Maryland Office of People's Counsel v. Maryland Public Service Commission

127 A.3d 582, 226 Md. App. 176, 2015 Md. App. LEXIS 169

• Court: Court of Special Appeals of Maryland
• Decided: December 15, 2015
• Docket: 2173/14
• Status: Published

Opinions

GRAEFF, J.

This case arises from an order issued by the Maryland Public Service Commission (the “Commission” or the “PSC”), one of the appellees. The order authorized Potomac Electric Power Company (“Pepeo” or the “Company”), another appel-lee, to: (1) increase its rates for the distribution of electricity by $27,883,000; and (2) impose a Grid Resiliency Charge (“GRC”) to contemporaneously recover costs associated with the Advanced Priority Feeders Project.¹

Appellants, AARP Maryland (“AARP”) and the Maryland Office of the People’s Counsel (“OPC”) filed separate petitions for judicial review in the Circuit Court for Baltimore City, challenging, inter alia, the decision on the GRC. Pepeo sought judicial review of the decision to increase its rates by $27,883,000, as opposed to the $60.8 million requested, arguing that the decision to award a return on equity (“ROE”) of 9.36%, as opposed to 10.25 %, was erroneous. On November 14, 2014, the circuit court affirmed the Commission’s decision to fund the GRC, but it reversed the Commission’s decision on the ROE and remanded for further proceedings.

On appeal, the parties present several questions for our review,² which we have combined and rephrased slightly, as follows:

1. Did the circuit court err in finding that the Commission’s decision to permit Pepeo to impose a Grid Resiliency Charge on customers was within its broad statutory authority, not arbitrary and capricious, and supported by substantial evidence?

2. Did the circuit court err in finding that the Commission did not act reasonably when setting Pepco’s ROE?

For the reasons set forth below, we shall affirm in part, and reverse in part, the judgment of the circuit court.³

FACTUAL AND PROCEDURAL BACKGROUND

Background on Public Utility Regulation

Maryland Code (2010 Repl.Vol.) §§ 2-101, 2-113 and 4-102 of the Public Utilities Article (“PU”), set forth the power of the Public Service Commission to supervise and regulate public service companies and the rates that they may charge customers.⁴ Section 2-112 states, in pertinent part, as follows:

(b) General powers. — (1) The Commission has the powers specifically conferred by law.

(2) The Commission has the implied and incidental powers needed or proper to carry out its functions under this division.

(c) Liberal construction. — The powers of the Commission shall be construed liberally.

The rate that the Commission sets, and that public utilities may charge, must be a “just and reasonable rate for the regulated services.” PU §§ 4—102(b), 4-201. A “just and reasonable rate” is defined as a rate that:

(1) does not violate any provision of [the Public Utilities] article;

(2) fully considers and is consistent with the public good; and

(3) except for rates of a common carrier, will result in an operating income to the public service company that yields, after reasonable deduction for depreciation and other necessary and proper expenses and reserves, a reasonable return on the fair value of the public service company’s property used and useful in providing service to the public.

PU § 4-101. This rate is “designed to yield to [a public utility] a ‘revenue requirement’ sufficient to pay its prudent expenses and to allow it the opportunity to earn a fair return on investments.” Office of People’s Counsel v. Maryland Pub. Serv. Comm’n, 355 Md. 1, 7-8, 733 A.2d 996 (1999).

In Maryland People’s Counsel v. Heintz, 69 Md.App. 74, 84, 516 A.2d 599 (1986), cert. denied, 309 Md. 48, 522 A.2d 393 (1987), this Court explained the traditional formula to establish rates with the following equation:

R = O + (V - D)r

where R=total revenue required; 0=operating expenses; V=value of property; D=depreciation; and r=rate of return. The property value minus depreciation yields the rate base. The public service company’s required revenue is derived after adding the operating expenses to the product of the rate of return times the rate base. Just and reasonable rates are then set from this revenue figure taking into consideration the public’s interest in receiving adequate and efficient service. Traditionally, a just and reasonable rate was that rate which produced the required revenue figure.

More recently, this Court stated that the rate that a public utility may charge is determined by

examining the utility’s income and expenses during a test year, calculating the rate base (the fair value of the property used and useful in rendering service) during that year, determining the utility’s cost of capital (its required rate of return), and then multiplying that rate of return against the rate base. The result is the amount of income to which the utility is entitled.

Bldg. Owners and Mngrs. Ass’n v. Pub. Serv. Comm’n, 93 Md.App. 741, 753, 614 A.2d 1006 (1992) (“BOMA ”). Depending on whether the net income was significantly higher or lower than the test year income, the PSC [is] empowered to make increases or decreases to rates. Id.

