentness
(A) Each electric utility shall design and propose a comprehensive energy efficiency and peak-demand reduction program portfolio, including a range of programs that encourage innovation and market access for cost-effective energy efficiency and peak-demand reduction for all customer classes, which will achieve the statutory benchmarks for peak-demand reduction, and meet or exceed the statutory benchmarks for energy efficiency. An electric utility's first program portfolio plan filed pursuant to this rule, shall be filed with supporting testimony prior to January 1, 2010. Each electric utility shall file an updated program portfolio plan by April 15, 2013, and by the fifteenth of April every third year thereafter, unless otherwise directed by the commission.
(B) Each electric utility shall demonstrate that its program portfolio plan is cost-effective on a portfolio basis. In general, each program proposed within a program portfolio plan must also be cost-effective, although each measure within a program need not be cost-effective. However, an electric utility may include a program within its program portfolio plan that is not cost-effective when that program provides substantial nonenergy benefits.
(C) Content of filing. An electric utility's program portfolio plan shall include, but not be limited to, the following:
(1) An executive summary and its assessment of potential pursuant to paragraph (A) of rule 4901:1-39-03 of the Administrative Code.
(2) A description of stakeholder participation in program planning efforts and program portfolio development.
(3) A description of attempts to align and coordinate programs with other public utilities' programs.
(4) A description of existing programs. The electric utility shall provide a summary of existing programs with a recommendation for whether the program should continue and, if so, a description of its relationship to any proposed programs. If a program has previously been approved and is unchanged, the electric utility may reference the program description currently in effect. If the electric utility is proposing to modify an existing program, the electric utility shall provide a description of the proposed modification and the basis for proposed changes.
(5) A description of proposed programs. An electric utility shall describe each program proposed to be included within its program portfolio plan with at least the following information:
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 505 1 4901:1-39-04 Program portfolio plan and filing requirements, OH ADC 4901:1-39-04
(a) A narrative describing why the program is recommended pursuant to the program design criteria in this chapter.
(b) Program objectives, including projections and basis for calculating energy savings and/or peak-demand reduction resulting from the program.
(c) The targeted customer sector.
(d) The proposed duration of the program.
(e) An estimate of the level of program participation.
(f) Program participation requirements, if any.
(g) A description of the marketing approach to be employed, including rebates or incentives offered through each program, and how it is expected to influence consumer choice or behavior.
(h) A description of the program implementation approach to be employed.
(i) A program budget with projected expenditures, identifying program costs to be borne by the electric utility and collected from its customers, with customer class allocation, if appropriate.
(j) Participant costs, if any.
(k) Proposed market transformation activities, if any, which have been identified and proposed to be included in the program portfolio plan.
(l) A description of the plan for preparing reports that document the electric utility's evaluation, measurement, and verification of the energy savings and/or peak-demand reduction resulting from each program and the process evaluations conducted by the electric utility. The independent program evaluator will prepare an independent evaluation, measurement, and verification plan at the direction of the commission staff to monitor, verify, evaluate and report on the energy savings and peak-demand reductions resulting from utility programs and mercantile customer activities. The independent program evaluator's plan may rely on data collected and reported by the electric utility.
(D) Unless otherwise ordered by the commission, any person may file objections within sixty days after the filing of an electric utility's program portfolio plan. Any person filing objections shall specify the basis for all objections, including any proposed additional or alternative programs, or modifications to the electric utility's proposed program portfolio plan.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 506 2 4901:1-39-04 Program portfolio plan and filing requirements, OH ADC 4901:1-39-04
(E) The commission shall set the matter for hearing and shall cause notice of the hearing to be published one time in a newspaper of general circulation in each county in the electric utility's certified territory. At such hearing, the electric utility shall have the burden to prove that the proposed program portfolio plan is consistent with the policy of the state of Ohio as set forth in section 4928.02 of the Revised Code, and meets the requirements of section 4928.66 of the Revised Code.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-39-04, OH ADC 4901:1-39-04
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 507 3 Ch. 4901:1-40, Refs & Annos, OH ADC Ch. 4901:1-40, Refs & Annos
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission 4901:1 Utilities Chapter 4901:1-40. Alternative Energy Portfolio Standard
OAC Ch. 4901:1-40, Refs & Annos Currentness
Editors' Notes
Promulgated pursuant to RC 111.15
Rules and appendices are current through March 31, 2018
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 508 1 4901:1-40-01 Definitions, OH ADC 4901:1-40-01
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-01
4901:1-40-01 Definitions
Currentness
(A) “Advanced energy fund” has the meaning set forth in section 4928.61 of the Revised Code.
(B) “Advanced energy resource” has the meaning set forth in division (A)(34) of section 4928.01 of the Revised Code.
(C) “Alternative energy resource” has the meaning set forth in division (A)(1) of section 4928.64 of the Revised Code.
(D) “Biologically derived methane gas” means landfill methane gas; or gas from the anaerobic digestion of organic materials, including animal waste, municipal wastewater, institutional and industrial organic waste, food waste, yard waste, and agricultural crops and residues.
(E) “Biomass energy” means energy produced from organic material derived from plants or animals and available on a renewable basis, including but not limited to: agricultural crops, tree crops, crop by-products and residues; wood and paper manufacturing waste, including nontreated by-products of the wood manufacturing or pulping process, such as bark, wood chips, sawdust, and lignin in spent pulping liquors; forestry waste and residues; other vegetation waste, including landscape or right-of-way trimmings; algae; food waste; animal wastes and by-products (including fats, oils, greases and manure); biodegradable solid waste; and biologically derived methane gas.
(F) “Clean coal technology” means any technology that removes or has the design capability to remove criteria pollutants and carbon dioxide from an electric generating facility that uses coal as a fuel or feedstock as identified in the control plan requirements in paragraph (C) of rule 4901:1-41-03 of the Administrative Code.
(G) “Co-firing” means simultaneously using multiple fuels in the generation of electricity. In the event of co-firing, the proportion of energy input comprised of a renewable energy resource shall dictate the proportion of electricity output from the facility that can be considered a renewable energy resource.
(H) “Commission” means the public utilities commission of Ohio.
(I) “Deliverable into this state” means that the electricity originates from a facility within a state contiguous to Ohio. It may also include electricity originating from other locations, pending a demonstration that the electricity could be physically delivered to the state.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 509 1 4901:1-40-01 Definitions, OH ADC 4901:1-40-01
(J) “Demand response” has the meaning set forth in rule 4901:1-39-01 of the Administrative Code.
(K) “Demand-side management” has the meaning set forth in paragraph (F) of rule 4901:5-5-01 of the Administrative Code.
(L) “Distributed generation” means electricity production that is on-site and is connected to the electricity grid.
(M) “Double-counting” means utilizing renewable energy, renewable energy credits, or energy efficiency savings to do any of the following:
(1) Satisfy multiple Ohio state renewable energy requirements or such requirements for more than one state.
(2) Comply with both the energy efficiency and advanced energy statutory benchmarks.
(3) Support multiple voluntary product offerings.
(4) Substantiate multiple marketing claims.
(5) Some combination of these.
(N) “Electric generating facility” means a power plant or other facility where electricity is produced.
(O) “Electric services company” has the meaning set forth in division (A)(9) of section 4928.01 of the Revised Code.
(P) “Electric utility” has the meaning set forth in division (A)(11) of section 4928.01 of the Revised Code.
(Q) “Energy efficiency” has the meaning set forth in rule 4901:1-39-01 of the Administrative Code.
(R) “Energy storage” means a facility or technology that permits the storage of energy for future use as electricity.
(S) “Fuel cell” means a device that uses an electrochemical energy conversion process to produce electricity.
(T) “Geothermal energy” means hot water or steam extracted from geothermal reservoirs in the earth's crust and used for electricity generation..
(U) “Hydroelectric energy” means electricity generated by a hydroelectric facility as defined in division (A)(35) of section 4928.01 of the Revised Code.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 510 2 4901:1-40-01 Definitions, OH ADC 4901:1-40-01
(V) “Hydroelectric facility” has the meaning set forth in division (A)(35) of section 4928.01 of the Revised Code.
(W) “Mercantile customer” has the meaning set forth in division (A)(19) of section 4928.01 of the Revised Code.
(X) “MISO” means “Midwest Independent Transmission System Operator, Inc.” or any successor regional transmission organization.
(Y) “Person” shall have the meaning set forth in division (A)(24) of section 4928.01 of the Revised Code.
(Z) “PJM” means “PJM Interconnection, LLC” or any successor regional transmission organization.
(AA) “Placed-in-service” means when a facility or technology becomes operational.
(BB) “Renewable energy credit” means the environmental attributes associated with one megawatt-hour of electricity generated by a renewable energy resource, except for electricity generated by facilities as described in paragraph (E) of rule 4901:1-40-04 of the Administrative Code.
(CC) “Renewable energy resource” has the meaning set forth in division (A)(35) of section 4928.01 of the Revised Code.
(DD) “Solar energy resources” means solar photovoltaic and/or solar thermal resources.
(EE) “Solar photovoltaic” means energy from devices which generate electricity directly from sunlight through the movement of electrons.
(FF) “Solar thermal” means the concentration of the sun's energy, typically through the use of lenses or mirrors, to drive a generator or engine to produce electricity.
(GG) “Solid wastes” has the meaning set forth in section 3734.01 of the Revised Code.
(HH) “Staff” means the commission staff or its authorized representative.
(II) “Standard service offer” means an electric utility offer to provide consumers, on a comparable and nondiscriminatory basis within its certified territory, all competitive retail electric services necessary to maintain essential electric service to consumers, including a firm supply of electric generation service.
(JJ) “Wind energy” means electricity generated from wind turbines, windmills, or other technology that converts wind into electricity.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 511 3 4901:1-40-01 Definitions, OH ADC 4901:1-40-01
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-01, OH ADC 4901:1-40-01
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 512 4 4901:1-40-02 Purpose and scope, OH ADC 4901:1-40-02
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-02
4901:1-40-02 Purpose and scope
Currentness
(A) This chapter addresses the implementation of the alternative energy portfolio standard, including the incorporation of renewable energy credits, as detailed in sections 4928.64 and 4928.65 of the Revised Code respectively. Parties affected by these alternative energy portfolio standard rules include all Ohio electric utilities and all electric services companies serving retail electric customers in Ohio. Any entities that do not serve Ohio retail electric customers shall not be required to comply with the terms of the alternative energy portfolio standard.
(B) The commission may, upon an application or a motion filed by a party, waive any requirement of this chapter, other than a requirement mandated by statute, for good cause shown.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-02, OH ADC 4901:1-40-02
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 513 1 4901:1-40-03 Requirements, OH ADC 4901:1-40-03
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-03
4901:1-40-03 Requirements
Currentness
(A) All electric utilities and affected electric services companies shall ensure that, by the end of the year 2024 and each year thereafter, electricity from alternative energy resources equals at least twenty-five per cent of their retail electric sales in the state.
