NRG Energy v. Public Service Comm'n

NRG, et al. v. Maryland Public Service Commission, No. 1181, September Term, 2020, filed. Opinion by Graeff, J.

MARYLAND PUBLIC SERVICE COMMISSION—STANDARD OFFER SERVICE ADMINISTRATIVE ADJUSTMENT RATES

PU § 7-505(b)(8) gives the Commission the authority to “determine the terms, conditions, and rates” of SOS. The Commission, after listening to all the testimony, decided on the appropriate rate for the Administrative Adjustment component of SOS. This decision was committed to the Commission’s broad discretion, and we give its decision in that regard deference. The Commission determined BGE’s recommendation was reasonable, with a couple of modifications suggested by Commission Staff. It acted within its discretion in rejecting the analysis set forth by ESC, and its decision was not arbitrary and capricious.

Two portions of the Order, however, require clarification and/or correction. First, the Commission states that two accounts should be excluded from the SOS analysis, and then, several sentences later, includes them in the calculations. Second, the Commission’s mathematical calculations appear incorrect. Accordingly, although the Commission’s decision, in general, was supported by substantial evidence and was not arbitrary and capricious, the Commission must clarify whether the accounts discussed should be included in the total costs and recalculate the Administrative Adjustment consistent with those calculations.

Circuit Court for Baltimore City Case No. 24-C-20-000232

REPORTED

IN THE COURT OF SPECIAL APPEALS

OF MARYLAND

No. 1181

September Term, 2020

______________________________________

NRG ENERGY, INC., ET AL.,

v.

THE MARYLAND PUBLIC SERVICE COMMISSION, ET AL.

______________________________________

Graeff, Reed, Wright, Alexander, Jr. (Senior Judge, Specially Assigned),

JJ. ______________________________________

Opinion by Graeff, J. ______________________________________ Pursuant to Maryland Uniform Electronic Legal Materials Act (§§ 10-1601 et seq. of the State Government Article) this document is authentic. Filed: September 30, 2021 2021-10-08 16:48-04:00

Suzanne C. Johnson, Clerk *Ripken, Laura S., J., did not participate in the Court’s decision to designate this opinion for publication pursuant to Maryland Rule 8-605.1.

This appeal arises from an order issued by the Maryland Public Service Commission (the “Commission”), one of the appellees. The order addressed, among other things, the price that Baltimore Gas and Electric (“BGE”), another appellee, is permitted to charge to supply Standard Offer Service (“SOS”) electricity to its customers. Appellants, NRG Energy Inc., Vistra Corp., Direct Energy Services, LLC, and Interstate Gas Supply, Inc. D/B/A IGS Energy, collectively referred to as the Energy Supplier Coalition (“ESC”), objected to the portion of the order that addressed the appropriate charge for the “Administrative Adjustment” portion of BGE’s electric supply rates. It filed a petition for judicial review of the order in the Circuit Court for Baltimore City, which denied the petition.

On appeal, appellants argue that the Commission erred, or was arbitrary or capricious, in setting the amount of the Administrative Adjustment Component of BGE’s SOS rate.1 Appellants ask us to remand the case “to the Commission to establish a market

1 We have combined the three questions presented by appellants in their brief, which are as follows:

1. Is the Commission entitled to deference when addressing an issue of first impression on which it has yet to develop precedent, consistent rulings or expertise?

2. Did the Commission err as a matter of law, or otherwise act in an arbitrary or capricious manner, in approving a standard offer service rate for BGE without applying the market price standard required by the Competition Act?

3. Did the Commission err as a matter of law, or otherwise act in an arbitrary or capricious manner, in disregarding statutory mandates

price for [BGE]’s SOS [rate] that reflects all of the costs that are incurred to provide this service in a manner that is required by the [statute].”

For the reasons set forth below, we shall vacate the judgment of the circuit court and remand for further proceedings.

FACTUAL AND PROCEDURAL BACKGROUND

I.

Statutory Scheme & Relevant History

Before addressing the specifics of this case, we address the background and statutory scheme regarding deregulation of electric utilities in Maryland. In Severstal Sparrows Point, LLC v. Pub. Serv. Comm’n of Maryland, 194 Md. App. 601, 604 (2010), this Court explained that the electric utility industry in Maryland is comprised of two components: supply and distribution. Supply (electricity) is a commodity, whereas distribution (power lines) is a service. Id. “Historically, these components were ‘bundled’ together and provided to customers exclusively by one utility company in each distribution territory. BGE controlled one such distribution area.” Id. (footnote omitted).

In 1999, the Maryland General Assembly enacted the Electric Customer Choice Act of 1999 (the “Competition Act”). See Md. Code Ann., Pub. Util. Article (“PU”) §§ 7-501– 517 (2020 Repl. Vol.). Severstal, 194 Md. App. at 604–05. The purpose of the Competition Act was to:

obligating the Commission to support the development of a competitive retail electric market?

(1) establish customer choice of electricity supply and electricity supply services;

(2) create competitive retail electricity supply and electricity supply services markets;

(3) deregulate the generation, supply, and pricing of electricity;

(4) provide economic benefits for all customer classes; and

(5) ensure compliance with federal and State environmental standards. PU § 7-504.

As this Court explained in Severstal, 194 Md. App. at 605:

To further these goals, the component parts of electric service were to be unbundled. Distribution was to remain monopolized and, therefore, the rates charged were to remain closely regulated by the PSC. Supply was to be deregulated, however, with the rates charged to be largely established by the market. In other words, electricity customers would, for the first time, be permitted to shop on the open market for a third-party electrical energy supplier.

• • * *

Although the [Competition] Act permitted consumers to shop for their supply of electricity, its drafters recognized that not all consumers could or would do so. For that reason, the law was written to obligate the electricity utilities such as BGE to continue to provide “backstop” electricity supply, known as Standard Offer Service (“SOS”), to consumers who chose not to shop for their electric supply or, for whatever reason, could not obtain electricity on the open market. The legislative goal was to phase out SOS over time as the competitive market more fully developed in Maryland. While most commercial electricity customers now shop for their energy supply, most residential customers and many small commercial customers do not. They continue to receive SOS electricity supply by default.

PU § 7-510(c)(2) explains SOS as follows:

(2) Electricity supply purchased from a customer’s electric company is known as standard offer service. A customer is considered to have chosen the standard offer service if the customer:

(i) is not allowed to choose an electricity supplier under the phase in of customer choice in subsection (a) of this section;

(ii) contracts for electricity with an electricity supplier and it is not delivered;

(iii) cannot arrange for electricity from an electricity supplier;

(iv) does not choose an electricity supplier;

(v) chooses the standard offer service; or

(vi) has been denied service or referred to the standard offer service by an electricity supplier in accordance with § 7-507(e)(6) of this subtitle.

Thus, a customer receives SOS if the customer does not shop for electric supply or cannot obtain electricity from another source. BGE now has two roles: (1) it is the sole distribution company delivering electricity to customers through, as ESC asserts, BGE’s “wires and poles”; and (2) for consumers who have not chosen a different supplier, it is also the SOS provider supplying the electricity in competition with other suppliers.2

With respect to charges involving distribution, BGE may charge “just and reasonable” rates. PU § 4-102. In its role as SOS provider, however, PU § 7-510(c)(3)(ii)(2) requires that electricity companies such as BGE supply SOS at a “market price that permits recovery of the verifiable, prudently incurred costs to procure or produce

2 BGE explains that customers may choose other suppliers for a variety of reasons, “including lower prices, fixed prices, or access to 100% renewable electricity.” The Commission has a website that describes potential benefits from choosing a competitive supplier, including obtaining “rates below the utility’s Standard Offer Service (or default) rate” and obtaining “electricity from ‘clean’ sources such as solar or wind.” The Benefits of Choice, MD ELECTRIC CHOICE, https://www.mdelectricchoice.com/how-it- works/benefits-of-choice/ (last visited Aug. 23, 2021).

the electricity plus a reasonable return.” The Commission is tasked with determining “the terms, conditions, and rates of” SOS. PU ⸹ 7-505(b)(8).

Following the enactment of the Competition Act, the Commission began working with electric utility companies, including BGE, to implement the Competition Act and provide SOS in Maryland. In 2003, the Commission, BGE, and other electric utility companies entered into a settlement agreement establishing a methodology to implement the provision of SOS to Maryland’s retail electric customers. See In re Competitive Selection of Elec. Supplier/Standard Offer Serv., 94 Md. P.S.C. 113, 2003 WL 21051678, 224 P.U.R.4th 185 (2003) (“2003 Order”) (footnotes omitted). The 2003 Order provided that the retail price for SOS would consist of: (1) purchase power costs; (2) transmissions costs; (3) an Administrative Charge; and (4) taxes. Id. at 3. The Administrative Charge would be composed “of a utility return component, an incremental costs component, uncollectibles, and an Administrative Adjustment component.” Id. (emphasis added). The settlement provided that the Administrative Adjustment initially would be set at 0.9 mills per kilowatt hour (“kWh”). Id. at 4.3 This reflected an offset of 1.1 mills for uncollectible costs in the SOS component. Id.

3 Mills per kilowatt hour (“kWh”) equals dollars per megawatt hour (“mWh”), and one mill is equivalent to one-tenth of one cent. See U.S. Energy Information Administration, Electric Power Annual 2019, U.S. Department of Energy, 171 (Feb. 2021), eia.gov/electricity/annual/pdf/epa.pdf.

In 2009, BGE filed a request to increase the Administrative Charge to allow it to recover an increase in another requirement. A Public Utility Law Judge determined, in part, that the Administrative Adjustment component should be eliminated.

In 2016, after several appeals and remands with respect to the Public Utility Law Judge’s decision, the Commission again addressed the Administrative Adjustment. See In the Matter of a Request by Baltimore Gas and Electric Co. for Recovery of Standard Offer Serv. Related Cash Working Cap. Revenue Requirement, No. 87891, 2016 WL 6873349, at *1 (Md. P.S.C. Nov. 17, 2016) (“2016 Order”). Noting that the purpose of the Competition Act was “to establish customer choice of electricity supply and to create a competitive retail electricity supply and services,” the Commission explained:

The Administrative Adjustment serves as a proxy for A&G [(administrative and general)] costs retail suppliers must include in their rates . . . which for the utility are embedded in BGE’s distribution rates. More directly, it places into SOS costs — costs that retail suppliers bear and report on FERC [Federal Energy Regulatory Commission] reporting forms — that are not fully represented by the incremental costs recovered in the Administrative Charge, such as: costs for billing, marketing and advertisement for customer acquisition; call center operations; product and price formation; hedging supply commitments; electronic data information; PJM membership fees; staffing for human resources; and policy and legal services. The Administrative Adjustment Component was meant to unbundle those incremental costs for SOS that are weaved into BGE’s distribution rates while also keeping the Company’s SOS prices competitive with retail energy suppliers’ costs and prices.