Severstal Sparrows Point, LLC v. Pub. Serv. Comm’n of Maryland, 194 Md.App. 601, 604, 5 A.3d 713 (2010).

The Court of Appeals similarly has explained the ratemak-ing process as follows:

“The orthodox making of public utility rates requires four basic determinations: (1) what are the enterprise’s gross utility revenues under the rate structure examined; (2) what are its operating expenses, including maintenance, depreciation and all taxes, appropriately incurred to produce those gross revenues; (3) what utility property provides the service for which rates are charged and thus represents the base (rate base) on which a return should be earned[;] and (4) what percentage figure (rate of return) should be applied to the rate base in order to establish the return to which investors in the utility enterprise are reasonably entitled.”

Office of People’s Counsel, 355 Md. at 8, 733 A.2d 996 (quoting Pub. Serv. Comm’n v. Baltimore Gas & Elec. Co., 273 Md. 357, 360 n. 2, 329 A.2d 691 (1974)).

Recent Changes in Reliability Regulations

In its order in this case, the Commission stated that, “[a]s far back as August 2010, the reliability and resiliency of Maryland’s electric distribution infrastructure has been one of the major focuses of this Commission.” In the Matter of the Application of Potomac Electric Power Company for an Increase in Its Retail Rates for the Distribution of Electric, Case No. 9311, Order No. 85724, at 159 (2013) (“Order No. 85724”). In 2011, the Maryland General Assembly passed the Maryland Electricity Service Quality and Reliability Act—Safety Violations, requiring the Commission to adopt stricter regulations regarding utility performance. HB 391 (Reg.Sess.2011) (enacting PU §§ 7-213, 13-201, 13-202). On April 17, 2012, the Commission held a rule making session, Rule Making 43 (“RM43”), and adopted revisions to the Code of Maryland Regulations (“COMAR”) that established minimum service quality and reliability standards for Maryland’s electric companies. See COMAR 20.50.12.01-12. Among other provisions, RM43 included a requirement that the electric utilities report on three reliability indexes: the Customer Average Interruption Duration Index (“CAIDI”); the System Average Interruption Duration Index (“SAIDI”); and the System Average Interruption Frequency Index (“SAIFI”).⁵ It also requires that utilities demonstrate compliance with minimum standards established by the Commission. See COMAR 20.50.12.02.

In 2012, Governor Martin O’Malley issued Executive Order 01.01.2012.15, establishing the Grid Resiliency Task Force, which was charged with evaluating methods for improving the resiliency and reliability of Maryland’s electric distribution system and assessing “what steps can be taken to strengthen Maryland’s electric distribution to better withstand the stresses that come with severe weather events.” Weathering the Storm: Report of the Grid Resiliency Task Force 6 (Sep. 24, 2012), available at http://perma.ee/LBB4-YAH6.⁶ The Task Force was created in response to “the potential impact of climate change on regional weather patterns and the prolonged power outages brought by recent hurricanes, blizzards, and the Derecho.”

On September 24, 2012, the Task Force issued its report, recommending, inter alia, that Maryland’s electric utilities “temporarily go above and beyond their requirements under RM43 in order to jumpstart the improvements and enable Marylanders to see real results in a compressed time frame” (Recommendation # 2). Recognizing that acceleration of reliability improvements would place a financial burden on utilities, the Task Force recommended that the Commission “authorize contemporaneous cost recovery through a tracker-like mechanism” to permit electric utilities to recover costs “exclusively for these accelerated and incremental investments and expenses.”⁷ The Task Force stated that “any tracker recovery mechanism must include significant oversight and approval by the PSC” and would require the utility to “project, with some degree of certainty, the costs of the various resiliency measures to be undertaken in advance of PSC approval of the plan.” This would allow “transparency surrounding the process, as well as oversight on the costs to be collected from ratepayers.”

Pepco’s Application

On November 30, 2012, Pepeo, a public service company that provides electric distribution services to approximately 530,000 customers in Montgomery and Prince George’s counties, filed an Application for Adjustments to its Retail Rates for the Distribution of Electric Energy. It stated that, “in order to maintain and enhance its infrastructure and implement cost-effective distribution technologies, Pepeo must continue to make substantial investments in infrastructure and must have a reasonable opportunity to recover its costs.”

In April 2013, pursuant to its authority under PU § 4-204, the Commission held a hearing. The hearing lasted ten days, and twelve parties participated: Pepeo, OPC, AARP, the Commission’s Technical Staff (“Staff’), Montgomery County, Town of Somerset in Chevy Chase, Mayor and Council of Rockville, City of Gaithersburg, U.S. General Services Administration (“GSA”), Maryland Energy Administration (“MEA”), POWERUPMONTCO of Montgomery County, and Apartment and Office Building Association of Metropolitan Washington (“AOBA”).