(1) Up to half of the electricity supplied from alternative energy resources may be generated from advanced energy resources.
(2) At least half of the electricity supplied from alternative energy resources shall be generated from renewable energy resources, including solar energy resources, in accordance with the following annual benchmarks:
Annual benchmarks for alternative energy resources generated from renewable and solar energy resources
By end of year: Renewable energy Solar energy resources resources
2009 0.25% 0.004%
2010 0.50% 0.01%
2011 1.0% 0.03%
2012 1.5% 0.06%
2013 2.0% 0.09%
2014 2.5% 0.12%
2015 3.5% 0.15%
2016 4.5% 0.18%
2017 5.5% 0.22%
2018 6.5% 0.26%
2019 7.5% 0.30%
2020 8.5% 0.34%
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 514 1 4901:1-40-03 Requirements, OH ADC 4901:1-40-03
2021 9.5% 0.38%
2022 10.5% 0.42%
2023 11.5% 0.46%
2024 and each year 12.5% 0.50% thereafter
(a) At least half of the annual renewable energy resources, including solar energy resources, shall be met through electricity generated by facilities located in this state. Facilities located in the state shall include a hydroelectric generating facility that is located on a river that is within or bordering this state, and wind turbines located in the state's territorial waters of Lake Erie.
(b) To qualify towards a benchmark, any electricity from renewable energy resources, including solar energy resources, that originates from outside of the state must be shown to be deliverable into this state.
(3) All costs incurred by an electric utility in complying with the requirements of section 4928.64 of the Revised Code, shall be avoidable by any consumer that has exercised choice of electricity supplier, during such time that a customer is served by an electric services company.
(B) The baseline for compliance with the alternative energy resource requirements shall be determined using the following methodologies:
(1) For electric utilities, the baseline shall be computed as an average of the three preceding calendar years of the total annual number of kilowatt-hours of electricity sold under its standard service offer to any and all retail electric customers whose electric load centers are served by that electric utility and are located within the electric utility's certified territory. The calculation of the baseline shall be based upon the average, annual, kilowatt-hour sales reported in that electric utility's three most recent forecast reports or reporting forms.
(2) For electric services companies, the baseline shall be computed as an average of the three preceding calendar years of the total annual number of kilowatt-hours of electricity sold to any and all retail electric consumers served by the company in the state, based upon the kilowatt-hour sales in the electric services company's most recent quarterly market-monitoring reports or reporting forms.
(a) If an electric services company has not been continuously supplying Ohio retail electric customers during the preceding three calendar years, the baseline shall be computed as an average of annual sales data for all calendar years during the preceding three years in which the electric services company was serving retail customers.
(b) For an electric services company with no retail electric sales in the state during the preceding three calendar years, its initial baseline shall consist of a reasonable projection of its retail electric sales in the state for a full calendar year. Subsequent baselines shall consist of actual sales data, computed in a manner consistent with paragraph (B)(2)(a) of this rule.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 515 2 4901:1-40-03 Requirements, OH ADC 4901:1-40-03
(3) An electric utility or electric services company may file an application requesting a reduced baseline to reflect new economic growth in its service territory or service area. Any such application shall include a justification indicating why timely compliance based on the unadjusted baseline is not feasible, a schedule for achieving compliance based on its unadjusted baseline, quantification of a new change in the rate of economic growth, and a methodology for measuring economic activity, including objective measurement parameters and quantification methodologies.
(C) Beginning in the year 2010, each electric utility and electric services company annually shall file a plan for compliance with future annual advanced- and renewable-energy benchmarks, including solar, utilizing at least a ten-year planning horizon. This plan, to be filed by April fifteenth of each year, shall include at least the following items:
(1) Baseline for the current and future calendar years.
(2) Supply portfolio projection, including both generation fleet and power purchases.
(3) A description of the methodology used by the company to evaluate its compliance options.
(4) A discussion of any perceived impediments to achieving compliance with required benchmarks, as well as suggestions for addressing any such impediments.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-03, OH ADC 4901:1-40-03
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 516 3 4901:1-40-04 Qualified resources, OH ADC 4901:1-40-04
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-04
4901:1-40-04 Qualified resources
Currentness
(A) The following resources or technologies, if they have a placed-in-service date of January 1, 1998, or after, are qualified resources for meeting the renewable energy resource benchmarks:
(1) Solar photovoltaic or solar thermal energy.
(2) Wind energy.
(3) Hydroelectric energy.
(4) Geothermal energy.
(5) Solid waste energy derived from fractionalization, biological decomposition, or other process that does not principally involve combustion.
(6) Biomass energy.
(7) Energy from a fuel cell.
(8) A storage facility, if it complies with the following requirements:
(a) The electricity used to pump the resource into a storage reservoir must qualify as a renewable energy resource, or the equivalent renewable energy credits are obtained.
(b) The amount of energy that may qualify from a storage facility is the amount of electricity dispatched from the storage facility.
(9) Distributed generation system used by a customer to generate electricity from one of the resources or technologies listed in paragraphs (A)(1) to (A)(8) of this rule.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 517 1 4901:1-40-04 Qualified resources, OH ADC 4901:1-40-04
(10) A renewable energy resource created on or after January 1, 1998, by the modification or retrofit of any facility placed in service prior to January 1, 1998.
(B) The following resources or technologies, if they have a placed-in-service date of January 1, 1998, or after, are qualified resources for meeting the advanced energy resource benchmarks:
(1) Any modification to an electric generating facility that increases its generation output without increasing the facility's carbon dioxide emissions (tons per year) in comparison to its actual annual carbon dioxide emissions preceding the modification. In such an instance, it is the incremental increase in generation output that may be quantified and applied toward an advanced energy requirement.
(2) Any distributed generation system, designed primarily to meet the energy needs of the customer's facility that utilizes co-generation of electricity and thermal output simultaneously.
(3) Clean coal technology.
(4) Advanced nuclear energy technology, from:
(a) Advanced nuclear energy technology consisting of generation III technology as defined by the nuclear regulatory commission or other later technology.
(b) Significant improvements to existing facilities. In such an instance, it is the incremental increase in generation attributable to the improvement that may be quantified and applied toward an advanced energy requirement. Extension of the life of existing nuclear generation capacity shall not qualify as advanced nuclear energy technology.
(5) Energy from a fuel cell.
(6) Advanced solid waste or construction and demolition debris conversion technology that results in measurable greenhouse gas emission reductions.
(7) Demand-side management and energy efficiency, above and beyond that used to comply with any other regulatory standard or programs.
(C) The following new or existing mercantile customer-sited resources may be qualified resources for meeting electric utilities' annual, renewable- or advanced-energy resource benchmarks, as applicable, provided that it does not constitute double-counting for any other regulatory requirement and that the mercantile customer has committed the resource for integration into the electric utility's demand-response, energy efficiency, or peak-demand reduction programs pursuant to rule 4901:1-39-08 of the Administrative Code.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 518 2 4901:1-40-04 Qualified resources, OH ADC 4901:1-40-04
(1) Renewable energy resources from mercantile customers include the following:
(a) Electric generation equipment that uses a renewable energy resource and is owned or controlled by a mercantile customer.
(b) Any renewable energy resource of the mercantile customer that can be utilized effectively as part of an alternative energy resource plan of an electric utility and would otherwise qualify as a renewable energy resource if it were utilized directly by an electric utility.
(2) Advanced energy resources from mercantile customers include the following:
(a) A resource that improves the relationship between real and reactive power.
(b) A mercantile customer-owned or controlled resource that makes efficient use of waste heat or other thermal capabilities.
(c) Storage technology that allows a mercantile customer more flexibility to modify its demand or load and usage characteristics.
(d) Electric generation equipment owned or controlled by a mercantile customer that uses an advanced energy resource.
(e) Any advanced energy resource of the mercantile customer that can be utilized effectively as part of an advanced energy resource plan of an electric utility and would otherwise qualify as an advanced energy resource if it were utilized directly by an electric utility.
(D) An electric utility or electric services company may use renewable energy credits (REC) to satisfy all or part of a renewable energy resource benchmark, including a solar energy resource benchmark.
(1) To be eligible for use towards satisfying a benchmark, a REC must originate from a facility that meets the definition of a renewable energy resource, including solar energy resources, and be measured by a utility-grade meter in compliance with paragraph B of rule 4901:1-10-05 of the Administrative Code, for facilities with generating capacity of more than six kilowatts. Such facilities could include a mercantile customer-sited resource that is not committed for integration into an electric utility's demand-response, energy efficiency, or peak-demand reduction program pursuant to rule 4901:1-39-08 of the Administrative Code but that otherwise qualifies under the terms of paragraph (A) of this rule.
(2) To use RECs as a means of achieving partial or complete compliance, an electric utility or electric services company must be a registered member in good standing of at least one of the following:
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 519 3 4901:1-40-04 Qualified resources, OH ADC 4901:1-40-04
(a) The PJM's generation attributes tracking system.
(b) The MISO's renewable energy tracking system.
(c) Another credible tracking system approved for use by the commission.
(3) A REC may be used for compliance any time in the five calendar years following the date of its initial purchase or acquisition.
(4) Double counting is prohibited.
(5) The RECs must be associated with electricity that was generated no earlier than July 31, 2008.
(E) For a generating facility of seventy-five megawatts or greater that is situated within this state and has committed by December 31, 2009, to modify or retrofit its generating unit or units to enable the facility to generate principally from biomass energy by June 30, 2013, the number of RECs produced by each megawatt-hour of electricity generated principally from biomass energy shall equal the actual percentage of biomass feedstock heat input used to generate such megawatt-hour multiplied by the quotient obtained by dividing the then existing unit dollar amount used to determine a renewable energy compliance payment as provided under division (C)(2)(b) of section 4928.64 of the Revised Code, by the then existing market value of one REC, but such megawatt-hour shall not equal less than one credit.
(F) An entity seeking resource qualification shall file an application for certification of its resources or technologies, upon such forms as may be prescribed by the commission. The application shall include a determination of deliverability to the state in accordance with paragraph (I) of rule 4901:1-40-01 of the Administrative Code.
(1) Any interested person may file a motion to intervene and file comments and objections to any application filed under this rule within twenty days of the date of the filing of the application.
(2) The commission may approve, suspend, or deny an application within sixty days of it being filed. If the commission does not act within sixty days, the application is deemed automatically approved on the sixty-first day after the date filed.
(3) If the commission suspends the application, the applicant shall be notified of the reasons for such suspension and may be directed to furnish additional information. The commission may act to approve or deny a suspended application within ninety days of the date that the application was suspended.
(4) Upon commission approval, the applicant shall receive notification of approval and a numbered certificate where applicable. The commission shall provide this certificate number to the appropriate attribute tracking system.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 520 4 4901:1-40-04 Qualified resources, OH ADC 4901:1-40-04
(5) Representatives of certified facilities must notify the commission within thirty days of any material changes in information previously submitted to the commission during the certification process. Failure to do so may result in revocation of certification status.