Id. at *14 (footnotes omitted).

The Administrative Adjustment Component and the Incremental Cost Component represent BGE’s costs to provide SOS. SOS providers, however, “intermingle incremental costs from SOS service with distribution service.” Id. The Commission concluded that *7 “elimination of the Administrative Adjustment Component would cause BGE distribution customers to subsidize costs for BGE customers who receive SOS services,” and it “would put energy retailers at a slight disadvantage and on an uneven playing field relative to BGE.” Id. at *16. Accordingly, the Commission determined that “[o]ne of the best ways to ensure that retail suppliers’ prices remain competitive with BGE’s SOS [was] to factor into BGE’s SOS prices the costs that retailers pay and place into the SOS rate, which BGE receive[d] from its embedded distribution rates.” Id.

On the record before the Commission at that time, however, it was “unable to glean what a reasonably precise Administrative Adjustment should be.” Id. Accordingly, it set the Administrative Adjustment rate at 0.0 mills per kWh, and it ordered that

[t]he issue of the precise amount of the Administrative Adjustment Component should be taken up in connection with BGE’s next general rate case, in which a cost of service study should be presented to reflect more precisely which costs should be properly allocated in distribution rates and which costs should be properly allocated to SOS prices.

Id.

II.

BGE’s 2019 Request to Increase Rates

On May 24, 2019, BGE sought to increase its Maryland retail electric and gas rates by $81.1 million and $67.6 million, respectively, through proposed tariff revisions. Pursuant to PU §§ 4-203 and 4-204, BGE was required to file an application with the *8 Commission regarding any change in its rates.4 As part of its application, and pursuant to the Commission’s 2016 Order, BGE included a completed cost of service study.

On May 29, 2019, the Commission docketed BGE’s application as Case No. 9610, suspended BGE’s proposed tariff revisions, and scheduled a pre-hearing conference. In the Matter of the Application of the Baltimore Gas and Electric Company for Adjustments to its Electr[i]c and Gas Base Rates, 89138, 2019 WL 2327760 (Md. P.S.C. May 29, 2019). On June 27, 2019, the Commission held a pre-hearing conference. The Maryland Office of People’s Counsel (“OPC”) and Commission Technical Staff (“Commission Staff”) entered their appearance. ESC filed a petition to intervene, which the Commission granted.5

4 In pertinent part, Md. Code Ann., Pub. Util. (“PU”) § 4-203 (2018 Supp.) provides as follows:

(a) Unless otherwise ordered by the Commission, a public service company may not establish a new rate or change in rate unless the public service company:

(1) provides to the Commission notice of the new rate or change in rate at least 30 days before the new rate is established or current rate is changed; and (2) publishes the new rate or change in rate in accordance with § 4- 202 of this subtitle during the entire 30 day notice period in new schedules or plainly indicated amendments to existing schedules.

PU § 4-204 (2010 Repl. Vol.) states, in pertinent part, as follows: “(a)(1) The Commission may suspend, effective immediately and without formal proceedings, any new rate or change in rate proposed by a public service company.” 5 In addition to ESC, Maryland Energy Group, W.R. Grace & Co., H.A. Wagner, LLC, C.P. Crane, LLC, the United States Department of Defense and other Federal Agencies, and Walmart, Inc., petitioned to intervene and were made parties to the case. These other entities are not parties to this appeal.

During the course of the case, BGE, ESC, Commission Staff, and OPC retained experts who filed prepared direct, rebuttal, and surrebuttal testimony. BGE’s 2019 request to increase its electric and gas base rates dealt with more than the setting of the Administrative Adjustment rate, but because only the Administrative Adjustment rate is relevant to this appeal, we will limit our discussion to the testimony that was relevant to the Administrative Adjustment.

A.

Prepared Direct Testimony

On May 24, 2019, BGE filed the prepared direct testimony of its expert witness, Jason Manuel, a Certified Public Accountant (CPA) and manager of BGE’s Revenue Policy Division. The other parties’ witnesses filed their prepared direct testimony with the Commission on September 10, 2019. The ESC presented testimony from Frank Lacey, an independent consultant with 25 years’ experience, and Chris Peterson, a CPA and an independent consultant specializing in forensic accounting. David Hoppock, the Assistant Director of the Commission’s Electricity Division, testified on behalf of Commission Staff, and Clarence Johnson, an independent consultant with 35 years’ experience as a regulatory analyst, testified on behalf of OPC.

1.

BGE

Mr. Manuel testified that, with respect to the Administrative Adjustment Component of the SOS Administrative charge, he conducted a cost of service study, which, as ordered by the Commission, would “reflect more precisely which costs should be *10 properly allocated in distribution rates and which costs should be properly allocated to SOS prices.” He noted that “[t]he Administrative Adjustment component of the SOS Administrative Charge represents a proxy for certain costs incurred by third-party electric suppliers to provide electric supply to their customers not otherwise included in SOS rates,” and the purpose of the “Administrative Adjustment is to better align BGE’s total SOS price with the electric supply market price, thus ‘leveling the playing field’ between the Company and alternative suppliers.”

Mr. Manuel stated that his analysis followed standard utility cost-causation principles and recognized that “all incremental costs incurred to provide SOS are currently functionalized to the SOS Administrative Charge,” through the Incremental costs component. Mr. Manuel “identified the following types of non-incremental costs and cost centers as supporting SOS: billing (including the billing system), credit & collections, customer call center, regulatory, accounting, and legal.” Those costs were tracked in the Company’s general ledger, allowing costs to “be functionalized [allocated] to SOS.”

With respect to billing costs allocated to SOS, BGE used a revenue percentage. With respect to the call center, BGE used data from its interactive voice response system to determine the percentage of calls relating to billing, credit and collections, and it then looked at percentages for distribution expenses and revenue. With respect to regulatory, accounting, and legal expenses, the individuals were asked to identify their SOS-related tasks and the time they spent on each activity. Mr. Manuel also “allocated all SOS-*11 functionalized costs between SOS customer classes on a sales volume basis.” The four classes are “Residential, Type I, Type II, and Hourly-Priced Service.”6

Although the Administrative Adjustment was intended to represent a proxy for the costs incurred by third-party electric suppliers, those costs could not be known “due to their competitively sensitive nature.” Mr. Manuel stated that “the allocated costs approach taken by BGE provides a rational foundation for setting a just and reasonable Administrative Adjustment for the indefinite future.”

Mr. Manuel’s approach resulted in an Adjustment rate of 0.99 mills per kWh across all four of BGE’s customer classes. Mr. Manuel rounded up the recommended rate to 1.0 mill per kWh to acknowledge “that the cost of service study the Company performed is not surgically precise but can be used by the Commission to set the Administrative Adjustment at a reasonable level for years to come, pending the need for another study.” A rate of 1.0 mill per kWh represented an “11% increase since the Administrative Adjustment was first set at 0.90 mills per kWh.”

2.

ESC

Mr. Lacey testified regarding ESC’s interest in the rate case, stating that they were competitive electric and gas supply businesses in Maryland that compete with SOS. They

6 “Type I customers are small-usage residential and commercial consumers. Type II customers are larger-usage commercial consumers.” Severstal Sparrows Point, LLC v. Pub. Serv. Comm’n of Maryland, 194 Md. App. 601, 606 (2010). “Because BGE procures electricity supply for Type I and Type II SOS customers at separate auctions, the price charged for electricity supply usually differs between the two classes of customers.” Id.

wanted to ensure that BGE’s rates for SOS “reflect the full cost of providing that service, so that customers are able to make more accurate comparisons when shopping for electricity supply.”

Mr. Lacey described his understanding of the Administrative Charge and Administrative Adjustment component as follows:

The Administrative Charge is generally made up of two types of costs. The first is the direct costs associated with providing SOS. These costs include working capital, bad debt and a return to shareholders. The direct costs of providing SOS are not included in distribution rates because they are not in any way related to distribution service. The other category of costs is indirect costs, or shared costs, of resources that serve both the distribution business and SOS. A portion of the indirect costs is allocated to the Administrative Adjustment component of the Administrative Charge. However, in making this allocation, costs are not removed from the distribution business. As BGE collects SOS revenues from customers, including the Administrative Adjustment, it is temporarily “over-collecting.” However, it then credits all of the Administrative Adjustment collections back to distribution customers. Without the crediting mechanism, BGE would over-collect every month.

Mr. Lacey testified that BGE had “not followed long-standing traditional cost allocation methodologies in determining the costs that should be allocated to the Administrative Adjustment.” It had failed to fully allocate costs that are incurred to provide SOS by omitting major cost categories and understating other cost allocations, which resulted in it “using revenues collected through distribution rates to subsidize standard offer service.” The “major cost categories” omitted included “administrative and general expenses, such as the costs of information technology (“IT”) and human resources (“HR”). Moreover, it had “failed to fully allocate costs from the accounting, regulatory and legal functions required to support SOS.” He explained:

Because BGE has included many of its costs of providing SOS in its distribution rates, distribution customers are subsidizing SOS service and all shopping customers are over-paying distribution rates. The subsidy results in an SOS rate that is too low and unfairly biases customers toward standard offer services, and a distribution rate that is above what a cost-based rate should be. When costs of providing SOS, which are currently embedded in distribution rates, are properly recovered through the SOS rate, distribution customers will no longer be subsidizing SOS. The elimination of this subsidy will improve the retail market, thereby giving customers more competitive supply options.

Mr. Lacey explained the difference between assigning and allocating costs, stating that “[c]osts can generally be divided into two categories – direct and indirect. Direct costs are assigned. Indirect costs are allocated. Direct costs should be ‘assigned’ to the business unit that incurs the cost.” To “determine if a cost is a direct cost,” one could “evaluate whether or not it would go away if the product or service goes away.” In contrast, indirect costs are those that are “incurred for more than one purpose,” such as administrative and general costs, i.e., office supplies and executive salaries.