Pepeo requested a rate increase of $60,827,000, with an increase in the ROE from 9.31% to 10.25%. It sought to increase its revenue through multiple adjustments.⁸ With respect to rate base, which represents the investments the Company has made in plant and equipment to provide electric service, and operating income, which is derived from the revenues the Company receives minus the reasonable costs incurred in providing service, Pepeo proposed three separate reliability plant ratemaking adjustments (“RMA”). Specifically, Pepeo proposed “RMA1,” which “annualizes the effect of reliability projects completed in the test year”; “RMA2,” which “reflects the effect of reliability plant that was added to Electric Plant in Service (“EPIS”) from January through March 2013”; and “RMA3,” which “reflects the impact of reliability projects that are projected to be placed in service between April and December of 2013, up to twelve months after the test year.” See Order No. 85724, at 10-11.⁹

With respect to the ROE, Pepeo stated that, at the current rates, its current adjusted ROE was 4.71%, a level “far below its authorized [ROE] as set by the Commissioner.” Pepeo requested a ROE of 10.25%.

Separate from the requested adjustments to the base rates, Pepeo asked to establish a surcharge tracker, the GRC, which would “enable Pepeo to accelerate investment in infrastructure in a condensed time frame consistent with Recommendation Two of the Grid Resiliency Task Force.” The Commission summarized Pepco’s request as a $192 million surcharge, consisting of “three specific reliability projects: $17 million for Accelerated Vegetation Management; $151 million for Selective Undergrounding of six feeders;[¹⁰] and $24 million for an Accelerated Priority Feeders project to accelerate the hardening of 24 feeders over two years.” Joseph F. Janocha, Manager of Rate Economics for Pepeo Holdings, Inc. (“PHI”), testified that the GRC was “intended to be a short term mechanism ... to initially recover costs associated with a specific, limited group of projects,” and it included a final reconciliation procedure to resolve any discrepancy between the estimated revenue requirement, i.e., the amount Pepeo expected to spend on accelerated reliability/resiliency improvement projects, and the amount Pepeo actually spent improving infrastructure and installing assets. Any discrepancy would “be reflected in the reconciliation process and customers would be appropriately credited, including interest.”

Public Service Commission Order No. 85724

On July 12, 2013, the Commission issued Order No. 85724, a 166-page order addressing Pepco’s rate increase application. With respect to Pepco’s rate base and operating income, the Commission found that RMA1 and RMA2 represented additions to plants in service through March 2013, which Pepeo updated for actual spending. Therefore, it determined that those reliability projects should be reflected in the rate base, and it increased the rate base accordingly. With respect to RMA3, which it deemed to be a mere forecast of anticipated spending that was not a known and measurable adjustment, the Commission rejected this proposal.

In addressing Pepco’s proposed ROE, the Commission stated that it was guided by the principles of Bluefield Waterworks & Implement Co. v. Public Service Commission of West Virginia, 262 U.S. 679, 692, 43 S.Ct. 675, 67 L.Ed. 1176 (1923) and Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 603, 64 S.Ct. 281, 88 L.Ed. 333 (1944), which require that a return be sufficient to attract capital on reasonable terms, maintain the utility’s financial integrity, and provide an opportunity to obtain a revenue comparable to other investments carrying similar risks. Addressing the evidence before it, the Commission concluded that a ROE of 9.36% was just and reasonable.

Finally, with respect to the GRC, the Commission approved the proposal, in part. It approved only the Accelerated Priority Feeders project, subject to the conditions that Pepeo: (1) provide additional detail for each feeder to be improved; (2) submit a revised calculation of revenue requirement that excluded the two rejected projects; (3) submit a base rate case petition that coincided with the projected completion of the approved project; and (4) submit an annual report regarding the status and costs of the project.

In sum, the Commission rejected Pepco’s request for a rate increase of $60,827,000, but it authorized Pepeo to file revised rates for an increase in revenue of $27,883,000. It stated that this revenue increase would have an impact on the average residential customer’s monthly bill of 2.19% or $2.41. The Commission also approved the GRC proposal with respect to the Acceleration Priority Feeders component, subject to the conditions specified.¹¹

Proceedings in the Circuit Court for Baltimore City

After the Commission issued its order, Pepeo, Montgomery County, AARP, and OPC, filed separate petitions for judicial review, which were consolidated. In total, the parties challenged nine separate decisions of the Commission, including its decisions setting Pepco’s ROE and authorizing Pepeo to implement the GRC.¹²

On November 14, 2014, after hearing argument, the circuit court issued its Order and Memorandum Opinion. The court affirmed the Commission on eight of the issues, including the GRC. It reversed the Commission’s decision regarding the ROE, however, remanding to the Commission “to make more specific findings regarding the impact of improved service reliability and the BSA [bill stabilization adjustment] in calculating Pepco’s ROE.”