(6) Certification of a resource or technology shall not predetermine compliance with annual benchmarks, and does not constitute any commission position regarding cost recovery.
(G) At its discretion, the commission may classify any new technology or additional resource as an advanced- or renewable-energy resource. Any interested person may request a hearing on such classification.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-04, OH ADC 4901:1-40-04
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 521 5 4901:1-40-05 Annual status reports and compliance reviews, OH ADC 4901:1-40-05
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-05
4901:1-40-05 Annual status reports and compliance reviews
Currentness
(A) Unless otherwise ordered by the commission, each electric utility and electric services company shall file by April fifteenth of each year, on such forms as may be published by the commission, an annual alternative energy portfolio status report analyzing all activities undertaken in the previous calendar year to demonstrate how the applicable alternative energy portfolio benchmarks and planning requirements have or will be met. Staff shall conduct annual compliance reviews with regard to the benchmarks under the alternative energy portfolio standard.
(1) Beginning in the year 2010, the annual review will include compliance with the most recent applicable renewable- and solar-energy resource benchmark.
(2) Beginning in the year 2025, the annual review will include compliance with the most recent applicable advanced energy resource benchmark.
(3) The annual compliance reviews shall consider any under-compliance an electric utility or electric services company asserts is outside its control, including but not limited to, the following:
(a) Weather-related causes.
(b) Equipment shortages for renewable or advanced energy resources.
(c) Resource shortages for renewable or advanced energy resources.
(B) Any person may file comments regarding the electric utility's or electric services company's alternative energy portfolio status report within thirty days of the filing of such report.
(C) Staff shall review each electric utility's or electric services company's alternative energy portfolio status report and any timely filed comments, and file its findings and recommendations and any proposed modifications thereto.
(D) The commission may schedule a hearing on the alternative energy portfolio status report.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 522 1 4901:1-40-05 Annual status reports and compliance reviews, OH ADC 4901:1-40-05
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-05, OH ADC 4901:1-40-05
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 523 2 4901:1-40-06 Force majeure, OH ADC 4901:1-40-06
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-06
4901:1-40-06 Force majeure
Currentness
An electric utility or electric services company may seek a force majeure determination from the commission for all or part of a minimum renewable- or solar-energy benchmark.
(A) A decision on a request for a force majeure determination will be rendered within ninety days of an electric utility or electric services company filing a request for such determination. The process and timeframes for such a determination shall be set by entry of the commission, the legal director, deputy legal director, or attorney examiner.
(1) At the time of requesting such a determination from the commission, an electric utility or electric services company shall demonstrate that it pursued all reasonable compliance options including, but not limited to, renewable energy credit (REC) solicitations, REC banking, and long-term contracts.
(2) The request shall include an assessment of the availability of qualified in-state resources, as well as qualified resources within the territories of PJM and the MISO.
(B) If the commission determines that force majeure conditions exist, it may modify that compliance obligation of the electric utility or electric services company, as it considers appropriate to accommodate the finding.
(1) Such modification does not automatically reduce future-year obligations.
(2) The commission retains the right to increase a future year's compliance obligation by the amount of any under compliance in a previous year that is attributed to a force majeure determination.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-06, OH ADC 4901:1-40-06
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 524 1 4901:1-40-07 Cost cap, OH ADC 4901:1-40-07
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-07
4901:1-40-07 Cost cap
Currentness
(A) An electric utility or electric services company may file an application requesting a determination from the commission that its reasonably expected cost of compliance with an advanced energy resource benchmark would exceed its reasonably expected cost of generation to customers by three per cent or more. The process and timeframes for such a determination shall be set by entry of the commission, the legal director, deputy legal director, or attorney examiner.
(1) The burden of proof for substantiating such a claim shall remain with the electric utility or electric services company.
(2) An electric utility or electric services company shall pursue all reasonable compliance options prior to requesting such a determination from the commission.
(3) In the case that the commission makes such a determination, the electric utility or electric services company may not be required to fully comply with that specific benchmark.
(B) An electric utility or electric services company may file an application requesting a determination from the commission that its reasonably expected cost of compliance with a renewable energy resource benchmark, including a solar energy resource benchmark, would exceed its reasonably expected cost of generation to customers by three per cent or more. The process and timeframes for such a determination shall be set by entry of the commission, the legal director, deputy legal director, or attorney examiner.
(1) The burden of proof for substantiating such a claim shall remain with the electric utility or electric services company.
(2) An electric utility or electric services company shall pursue all reasonable compliance options prior to requesting such a determination from the commission.
(3) In the case that the commission makes such a determination, the electric utility or electric services company may not be required to fully comply with that specific benchmark.
(C) Calculations involving a three per cent cost cap shall consist of comparing the total expected cost of generation to customers of an electric utility or electric services company, while satisfying an alternative energy portfolio standard
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 525 1 4901:1-40-07 Cost cap, OH ADC 4901:1-40-07 requirement, to the total expected cost of generation to customers of the electric utility or electric services company without satisfying that alternative energy portfolio standard requirement.
(D) Any costs included in a commission-approved unavoidable surcharge for construction or environmental expenditures of generation resources shall be excluded from consideration as a cost of compliance under the terms of the alternative energy portfolio standard and therefore, would not count against the applicable cost cap. Such costs should, however, be included in the calculation of the total expected cost of generation to customers described in paragraph (C) of this rule.
(E) If the commission makes a determination that a three per cent provision is triggered, the electric utility or electric services company shall comply with each benchmark up to the point that the three per cent increment would be reached for each benchmark.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-07, OH ADC 4901:1-40-07
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 526 2 4901:1-40-08 Compliance payments, OH ADC 4901:1-40-08
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-08
4901:1-40-08 Compliance payments
Currentness
(A) Any electric utility or electric services company that does not achieve an annual renewable energy resource benchmark, including a solar benchmark, shall remit a compliance payment based on the amount of noncompliance rounded up to the next megawatt hour (MWh), unless the commission has identified the existence of force majeure conditions or the commission has determined that the three per cent cost-cap provision would be exceeded in the event of full compliance.
(1) The required payment for noncompliance with any solar energy resource benchmark shall be calculated by quantifying the level of noncompliance, rounded to the next MWh, and multiplying this figure by the per MWh amount in the table below.
Solar energy resources - compliance payment
Year Payment per MWh
2009 $450
2010 and 2011 $400
2012 and 2013 $350
2014 and 2015 $300
2016 and 2017 $250
2018 and 2019 $200
2020 and 2021 $150
2022 and 2023 $100
2024 and beyond $50
(2) The required payment for noncompliance with any renewable energy resource benchmark, excluding solar, shall be calculated by quantifying the level of noncompliance, rounded to the next MWh, and multiplying this figure by an amount determined by the commission.
(a) The per MWh payment for renewable energy resources for the year 2009 is forty-five dollars.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 527 1 4901:1-40-08 Compliance payments, OH ADC 4901:1-40-08
(b) Beginning in the year 2010, the per MWh payment for renewable energy resources will be adjusted annually to reflect the annual change to the consumer price index as defined in section 101.27 of the Revised Code. Such adjustment shall be performed by staff no later than June first of each calendar year. This annual adjustment shall be calculated using the following formula:
= ((CPIYR2/CPIYR1) * current per MWh payment)
(c) In no event shall the compliance payment for renewable energy resources be less than forty-five dollars per MWh.
(3) At least annually, the staff shall conduct a review of the renewable energy resource market, including solar, both within this state and within the regional transmission systems active in the state. The results of this review shall be used to determine if changes to the solar- or renewable-energy compliance payments are warranted, as follows:
(a) The commission may increase compliance payments if needed to ensure that electric utilities and electric services companies are not using the payments in lieu of acquiring or producing energy or RECs from qualified renewable resources, including solar.
(b) Any recommendation to reduce the compliance payments shall be presented to the general assembly.
(B) Any compliance payment shall be submitted to the commission for deposit to the credit of the advanced energy fund. All compliance payments shall be delivered to the commission within thirty days of the imposition of any compliance payment requirement.
(C) Compliance payments shall be subject to such collection and enforcement procedures as apply to the collection of a forfeiture under sections 4905.55 to 4905.60 and 4905.64 of the Revised Code.
(D) Any electric utility or electric services company found to be liable for a compliance payment is prohibited from passing compliance payments on to consumers. In the event that a compliance payment is required, an electric utility or electric services company shall submit an attestation, signed by a company officer or designee, indicating that it will not seek to recover the specific compliance payment from consumers. Such attestation shall be submitted to staff within thirty days of the imposition of any compliance payment requirement.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
Rules and appendices are current through March 31, 2018
4901:1-40-08, OH ADC 4901:1-40-08
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 528 2 4901:1-40-08 Compliance payments, OH ADC 4901:1-40-08
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 529 3 4901:1-40-09 Annual report, OH ADC 4901:1-40-09
Baldwin's Ohio Administrative Code Annotated 4901 Public Utilities Commission (Refs & Annos) 4901:1 Utilities (Refs & Annos) Chapter 4901:1-40. Alternative Energy Portfolio Standard (Refs & Annos)
OAC 4901:1-40-09
4901:1-40-09 Annual report
Currentness
(A) Pursuant to division (D)(1) of section 4928.64 of the Revised Code, an annual report shall be submitted to the general assembly addressing at least the following topics:
(1) The compliance status of electric utilities and electric services companies with respect to the advanced- and renewable-energy resource benchmarks.
(2) Suggested strategies for electric utility and electric services company compliance.
(3) Suggested strategies for encouraging the use of alternative energy resources in supplying this state's electricity needs in a manner that considers:
(a) Available technology.
(b) Costs.
(c) Job creation.
(d) Economic impacts.
(B) The report shall be submitted in accordance with section 101.68 of the Revised Code.
(C) Prior to its submission to the general assembly, the report will be issued for public comment by interested persons for thirty days, unless otherwise ordered by the commission. The process and timeframes for soliciting public comment shall be set by entry of the commission, the legal director, deputy director, or attorney examiner.
Credits HISTORY: 2009-10 OMR pam. #5 (E), eff. 12-10-09
RC 119.032 rule review date(s): 9-30-13
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 530 1 4901:1-40-09 Annual report, OH ADC 4901:1-40-09
Rules and appendices are current through March 31, 2018
4901:1-40-09, OH ADC 4901:1-40-09
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 531 2 106.021 Criteria for recommending invalidation by general assembly, OH ST § 106.021
KeyCite Yellow Flag - Negative Treatment Proposed Legislation Baldwin's Ohio Revised Code Annotated Title I. State Government Chapter 106. Agency Rules
R.C. § 106.021
106.021 Criteria for recommending invalidation by general assembly
Effective: September 17, 2014 Currentness
If, upon reviewing a proposed rule or revised proposed rule, the joint committee on agency rule review makes any of the following findings with regard to the proposed rule or revised proposed rule, the joint committee may recommend to the senate and house of representatives the adoption of a concurrent resolution to invalidate the proposed rule or revised proposed rule or a part thereof:
(A) The proposed rule or revised proposed rule exceeds the scope of its statutory authority.