Mr. Lacey testified that improper allocation of costs to SOS harms consumers in several ways. It “harms consumers on SOS because it prevents them from being able to make a fair comparison to alternatives that may in fact offer real value to these customers, and it obscures the appropriate price signal, potentially resulting in over-consumption.”

Mr. Peterson testified that, with respect to the Administrative Adjustment Component, BGE’s analysis was “flawed” because it had not properly allocated costs related to SOS. He recommended increases to the Administrative Adjustment that were consistent with “sound financial accounting cost allocation methodologies, and best practices across a wide variety of industries.”

Mr. Peterson stated that BGE’s proposed Administrative Adjustment of 1.0 mill per kilowatt hour amounted to one-tenth of one cent. He agreed with Mr. Lacey that, in making its calculation, BGE failed to include certain cost categories, and it significantly understated costs in the categories it did include.

BGE listed a total of eight cost categories: (1) Billing System Amortization Expense; (2) Billing System Unamortized Costs; (3) Credit & Collections; (4) Billing; (5) Call Center; (6) Regulatory; (7) Accounting; and (8) Legal. Although Mr. Peterson did not take issue with the inclusion of those eight categories, he testified that other categories of costs should have been part of the calculations, including Information Technology, Human Resources, Customer Service and Depreciation.

Moreover, Mr. Peterson stated that several cost categories included were understated. Although he found the allocation for the first three categories to be reasonable, and he could not find a better allocation for the accounting costs, he discussed how other costs were understated. The costs for call center allocations, based on the number of calls answered by category, understated the actual cost because BGE considered only collection calls and billing inquiry calls as relevant to SOS, but it failed to consider other calls, such as those categorized as “Energy Assistance and Start, Stop Move Service [that] would necessarily involve SOS.” Mr. Peterson testified that costs allocated to call center expenses should be $4,013,555, as opposed to the $2,655,323 allocated by BGE. With respect to the cost allocation for Regulatory, Accounting, and Legal Expenses, Mr. Peterson stated that *15 BGE’s allocation of $106,253 in expenses was arbitrary. Using a percent of commodity revenue allocator, he proposed allocations of $2,364,578 to SOS for those expenses.7

After recomputing the costs, Mr. Peterson recommended allocating $173,074,451 of costs to the Administrative Adjustment, as compared to BGE’s proposed $12,324,792. In most categories, he calculated the allocation based on a 45.60% of electric commodity revenue to total electric operating revenue.8 Based on these figures, he recommended an “administrative adjustment of 11.82 Mills per kWh for the residential customer class and 21.06 Mills per kWh for the commercial and industrial customer classes.”

3.

Commission Staff

David Hoppock, Commission Staff’s Assistant Director of the Electricity Division, summarized BGE’s proposal, as follows:

Billing system, billing, and credit and collections costs are separated between electric distribution and SOS functions based on the percent of billed SOS revenue relative to all electric operating revenues (2018 data). For call center costs, BGE first determines the percentage of calls related to billing and credit and collections, next BGE multiplied this by the percent of bill SOS revenue relative to all electric operating revenues (2018 data) to separate costs between electric distribution and SOS functions. For regulatory, accounting, and legal costs BGE analyzed the amount of time spent on SOS by BGE employees to determine the separation between electric distribution and SOS functions. BGE then allocated costs functionalized to SOS between SOS rate classes based on 2018 sales by SOS class. This method results in the same Administrative Adjustment rate, $0.00099 per kWh for all SOS

7 As indicated, he did not change BGE’s allocation for accounting costs because he did not have sufficient data available. 8 Mr. Peterson used a lower percentage for the categories of call center, accounting, depreciation and amortization.

rates classes. BGE proposes to round this value up to $0.001 per kWh. [(Footnotes omitted.)]

Mr. Hoppock stated that he had “not yet conducted a full review of all costs BGE separates between the electric distribution and SOS functions.” Despite this, he found “the calculations and methods BGE use[d] to separate costs between electric distribution and SOS functions to be reasonable at this time.” He also agreed with the total costs of $12,324,792 proposed by BGE.9 He was, however, “concerned that the method BGE use[d] to allocate SOS Administrative Adjustment costs between SOS classes [did] not follow cost causation for some cost categories.” He also recommended that, instead of reimbursing distribution customers for SOS Administrative Adjustment costs allocated to SOS but also recovered from distribution rates, BGE should remove these costs from distribution rates. He recommended that the Commission require BGE to file an adjustment to distribution rates at the conclusion of the case.

4.

OPC

Mr. Johnson, who was retained by the OPC, recommended that the Commission reject BGE’s request to increase customer charges. With respect to the Administrative

9 As discussed, infra, in Commission Staff’s rebuttal testimony, Mr. Hoppock increased its allocation of costs to $15,123,164 by adding additional cost categories, such as FERC accounts. In Commission Staff’s surrebuttal testimony, it again increased its allocation, this time to $16,150,367, by increasing the amounts allocated to certain cost categories and adding several other cost categories. In Commission Staff’s subsequent rejoinder/settlement testimony, certain costs that BGE asserted had been double counted by Commission Staff were eliminated, and Mr. Hoppock proposed to allocate $15,920,967 to the Administrative Adjustment.

Charge for SOS, he did not agree with BGE’s proposal because it resulted “in a 51% increase in the current administrative charge applied to customers on SOS,” and “the increase [would] impact a substantial number of customers within the residential class.” Mr. Johnson also noted that BGE had not tried to determine whether its charge was “comparable to administrative costs incurred by competitive suppliers” or “charges assigned to comparable standard offer service rates in other states.” He testified that a fee that was too high could lead to competitive market suppliers viewing the SOS rate as a “price umbrella,” which could “result in non-competitive behavior to the detriment of consumers.” He also noted that an obligation imposed on an SOS provider could be viewed as a handicap, given that it must be available to all customers, even those dropped or denied by competitive retailers due to credit or payment issues.

B.

Prepared Rebuttal Testimony

On October 4, 2019, witnesses for all parties filed prepared rebuttal testimony with the Commission. Beginning with BGE, we shall address relevant portions of the parties’ testimony.

1.

BGE

Mr. Manuel reiterated that all incremental costs related to SOS were already allocated to SOS and included in the SOS Administrative Charge. In performing its cost of service study, BGE allocated the non-incremental electric distribution costs that support SOS, with its eye on the Commission’s objective “to better align the costs included in *18 BGE’s total SOS price (of which the Administrative Adjustment is a component) with the costs borne by electric suppliers, and therefore keep SOS ‘priced competitive with retail suppliers’ costs and prices.’”

Mr. Manuel summarized the various positions of the parties with respect to the proposed Administrative Adjustment with the following chart: The rates recommended by both BGE and Commission Staff were based on non-incremental costs of $12.3 million to be functionalized to SOS rates. The difference between their recommendations was that BGE’s proposed rates were based on an allocation of costs by sale volume, whereas Commission Staff’s proposed rates incorporated different allocations. ESC’s proposed rates were based on indirect costs of $173.1 million, which resulted in ESC recommending functionalization of more than ten times the cost that BGE and Commission Staff proposed.

Mr. Manuel also noted that, in comparison to the original Administrative Adjustment rate of 0.9 mills per kWh, BGE’s proposed rate of 1.0 mills per kWh represented an 11% increase, Commission Staff’s proposed rate of 1.11 mills per kWh was *19 a 23% increase, and ESC’s proposed rates of 11.82 mills per kWh and 13.89 mills per kWh represented a 1,213% and 1,443% increase, respectively. Mr. Manuel characterized the 11% and 23% increases as “modest increases from the original rates first implemented,” but ESC’s rate, which was more than a 1,000% increase from the rate implemented as part of the earlier settlement agreement, was an “outlier.”

Mr. Manuel testified that ESC’s arguments were premised on the assumption that the electric supply market was not healthy and that BGE’s SOS price was not at a market price. This premise, however, was undercut by statistics regarding electric customer choice, which showed that, as of August 2019, 24% of BGE’s residential customers obtained “electric supply from 67 active retail electric suppliers.” “The percentage of commercial and industrial customers choosing third-party electric suppliers is even more robust, nearly reaching 100% for BGE’s largest SOS customer class.” Thus, there did not need to be a 1,000% increase in the Administrative Adjustment rate to achieve a “market price” for SOS.

Mr. Manuel noted that Mr. Hoppock agreed that BGE’s separation of costs between electric distribution and SOS functions was reasonable, but he recommended two adjustments regarding the allocation of costs among SOS customer classes. He did not oppose Commission Staff’s two recommended allocation adjustments, although he believed BGE’s proposed allocators were reasonable.

The Administrative Adjustment was intended to serve as a proxy for costs that retail suppliers must include in their rates, and although ESC criticized BGE’s proposed rate, it had not provided, and refused to provide, “any insight into the actual costs that electric *20 suppliers incur to provide their service.” If “ESC believe[d] that BGE’s proposed rates [were] too low,” then ESC should have provided actual cost information to substantiate its belief that the Administrative Adjustment rates needed to reflect an increase of more than 1,000%.

Mr. Manuel stated that ESC’s recommendation that $173.1 million of non-incremental costs be allocated to SOS was “nonsensical.” It allocated an unreasonably large percentage of electric distribution “cost pools” to SOS. For example, it allocated close to $80 million of electric depreciation and amortization expenses, and $60 million of administration and general overhead, despite that the SOS business is “neither capital-intensive nor labor intensive.” He explained:

At its core, BGE is a capital-intensive gas and electric distribution and transmission utility with more than 3,000 full-time employees. BGE’s SOS service, on the other hand, utilizes two (2) full-time back office employees exclusively, along with a handful of employees on a partial basis, that charged a total of $700 thousand of labor and fringe benefits to SOS as incremental costs in 2018. ESC’s proposal to functionalize $173.1 million of indirect costs to SOS customers is simply illogical.

Mr. Manuel disagreed with ESC’s assertion that, to arrive at a market price, it had to include all categories of costs mentioned in the Commission’s 2016 Order, noting that BGE does not incur SOS “marketing/advertising costs” or “hedging supply commitment costs.” Mr. Manuel also noted that BGE had included cost categories not specifically mentioned in the 2016 Order, such as costs for credit collections and accounting.