On December 15, 2014, and December 19, 2014, OPC and AARP, respectively, filed notices of appeal.

DISCUSSION

I.

Standard of Review

“We review decisions of the Commission as ‘consistent with the standard of review applicable to all administrative agencies.’ ” Columbia Gas of Maryland, Inc. v. Pub. Serv. Comm’n of Maryland, 224 Md.App. 575, 580, 121 A.3d 224 (2015) (quoting Office of People’s Counsel v. Maryland Pub. Serv. Comm’n, 355 Md. 1, 15, 733 A.2d 996 (1999)). The limited scope of judicial review of Commission decisions is set forth in PU § 3-203, 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, the order is unsupported by substantial evidence on the record considered as a whole.

This Court has explained the scope of our review as follows:

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. [738 A.2d 996] (1999). Indeed, if reasoning minds could reasonably reach the Commission’s decision from the facts in the record, then the decision is based upon substantial evidence, and we will not reject that conclusion. Liberty Nursing Center, Inc. v. Department of Health and Mental Hygiene, 330 Md. 433, 442-43 [624 A.2d 941] (1993).

Finally, in reviewing a decision of an agency, our role “is precisely the same as that of the circuit court.” Department of Health & Mental Hygiene v. Shrieves, 100 Md.App. 283, 303-04 [641 A.2d 899] (1994). Consequently, we “do not evaluate the findings of fact and conclusions of law made by the circuit court.” Consumer Protection Division v. Luskin’s, Inc., 120 Md.App. 1, 22 [706 A.2d 102] (1998), rev’d in part on other grounds, 353 Md. 335 [726 A.2d 702] (1999). This Court is not concerned with whether the circuit court applied the correct standard of review so long as we are satisfied that the agency decision is proper. Giant Food, Inc. v. Department of Labor, Licensing and Regulation, 124 Md.App. 357, 363 [722 A.2d 398] (1999), rev’d on other grounds, 356 Md. 180 [738 A.2d 856] (1999).

Mid-Atl. Power Supply Ass’n v. Maryland Pub. Serv. Comm’n, 143 Md.App. 419, 432, 795 A.2d 160 (2002) (parallel citations omitted). Accord Severstal Sparrows Point, 194 Md.App. at 610, 5 A.3d 713.

II.

Grid Resiliency Charge

Appellants contend that the Commission erred in authorizing Pepeo to impose the GRC. In support, both OPC and AARP argue that the Commission exceeded its statutory authority to approve the GRC because it was not a “just and reasonable rate.” OPC additionally argues that the Commission “acted arbitrarily and capriciously when it abandoned the ‘known and measurable’ standard for reliability projects and adopted the ‘accelerated and incremental’ standard.” And AARP argues that the Commission’s decision to approve the GRC was not reasonable because there was not substantial evidence that Pepeo would have suffered financial strain without the GRC surcharge.

Pepeo contends that appellants’ argument that the Commission lacked the statutory authority to approve the GRC is not properly before this Court because it was not raised before the Commission. In any event, Pepeo asserts, the Commission had the statutory authority to approve the GRC “pursuant to its plenary rate-making authority under PU § 4-101.” Pepeo further disputes OPC’s argument that the decision to approve the GRC was arbitrary and capricious, asserting that the Commission provided a reasoned analysis for its approval of the GRC. With respect to AARP’s argument that the approval of the GRC was not supported by substantial evidence of financial strain, Pepeo asserts that such a finding was not required.

The Commission contends that it had authority to authorize the GRC under its “broad powers” pursuant to PU § 2-112(b)(2). It further argues that its decision was not arbitrary and capricious, asserting that it provided several valid reasons for approving the GRC. With respect to AARP’s argument that “the Commission acted arbitrarily and capriciously because ‘there was no substantial evidence presented showing that Pepeo would encounter any financial strain ... without the benefit of the GRC,” the Commission asserts that AARP is applying the wrong test. It argues that the proper test is “just and reasonable,” not a showing of financial strain.

A.