(B) The proposed rule or revised proposed rule conflicts with the legislative intent of the statute under which it was proposed.
(C) The proposed rule or revised proposed rule conflicts with another proposed or existing rule.
(D) The proposed rule or revised proposed rule incorporates a text or other material by reference and either the agency has failed to file the text or other material incorporated by reference as required by section 121.73 of the Revised Code or the incorporation by reference fails to meet the standards stated in sections 121.72, 121.75, and 121.76 of the Revised Code.
(E) The agency has failed to prepare a complete and accurate rule summary and fiscal analysis of the proposed rule or revised proposed rule as required by section 127.18 of the Revised Code.
(F) The agency has failed to demonstrate through the business impact analysis, recommendations from the common sense initiative office, and the memorandum of response that the regulatory intent of the proposed rule or revised proposed rule justifies its adverse impact on businesses in this state.
CREDIT(S)
(2014 S 3, eff. 9-17-14)
R.C. § 106.021, OH ST § 106.021
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 532 1 106.021 Criteria for recommending invalidation by general assembly, OH ST § 106.021
Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 533 2 111.15 Rules filed; duties of legislative service commission;..., OH ST § 111.15
KeyCite Yellow Flag - Negative Treatment Proposed Legislation Baldwin's Ohio Revised Code Annotated Title I. State Government Chapter 111. Secretary of State (Refs & Annos) Organization, Powers, and Duties
R.C. § 111.15
111.15 Rules filed; duties of legislative service commission; standards and procedures
Effective: January 1, 2018 Currentness
(A) As used in this section:
(1) “Rule” includes any rule, regulation, bylaw, or standard having a general and uniform operation adopted by an agency under the authority of the laws governing the agency; any appendix to a rule; and any internal management rule. “Rule” does not include any guideline adopted pursuant to section 3301.0714 of the Revised Code, any order respecting the duties of employees, any finding, any determination of a question of law or fact in a matter presented to an agency, or any rule promulgated pursuant to Chapter 119. or division (C)(1) or (2) of section 5117.02 of the Revised Code. “Rule” includes any amendment or rescission of a rule.
(2) “Agency” means any governmental entity of the state and includes, but is not limited to, any board, department, division, commission, bureau, society, council, institution, state college or university, community college district, technical college district, or state community college. “Agency” does not include the general assembly, the controlling board, the adjutant general's department, or any court.
(3) “Internal management rule” means any rule, regulation, bylaw, or standard governing the day-to-day staff procedures and operations within an agency.
(B)(1) Any rule, other than a rule of an emergency nature, adopted by any agency pursuant to this section shall be effective on the tenth day after the day on which the rule in final form and in compliance with division (B)(3) of this section is filed as follows:
(a) The rule shall be filed in electronic form with both the secretary of state and the director of the legislative service commission;
(b) The rule shall be filed in electronic form with the joint committee on agency rule review. Division (B)(1)(b) of this section does not apply to any rule to which division (D) of this section does not apply.
An agency that adopts or amends a rule that is subject to division (D) of this section shall assign a review date to the rule that is not later than five years after its effective date. If a review date assigned to a rule exceeds the five-year maximum,
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 534 1 111.15 Rules filed; duties of legislative service commission;..., OH ST § 111.15 the review date for the rule is five years after its effective date. A rule with a review date is subject to review under section 106.03 of the Revised Code. This paragraph does not apply to a rule of a state college or university, community college district, technical college district, or state community college.
If an agency in adopting a rule designates an effective date that is later than the effective date provided for by division (B)(1) of this section, the rule if filed as required by such division shall become effective on the later date designated by the agency.
Any rule that is required to be filed under division (B)(1) of this section is also subject to division (D) of this section if not exempted by that division.
If a rule incorporates a text or other material by reference, the agency shall comply with sections 121.71 to 121.76 of the Revised Code.
(2) A rule of an emergency nature necessary for the immediate preservation of the public peace, health, or safety shall state the reasons for the necessity. The emergency rule, in final form and in compliance with division (B)(3) of this section, shall be filed in electronic form with the secretary of state, the director of the legislative service commission, and the joint committee on agency rule review. The emergency rule is effective immediately upon completion of the latest filing, except that if the agency in adopting the emergency rule designates an effective date, or date and time of day, that is later than the effective date and time provided for by division (B)(2) of this section, the emergency rule if filed as required by such division shall become effective at the later date, or later date and time of day, designated by the agency.
An emergency rule becomes invalid at the end of the one hundred twentieth day it is in effect. Prior to that date, the agency may file the emergency rule as a nonemergency rule in compliance with division (B)(1) of this section. The agency may not refile the emergency rule in compliance with division (B)(2) of this section so that, upon the emergency rule becoming invalid under such division, the emergency rule will continue in effect without interruption for another one hundred twenty-day period.
(3) An agency shall file a rule under division (B)(1) or (2) of this section in compliance with the following standards and procedures:
(a) The rule shall be numbered in accordance with the numbering system devised by the director for the Ohio administrative code.
(b) The rule shall be prepared and submitted in compliance with the rules of the legislative service commission.
(c) The rule shall clearly state the date on which it is to be effective and the date on which it will expire, if known.
(d) Each rule that amends or rescinds another rule shall clearly refer to the rule that is amended or rescinded. Each amendment shall fully restate the rule as amended.
If the director of the legislative service commission or the director's designee gives an agency notice pursuant to section 103.05 of the Revised Code that a rule filed by the agency is not in compliance with the rules of the legislative service commission, the agency shall within thirty days after receipt of the notice conform the rule to the rules of the commission as directed in the notice.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 535 2 111.15 Rules filed; duties of legislative service commission;..., OH ST § 111.15
(C) All rules filed pursuant to divisions (B)(1)(a) and (2) of this section shall be recorded by the secretary of state and the director under the title of the agency adopting the rule and shall be numbered according to the numbering system devised by the director. The secretary of state and the director shall preserve the rules in an accessible manner. Each such rule shall be a public record open to public inspection and may be transmitted to any law publishing company that wishes to reproduce it.
(D) At least sixty-five days before a board, commission, department, division, or bureau of the government of the state files a rule under division (B)(1) of this section, it shall file the full text of the proposed rule in electronic form with the joint committee on agency rule review, and the proposed rule is subject to legislative review and invalidation under section 106.021 of the Revised Code. If a state board, commission, department, division, or bureau makes a revision in a proposed rule after it is filed with the joint committee, the state board, commission, department, division, or bureau shall promptly file the full text of the proposed rule in its revised form in electronic form with the joint committee. A state board, commission, department, division, or bureau shall also file the rule summary and fiscal analysis prepared under section 127.18 of the Revised Code in electronic form along with a proposed rule, and along with a proposed rule in revised form, that is filed under this division. If a proposed rule has an adverse impact on businesses, the state board, commission, department, division, or bureau also shall file the business impact analysis, any recommendations received from the common sense initiative office, and the associated memorandum of response, if any, in electronic form along with the proposed rule, or the proposed rule in revised form, that is filed under this division.
A proposed rule that is subject to legislative review under this division may not be adopted and filed in final form under division (B)(1) of this section unless the proposed rule has been filed with the joint committee on agency rule review under this division and the time for the joint committee to review the proposed rule has expired without recommendation of a concurrent resolution to invalidate the proposed rule.
As used in this division, “commission” includes the public utilities commission when adopting rules under a federal or state statute.
This division does not apply to any of the following:
(1) A proposed rule of an emergency nature;
(2) A rule proposed under section 1121.05, 1121.06, 1349.33, 1707.201, 1733.412, 4123.29, 4123.34, 4123.341, 4123.342, 4123.40, 4123.411, 4123.44, or 4123.442 of the Revised Code;
(3) A rule proposed by an agency other than a board, commission, department, division, or bureau of the government of the state;
(4) A proposed internal management rule of a board, commission, department, division, or bureau of the government of the state;
(5) Any proposed rule that must be adopted verbatim by an agency pursuant to federal law or rule, to become effective within sixty days of adoption, in order to continue the operation of a federally reimbursed program in this state, so long as the proposed rule contains both of the following:
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 536 3 111.15 Rules filed; duties of legislative service commission;..., OH ST § 111.15
(a) A statement that it is proposed for the purpose of complying with a federal law or rule;
(b) A citation to the federal law or rule that requires verbatim compliance.
(6) An initial rule proposed by the director of health to impose safety standards and quality-of-care standards with respect to a health service specified in section 3702.11 of the Revised Code, or an initial rule proposed by the director to impose quality standards on a facility listed in division (A)(4) of section 3702.30 of the Revised Code, if section 3702.12 of the Revised Code requires that the rule be adopted under this section;
(7) A rule of the state lottery commission pertaining to instant game rules.
If a rule is exempt from legislative review under division (D)(5) of this section, and if the federal law or rule pursuant to which the rule was adopted expires, is repealed or rescinded, or otherwise terminates, the rule is thereafter subject to legislative review under division (D) of this section.
Whenever a state board, commission, department, division, or bureau files a proposed rule or a proposed rule in revised form under division (D) of this section, it shall also file the full text of the same proposed rule or proposed rule in revised form in electronic form with the secretary of state and the director of the legislative service commission. A state board, commission, department, division, or bureau shall file the rule summary and fiscal analysis prepared under section 127.18 of the Revised Code in electronic form along with a proposed rule or proposed rule in revised form that is filed with the secretary of state or the director of the legislative service commission.
CREDIT(S)
(2017 H 49, § 130.21, eff. 1-1-18; 2014 S 3, eff. 9-17-14; 2013 H 59, eff. 9-29-13; 2013 S 67, eff. 9-4-13; 2011 S 2, eff. 1-1-12; 2006 H 197, eff. 11-13-06; 2005 H 81, eff. 4-14-06; 2002 S 265, eff. 9-17-02; 2002 S 138, eff. 6-18-02; 2002 H 386, eff. 5-24-02; 1999 S 11, § 6, eff. 4-1-02; 1999 S 11, § 3, eff. 4-1-01; 1999 S 11, § 1, eff. 9-15-99; 1998 H 850, eff. 3-18-99; 1998 H 562, eff. 9-30-98; 1997 S 130, eff. 9-18-97; 1997 H 215, eff. 6-30-97; 1996 S 82, eff. 3-7-97; 1996 H 538, eff. 1-1-97; 1996 S 211, eff. 9-26-96; 1996 H 473, eff. 9-26-96; 1995 S 156, eff. 6-30-95; 1995 S 50, eff. 4-20-95; 1994 H 695, eff. 9-29-94; 1992 S 359, eff. 12-22-92; 1992 H 437; 1985 S 269, H 201; 1984 S 239, H 244; 1981 H 694, H 1; 1980 H 440; 1979 H 204, H 657, S 8; 1978 S 321; 1977 H 25, H 257; 1976 H 317; 1953 H 1; GC 161-1)
Notes of Decisions (26)
R.C. § 111.15, OH ST § 111.15 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 537 4 119.01 Definitions, OH ST § 119.01
KeyCite Yellow Flag - Negative Treatment Proposed Legislation Baldwin's Ohio Revised Code Annotated Title I. State Government Chapter 119. Administrative Procedure (Refs & Annos) Definitions
R.C. § 119.01
119.01 Definitions
Effective: January 1, 2018 Currentness
As used in sections 119.01 to 119.13 of the Revised Code:
(A)(1) “Agency” means, except as limited by this division, any official, board, or commission having authority to promulgate rules or make adjudications in the civil service commission, the division of liquor control, the department of taxation, the industrial commission, the bureau of workers' compensation, the functions of any administrative or executive officer, department, division, bureau, board, or commission of the government of the state specifically made subject to sections 119.01 to 119.13 of the Revised Code, and the licensing functions of any administrative or executive officer, department, division, bureau, board, or commission of the government of the state having the authority or responsibility of issuing, suspending, revoking, or canceling licenses.