With respect to ESC’s reliance on BGE’s Cost Allocation Manual and the National Association of Regulatory Utility Commissioners’ (“NARUC”) Guidelines for Cost Allocations and Affiliate Transactions, Mr. Manual stated that ESC demonstrated a *21 “fundamental misunderstanding of the purpose of th[o]se documents,” which relate to affiliate transactions, not SOS cost allocation. Moreover, the NARUC Manual states that “[t]he classification and treatment of the joint and common costs requires considerable judgment in an embedded cost of service Study.” (NARUC Electric Utility Cost Allocation Manual at 15, issued January 1992). Consistent with that approach, he “applied [his] professional judgment to prepare a cost of service study which functionalized indirect costs that support SOS to the Administrative Adjustment.”

Mr. Manuel stated that BGE did not try to “keep SOS prices artificially low in order to take advantage of any perceived incentive to retain SOS customers.” Rather, BGE advocated for an Administrative Adjustment that results “in a market price for SOS.”

Once the Administrative Adjustment rate is set and included in the SOS Administrative Charge, BGE will credit that amount to all distribution customers. ESC agreed with that approach, but Commission Staff recommended resetting base rates, which Mr. Manuel thought to be “overly complicated and unnecessarily burdensome.”

2.

ESC

Mr. Lacey stated that Commission Staff had “not done a full review of the costs that BGE allocates to the distribution and SOS functions,” and if it had, it would have been clear that BGE “omitted major cost categories and significantly understated other cost allocations to SOS.” Because Commission Staff had not conducted a full cost study, Mr. Lacey urged the Commission to disregard Mr. Hoppock’s testimony. Mr. Lacey also stated that Commission Staff’s characterization of BGE’s Administrative Adjustment rate as *22 “reasonable” was not the proper standard, noting that the order required BGE to conduct a study “to reflect more precisely which costs should be properly allocated in distribution rates and which costs should be properly allocated to SOS prices.” Moreover, the 2016 Order identified specific costs to be included in the SOS rates, many of which were not included on BGE’s proposal, such as Administrative and General (“A&G”) expenses. Mr. Lacey’s concern with Mr. Hoppock’s approach was that he overlooked shared costs to be allocated to SOS, but he did not have any concern with the proposal to allocate costs differently to different categories of customers once the “bucket of costs is defined.”

With respect to Mr. Johnson’s testimony, he “simply oppose[d] the implementation of the Administrative Adjustment,” a position the Commission had already rejected in requiring BGE to present a cost of service study. Mr. Lacey next addressed Mr. Johnson’s objection to BGE’s proposal for an Administrative Adjustment of 1.0 mills per kilowatt hour because it represented a 51% increase in the current Administrative Charge, which would impact customers. He stated that was not a valid objection because “the actual increase of one-tenth of a cent equates to about 1.3 percent of the total energy charge and less than 1 percent of the total current charges on a customer’s bill.”

Mr. Lacey argued that the Administrative Adjustment should be increased significantly from BGE’s proposal, which did not reflect a fully-allocated cost analysis that included costs incurred to provide SOS. This “violates the general rate making principle of cost causation by failing to completely allocate costs between supply and distribution categories.”

3.

Commission Staff

Mr. Hoppock amended his proposed Administrative Adjustment rate, increasing the total amount functionalized to the Administrative Adjustment from $12,324,792 to $15,123,164. The increase was the result of increasing the amount allocated to Call Center, as well as adding seven cost categories to the Administrative Adjustment: (1) FERC Account 909; (2) FERC Account 910; (3) Additional FERC Account 920 Expenses; (4) FERC Account 921; (5) FERC Account 923; (6) FERC Account 930.2; and (7) General Plant Depreciation Amortization Account 391. With respect to call center costs, Mr. Hoppock agreed with ESC that calls relating to energy assistance and Start, Stop, and Move calls should be allocated to SOS because retail suppliers incur these types of Call Center costs.

With respect to FERC Account 909 (informational and instructional advertising expense), FERC Account 930.2 (miscellaneous general expenses), and General Plant Depreciation Amortization Account 391 (office furniture, furnishing, and equipment), Mr. Hoppock recommended allocating the expenses in those cost categories “based on revenue” because retail suppliers likely incurred those types of costs.10 With respect to FERC Account 910 (miscellaneous customer service expenses), FERC Account 920 (administrative and general salaries), FERC Account 921 (office supplies expenses), and

10 With respect to Account 391, Mr. Hoppock further explained that, although the allocation should be based on revenue, he proposed to further “take the percentage of the allocated Account 391 SOS plant relative to total general plant to determine the general plant depreciation and amortization expense that should be allocated to SOS.”

FERC Account 923 (outside services employed), Mr. Hoppock noted that BGE identified portions of those cost categories as supporting SOS, and therefore, he recommended characterizing those accounts as incremental costs directly assigned to SOS. With respect to FERC Account 920 (administrative and general salaries), Mr. Hoppock noted that BGE had included $106,253 in incremental regulatory, accounting, and legal costs in the SOS Administrative Adjustment. He added $68,459 in additional incremental costs that “should be characterized as incremental costs directly assigned to SOS.” Mr. Hoppock proposed allocating costs regarding Account 930.2, miscellaneous general expenses, including “labor and expenses incurred in connection with general management of the utility not included in other accounts,” because, although BGE said it did not incur any such SOS costs, “other retailers, suppliers do incur general management expenses.” He recommended allocating this account based on revenue.

The following table, which Mr. Hoppock included in his prepared rebuttal testimony, broke down Commission Staff’s proposed changes to the allocation of several cost categories to the Administrative Adjustment:

4.

OPC

Mr. Johnson disagreed with the allocation method relied upon by Commission Staff, asserting that “the allocation methods recommended by Mr. Hoppock for the SOS classes are not consistent with the method (commodity revenues) used to allocate the cost components to SOS.” He testified that ESC’s proposal to allocate over $173 million to the Administrative Adjustment was “excessive on its face,” and its proposed fully distributed cost analysis was “not consistent with standard practices for electric utility cost of service studies and inappropriately assigns distribution cost categories to SOS without any clear connection between the costs and SOS service.” He also noted that ESC’s proposal to allocate 46% of BGE’s administrative and general costs to SOS was not consistent with *26 the NARUC Cost Allocation Manual (“CAM”) because “methods prescribed by the NARUC [CAM] would assign little, if any, cost to SOS.”

Additionally, Mr. Johnson asserted that the process ESC’s witnesses employed was “incomplete,” explaining: “The proposed quantification of the administrative adjustment is incomplete because it stops at assigning utility costs to SOS without also recognizing the benefits that other competitive suppliers receive from the utility cost.” To remedy this issue, he proposed adding a “third bucket for costs related to competitive suppliers.”11

C.

Prepared Surrebuttal Testimony

On October 22, 2019, witnesses for BGE, ESC, and Commission Staff filed prepared surrebuttal testimony with the Commission. OPC did not file surrebuttal testimony.

1.

BGE

Mr. Manuel stated that a “full unbundling of BGE’s distribution cost of service” was complex, and it was not required “to achieve the goal of the Administrative Adjustment, which is to serve as a proxy for certain costs incurred by retail suppliers but included in BGE’s distribution rates.” He explained that, although the “reference point”

11 As an example of a cost that should be placed in a third bucket, Mr. Johnson pointed to call center costs. He argued that “BGE’s call center also receives calls from customers of competitive suppliers or from customers with questions about retail choice.” Accordingly, “SOS customers would be paying more than their fair share because they would be paying for the SOS portion of the costs through SOS rates and paying for the retail supply portion of the costs through their distribution rates.”

was levels of costs incurred by retail suppliers, BGE examined its costs “because better retail supplier financial information was not available.”

With respect to Commission Staff’s proposal to increase the total amount allocated to SOS in the Administrative Adjustment from $12,324,792 to $15,123164, Mr. Manuel asserted that Commission Staff erred in two ways. First, Commission Staff “propose[d] to functionalize certain additional costs without considering proper cost allocation principles.” Second, Commission Staff “double-count[ed] costs that were already included in the original $12.3 million,” such as “administrative and general (A&G) expense FERC Accounts.” He addressed specific categories of costs, including why his allocation of call center and other costs was appropriate. He did agree with Commission Staff’s conclusion that a portion of FERC Account 391, Office Furniture and Equipment, should be functionalized to SOS, but he noted that the amount, $0.1 million, was “effectively already accounted for in [his] recommendation to round [his] proposed SOS Administrative Adjustment rates from 0.99 mills per kWh to 1.00 mills per kWh.” He reiterated his recommendation to approve the Administrative Adjustment rates to which he previously testified. He did not object to Commission Staff’s recommended customer class allocation adjustments, but he rejected its recommendation of costs of $15.1 million.

With respect to ESC’s proposal to significantly increase Administrative Adjustment rates, Mr. Manuel argued that this was inconsistent with the statement in the 2016 Order that “elimination of the Administrative Adjustment Component would put energy retailers at a slight disadvantage and on an uneven playing field relative to BGE.” Moreover, if the SOS “Administrative Adjustment rates were in need of the massive rate increases proposed *28 by ESC, it is doubtful that the Commission would have set the rate at 0 mills/kWh until a ‘reasonably precise Administrative Adjustment’ could be determined in a future case.” Indeed, Mr. Manuel stated that the retail supply market was “quite robust,” which supported the reasonableness of BGE’s proposal. He stated that ESC had failed to justify the allocation of approximately $80 million in electric distribution depreciation expenses and another $60 million in A&G overhead costs where “the SOS business is neither capital-intensive nor labor-intensive.” In sum, “ESC did not provide cost causation arguments that would support the excessive amount of costs they proposed to functionalize to SOS.”

Finally, addressing OPC’s rebuttal testimony, Mr. Manuel stated that Mr. Johnson’s argument favoring a “third bucket” of costs was interesting and warranted further review. Such a proposal, however, could more adequately be considered in a “Phase II proceeding.”

2.

ESC

Mr. Lacey’s surrebuttal testimony, in response to BGE and OPC rebuttal testimony, noted that, “[n]one of the witnesses [say] that a fully allocated approach to ratemaking is inappropriate” or suggest that “any of the cost categories identified by ESC are inaccurate.” He stated that ESC’s “solution does not increase costs. It only moves costs into different buckets. BGE acknowledged that the Administrative Adjustment, if implemented correctly, will keep BGE and ratepayers financially neutral no matter the size of the allocation to the Administrative Adjustment.”