Proceedings Below

In support of its GRC proposal, Pepeo submitted the testimony of three company witnesses: Frederick J. Boyle, Senior Vice President and Chief Financial Officer of PHI, William M. Gausman, Senior Vice President of Strategic Initiatives for PHI, and Mr. Janocha, Manager of Rate Economics for PHI. Mr. Boyle explained that Pepco’s rate increase application included accelerated service reliability programs that addressed recommendations set forth by the Grid Resiliency Task Force. He testified that Pepeo would not accelerate these proposed projects without the GRC:

These accelerated expenditures are incremental to the Company’s base capital and operating cost plans. Absent the Grid Resiliency Charge, the Company, while meeting its current reliability standards, will not perform these projects in this time frame. As the Task Force acknowledged, taking on this added level of investment will impose “undue financial pressure on the utilities,” and therefore the Task Force recommended that the Commission authorize contemporaneous cost recovery through a tracker-like mechanism for the accelerated investments.”

After discussing in more detail each of the three proposed accelerated reliability projects, Mr. Boyle noted that “the proposed Grid Resiliency Charge will appear as a separate line item on customers’ bills.... If the charges are approved, the monthly bill impact for a residential customer using 1,000 kWh per month would be $0.96 in 2014; $1.70 in 2015 and $1.93 in 2016.”

Mr. Boyle explained that the GRC “in no way affects the Commission’s ability or authority to conduct a prudence review of Grid Resiliency Charge investments and expenses, and — as with any other investment or expense — ultimately determine to exclude or reduce recovery for any item that the Commission deems imprudent.” He also discussed Pepco’s proposed “true-up” process, which would result “in customers[] paying for the actual amount of the project based on when the asset was actually placed into service.”¹³

On cross-examination, Mr. Boyle explained that, although Pepco’s GRC proposal indicated the company’s intent to keep the GRC in effect for three years, Pepeo would nonetheless continue to collect the GRC until Pepeo brought its next rate case. Mr. Boyle conceded that Pepeo had not yet committed to a specific date on which the company would initiate another rate ease.

Mr. Gausman’s direct testimony was similar to Mr. Boyle’s testimony. Most notably, Mr. Gausman testified that, without the GRC tracker, the company would not perform the proposed projects on an accelerated schedule:

Performing these projects on the accelerated schedule is not included in the Company’s scope of work to meet its SAIFI and SAIDI performance requirements under the Service Quality and Reliability Standards. The company is prepared to perform these projects to address the acceleration recommended in the Task Force Report. However, as discussed by Company Witness Boyle and as discussed further, the Company cannot take on the additional investment on top of the significant financial commitment that has already been made. Additional investments to further accelerate the reliability standards can only be made with approval of the Grid Resiliency Charge.

Mr. Janocha testified that the GRC, “Pepco’s proposed tracker mechanism,” was based on recommendations of the Task Force report. He explained:

The company is proposing a recovery mechanism associated only with incremental accelerated investments and expenses associated with the reliability projects discussed by Company Witness Gausman. The Grid Resiliency Charge will be incorporated into the tariff through a new tariff rider, which is provided as Schedule (JFJ)-6. The Grid Resiliency Charge would be in effect for approximately three years beginning in January 2014.

Mr. Janocha also described how the GRC was calculated:

The revenue requirement and resulting charge included in the Grid Resiliency Charge Rider are calculated using projected cost data including, but not limited to: the actual costs of engineering, design and construction; the cost of removal (net of salvage) and property acquisition; and actual labor, materials, and capitalized Allowance for Funds Used During Construction (AFUDC). The Company will track the capital investments individually for each project through a separate work order in a Construction Work in Progress (CWIP) account and record a monthly accrual of AFUDC which will be included in the CWIP balance.

The revenue requirement includes a return on investment and return of investment through depreciation based on the capital costs. The revenue requirement also includes a provision for the recovery of accelerated tree trimming expenses, which the Company proposes to amortize over two years beginning in January 2014.

Mr. Janocha noted that the GRC would be subject to deferred accounting. Pepeo would track the differences between actual and forecasted expenditures through a “monthly over/under recovery calculation.” “The deferred balance would be reconciled upon termination of the Grid Resiliency Charge.” Pepeo proposed to file an “annual report showing the status of each project, tasks completed, percentage of projects completed, and actual expenditures to date.” Mr. Janocha then discussed how the GRC rates would be developed for each of Pepco’s tariff rate schedules. As with Pepco’s other witnesses, Mr. Janocha stated that the GRC charge would terminate when it filed its next rate case after all the GRC projects are “placed into service.”