Sections 119.01 to 119.13 of the Revised Code do not apply to the public utilities commission. Sections 119.01 to 119.13 of the Revised Code do not apply to the utility radiological safety board; to the controlling board; to actions of the superintendent of financial institutions and the superintendent of insurance in the taking possession of, and rehabilitation or liquidation of, the business and property of banks, savings and loan associations, savings banks, credit unions, insurance companies, associations, reciprocal fraternal benefit societies, and bond investment companies; to any action taken by the division of securities under section 1707.201 of the Revised Code; or to any action that may be taken by the superintendent of financial institutions under section 1113.03, 1121.06, 1121.10, 1125.09, 1125.12, 1125.18, 1349.33, 1733.35, 1733.361, 1733.37, or 1761.03 of the Revised Code.
Sections 119.01 to 119.13 of the Revised Code do not apply to actions of the industrial commission or the bureau of workers' compensation under sections 4123.01 to 4123.94 of the Revised Code with respect to all matters of adjudication, or to the actions of the industrial commission, bureau of workers' compensation board of directors, and bureau of workers' compensation under division (D) of section 4121.32, sections 4123.29, 4123.34, 4123.341, 4123.342, 4123.40, 4123.411, 4123.44, 4123.442, 4127.07, divisions (B), (C), and (E) of section 4131.04, and divisions (B), (C), and (E) of section 4131.14 of the Revised Code with respect to all matters concerning the establishment of premium, contribution, and assessment rates.
(2) “Agency” also means any official or work unit having authority to promulgate rules or make adjudications in the department of job and family services, but only with respect to both of the following:
(a) The adoption, amendment, or rescission of rules that section 5101.09 of the Revised Code requires be adopted in accordance with this chapter;
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 538 1 119.01 Definitions, OH ST § 119.01
(b) The issuance, suspension, revocation, or cancellation of licenses.
(B) “License” means any license, permit, certificate, commission, or charter issued by any agency. “License” does not include any arrangement whereby a person or government entity furnishes medicaid services under a provider agreement with the department of medicaid.
(C) “Rule” means any rule, regulation, or standard, having a general and uniform operation, adopted, promulgated, and enforced by any agency under the authority of the laws governing such agency, and includes any appendix to a rule. “Rule” does not include any internal management rule of an agency unless the internal management rule affects private rights and does not include any guideline adopted pursuant to section 3301.0714 of the Revised Code.
(D) “Adjudication” means the determination by the highest or ultimate authority of an agency of the rights, duties, privileges, benefits, or legal relationships of a specified person, but does not include the issuance of a license in response to an application with respect to which no question is raised, nor other acts of a ministerial nature.
(E) “Hearing” means a public hearing by any agency in compliance with procedural safeguards afforded by sections 119.01 to 119.13 of the Revised Code.
(F) “Person” means a person, firm, corporation, association, or partnership.
(G) “Party” means the person whose interests are the subject of an adjudication by an agency.
(H) “Appeal” means the procedure by which a person, aggrieved by a finding, decision, order, or adjudication of any agency, invokes the jurisdiction of a court.
(I) “Internal management rule” means any rule, regulation, or standard governing the day-to-day staff procedures and operations within an agency.
CREDIT(S)
(2017 H 49, § 130.21, eff. 1-1-18; 2014 S 3, eff. 9-17-14; 2013 H 59, eff. 9-29-13; 2010 H 292, eff. 9-13-10; 2007 H 100, eff. 9-10-07; 2005 H 81, eff. 4-14-06; 2002 S 138, eff. 6-18-02; 2002 H 386, eff. 5-24-02; 1999 H 470, eff. 7-1-00; 1998 H 850, eff. 3-18-99; 1997 H 215, eff. 6-30-97; 1996 S 82, eff. 3-7-97; 1996 H 538, eff. 1-1-97; 1996 S 293, eff. 9-26-96 (General Effective Date); 1995 S 162, eff. 10-29-95; 1995 H 7, eff. 9-1-95; 1994 H 695, eff. 9-29-94; 1992 H 437, eff. 4-30-92; 1989 H 111; 1985 H 201; 1984 H 244; 1983 H 260; 1980 H 403; 1979 H 204; 1977 H 257; 1976 S 545, H 920; 1975 H 1; 1973 H 366; 1969 H 1; 132 v S 97; 1953 H 1; GC 154-62)
Notes of Decisions (151)
R.C. § 119.01, OH ST § 119.01
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 539 2 119.01 Definitions, OH ST § 119.01
Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 540 3 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
Baldwin's Ohio Revised Code Annotated Title XXI. Courts--Probate--Juvenile (Refs & Annos) Chapter 2101. Probate Court--Jurisdiction; Procedure (Refs & Annos) Fees and Costs
R.C. § 2101.16
2101.16 Fees; cost of investigations; advance deposit
Effective: April 6, 2017 Currentness
(A) Except as provided in section 2101.164 of the Revised Code, the fees enumerated in this division shall be charged and collected, if possible, by the probate judge and shall be in full for all services rendered in the respective proceedings:
(1) Account, in addition to advertising charges
...... $ 12.00
Waivers and proof of notice of hearing on account, per page, minimum one dollar
...... $ 1.00
(2) Account of distribution, in addition to advertising charges
...... $ 7.00
(3) Adoption of child, petition for
...... $ 50.00
(4) Alter or cancel contract for sale or purchase of real property, complaint to
...... $ 20.00
(5) Application and order not otherwise provided for in this section or by rule adopted pursuant to division (E) of this section
...... $ 5.00
(6) Appropriation suit, per day, hearing in
...... $ 20.00
(7) Birth, application for registration of
...... $ 7.00
(8) Birth record, application to correct
...... $ 5.00
(9) Bond, application for new or additional
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 541 1 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
...... $ 5.00
(10) Bond, application for release of surety or reduction of
...... $ 5.00
(11) Bond, receipt for securities deposited in lieu of
...... $ 5.00
(12) Certified copy of journal entry, record, or proceeding, per page, minimum fee one dollar
...... $ 1.00
(13) Citation and issuing citation, application for
...... $ 5.00
(14) Change of name, petition for
...... $ 20.00
(15) Claim, application of administrator or executor for allowance of administrator's or executor's own
...... $ 10.00
(16) Claim, application to compromise or settle
...... $ 10.00
(17) Claim, authority to present
...... $ 10.00
(18) Commissioner, appointment of
...... $ 5.00
(19) Compensation for extraordinary services and attorney's fees for fiduciary, application for
...... $ 5.00
(20) Competency, application to procure adjudication of
...... $ 20.00
(21) Complete contract, application to
...... $ 10.00
(22) Concealment of assets, citation for
...... $ 10.00
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 542 2 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
(23) Construction of will, complaint for
...... $ 20.00
(24) Continue decedent's business, application to
...... $ 10.00
Monthly reports of operation
...... $ 5.00
(25) Declaratory judgment, complaint for
...... $ 20.00
(26) Deposit of will
...... $ 5.00
(27) Designation of heir
...... $ 20.00
(28) Distribution in kind, application, assent, and order for
...... $ 5.00
(29) Distribution under section 2109.36 of the Revised Code, application for an order of
...... $ 7.00
(30) Docketing and indexing proceedings, including the filing and noting of all necessary documents, maximum fee, fifteen dollars
...... $ 15.00
(31) Exceptions to any proceeding named in this section, contest of appointment or
...... $ 10.00
(32) Election of surviving partner to purchase assets of partnership, proceedings relating to
...... $ 10.00
(33) Election of surviving spouse under will
...... $ 5.00
(34) Fiduciary, including an assignee or trustee of an insolvent debtor or any guardian or conservator accountable to the probate court, appointment of
...... $ 35.00
(35) Foreign will, application to record
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 543 3 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
...... $ 10.00
Record of foreign will, additional, per page
...... $ 1.00
(36) Forms when supplied by the probate court, not to exceed
...... $ 10.00
(37) Heirship, complaint to determine
...... $ 20.00
(38) Injunction proceedings
...... $ 20.00
(39) Improve real property, petition to
...... $ 20.00
(40) Inventory with appraisement
...... $ 10.00
(41) Inventory without appraisement
...... $ 7.00
(42) Investment or expenditure of funds, application for
...... $ 10.00
(43) Invest in real property, application to
...... $ 10.00
(44) Lease for oil, gas, coal, or other mineral, petition to
...... $ 20.00
(45) Lease or lease and improve real property, petition to
...... $ 20.00
(46) Marriage license
...... $ 10.00
Certified abstract of each marriage
...... $ 2.00
(47) Minor or incompetent person, etc., disposal of estate under twenty-five thousand dollars of
...... $ 10.00
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 544 4 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
(48) Mortgage or mortgage and repair or improve real property, complaint to
...... $ 20.00
(49) Newly discovered assets, report of
...... $ 7.00
(50) Nonresident executor or administrator to bar creditors' claims, proceedings by
...... $ 20.00
(51) Power of attorney or revocation of power, bonding company
...... $ 10.00
(52) Presumption of death, petition to establish
...... $ 20.00
(53) Probating will
...... $ 15.00
Proof of notice to beneficiaries
...... $ 5.00
(54) Purchase personal property, application of surviving spouse to
...... $ 10.00
(55) Purchase real property at appraised value, petition of surviving spouse to
...... $ 20.00
(56) Receipts in addition to advertising charges, application and order to record
...... $ 5.00
Record of those receipts, additional, per page
...... $ 1.00
(57) Record in excess of fifteen hundred words in any proceeding in the probate court, per page
...... $ 1.00
(58) Release of estate by mortgagee or other lienholder
...... $ 5.00
(59) Relieving an estate from administration under
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 545 5 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
section 2113.03 of the Revised Code or granting an order for a summary release from administration under section 2113.031 of the Revised Code
...... $ 60.00
(60) Removal of fiduciary, application for
...... $ 10.00
(61) Requalification of executor or administrator
...... $ 10.00
(62) Resignation of fiduciary
...... $ 5.00
(63) Sale bill, public sale of personal property
...... $ 10.00
(64) Sale of personal property and report, application for
...... $ 10.00
(65) Sale of real property, petition for
...... $ 25.00
(66) Terminate guardianship, petition to
...... $ 10.00
(67) Transfer of real property, application, entry, and certificate for
...... $ 7.00
(68) Unclaimed money, application to invest
...... $ 7.00
(69) Vacate approval of account or order of distribution, motion to
...... $ 10.00
(70) Writ of execution
...... $ 5.00
(71) Writ of possession
...... $ 5.00
(72) Wrongful death, application and settlement of claim for
...... $ 20.00
(73) Year's allowance, petition to review
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 546 6 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
...... $ 7.00
(74) Guardian's report, filing and review of
...... $ 5.00
(75) Mentally ill person subject to court order, filing of affidavit and proceedings for
...... $ 25.00
(B)(1) In relation to an application for the appointment of a guardian or the review of a report of a guardian under section 2111.49 of the Revised Code, the probate court, pursuant to court order or in accordance with a court rule, may direct that the applicant or the estate pay any or all of the expenses of an investigation conducted pursuant to section 2111.041 or division (A)(2) of section 2111.49 of the Revised Code. If the investigation is conducted by a public employee or investigator who is paid by the county, the fees for the investigation shall be paid into the county treasury. If the court finds that an alleged incompetent or a ward is indigent, the court may waive the costs, fees, and expenses of an investigation.