Mr. Lacey stated that “[t]he Commission should compel a full allocation of costs to SOS before approving BGE’s proposed increased rates,” asserting that “Mr. Manuel did *29 not capture non-incremental costs such as office space, furniture, supplies, and office equipment, all of which [were] utilized in the delivery of SOS,” and “[e]xcluding such basic business expenses . . . is simply not a complete or ‘more precise’ reflection of the cost that should be allocated to the SOS business.” He stated that the differences among the parties’ proposed Administrative Adjustments were “the direct result of BGE and Commission Staff failing to use a fully-allocated cost approach, which has been a fundamental premise of utility ratemaking for decades.”

Mr. Lacey explained that, if a “resource is used for both services, the costs of that resource should be allocated, in an appropriate manner, to those services.” It was “unfathomable to suggest that a $1 billion SOS business would incur no IT costs to serve over 800,000 customers. Similarly, it could not operate without paying rent or purchasing office supplies.” “BGE ha[d] offered no rationale for not allocating even the most basic business expenses to its SOS business,” and its analysis was “simply lacking.”12

12 When asked about Mr. Manuel’s assertion that ESC had not provided costs that other electric suppliers incurred, Mr. Lacey responded:

This proceeding is not about the costs that are incurred by competitive retailers. Rather, it is about whether BGE’s rates, and its underlying cost allocations, are just and reasonable. In order for BGE’s rates to be just and reasonable, they must, at a minimum, reflect a proper allocation of costs among all functions. Given that BGE has not used a fully-allocated cost approach, its proposed rates are not just and reasonable. I understand that the Commission in Case No. 9221 described the Administrative Adjustment as serving a proxy for A&G costs that retail suppliers must include in their prices. However, the Commission did not say that actual supplier costs should be considered. Instead, the Commission found that certain cost categories that would be incurred by competitive suppliers should be included in the SOS rate.

Mr. Lacey disagreed with Mr. Manuel’s assessment that the competitive retail electric market was “healthy,” given that more than 75% of BGE’s residential customers were receiving their electric supply from BGE, and there were 67 retail electric suppliers operating in the market. “By not allocating costs to SOS, BGE is able to keep its cost below the market price of retail electricity service.”

Mr. Lacey also disagreed with OPC’s assertion that a “third bucket” was required, stating that such a proposal was “fatally flawed” because “BGE’s costs are not and should not be based on ‘benefits’” received by retail customers, but rather, “they should be based on cost-causation principles.” Moreover, “[t]he costs that BGE incurs to operate the market benefit all customers, not just customers of competitive energy suppliers.”

Mr. Peterson noted that, with respect to the original eight categories BGE included in calculating the Administrative Adjustment, the calculations by BGE, Commission Staff, and ESC were “relatively close,” although ESC added costs for regulatory and legal costs.13 Mr. Peterson provided the following table to illustrate this point:

13 As discussed, supra, these cost categories were (1) Billing System Amortization; (2) Billing System Unamortized; (3) Credit & Collections; (4) Billing; (5) Call Center; (6) Regulatory; (7) Accounting; and (8) Legal.

Although Commission Staff had allocated additional categories of costs to SOS, as reflected in Mr. Hoppock’s rebuttal testimony,14 ESC did not agree with the amounts allocated and thought additional cost components should be added. Three additional tables illustrated where BGE, Commission Staff, and ESC differed:

14 The number listed in the above chart for Commission Staff was less than the $15,123,164 given by Mr. Hoppock in his amended proposed Administrative Adjustment because it reflected only the first eight categories of costs.

Mr. Peterson also included a fifth table, which included a summary of the cost components reflected in the other four tables:

3.

Commission Staff

In his surrebuttal testimony, Mr. Hoppock recommended that the Commission adopt his adjusted allocation to the Administrative Adjustment costs. He explained, however, that after receiving more information from BGE, he increased “the allocation of call center costs to SOS.” This change, coupled with other changes to various cost categories, increased Commission Staff’s total proposed allocation to $16,150,367, as demonstrated by Mr. Hoppock in the following table: *33 As shown by the table, Commission Staff increased the proposed allocations to Call Center, FERC Account 910, Additional FERC Account 920 Expenses, and FERC Account 923. Commission Staff decreased the allocations to FERC Account 909, and it added “Load Profiling and Settlement Costs” as a cost category.

Mr. Hoppock explained that he reduced the allocation to FERC Account 909 because “retail suppliers likely [did] not incur” certain costs associated with that Account, such as “Educational School Programs, Seasonal Readiness (winter/summer ready), Safety, and Outage Education.” Mr. Hoppock increased the allocation for “Accounts 910, 920, and 923” due to his increased allocation to the Call Center cost category.

D.

Submitted Testimony After 2019 Settlement Agreement

On October 25, 2019, BGE, Commission Staff, OPC, and several other parties not involved in this appeal (“Settling Parties”), entered into a settlement agreement (“2019 Settlement Agreement”). This agreement provided, among other things, that BGE would file rate schedules “authorizing an electric base rate of $25 million, and a gas base rate increase of $54 million.” It resolved all contested issues except for the amount of the SOS Administrative Adjustment. The Settling Parties agreed that “[a]n appropriate SOS Administrative Adjustment [would] be addressed in the Phase II proceeding,” and that additional discovery for that proceeding would begin on February 15, 2020.

On October 28, 2019, the Commission sent the parties a Notice of Amended Procedural Schedule, which required additional testimony on the issue of the SOS Administrative Adjustment. On November 8, 2019, following the execution of the 2019 Settlement Agreement, BGE, ESC, Commission Staff, and OPC witnesses prepared and submitted testimony regarding the remaining contested issue unresolved by the 2019 Settlement Agreement, the SOS Administrative Adjustment, which also addressed contentions raised in surrebuttal testimony.15

15 Several parties titled their submissions as rejoinder testimony, as they addressed contentions raised in the surrebuttal testimony of the other parties.

1.

BGE

Mr. Manuel stated that BGE maintained its recommendation regarding SOS Administrative Adjustment rates. He reiterated that “the SOS Administrative Charge already capture[d] the incremental costs associated with providing SOS (under the Incremental Charge component of the Administrative Charge),” and it had conducted the study to “capture non-incremental costs that support SOS.”

Although Commission Staff’s proposed Administrative Adjustment rates were “not unreasonable,” he believed that Commission Staff had double-counted certain costs. ESC’s proposed Administrative Adjustment rate, however, was “more than 10,000% larger” than the rate BGE and Commission Staff proposed, and it was “illogical” because it included costs in the Administrative Charge that BGE would incur even if it ceased its SOS business. For example, Mr. Lacey proposed that a greater amount of billing costs be allocated to SOS because BGE generated millions of invoices per year for SOS, but “every single one of those ‘invoices’ would be generated, and resulting payments collected, in the absence of SOS” because “[e]very BGE distribution customer receives a bill.” Moreover, “[t]he only difference between SOS and shopping customers [was] a single line item on that invoice.” And BGE’s proposal allocated 45.6%, $9.6 million, of electric distribution and collection costs to SOS in the study. Additionally, ESC proposed “to functionalize to SOS nearly $80 million of administrative & general overhead,” but the “SOS business is neither capital-intensive nor labor-intensive.” Indeed, BGE’s Incremental Cost component rate, which addresses “the non-energy costs BGE directly incurs as a result of providing *36 SOS (i.e., labor for administering the SOS auction process and managing PJM and supplier interactions, etc.), is currently 0.08 mills-per-kWh.” ESC failed to justify how its high costs could be attributed to SOS.

2.

ESC

Mr. Lacey admitted that the 2016 Order did not mandate a specific “allocation methodology,” but he asserted that, “for the Commission to accomplish the goal that it set forth in [the 2016 Order] of properly allocating costs to distribution service and SOS, it must adopt [ESC’s] solution,” i.e., a “full unbundling and the allocation of a portion of the indirect costs associated with each resource that is consumed or utilized by BGE in the provision of SOS.” It was necessary to allocate indirect costs, as opposed to only including direct cost, because “[t]he purpose of the Administrative Adjustment was to capture indirect costs that are incurred by BGE in providing SOS.”

With respect to the contention that the increase was too high, Mr. Lacey stated that the impact on SOS customers could be mitigated by phasing in the increased rates over time. He also noted that the size of ESC’s proposed modification to the Administrative Adjustment was irrelevant because indirect costs are merely reallocated, not increased.

3.

Commission Staff

Mr. Hoppock interpreted the 2016 Order as requiring two types of costs to be factored into the Administrative Adjustment: “1) the incremental costs embedded in distribution rates SOS causes BGE to incur, as well as 2) a proxy for customer costs that *37 retail suppliers incur beyond those identified as incremental SOS costs that are currently in BGE distribution rates.” ESC allocated certain FERC Accounts as supporting SOS based solely on the description of the account, but the actual costs in those accounts may not support SOS. For example, ESC allocated all of FERC Account 928, but to Mr. Hoppock’s knowledge, the costs of that account did not support SOS. The 2016 Order “clearly state[d] that the Administrative Adjustment serves as a proxy for costs retail suppliers must include in their rates and are meant to keep SOS prices competitive with retail suppliers’ costs and prices.” Therefore, ESC’s proposed allocation of costs that “most retail suppliers do not incur, such as common plant AMI, directly conflict[ed] with the clear language of” the 2016 Order.16

Mr. Hoppock disagreed with BGE’s assertion that he double counted costs in FERC Accounts 910, 920, 921, and 923, but he did agree that there appeared to be “some inconsistencies between BGE responses regarding what Accounts are included in call

16 “Advanced metering infrastructure (AMI) is an integrated system of smart meters, communications networks, and data management systems that enables two-way communications between utilities and customers.” Office of Electricity Delivery and Energy Reliability, Advanced Metering Infrastructure and Customers Systems: Results from the Smart Grid Investment Grant Program, U.S. Department of Energy, at 4 (Sept. 2016), https://www.energy.gov/sites/prod/files/2016/12/f34/AMI%20Summary %20Report_09-26-16.pdf. The purpose of AMI is to help customers cut down on electricity consumption. Id. In 2010, the Commission issued Order Number 83531, which, among other things, authorized BGE to launch its Smart Grid Initiative that implemented AMI, replacing the current electric meters with over 2 million “smart meters,” which are designed to help customers communicate with BGE to better save electricity. Public Service Commission, 2010 Annual Report, at 12 (https://www.psc.state.md.us/wp- content/uploads/MD-PSC-2010-Annual-Report.pdf).

center and billing costs in BGE’s proposed SOS Administrative Adjustment.” Accordingly, Mr. Hoppock provided a set of adjusted rates that omitted those contested FERC Accounts from the Administrative Adjustment, which resulted in an allocation of $15,920,967 across all four customer classes and Administrative Adjustment rates of 1.44, 1.23, 0.47, and 0.35 mills per kWh across the Residential, Type I, Type II, and Hourly-Priced Service classes, respectively.