In his rebuttal testimony, Mr. Janocha responded to concerns regarding the use of projected costs, as well as the argument that the Commission had rejected similarly structured surcharges:

The nature of the costs being recovered through the Grid Resiliency Charge and the mechanism developed for cost recovery have features that distinguish it from either a forecasted test year or the previously presented surcharge mechanisms. First, the Grid Resiliency Charge is intended to be a short term mechanism intended to initially recover costs associated with a specific, limited group of projects presented in this proceeding. Ultimately, the long term recovery of the capital investment would be through base distribution rates. By contract, the Reliability Investment Recovery Mechanism proposed by the Company in Case No. 9286 was designed as a more long term mechanism, intended as an initial recovery mechanism for a wide range of reliability investments.

Second, the nature of the projects included for recovery through the Grid Resiliency Charge are such that electric plant is placed in service on essentially a continuous basis from the outset of each project. The Grid Resiliency Charge accounts for this by calculating an annual revenue requirement using an average rate base. Consequently, on an annual basis, customers are effectively paying for infrastructure as it is being placed into service.

Mr. Janocha reiterated that customers would pay only for investments actually put into service:

[T]he proposed deferred accounting mechanism provides a level of customer protection through which customers will ultimately have paid only for approved electric plant that is placed in service. The Grid Resiliency Charge mechanism includes a final reconciliation of the forecasted revenue requirement to the actual revenue requirement associated with electric plant actually placed into service. Additionally, all investment associated with the Grid Resiliency Charge will be subject to review in a future base distribution case. Any costs that may be disallowed will be reflected in the reconciliation process and customers would be appropriately credited, including interest.

In opposition to Pepco’s GRC proposal, OPC submitted testimony from two witnesses: David E. Dismukes, Consulting Economist with the Acadian Consulting Group, and Peter J. Lanzalotta, Principal with Lanzalotta & Associates LLC. Mr. Dismukes recommended that the Commission reject the Company’s GRC proposal, asserting that it was “premature, inconsistent with the recommendations included in the Governor’s Resiliency Task Force Report, includes a number of inherent mechanism design flaws, and is inconsistent with prior Commission precedent on infrastructure trackers.” With respect to his prematurity argument, Mr. Dismukes stated that, there were “a number of prerequisite investigations that must be completed before a true resiliency-based set of standards can be established for Maryland.”

With respect to his assertion that the GRC proposal had “inherent mechanism design flaws,” Mr. Dismukes stated that the proposed GRC contained a number of “administrative deficiencies,” including the following:

1) The “defined term” of the program is ambiguous.

2) The GRC revenue requirement will be developed on a projected rather than actual basis.

3) The Company does not explain how or when the prudence of its investments will be evaluated.

4) The Company’s proposed annual reporting process is insufficient.

5) The GRC proposal does not include any ratepayer protections. Further, “coupling” the BSA with the proposed GRC could create capital inefficiencies and lead to a string of ever-increasing surcharges (for both BSA-allowed revenue losses and GRC-allowed capital investments).

6) The GRC has no sunset provisions.

Mr. Dismukes asserted that the GRC proposal was inconsistent with prior Commission precedent, stating that the Commission had addressed several similar infrastructure cost recovery mechanisms, and it had rejected each one. He stated:

The consistent theme in each of these rejections has included the Commission’s belief that its current regulatory structure is adequate in addressing reliability investment needs, and the position that the practical implementation of investment cost trackers, projected rate base, or forward test years can likely result in greater inefficiencies, disincentives, and harm than the problems these proposals are purportedly designed to correct. The Commission should defer any decision on issues like the GRC, and how to incorporate the accelerated and incremental resiliency and reliability investments proposed by the Task Force, until a comprehensive investigations of these opportunities, has been conducted.

At the hearing before the Commission, Mr. Dismukes agreed that the Commission was not precluded by precedent from approving the GRC. He stated, contrary to OPC’s position on appeal that the Commission lacked statutory authority to approve the GRC, that the “Commission can do whatever it wants in the public interest.”

Mr. Lanzalotta similarly recommended that the Commission reject all three of Pepco’s proposed GRC projects, asserting that Pepeo had “not demonstrated that such work [would] successfully improve reliability during major outage events.” He discussed specific reasons why various aspects of the GRC proposal failed to ensure reliability improvements.