(2) In relation to the appointment or functioning of a guardian for a minor or the guardianship of a minor, the probate court may direct that the applicant or the estate pay any or all of the expenses of an investigation conducted pursuant to section 2111.042 of the Revised Code. If the investigation is conducted by a public employee or investigator who is paid by the county, the fees for the investigation shall be paid into the county treasury. If the court finds that the guardian or applicant is indigent, the court may waive the costs, fees, and expenses of an investigation.
(3) In relation to the filing of an affidavit of mental illness for a mentally ill person subject to court order, the court may waive the fee under division (A)(75) of this section if the court finds that the affiant is indigent or for good cause shown.
(C) Thirty dollars of the thirty-five-dollar fee collected pursuant to division (A)(34) of this section and twenty dollars of the sixty-dollar fee collected pursuant to division (A)(59) of this section shall be deposited by the county treasurer in the indigent guardianship fund created pursuant to section 2111.51 of the Revised Code.
(D) The fees of witnesses, jurors, sheriffs, coroners, and constables for services rendered in the probate court or by order of the probate judge shall be the same as provided for similar services in the court of common pleas.
(E) The probate court, by rule, may require an advance deposit for costs, not to exceed one hundred twenty-five dollars, at the time application is made for an appointment as executor or administrator or at the time a will is presented for probate.
(F)(1) Thirty dollars of the fifty-dollar fee collected pursuant to division (A)(3) of this section shall be deposited into the “putative father registry fund,” which is hereby created in the state treasury. The department of job and family services shall use the money in the fund to fund the department's costs of performing its duties related to the putative father registry established under section 3107.062 of the Revised Code.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 547 7 2101.16 Fees; cost of investigations; advance deposit, OH ST § 2101.16
(2) If the department determines that money in the putative father registry fund is more than is needed for its duties related to the putative father registry, the department may use the surplus moneys in the fund as permitted in division (C) of section 2151.3534, division (B) of section 2151.3530, or section 5103.155 of the Revised Code.
CREDIT(S)
(2016 S 332, eff. 4-6-17; 2013 S 23, eff. 3-20-15; 2014 S 43, eff. 9-17-14; 2011 S 124, eff. 1-13-12; 2009 S 106, eff. 3-24-10; 2007 H 372, eff. 3-24-08; 2003 H 95, eff. 6-26-03; 2000 H 313, eff. 8-29-00; 1999 H 471, eff. 7-1-00; 1996 H 419, eff. 9-18-96; 1994 H 457, eff. 11-9-94; 1993 H 9, eff. 9-14-93; 1992 H 89; 1989 S 46; 1985 H 419; 1984 H 84; 1982 H 317; 1977 H 1; 1976 S 466, H 740; 1975 S 145, H 1; 126 v 607; 1953 H 1; GC 10501-20, 10501-42)
Notes of Decisions (17)
R.C. § 2101.16, OH ST § 2101.16 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 548 8 4769.08 Costs of investigations and hearings, OH ST § 4769.08
Baldwin's Ohio Revised Code Annotated Title XLVII. Occupations--Professions (Refs & Annos) Chapter 4769. Health Care Practitioner Balance Billing (Refs & Annos)
R.C. § 4769.08
4769.08 Costs of investigations and hearings
Currentness
In the case of a violator of section 4769.02 of the Revised Code who elected a hearing under division (B) of section 4769.03 of the Revised Code, an adjudication order issued under division (C) or (D) of section 4769.03 of the Revised Code may, in addition to imposing the penalties specified in those divisions, require the violator to pay the reasonable costs, not exceeding twenty-five thousand dollars, of the investigation and adjudication conducted under division (B) of that section. If a health care practitioner or employer elected a hearing under division (B) of that section and was found not to have violated section 4769.02 of the Revised Code, the department of health may pay the health care practitioner's or employer's reasonable costs, not to exceed twenty-five thousand dollars, including attorneys' fees, associated with the conduct of the investigation and adjudication.
Notwithstanding section 119.12 of the Revised Code, the filing of a judicial appeal of an adjudication order issued under section 4769.03 of the Revised Code shall operate as a suspension of the adjudication order pending the outcome of the appeal.
CREDIT(S)
(1992 H 478, eff. 1-14-93)
R.C. § 4769.08, OH ST § 4769.08 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 549 1 4903.13 Reversal of final order; notice of appeal, OH ST § 4903.13
Baldwin's Ohio Revised Code Annotated Title XLIX. Public Utilities Chapter 4903. Public Utilities Commission--Hearings (Refs & Annos) Appeals
R.C. § 4903.13
4903.13 Reversal of final order; notice of appeal
Currentness
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 unlawful or unreasonable.
The proceeding to obtain such reversal, vacation, or modification shall be by notice of appeal, filed with the public utilities commission by any party to the proceeding before it, against the commission, setting forth the order appealed from and the errors complained of. The notice of appeal shall be served, unless waived, upon the chairman of the commission, or, in the event of his absence, upon any public utilities commissioner, or by leaving a copy at the office of the commission at Columbus. The court may permit any interested party to intervene by cross-appeal.
CREDIT(S)
(1953 H 1, eff. 10-1-53; GC 544, 545)
Notes of Decisions (171)
R.C. § 4903.13, OH ST § 4903.13 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 550 1 4928.64 Qualifying renewable energy resources requirements;..., OH ST § 4928.64
KeyCite Yellow Flag - Negative Treatment Proposed Legislation Baldwin's Ohio Revised Code Annotated Title XLIX. Public Utilities Chapter 4928. Competitive Electric Retail Service Energy Efficiency Revolving Loan Program
R.C. § 4928.64
4928.64 Qualifying renewable energy resources requirements; review; reporting
Effective: September 29, 2017 Currentness
(A)(1) As used in this section, “qualifying renewable energy resource” means a renewable energy resource, as defined in section 4928.01 of the Revised Code that:
(a) Has a placed-in-service date on or after January 1, 1998;
(b) Is any run-of-the-river hydroelectric facility that has an in-service date on or after January 1, 1980;
(c) Is a small hydroelectric facility;
(d) Is created on or after January 1, 1998, by the modification or retrofit of any facility placed in service prior to January 1, 1998; or
(e) Is a mercantile customer-sited renewable energy resource, whether new or existing, that the mercantile customer commits for integration into the electric distribution utility's demand-response, energy efficiency, or peak demand reduction programs as provided under division (A)(2)(c) of section 4928.66 of the Revised Code, including, but not limited to, any of the following:
(i) A resource that has the effect of improving the relationship between real and reactive power;
(ii) A resource that makes efficient use of waste heat or other thermal capabilities owned or controlled by a mercantile customer;
(iii) Storage technology that allows a mercantile customer more flexibility to modify its demand or load and usage characteristics;
(iv) Electric generation equipment owned or controlled by a mercantile customer that uses a renewable energy resource.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 551 1 4928.64 Qualifying renewable energy resources requirements;..., OH ST § 4928.64
(2) For the purpose of this section and as it considers appropriate, the public utilities commission may classify any new technology as such a qualifying renewable energy resource.
(B)(1) By 2027 and thereafter, an electric distribution utility shall provide from qualifying renewable energy resources, including, at its discretion, qualifying renewable energy resources obtained pursuant to an electricity supply contract, a portion of the electricity supply required for its standard service offer under section 4928.141 of the Revised Code, and an electric services company shall provide a portion of its electricity supply for retail consumers in this state from qualifying renewable energy resources, including, at its discretion, qualifying renewable energy resources obtained pursuant to an electricity supply contract. That portion shall equal twelve and one-half per cent of the total number of kilowatt hours of electricity sold by the subject utility or company to any and all retail electric consumers whose electric load centers are served by that utility and are located within the utility's certified territory or, in the case of an electric services company, are served by the company and are located within this state. However, nothing in this section precludes a utility or company from providing a greater percentage.
(2) The portion required under division (B)(1) of this section shall be generated from renewable energy resources, including one-half per cent from solar energy resources, in accordance with the following benchmarks:
By end of year Renewable energy Solar energy resources resources
2009 0.25% 0.004%
2010 0.50% 0.010%
2011 1% 0.030%
2012 1.5% 0.060%
2013 2% 0.090%
2014 2.5% 0.12%
2015 2.5% 0.12%
2016 2.5% 0.12%
2017 3.5% 0.15%
2018 4.5% 0.18%
2019 5.5% 0.22%
2020 6.5% 0.26%
2021 7.5% 0.3%
2022 8.5% 0.34%
2023 9.5% 0.38%
2024 10.5% 0.42%
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 552 2 4928.64 Qualifying renewable energy resources requirements;..., OH ST § 4928.64
2025 11.5% 0.46%
2026 and each calendar 12.5% 0.5%. year thereafter
(3) The qualifying renewable energy resources implemented by the utility or company shall be met either:
(a) Through facilities located in this state; or
(b) With resources that can be shown to be deliverable into this state.
(C)(1) The commission annually shall review an electric distribution utility's or electric services company's compliance with the most recent applicable benchmark under division (B)(2) of this section and, in the course of that review, shall identify any undercompliance or noncompliance of the utility or company that it determines is weather-related, related to equipment or resource shortages for qualifying renewable energy resources as applicable, or is otherwise outside the utility's or company's control.