4.

OPC

Mr. Johnson maintained his earlier position that none of the parties had presented an adequate cost analysis, and therefore, there was no way to properly allocate costs to SOS or the Administrative Adjustment. He highlighted the disparity between the allocations proposed by BGE, Commission Staff, and ESC, asserting that the disparity “demonstrate[d] the frailty of precision and the wide variance in assignable costs that can be produced by differing methods.” If the Commission truly desired to “level the playing fields” between BGE’s SOS and competitive suppliers, then “the cost analyses should assign costs to both SOS and the competitive suppliers if both receive benefit from the distribution company incurring the cost.” A failure to do so could result in SOS customers “paying more than their fair share because they would be paying for the SOS portion of the costs through SOS rates and paying for the retail supply portion of the costs through their distribution rates.” Avoiding this result by properly allocating costs to competitive suppliers, however, would require additional time and information.

Mr. Johnson noted that Commission Staff’s allocation had increased 35% since Mr. Hoppock originally accepted BGE’s proposed allocation to the Administrative Adjustment. He stated that ESC’s proposed allocation of over $173 million was “excessive and unreasonable.” He argued that labor, as opposed to revenue, was the proper allocator and was consistent with NARUC guidelines.

E.

Hearing Before the Commission

On November 14, 2019, the parties and their expert witnesses appeared before the Commission for a hearing. The parties admitted the prepared testimony of their expert witnesses, and then opposing counsel and the Commission asked questions.

1.

Mr. Manuel

Mr. Manuel reiterated that the cost of service study he prepared determined “reasonably precise administrative adjustment rates that represent a proxy of the costs that retail suppliers bear,” while also “ensuring that the results of [his] study supported a market price.” He explained why BGE’s proposed allocation did not include any HR expenses, stating: “BGE does not staff its HR department to specifically support SOS. To the extent that there are HR costs that indirectly support the costs that support SOS, if I were to include those costs, those costs would be nominal in nature” and “certainly would not rise to the level of costs that ESC proposed.” With respect to Commission Staff’s inclusion of other cost categories in its proposal, such as office furniture, he explained that, “to the extent there is furniture for the small number of employees that support SOS, my rounding *40 of the SOS administrative adjustment to one mill exactly, more than covered the amount that [Commission Staff] determined should be allocated for office furniture.” When asked if he believed it was “appropriate for BGE to base its SOS rates on the costs that are incurred by [competitive] suppliers,” Mr. Manuel responded in the affirmative, explaining that “the point of the administrative adjustment is to represent a proxy of those very costs.” Mr. Manuel, however, was not aware of any utility that set its rates based on the costs incurred by other competitors.

2.

Mr. Peterson & Mr. Lacey

Mr. Peterson conceded on cross-examination that he had not personally conducted a utility cost of service study. He stated, however, that as a CPA, he had done “significant work in cost allocation,” and “doing cost allocations . . . is equivalent to a carpenter knowing how to use a saw,” i.e., it was “a common tool.” He also acknowledged that, in a similar case before the Pennsylvania Public Utility Commission, his arguments favoring a large increase in the costs allocated to default electricity service were rejected.

Mr. Lacey stated that the costs BGE included in its proposal were non-incremental. He reiterated his position that “[t]he Commission ordered a fully unbundled or cost of service study to figure out the costs that are woven into distribution rates that support SOS.”

3.

Mr. Hoppock

Mr. Hoppock stated that he used a two-step process to determine costs: (1) “incremental costs still in distribution rates caused by SOS,” and (2) costs that were a proxy *41 for costs retail suppliers incurred. It was possible that he double-counted certain costs, specifically accounts 910, 920, and 923. Given his uncertainty, he deferred to the Commission to make a proper determination on that issue. In response to a question from the Commission, he agreed that the amount of potential double-counting was approximately $230,000. With respect to the overall difference between his recommendation of costs of $15.9 million, as opposed to BGE’s $12.3 million, these differences included: (1) for the call center, he had costs of $5 million, as opposed to BGE’s cost of $2.7 million; (2) he added costs for FERC accounts 909 and 930.2; (3) “general plant depreciation amortization”; and (4) account 391, furniture.17

4.

Mr. Johnson

Mr. Johnson reiterated his position that the administrative adjustment proposed by BGE be rejected. He noted that most of the SOS cost is based on periodic auctions for purchase power, which is “reflective of market price.” The proposal by ESC to increase costs allocated to SOS by $173.1 “immensely overstates the allocation administrative and general costs” and it includes “double counting of costs.”

17 FERC accounts 910, 920, 921, and 923 are the costs that BGE asserted were double counted.

F.

The Commission’s Ruling

On December 17, 2019, the Commission issued Order No. 89400 (“2019 Order”). After addressing other issues raised in the 2019 Settlement Agreement, the Commission dealt with the sole contested issue, the SOS Administrative Adjustment rate.

The Commission thoroughly discussed the testimony presented, and it noted the wide range of proposals for costs for the SOS Administrative Adjustment rate, including: $12.3 million from BGE, $15.9 million from Commission Staff’s final position, $173.1 million from ESC, and OPC’s proposal to not increase costs at all. The Commission noted that it previously had determined that retaining the Administrative Adjustment rate would help level the playing field between utility-provided SOS rates and competitive suppliers, but it “only serves as a ‘proxy’ for administrative and general costs retail suppliers must include in their rates, which are embedded in the distribution rates of utility companies.” The Commission noted that OPC’s position, to keep the SOS Administrative Rate at 0.00 mills per kWh, was inconsistent with that prior directive.

The Commission then addressed ESC’s proposal to allocate $173.1 million of non-incremental costs to SOS. It found that this proposal was “a significant departure from prior Commission decisions setting an appropriate Administrative Adjustment,” noting BGE’s argument that ESC’s proposal allocated unreasonably large amounts of percentages of electric distribution costs to SOS, including close to “$60 million of administrative and general overhead and $80 million of electric distribution depreciation and amortization expense,” despite that SOS is not “capital intensive” or “labor intensive.” With respect to *43 ESC’s argument that its proposal was the only one to fully unbundle SOS costs, the Commission stated that the 2016 Order “call[ed] for the SOS Administrative Adjustment to be reasonably precise, not a full unbundling as argued by ESC.”18

The Commission found that BGE’s proposal was well-reasoned and followed the Commission’s directive. It summarized BGE’s identification of “four high level cost centers with non-incremental costs that support SOS,” as follows:

Billing systems: BGE functionalized a portion of the electric distribution billing system costs (both amortization of the billing system and the unamortized costs in rate base) using a revenue allocator.

Billing, credit & collections: BGE identified the billing and credit & collections projects that support SOS, then functionalized a portion of the electric distribution costs for those projects to SOS using a revenue allocator.

Customer call center: BGE used data from its interactive voice response (IVR) system to first determine the percentage of incoming calls from customers that related to billing or credit & collections. BGE applied this percentage to the customer calls center’s electric distribution expenses first, and then further functionalized to SOS using the revenue allocator.

Regulatory, accounting & legal: BGE personnel from these areas were asked to identify their SOS-related tasks/deliverables and then estimate time they spent on each activity. Based on this information, the functionalization factor for each area was derived by multiplying the percentage of time spent per employee during the year on SOS-related activities by the respective cost center expenses recorded in the general ledger.

The Commission noted, however, that BGE’s approach did not include certain costs listed in the 2016 Order, as discussed in Commission Staff’s proposed costs, including:

FERC Account 909 Informational and Instructional Expense, FERC Account 910 Miscellaneous Customer Service, Account 920 Administrative and

18 As indicated, the Commission’s previous Order requested that a “cost of service study should be presented to reflect more precisely which costs should be properly allocated in distribution rates and which costs should be properly allocated to SOS prices.”

General Salaries, Account 921 Office Supplies and Expenses, Account 923 Outside Services, Account 930.2 Miscellaneous General Expenses, General Plant Depreciation Amortization Account 391, and Load Profiling and Settlement Costs.

The Commission discounted some of Commission Staff’s proposed additions, as follows:

The Commission does not, however, find that Staff witness Hoppock’s reasoning for additional allocation of call center “Start, Stop and Move” or “General Business Inquiry” costs are sufficiently supported or appropriate and therefore rejects those additions to BGE’s cost of service allocation. Regarding the other additional cost categories, the Commission notes that BGE witness Manuel agreed that the inclusion of FERC Account 909, 930.2, and Load Profiling may be reasonable to allocate a portion of General Plant Depreciation Amortization Account 391 to SOS, as this utility account relates to office furniture and equipment that is used by all BGE employees, including the few employees directly supporting SOS activities.19 However, the Commission finds that Staff did not adequately support its allocation of costs from FERC Account 909 (Informational and Instructional Advertising Expense) and FERC Account 930.2 (Miscellaneous General Expense). These should be excluded, as none of the expenses in either account relate to SOS. During the hearing, Witness Hoppock conceded that he did not have specific documentation to support these costs but believed these were costs likely to be borne by retail suppliers.

As a result of these findings, the Commission determined that the appropriate cost allocation method was a “hybrid approach,” which combined portions of BGE’s and

19 When read in conjunction with the next sentence, it appears that the Commission meant to refer only to FERC Account 391. The record reflects that the brief to which the Commission referred notes Mr. Manuel’s agreement that a portion of Account 391, office furniture and equipment, should be allocated to SOS, but it states that BGE’s position, and Mr. Manuel’s testimony, was that costs for Account 909 (Advertising) and Account 930.2 (Miscellaneous General Expenses) should not be allocated to SOS because BGE did not incur any SOS costs in these Accounts, and Mr. Hoppock did not have evidence that these costs were incurred by other suppliers.

Commission Staff’s SOS Administrative Adjustment. It accepted the total costs for the hybrid approach in the following cost categories:

Billing System Amortization Expense ($1,979,003), Billing System Unamortized Costs ($1,434,101), Credit & Collections ($4,409,677), Billing ($1,740,435) [], Call Center ($2,655,323 million), Regulatory ($81,263), Accounting ($14,460), and Legal ($8,530). . . . FERC Accounts 909 ($468,811), FERC Account 930.2 ($260,175), General Plant Depreciation Amortization ($133,774), and Load Profiling and Settlement Costs ($382,097).