AARP submitted testimony from one witness, Ralph C. Smith, Senior Regulatory Utility Consultant with Larkin & Associates, PLLC, in opposition to Pepco’s GRC proposal. Mr. Smith asserted that “Pepeo has merely stated that it cannot undertake additional reliability projects without its new proposed surcharge. However, Pepeo has not proven this.” Mr. Smith recommended that the Commission reject Pepco’s GRC proposal, stating that his position was “primarily based on an opposition to piecemeal ratemaking, surcharges and riders that seek recovery of costs outside of traditional base rates, a concern that has been shared by this Commission as reflected in its decisions on such proposals in the past.” He further stated that he had “additional concerns regarding the specific details of Pepco’s proposed [GRC].” Noting that a “utility is obligated to provide reasonable service and to invest in the maintenance and reliability of its distribution system as a normal duty.” Mr. Smith stated that Pepeo had

failed to document adequate reasons why a specific rider is needed to continue or expand its program of investments and tree trimming expenditures that is needed to deliver adequate and reasonable reliability of electric distribution service. Nor has the Company presented adequate cost-benefit analysis to justify its proposed additional charges to ratepayers for this surcharge. Relying on a surcharge for recovery of costs also unbalances the traditional regulatory process and rewards the Company by allowing rate recovery and financing costs for selected expenditures made between rate cases, and without the balanced review of all elements of the utilities revenue requirement that would occur in a rate case.

Mr. Smith further asserted:

Pepeo has a line of credit to $350 million (for which Maryland ratepayers are being charged) and that existing credit line supports Pepco’s access to low-cost temporary financing sources, such as commercial paper, that have a cost rate far below some of the long-term capital source such as Pepco’s shareholder equity. The existence of Pepco’s short-term borrowing sources and the lower finance costs associated with such sources should be considered in addressing whether and how Pepeo could finance authorized Grid Resiliency expenditures between rate cases, and also for determining the financing cost rate that should be applied if a new surcharge were to be authorized in the current case,

(footnote omitted).

After considering all the evidence presented regarding Pep-co’s GRC proposal, the Commission rendered its decision. The Commission began by explaining the “backdrop” for its decision, as well as its general view on accelerated reliability work:

As far back as August 2010, the reliability and resiliency of Maryland’s electric distribution infrastructure has been one of the major focuses of this Commission. Since then we have departed from our traditional ratemaking principles by allowing end-of-test year reliability plant and three month post-test year reliability spending adjustments in rate cases. In several of the rate cases since then we have been asked to approve a concurrent surcharge for proposed reliability projects, but to date we have found those proposals lacking. Last year, following the power outages throughout the State caused by the Derecho storm, the [Task Force] appointed by the Governor recommended that such reliability spending surcharges may be appropriate. It is with this backdrop that we consider in this case Pepco’s proposed Grid Resiliency Charge.

The Company has identified specific infrastructure improvements that would produce accelerated and incremental reliability benefits. These projects, by virtue of their incremental benefits, are designed to exceed the scope of the utility’s plan to realize their RM43 annual performance standards. We find that a properly defined tracker proposal, when aligned with specific and measurable milestones and expenditures, can be appropriate to support the projects that are required to address the immediate challenges to improving reliability in Maryland. Although the proposals for trackers presented to us to date have been lacking in certain areas, the need for accelerated reliability work coupled with an aligned cost recovery mechanism is in our view justified, and indeed beneficial to ratepayers, under certain circumstances.

The [Task Force] Report stated that accelerated reliability cost recovery would be “exclusively for accelerated and incremental investments and expenses.” Hence, a paramount question for us in deciding whether to grant the Company’s GRC Proposal is whether, on this current record, we find that the proposed projects are accelerated and incremental to what is required to meet the current minimum reliability standards. And if so, the next question is whether the level of increased reliability and resiliency gained warrant a departure from Commission precedent.

The Commission then addressed Pepco’s GRC proposal. With respect to the Advanced Priority Feeders, the only proposal at issue here, the Commission stated as follows:

Company Witness Gausman stated that the priority feeders chosen under the GRC Proposal include “outage data without exclusions for major events.” (emphasis added). Currently, the Company takes corrective action on the poorest performing 3% of feeders, identified by a methodology that excludes major storm events. We find that the remediation to the priority feeders will provide cost effective incremental reliability benefits to the end users associated with feeders particularly prone to outages due to major storm events. The fact that this Accelerated Priority Feeders project includes 24 feeders in addition to the 55 feeders already in the 2013 base construction plan satisfies the acceleration component of the GRC.

Accordingly, the Commission approved Pepco’s GRC proposal with respect to the Advanced Priority Feeders component, subject to the following conditions:

First, because this is a new tool we are considering undertaking for accelerated reliability work, we are obligated to the State and to the ratepayers to closely monitor the success and effectiveness of such a mechanism. To accomplish this, a tracker proposal must specifically identify a list of qualifying projects, a timeline, and interim milestones. The project descriptions must contain sufficient detail so as to track progress and related costs, and a commitment that any deviation from the project list requires further Commission approval. We recognize that the Company has supplied this information to some degree for the GRC. In this case, however, we direct the Company to provide additional detail for each feeder that includes the following: (1) a description of the proposed hardening work; (2) a performance objective for each project; (3) incremental milestones and estimated costs for each feeder project; and (4) estimated total costs.