(2) Subject to the cost cap provisions of division (C)(3) of this section, if the commission determines, after notice and opportunity for hearing, and based upon its findings in that review regarding avoidable undercompliance or noncompliance, but subject to division (C)(4) of this section, that the utility or company has failed to comply with any such benchmark, the commission shall impose a renewable energy compliance payment on the utility or company.
(a) The compliance payment pertaining to the solar energy resource benchmarks under division (B)(2) of this section shall be an amount per megawatt hour of undercompliance or noncompliance in the period under review, as follows:
(i) Three hundred dollars for 2014, 2015, and 2016;
(ii) Two hundred fifty dollars for 2017 and 2018;
(iii) Two hundred dollars for 2019 and 2020;
(iv) Similarly reduced every two years thereafter through 2026 by fifty dollars, to a minimum of fifty dollars.
(b) The compliance payment pertaining to the renewable energy resource benchmarks under division (B)(2) of this section shall equal the number of additional renewable energy credits that the electric distribution utility or electric services company would have needed to comply with the applicable benchmark in the period under review times an amount that shall begin at forty-five dollars and shall be adjusted annually by the commission to reflect any change in the consumer price index as defined in section 101.27 of the Revised Code, but shall not be less than forty-five dollars.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 553 3 4928.64 Qualifying renewable energy resources requirements;..., OH ST § 4928.64
(c) The compliance payment shall not be passed through by the electric distribution utility or electric services company to consumers. The compliance payment shall be remitted to the commission, for deposit to the credit of the advanced energy fund created under section 4928.61 of the Revised Code. Payment of the compliance payment shall be subject to such collection and enforcement procedures as apply to the collection of a forfeiture under sections 4905.55 to 4905.60 and 4905.64 of the Revised Code.
(3) An electric distribution utility or an electric services company need not comply with a benchmark under division (B)(2) of this section to the extent that its reasonably expected cost of that compliance exceeds its reasonably expected cost of otherwise producing or acquiring the requisite electricity by three per cent or more. The cost of compliance shall be calculated as though any exemption from taxes and assessments had not been granted under section 5727.75 of the Revised Code.
(4)(a) An electric distribution utility or electric services company may request the commission to make a force majeure determination pursuant to this division regarding all or part of the utility's or company's compliance with any minimum benchmark under division (B)(2) of this section during the period of review occurring pursuant to division (C)(2) of this section. The commission may require the electric distribution utility or electric services company to make solicitations for renewable energy resource credits as part of its default service before the utility's or company's request of force majeure under this division can be made.
(b) Within ninety days after the filing of a request by an electric distribution utility or electric services company under division (C)(4)(a) of this section, the commission shall determine if qualifying renewable energy resources are reasonably available in the marketplace in sufficient quantities for the utility or company to comply with the subject minimum benchmark during the review period. In making this determination, the commission shall consider whether the electric distribution utility or electric services company has made a good faith effort to acquire sufficient qualifying renewable energy or, as applicable, solar energy resources to so comply, including, but not limited to, by banking or seeking renewable energy resource credits or by seeking the resources through long-term contracts. Additionally, the commission shall consider the availability of qualifying renewable energy or solar energy resources in this state and other jurisdictions in the PJM interconnection regional transmission organization, L.L.C., or its successor and the midcontinent independent system operator or its successor.
(c) If, pursuant to division (C)(4)(b) of this section, the commission determines that qualifying renewable energy or solar energy resources are not reasonably available to permit the electric distribution utility or electric services company to comply, during the period of review, with the subject minimum benchmark prescribed under division (B)(2) of this section, the commission shall modify that compliance obligation of the utility or company as it determines appropriate to accommodate the finding. Commission modification shall not automatically reduce the obligation for the electric distribution utility's or electric services company's compliance in subsequent years. If it modifies the electric distribution utility or electric services company obligation under division (C)(4)(c) of this section, the commission may require the utility or company, if sufficient renewable energy resource credits exist in the marketplace, to acquire additional renewable energy resource credits in subsequent years equivalent to the utility's or company's modified obligation under division (C)(4)(c) of this section.
(5) The commission shall establish a process to provide for at least an annual review of the renewable energy resource market in this state and in the service territories of the regional transmission organizations that manage transmission systems located in this state. The commission shall use the results of this study to identify any needed changes to the amount of the renewable energy compliance payment specified under divisions (C)(2)(a) and (b) of this section.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 554 4 4928.64 Qualifying renewable energy resources requirements;..., OH ST § 4928.64
Specifically, the commission may increase the amount to ensure that payment of compliance payments is not used to achieve compliance with this section in lieu of actually acquiring or realizing energy derived from qualifying renewable energy resources. However, if the commission finds that the amount of the compliance payment should be otherwise changed, the commission shall present this finding to the general assembly for legislative enactment.
(D) The commission annually shall submit to the general assembly in accordance with section 101.68 of the Revised Code a report describing all of the following:
(1) The compliance of electric distribution utilities and electric services companies with division (B) of this section;
(2) The average annual cost of renewable energy credits purchased by utilities and companies for the year covered in the report;
(3) Any strategy for utility and company compliance or for encouraging the use of qualifying renewable energy resources in supplying this state's electricity needs in a manner that considers available technology, costs, job creation, and economic impacts.
The commission shall begin providing the information described in division (D)(2) of this section in each report submitted after September 10, 2012. The commission shall allow and consider public comments on the report prior to its submission to the general assembly. Nothing in the report shall be binding on any person, including any utility or company for the purpose of its compliance with any benchmark under division (B) of this section, or the enforcement of that provision under division (C) of this section.
(E) All costs incurred by an electric distribution utility in complying with the requirements of this section shall be bypassable by any consumer that has exercised choice of supplier under section 4928.03 of the Revised Code.
CREDIT(S)
(2017 H 49, eff. 9-29-17; 2014 S 310, eff. 9-12-14; 2012 S 315, eff. 9-10-12; 2010 S 232, eff. 6-17-10; 2009 H 2, eff. 7-1-09; 2008 S 221, eff. 7-31-08)
Notes of Decisions (1)
R.C. § 4928.64, OH ST § 4928.64 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 555 5 4928.66 Energy efficiency programs; implementation, OH ST § 4928.66
Baldwin's Ohio Revised Code Annotated Title XLIX. Public Utilities Chapter 4928. Competitive Electric Retail Service Energy Efficiency Revolving Loan Program
R.C. § 4928.66
4928.66 Energy efficiency programs; implementation
Effective: September 12, 2014 Currentness
(A)(1)(a) Beginning in 2009, an electric distribution utility shall implement energy efficiency programs that achieve energy savings equivalent to at least three-tenths of one per cent of the total, annual average, and normalized kilowatt-hour sales of the electric distribution utility during the preceding three calendar years to customers in this state. An energy efficiency program may include a combined heat and power system placed into service or retrofitted on or after the effective date of the amendment of this section by S.B. 315 of the 129th general assembly, September 10, 2012, or a waste energy recovery system placed into service or retrofitted on or after September 10, 2012, except that a waste energy recovery system described in division (A)(38)(b) of section 4928.01 of the Revised Code may be included only if it was placed into service between January 1, 2002, and December 31, 2004. For a waste energy recovery or combined heat and power system, the savings shall be as estimated by the public utilities commission. The savings requirement, using such a three-year average, shall increase to an additional five-tenths of one per cent in 2010, seven-tenths of one per cent in 2011, eight- tenths of one per cent in 2012, nine-tenths of one per cent in 2013, and one per cent in 2014. In 2015 and 2016, an electric distribution utility shall achieve energy savings equal to the result of subtracting the cumulative energy savings achieved since 2009 from the product of multiplying the baseline for energy savings, described in division (A)(2)(a) of this section, by four and two-tenths of one per cent. If the result is zero or less for the year for which the calculation is being made, the utility shall not be required to achieve additional energy savings for that year, but may achieve additional energy savings for that year. Thereafter, the annual savings requirements shall be, for years 2017, 2018, 2019, and 2020, one per cent of the baseline, and two per cent each year thereafter, achieving cumulative energy savings in excess of twenty-two per cent by the end of 2027. For purposes of a waste energy recovery or combined heat and power system, an electric distribution utility shall not apply more than the total annual percentage of the electric distribution utility's industrial- customer load, relative to the electric distribution utility's total load, to the annual energy savings requirement.
(b) Beginning in 2009, an electric distribution utility shall implement peak demand reduction programs designed to achieve a one per cent reduction in peak demand in 2009 and an additional seventy-five hundredths of one per cent reduction each year through 2014. In 2015 and 2016, an electric distribution utility shall achieve a reduction in peak demand equal to the result of subtracting the cumulative peak demand reductions achieved since 2009 from the product of multiplying the baseline for peak demand reduction, described in division (A)(2)(a) of this section, by four and seventy- five hundredths of one per cent. If the result is zero or less for the year for which the calculation is being made, the utility shall not be required to achieve an additional reduction in peak demand for that year, but may achieve an additional reduction in peak demand for that year. In 2017 and each year thereafter through 2020, the utility shall achieve an additional seventy-five hundredths of one per cent reduction in peak demand.
(2) For the purposes of divisions (A)(1)(a) and (b) of this section:
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 556 1 4928.66 Energy efficiency programs; implementation, OH ST § 4928.66
(a) The baseline for energy savings under division (A)(1)(a) of this section shall be the average of the total kilowatt hours the electric distribution utility sold in the preceding three calendar years. The baseline for a peak demand reduction under division (A)(1)(b) of this section shall be the average peak demand on the utility in the preceding three calendar years, except that the commission may reduce either baseline to adjust for new economic growth in the utility's certified territory. Neither baseline shall include the load and usage of any of the following customers:
(i) Beginning January 1, 2017, a customer for which a reasonable arrangement has been approved under section 4905.31 of the Revised Code;
(ii) A customer that has opted out of the utility's portfolio plan under section 4928.6611 of the Revised Code;
(iii) A customer that has opted out of the utility's portfolio plan under Section 8 of S.B. 310 of the 130th general assembly.
(b) The commission may amend the benchmarks set forth in division (A)(1)(a) or (b) of this section if, after application by the electric distribution utility, the commission determines that the amendment is necessary because the utility cannot reasonably achieve the benchmarks due to regulatory, economic, or technological reasons beyond its reasonable control.
(c) Compliance with divisions (A)(1)(a) and (b) of this section shall be measured by including the effects of all demand- response programs for mercantile customers of the subject electric distribution utility, all waste energy recovery systems and all combined heat and power systems, and all such mercantile customer-sited energy efficiency, including waste energy recovery and combined heat and power, and peak demand reduction programs, adjusted upward by the appropriate loss factors. Any mechanism designed to recover the cost of energy efficiency, including waste energy recovery and combined heat and power, and peak demand reduction programs under divisions (A)(1)(a) and (b) of this section may exempt mercantile customers that 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, including waste energy recovery and combined heat and power, or peak demand reduction programs, if the commission determines that that exemption reasonably encourages such customers to commit those capabilities to those programs. If a mercantile customer makes such existing or new demand-response, energy efficiency, including waste energy recovery and combined heat and power, or peak demand reduction capability available to an electric distribution utility pursuant to division (A)(2)(c) of this section, the electric utility's baseline under division (A)(2)(a) of this section shall be adjusted to exclude the effects of all such demand-response, energy efficiency, including waste energy recovery and combined heat and power, or peak demand reduction programs that may have existed during the period used to establish the baseline. The baseline also shall be normalized for changes in numbers of customers, sales, weather, peak demand, and other appropriate factors so that the compliance measurement is not unduly influenced by factors outside the control of the electric distribution utility.
