NRG Energy v. Public Service Comm'n ( 2021 )

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?
2
(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:
3
(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).
4
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.
3Mills 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.
5
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
6
“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
7
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.
8
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
9
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-
10
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.
11wanted 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:
12
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.”
13
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
14
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.
15
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.
16
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
17
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
18
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
19
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
20
“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
21
“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.”
22
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.”
23
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:
24
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
25
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.”
26
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
27
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
28
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.
29
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.
30
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.
31
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:
32
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.
33
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.
34
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
35
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
36
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).
37
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.
38
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
39
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
40
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.
41
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
42
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.”
43
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.
44
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
45
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[.]”
46
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
47
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.
48
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
49
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
50
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 .
51
. . 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,
52
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.
53
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
54
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
55
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
56
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.
57
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.
58