Accordingly, the Commission allocated costs of $13,569,649 to SOS. It adopted “BGE’s ‘normalized’ allocation method, which computes the mills per kWh as the same across each customer class (and is computed to be 1.09 mills per kWh).” It ordered that BGE file tariffs “allocating a total of $13,569,649 in its indirect costs to [SOS] that are currently embedded in BGE’s distribution rates and set a normalized distribution SOS Administrative Adjustment rate of 1.09 mills per kWh.”

III.

Appeal to the Circuit Court

On January 15, 2020, ESC appealed the 2019 Order, filing a Petition for Judicial Review in the Circuit Court for Baltimore City. On August 13, 2020, ESC filed its memorandum in support of its petition, requesting that the court “(1) reverse the relevant portions of the Commission’s decision; and (2) remand the matter to the Commission with instructions that it require BGE to allocate overhead costs to SOS in a manner that ensures the recovery of all costs incurred to provide SOS through the rate charged for that *46 service.”20 In its memorandum, ESC reiterated many of the arguments it raised before the Commission, including that the law required the Commission to set a price that was “market based,” and the only way to set such a price was to conduct a fully allocated cost of service study.

On September 14, 2020, BGE filed a memorandum in opposition to ESC’s petition, arguing that the 2019 Order “was supported by substantial evidence and was not arbitrary or capricious.” The Commission filed its own memorandum in opposition, raising similar arguments.

On October 1, 2020, the court held a remote hearing on ESC’s petition. Counsel for ESC argued that there were “four specific adverse results of the Commission’s decision[:]” (1) the distribution rates of all customers remained too high; (2) the SOS rates were too low; (3) competitive suppliers were forced to compete with these artificially low SOS rates; and (4) customers of competitive suppliers were subsidizing SOS customers. Counsel argued that, because of these deficiencies, the Commission erred as a matter of law in two ways. First, citing Severstal, ESC asserted that SOS needed to be set at a market price, and “[t]o comply with the market price standard, it’s necessary for the company to consider all of its overhead costs and look at each one and consider whether the underlying resource is

20 ESC presented two questions for review before the circuit court: (1) whether the 2019 Order was “in violation of the law that establishes a market price standard in setting rates for the sale of electricity by the utility and otherwise arbitrary and capricious[;]” and (2) whether the 2019 Order was “in violation of the law that imposes a series of obligations on the agency to develop, monitor and correct deficiencies in the competitive retail electric market and otherwise arbitrary and capricious[.]”

used to provide SOS.” Second, by allowing distribution rates to subsidize SOS rates, the Commission violated the Competition Act and was not supporting the development of a competitive electricity supply market. Additionally, counsel argued that the court was not required to give the Commission’s decision deference because “it didn’t even give lip service to the market price standard,” and “the Commission ha[d] never before been presented with the results of a fully allocated cost study to establish a market price.”

Counsel for the Commission argued that the 2019 Order was “well reasoned, based on the record, and clearly supported by substantial evidence, and was not arbitrary and capricious.” Furthermore, the 2019 Order resulted in a “just and reasonable rate” and “did not violate the Competition Act.” Counsel noted that Commission decisions were deemed to be prima facie correct “unless clearly shown to be unconstitutional, outside the statutory authority, or jurisdiction of the Commission, made on unlawful procedure, arbitrary or capricious, affected by other error of law, or . . . unsupported by substantial evidence of the record considered as a whole.” ESC could not demonstrate that the Commission “exercised its discretion unreasonably or without rational basis.” In support, counsel noted that the 2016 Order stated only that the Administrative Adjustment was a proxy for the costs incurred by competitive suppliers, and the Commission, after examining all of the testimony and data provided by the various parties, crafted its own “hybrid” approach using its “reasoned judgment.”

Counsel for BGE argued that “the Commission is absolutely owed deference in this case.” Counsel explained that the 2019 Order is entitled to deference because it involved “a fact intensive inquiry,” as evidenced by the factual disputes in ESC’s own briefs. The *48 Commission, not ESC, “was in the best position to determine what type of cost allocation approach the Commission requested in its own 2016 [O]rder.”

Prior to ending the hearing, the court asked counsel for ESC if the issue was “not so much that the Commission didn’t agree” with the size of ESC’s $173 million allocation, “but that the number that the Commission came up with was not supported by substantial evidence or otherwise arbitrary in the formula that they used[.]” Counsel for ESC replied: “That’s correct, Your Honor. It’s the method that was used, this very limited look at [BGE’s] overhead costs.”

On November 18, 2020, the court issued an Order Denying Petition for Judicial Review. In its Order, the court found that it “must give deference to the Commission’s expertise and findings; even more so than that deference afforded other administrative agencies.” The Order then stated:

FOUND that the law requires that the Commission establish rates that are “just and reasonable”; the law does not require that the Commission establish rates that are fair market value; and it is further

FOUND that the record is replete with substantial evidence to support the Commission’s Order No. 89400. including, but not limited to, consideration of expert testimony (at hearings during which the witnesses were examined and cross-examined under oath), extensive exhibits, and legal memoranda or briefs. As such, any reasonable mind could have reached the conclusion the Commission reached. Public Service Commission v. Delmarva Power and Light Company, 42 Md. App. 492 (1979); and it is further

FOUND that Petitioners have failed to establish that Order No. 89400 is unconstitutional, outside the statutory authority or jurisdiction of the Commission, made on unlawful procedure, arbitrary or capricious, affected by other error of law, or unsupported by substantial evidence on the record considered as a whole. Md. Code Ann., Pub. Util. § 3-203[.]

This appeal followed.

DISCUSSION

As indicated, PU §7-510(c)(3)(ii)(2) “requires that the utility furnish SOS at ‘a market price that permits recovery of the verifiable, prudently incurred costs to procure or produce the electricity plus a reasonable return.” ESC contends that the “Commission erred as a matter of law” by not requiring BGE to charge the statutory “market price” for its SOS rate. It argues that, in allowing BGE to underprice SOS, the Commission failed to fulfill its statutory duties under the Competition Act to ensure a competitive retail market.

ESC asserts that the “only way to establish a market price is to perform a fully allocated cost of service study.” It argues that BGE’s study was incomplete, and the Commission ignored the requirement that a market price be established for BGE’s SOS by its “refusal to mandate that BGE include in the SOS rate a portion of the overhead costs associated with each resource that BGE uses to support or provide SOS.” It argues that the Commission’s decision setting the Administrative Adjustment rate was arbitrary and capricious.

BGE contends that the Commission has “broad statutory discretion to regulate BGE’s [SOS] rates,” and the “Commission’s decision to set the Administrative Adjustment rate at 1.09 mills per kWh was supported by substantial evidence and was not arbitrary or capricious.” It asserts that the approach taken by BGE and Commission Staff “followed traditional cost-causation ratemaking principles, in which only those costs that are determined to be . . . linked” to SOS are allocated, and ESC’s approach was properly “rejected for failing to follow the basic principle.” It notes that it was the Commission, in *50 its rate-setting capacity, not the General Assembly, who created the Administrative Adjustment.

The Commission contends that its “decision was well reasoned based on the record, clearly supported by substantial evidence, and was not otherwise arbitrary or capricious.” It “evaluated the positions and recommendations of each party,” and after weighing all the evidence, it properly adopted a hybrid solution to allocate costs to SOS.

In conducting our analysis of the parties’ contentions, we note initially that, “[i]n an appeal from judicial review of an agency decision, we review the agency’s decision,” not the decision of the circuit court. Maryland Office of People’s Counsel v. Maryland Pub. Serv. Comm’n, 461 Md. 380, 391 (2018). PU § 3-203 sets forth the limited scope of our review of the decision of the Commission, as follows:

Every final decision, order, or regulation of the Commission is prima facie correct and shall be affirmed unless clearly shown to be:

(1) unconstitutional; (2) outside the statutory authority or jurisdiction of the Commission; (3) made on unlawful procedure; (4) arbitrary or capricious; (5) affected by other error of law; or (6) if the subject of review is an order entered in a contested proceeding after a hearing, unsupported by substantial evidence on the record considered as a whole.

(Emphasis added).

This Court has explained:

Because a final decision of the Commission is prima facie correct, it will “not be disturbed on the basis of a factual question except upon clear and satisfactory evidence that it was unlawful and unreasonable.” Office of the People’s Counsel v. Maryland Public Service Commission, 355 Md. 1, 14 (1999). Indeed, if reasoning minds could reasonably reach the Commission’s

decision from the facts in the record, then the decision is based upon substantial evidence, and we will not reject that conclusion. Liberty Nursing Center, Inc. v. Department of Health and Mental Hygiene, 330 Md. 433, 442- 43 (1993).

Maryland Office of People’s Counsel v. Maryland Public Service Commission, 226 Md. App. 176, 190-91 (2015).

The Court of Appeals recently gave a thorough explanation of the standard of review of a Commission decision, as follows:

[T]he standard of review does not depend on whether we would reach the same conclusions as the Commission, but on whether the Commission’s decision or process is infected by the specified defects. . . .

It has often been said that the standard of review of Commission decisions is “consistent with the standard of review applicable to all administrative agencies.” E.g., Office of People’s Counsel v. Public Service Commission, 355 Md. 1, 15, 733 A.2d 996 (1999); Town of Easton v. Public Service Commission, 379 Md. 21, 31, 838 A.2d 1225 (2003). The standard of review set forth in PU § 3-203 is certainly consistent with that applied to other administrative agencies under Maryland Administrative Procedure Act (“APA”), which does not apply to the Commission. In particular, the specified bases for reversing a Commission decision are the same as set forth for reversing an agency decision in the provision for judicial review in the APA. See Maryland Code, State Government Article, §§ 10-203(a)(3)(v), 10- 222(h).

However, PU § 3-203 also appears to be a more deferential standard in some respects compared to the standard of review under the APA. In particular, with respect to decisions of the Commission, the General Assembly has directed that the Commission’s decision is “prima facie correct” and is to be affirmed unless the listed defects are “clearly shown.” That language is absent from the APA’s provision concerning judicial review. The distinction does not appear to be unintended. The statute establishing the Commission preceded the APA and the APA provision concerning judicial review was enacted just two years after enactment of the current version of the judicial review provision in the Commission’s statute. See Mid-Atlantic Power Supply Ass’n v. Public Service Commission, 361 Md. 196, 214, 760 A.2d 1087 (2000). (“Had the Legislature intended that the standard for judicial review of . . . Commission proceedings be the same as .