(d)(i) Programs implemented by a utility may include the following:
(I) Demand-response programs;
(II) Smart grid investment programs, provided that such programs are demonstrated to be cost-beneficial;
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 557 2 4928.66 Energy efficiency programs; implementation, OH ST § 4928.66
(III) Customer-sited programs, including waste energy recovery and combined heat and power systems;
(IV) Transmission and distribution infrastructure improvements that reduce line losses;
(V) Energy efficiency savings and peak demand reduction that are achieved, in whole or in part, as a result of funding provided from the universal service fund established by section 4928.51 of the Revised Code to benefit low-income customers through programs that include, but are not limited to, energy audits, the installation of energy efficiency insulation, appliances, and windows, and other weatherization measures.
(ii) No energy efficiency or peak demand reduction achieved under divisions (A)(2)(d)(i)(IV) and (V) of this section shall qualify for shared savings.
(iii) Division (A)(2)(c) of this section shall be applied to include facilitating efforts by a mercantile customer or group of those customers to offer customer-sited demand-response, energy efficiency, including waste energy recovery and combined heat and power, or peak demand reduction capabilities to the electric distribution utility as part of a reasonable arrangement submitted to the commission pursuant to section 4905.31 of the Revised Code.
(e) No programs or improvements described in division (A)(2)(d) of this section shall conflict with any statewide building code adopted by the board of building standards.
(B) In accordance with rules it shall adopt, the public utilities commission shall produce and docket at the commission an annual report containing the results of its verification of the annual levels of energy efficiency and of peak demand reductions achieved by each electric distribution utility pursuant to division (A) of this section. A copy of the report shall be provided to the consumers' counsel.
(C) If the commission determines, after notice and opportunity for hearing and based upon its report under division (B) of this section, that an electric distribution utility has failed to comply with an energy efficiency or peak demand reduction requirement of division (A) of this section, the commission shall assess a forfeiture on the utility as provided under sections 4905.55 to 4905.60 and 4905.64 of the Revised Code, either in the amount, per day per undercompliance or noncompliance, relative to the period of the report, equal to that prescribed for noncompliances under section 4905.54 of the Revised Code, or in an amount equal to the then existing market value of one renewable energy credit per megawatt hour of undercompliance or noncompliance. Revenue from any forfeiture assessed under this division shall be deposited to the credit of the advanced energy fund created under section 4928.61 of the Revised Code.
(D) The commission may establish rules regarding the content of an application by an electric distribution utility for commission approval of a revenue decoupling mechanism under this division. Such an application shall not be considered an application to increase rates and may be included as part of a proposal to establish, continue, or expand energy efficiency or conservation programs. The commission by order may approve an application under this division if it determines both that the revenue decoupling mechanism provides for the recovery of revenue that otherwise may be forgone by the utility as a result of or in connection with the implementation by the electric distribution utility of any energy efficiency or energy conservation programs and reasonably aligns the interests of the utility and of its customers in favor of those programs.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 558 3 4928.66 Energy efficiency programs; implementation, OH ST § 4928.66
(E) The commission additionally shall adopt rules that require an electric distribution utility to provide a customer upon request with two years' consumption data in an accessible form.
CREDIT(S)
(2014 S 310, eff. 9-12-14; 2012 S 315, eff. 9-10-12; 2008 S 221, eff. 7-31-08)
Notes of Decisions (4)
R.C. § 4928.66, OH ST § 4928.66 Current through File 66 of the 132nd General Assembly (2017-2018), 2017 State Issue 1, and 2018 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 559 4 5164.70 Limit on medicaid payment for medicaid service provided..., OH ST § 5164.70
Baldwin's Ohio Revised Code Annotated Title LI. Public Welfare Chapter 5164. Medical Assistance Programs Payments
R.C. § 5164.70 Formerly cited as OH ST § 5111.021
5164.70 Limit on medicaid payment for medicaid service provided by hospital, nursing facility, or ICF/IID
Effective: September 29, 2017 Currentness
Except as otherwise required by federal statute or regulation, no medicaid payment for any medicaid service provided by a hospital, nursing facility, or ICF/IID shall exceed the limits established under Subpart C of 42 C.F.R. Part 447.
CREDIT(S)
(2017 H 49, eff. 9-29-17; 2013 H 59, eff. 9-29-13)
Notes of Decisions (37)
R.C. § 5164.70, OH ST § 5164.70 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 560 1 5709.212 Fees, OH ST § 5709.212
Baldwin's Ohio Revised Code Annotated Title LVII. Taxation (Refs & Annos) Chapter 5709. Taxable Property--Exemptions (Refs & Annos) Air or Noise Pollution Control Facility Exemption
R.C. § 5709.212
5709.212 Fees
Effective: September 29, 2017 Currentness
(A) With every application for an exempt facility certificate filed pursuant to section 5709.21 of the Revised Code, the applicant shall pay a fee equal to one-half of one per cent of the total exempt facility project cost, not to exceed two thousand dollars. If the director of environmental protection is required to provide the opinion for an application, the fee shall be credited to the non-Title V clean air fund created in section 3704.035 of the Revised Code for use in administering section 5709.211 of the Revised Code, unless the application is for an industrial water pollution control facility. If the application is for an industrial water pollution control facility, the fee shall be credited to the surface water protection fund created in section 6111.038 of the Revised Code for use in administering section 5709.211 of the Revised Code. If the director of development is required to provide the opinion for an application, the fee for each exempt facility application shall be credited to the exempt facility inspection fund, which is hereby created in the state treasury, for appropriation to the development services agency for use in administering section 5709.211 of the Revised Code.
An applicant is not entitled to any tax exemption under section 5709.25 of the Revised Code until the fee required by this section is paid. The fee required by this section is not refundable, and is due with the application for an exempt facility certificate even if an exempt facility certificate ultimately is not issued or is withdrawn. Any application submitted without payment of the fee shall be deemed incomplete until the fee is paid.
(B) The application fee imposed under division (A) of this section for a jointly owned facility shall be equal to one-half of one per cent of the total exempt facility project cost, not to exceed two thousand dollars for each facility that is the subject of the application.
CREDIT(S)
(2017 H 49, eff. 9-29-17; 2012 H 487, eff. 9-10-12; 2003 H 95, eff. 9-26-03)
R.C. § 5709.212, OH ST § 5709.212 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 561 1 6137.051 Complaint of need for repairs; procedures, OH ST § 6137.051
Baldwin's Ohio Revised Code Annotated Title LXI. Water Supply--Sanitation--Ditches Chapter 6137. Ditch Maintenance Fund (Refs & Annos)
R.C. § 6137.051
6137.051 Complaint of need for repairs; procedures
Currentness
Whenever the owner of any lands assessed for construction of an improvement authorized prior to August 23, 1957, files a written complaint that the improvement is in need of repair, the county engineer or his designated representative shall make an inspection of the condition of the improvement within sixty days of receipt of the complaint and shall request the owner to accompany him. If the county engineer finds that a need exists, he shall make an estimate of the cost of the necessary work and material required for the repair. The board of county commissioners, if it finds the work to be necessary and feasible, may authorize the county engineer to make the repairs at a cost not to exceed four thousand dollars. For the purpose of paying for the necessary work and materials, the board of county commissioners may establish a drainage repair fund for the improvement to be repaired. The county engineer shall prepare and submit a schedule of assessments upon the benefiting lands to the board of county commissioners in the amount of the actual costs of the repair. The board of county commissioners may revise the estimated assessments as they consider equitable and shall certify the assessments to the county auditor for collection. Not more than four semiannual installments, as taxes are paid, shall be given to owners to pay for the repair assessments, and if any such assessment is twenty-five dollars or less, or whenever the unpaid balance of any such assessment is twenty-five dollars or less, the same shall be paid in full, and not in installments, at the time the first installment would otherwise become due. If the drainage repair fund for the improvement to be so repaired is inadequate for the repair, the board of county commissioners may make payment for the repair from the county general fund, which sum so paid from the general fund shall be a charge against the appropriate drainage maintenance fund to be repaid to the general fund as soon as adequate funds are available in the drainage maintenance fund.
CREDIT(S)
(1980 H 268, eff. 4-9-81; 1969 H 276; 128 v 694)
Notes of Decisions (1)
R.C. § 6137.051, OH ST § 6137.051 Current through File 59 of the 132nd General Assembly (2017-2018) and 2017 State Issue 1.
End of Document © 2018 Thomson Reuters. No claim to original U.S. Government Works.
© 2018 Thomson Reuters. No claim to original U.S. Government Works. APP. 562 1 CERTIFICATE OF SERVICE
I hereby certify that a copy of the foregoing Merit Brief and Appendix of Appellants
Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison
Company (Volume III), was served by electronic mail on the 21st day of May, 2018, upon the following:
Colleen L. Mooney Samantha Williams [email protected] [email protected]
Ohio Partners for Affordable Energy Robert Dove [email protected]
Natural Resources Defense Council
Christopher Healey Kimberly W. Bojko [email protected] [email protected]
Zachary Woltz Danielle Ghiloni Walter [email protected] [email protected],
Ohio Consumers’ Counsel Ohio Manufacturers Association Energy Group
Madeline P. Fleisher Matthew R. Pritchard [email protected] [email protected]
Robert Kelter Samuel Randazzo [email protected] [email protected]
Environmental Law and Policy Center Industrial Energy Users of Ohio
Angela Paul Whitfield Matthew W. Warnock [email protected] [email protected]
Counsel for The Kroger Company Dylan F. Borchers [email protected]
Devin Parram [email protected]
Teresa Orahood [email protected]
The Ohio Hospital Association
Joseph E. Oliker Trent A. Dougherty [email protected] [email protected]
IGS Energy Miranda Leppla [email protected]
Ohio Environmental Council
John Finnigan Christopher J. Allwein [email protected] [email protected]
Environmental Defense Fund Energy Management Solutions, Inc.
Joel E. Sechler Natalia Messenger [email protected] [email protected]
EnerNOC, Inc. John Jones [email protected]
Ohio Attorney General for PUCO Staff
Debra Hight William L. Wright [email protected] [email protected]
Vesta Miller Public Utilities Commission of Ohio [email protected]
Sandra Coffey [email protected]
Public Utilities Commission of Ohio
/s Michael R. Gladman An Attorney for Appellants Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison Company
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