. . under the APA, it is inconceivable that it would have excluded the . . . Commission from the APA”).

In giving meaning to this language in PU § 3-203 without rendering it surplusage, we believe that it calls for a court to be particularly mindful of the deference owed to the Commission on those issues on which courts typically accord some degree of deference to administrative agencies – i.e. findings of fact, mixed questions of law and fact, and the construction of particular statutes administered, and regulations adopted, by the agency. On those questions on which a court does not typically defer to an agency – general questions of law, jurisdiction and constitutionality – PU § 3-203 requires no greater deference to the Commission than any other agency. Such legal questions “are completely subject to review by courts.” In sum, with respect to the Commission, “this Court has tended to accord particular deference (though not total deference) to PSC decisions.” Accokeek, Mattawoman, Piscataway Creeks Community Council, Inc. [v. Pub. Serv. Comm’n], 451 Md. [1,] 12, 150 A.3d 856 [(2016)]; see also Baltimore Gas & Elec. Co., 305 Md. at 170, 501 A.2d 1307 (recognizing that this Court has “consistently held that Commission orders enjoy a high degree of judicial deference on review”) (citations omitted).

Maryland Office of People’s Counsel, 461 Md. at 392–94 (footnotes omitted).

With that standard of review in mind, we address the Commission’s order in this case. ESC makes several arguments in support of its contention that the Order should be reversed, but the argument, at its core, is that the Administrative Adjustment adopted by the Commission resulted in BGE providing SOS to residential and small commercial customers at a price that was below the “market price” required by PU § 7-510(c)(3)(ii)(2). As indicated, the “market price” for SOS is composed of the “verifiable, prudently incurred costs to procure or produce the electricity plus a reasonable return.”

The Commission’s Order in this case, however, must be considered in the context with all the work that previously has been done to establish a market price for SOS. As indicated, the 2003 Settlement Order, involving BGE and other electric companies, *53 established that the market price for SOS would consist of purchase power costs, transmission costs, taxes, and an administrative charge. The Administrative Charge component was further broken down to include “a utility return component, incremental, or direct, costs to provide SOS, uncollectibles, and an Administrative Adjustment, which was set initially at 0.9 mills per kWh.” The Administrative Adjustment subsequently was changed to 0.0 mills per kWh, with the appropriate amount to be considered in “BGE’s next general rate case, in which a cost of service study should be presented to reflect more precisely which costs should be properly allocated in distribution rates and which costs should be properly allocated to SOS prices.” Thus, the formula to determine what would constitute a market rate was established years ago. What was left to be determined was the appropriate rate for the Administrative Adjustment component, which served as a proxy for administrative costs that retail suppliers must include in their rates, but are embedded in BGE’s distribution rates.

When BGE requested a rate increase in 2019, it included, as instructed, a cost of service study that assessed indirect costs incurred to provide SOS, which would “reflect more precisely which costs should be properly allocated in distribution rates and which costs should be properly allocated to SOS prices.” The Commission’s decision in this case was to determine whether the cost of service study conducted by BGE adequately assessed the costs that should be included in the Administrative Adjustment component, i.e. non-incremental, or indirect, costs that supported SOS that were not otherwise included in the Administrative Charge.

In addressing ESC’s contention that the Commission erred in determining that the appropriate Administrative Adjustment was 1.09 mills per kWh, we start with the proposition that the Commission’s decision is prima facie correct unless ESC “clearly show[s]” one of the six enumerated statutory defects. PU § 3-203. There is no question that the decision regarding BGE’s request for a rate increase was within the statutory authority and jurisdiction of the Commission. PU §7-505(b)(8) specifically gives the Commission the authority to “determine the terms, conditions, and rates” of SOS in accordance with other provisions, including the provision in PU § 7-510(c)(3)(ii)(2) that requires BGE to provide SOS at a market price. In furtherance of that statutory mandate, the Commission adopted the Administrative Adjustment as a component of the market price of SOS to keep “SOS prices competitive with retail energy suppliers’ costs and prices.” 2016 Order, at 14.

ESC’s argument appears to encompass the statutory defects set forth in PU § 3-203(5), the Order was “affected by . . . error of law,” and PU § 3-203(4), the Order was “arbitrary or capricious.” ESC contends that the Commission erred as a matter of law because it ignored the statute requiring that a market price be established for SOS. As indicated, however, the formula to establish a market price had already been established, and the proceedings at issue here were to address the facts presented to determine what costs should be included in the Administrative Adjustment component for SOS. This determination was not, as ESC asserts, a question of law.

Rather, as BGE and the Commission note, the implementation of, and rate-setting related to SOS is subject to the Commission’s broad discretion, and its decision in that *55 regard should be given deference. In determining the appropriate rate for the Administrative Adjustment in this case, the Commission considered the cost of service study BGE conducted, as well as BGE’s recommendation of an SOS Administrative Adjustment rate of 1.0 mill per kWh. Mr. Manuel explained the basis for his reasoning, and multiple other witnesses expressed their opinions on this study and other methods to calculate the Administrative Adjustment.

The Commission, the expert rate-setting agency, listened to the testimony, judged the credibility of the witnesses, and weighed the evidence in determining that the appropriate Administrative Adjustment was 1.09 mills per kWh. This determination was a discretionary decision made based on the facts presented, and it is a decision on which this Court gives deference.

Thus, our review in this case is limited to whether the Commission’s decision setting the SOS Administrative Adjustment at 1.09 was arbitrary and capricious. To prevail in that regard, ESC must show that the Commission “exercised its discretion unreasonably or without a rational basis.” Maryland Office of People’s Counsel, 461 Md. at 399. We conclude, with exceptions explained below, that the Commission’s decision was not arbitrary or capricious, but rather, it was supported by substantial evidence.

Mr. Manuel provided extensive testimony regarding how he conducted the cost of service study and how he arrived at his determination that the appropriate Administrative Adjustment was 1.0 mill per kWh, an increase in the rate for that component. He noted that incremental, or direct, costs related to SOS were already allocated to SOS and included in the SOS Administrative Charge. His study identified the types of costs and cost centers *56 that support SOS. After identifying those costs, he determined an approach that he thought was reasonable for allocating a portion of those non-incremental costs to SOS. His study resulted in a charge of 0.99 mills per kWh, but he recommended a 1.00 mill per kWh Administrative Adjustment because he recognized that his study was “not surgically precise,” but it could be used “to set the Administrative Adjustment at a reasonable level for years to come.” Mr. Manuel testified that he used traditional cost-causation principles in his study.

Commission Staff testified that BGE’s analysis was reasonable, although Mr. Hoppock suggested a few additional costs that should be allocated to SOS. His proposal, after some modifications, was to increase the costs allocated for the SOS Administrative Adjustment rate, from BGE’s proposal of $12.3 million to $15.9 million.

The Commission determined that the appropriate cost allocation for the Administrative Adjustment was a “hybrid approach,” which accepted BGE’s cost of service study, with some additions proposed by Commission Staff. Accordingly, it allocated costs of $13,569,649 to SOS, which resulted in an Administrative Adjustment rate of 1.09 mills per kWh.

ESC essentially argues that the Commission was required to accept its recommendation, stating that, “[r]equiring BGE to perform a fully distributed cost allocation study is the only way for the Commission to have ensured compliance with the market price standard in the state.” (Emphasis added). Numerous witnesses, however, disagreed with this analysis. They explained why, in their opinion, the recommended analysis by ESC’s witnesses, which allocated $173.1 million in non-incremental costs to *57 SOS, was inappropriate, “nonsensical,” and “excessive on its face.” Mr. Johnson testified that ESC’s analysis was “not consistent with standard practices for electric utility cost of service studies and inappropriately assigns distribution cost categories to SOS without any clear connection between the costs and SOS service.” The Commission credited that testimony and gave as an example the unreasonably large percentage of costs allocated to SOS for administrative and general overhead and depreciation, even though the SOS business was not “labor intensive” or “capital intensive.”21

It was within the Commission’s discretion to reject the analysis set forth by ESC, determine that a fully distributed cost allocation study was not required, and conclude that BGE’s study, which reflected “more precisely” additional costs that should be allocated to SOS, was reasonable and appropriate. The Commission’s decision, adopting BGE’s cost of service study, with the addition of some costs suggested by Commission Staff was, for the most part, neither arbitrary nor capricious.

There are however, two portions of the 2019 Order that requires clarification and/or correction. First, the Commission stated on page 38 of the Order that Commission Staff “did not adequately support its allocation of costs from” FERC Accounts 909 and 930.2, and because the expenses in those accounts did not relate to SOS, those costs should be excluded. Several sentences later, however, it stated that it was accepting Commission

21 As indicated, Mr. Manuel testified that, of the 300 employees employed by BGE, it utilized only two full-time employees exclusively for SOS, along with a handful of employees on a partial basis, which resulted in a total of $70,000 of incremental costs for SOS due to labor and fringe benefits. Nevertheless, ESC allocated $60 million to SOS for non-incremental costs of administrative and general overhead.

Staff’s inclusion of FERC Accounts 909 ($468,811) and 930.2 ($260,175), and these costs were included in the total costs of $13,569,649 adopted by the Commission. If the Commission intended to exclude those costs, they should not be included in the total costs allocated to SOS, and the Administrative Adjustment would need to be recalculated.

Second, the Commission calculated the total costs to be $13,569,649. Our calculation of the total costs, using the figures listed, is $13,567,649.22

Accordingly, although we conclude, in general, that the Commission’s decision was supported by substantial evidence and was not arbitrary and capricious, we shall vacate the Commission’s decision and remand for the Commission to clarify whether FERC Accounts 909 and 930.2 should be included in the total costs, recalculate the total costs to be allocated to SOS, and recalculate the Administrative Adjustment consistent with those calculations.

JUDGMENT VACATED AND CASE REMANDED FOR FURTHER PROCEEDINGS CONSISTENT WITH THIS OPINION. COSTS TO BE DIVIDED EQUALLY BETWEEN THE PARTIES.

22 We note that the figures listed by the Commission included costs for Accounting in the amount of $14,460, but the parties had allocated $16,460 in costs for Accounting. That may explain the $2,000 difference, but the Commission can advise on remand.