Second, we also recognize that Company Witness Janocha laid the foundation for a detailed cost recovery mechanism and rate design in his discussion of a new tariff rider. We approve this methodology for calculating the revenue requirement and resulting charge under the GRC Rider. However, since we do not approve either the Vegetation Management or Selective Undergrounding components of the Company’s GRC proposal at this time, we direct the Company to submit a revised calculation of revenue requirement to set the initial rates specific to the approved list of qualifying feeder projects as described by Witness Janocha. We note that the GRC cost recovery in 2014 attributed to priority feeders is estimated to be $0.06 per month for a typical residential customer. Given that the GRC would be limited in scope to the Accelerated Priority Feeders project, we decline to adopt the Company’s proposed incentive structure.

Third, we share the concerns and criticism by several of the other parties with respect to the lack of a sunset date and certain other consumer protection measures in the GRC proposal design. To this end, we direct the Company to submit a base rate case petition that aligns with the projected completion date of the qualifying projects, and stipulate that the qualifying projects and GRC revenues are subject to full review in the next base rate case following the completion of these projects. At that time, if the net capitalized amount of the qualifying projects is deemed reasonable and prudent, such costs will be rolled into the rate base resulting in termination of the GRC mechanism.

Lastly, we agree with concerns raised by several parties to the case that the Company’s proposal in its current form does not contain assurances that expenditures will be just and reasonable. To this end, we direct the Company to provide an annual report to the Commission and Staff which includes: (1) the status of each project and respective milestones completed; (2) actual money spent to date on each project and respective milestone; (3) the reconciliation of projected costs and recoveries that includes a true-up calculation of over- and underrecoveries; and (4) a proposed rate for the GRC for the subsequent year, including bill impact estimates. Following the annual report submission, the Commission will issue an order to establish the Company’s proposed new annual GRC adjustment for the following year.

The Commission then discussed why it denied the Accelerated Vegetation Management component of the GRC, as well as the Selective Undergrounding project. It then concluded by stating that it “conditionally approve[d] [Pepco’s] GRC proposal, limited in scope to its Advanced Priority Feeders component.” Order No. 85724, at 159-64.

On appeal, the circuit court affirmed the Commission’s decision to allow the GRC, concluding that PU § 2—112(b)(2) grants the Commission “implied and incidental powers needed or proper to carry out its functions” and PU § 2-112(c) states that “the powers of the Commission shall be construed liberally.” The court stated that the Commission “carefully considered Pepco’s GRC proposal and based its decision on the testimony of the various witnesses,” it “provided a reasoned explanation of partially granting Pepco’s GRC request, and explained why it was willing to impose this surcharge, which it had previously declined to do in prior rate cases.”

B.

Statutory Authority to Approve the GRC

OPC and AARP argue that the Commission did not have statutory authority to approve the GRC. In particular, they assert that, pursuant to PU § 4-101, the Commission is authorized to approve rates only if they are “just and reasonable,” and one requirement of just and reasonable rates is that the rate will result in an operating income that yields “a reasonable return on the fair value of the public service company’s property used and useful in providing service to the public.” PU § 4-101(3). They assert that the Commission exceeded its statutory authority when it authorized cost recovery through the GRC because it authorized collection of a return on property before it was in service, and therefore, before it was “used and useful” in providing service to the public.

Pepeo contends that this argument is not properly before this Court because appellants did not raise it before the Commission. In support, Pepco cites Brodie v. Motor Vehicle Administration of Maryland, 367 Md. 1, 785 A.2d 747 (2001), for the proposition that “a reviewing court will not consider a statutory interpretation argument unless [it] was presented to the agency.”

AARP does not dispute that it did not raise the issue of the Commission’s authority to approve the GRC, but it asserts that this Court can address the issue nevertheless.¹⁴ In support, it cites Md. Rule 8-131(a), asserting that “issues about the jurisdiction of the trial court over the subject matter may be 'raised in and decided by the appellate court whether or not raised in and decided by the trial court.’ ”

We agree with Pepeo that the issue whether the Commission exceeded its statutory authority in approving the GRC is not properly before this Court. In Brodie, 367 Md. at 2, 785 A.2d 747, the Court of Appeals was presented with a single question: “[W]hether the MVA was authorized to revoke a driver’s license that already had been revoked.” Id. The Court concluded that it was unable to address the question because that issue was raised for the first time in the circuit court. Id. at 3-4, 785 A.2d 747. The Court noted the general rule that, in an action for judicial review of an adjudicatory decision by an administrative agency, a reviewing court ordinarily

“may not pass upon issues presented to it for the first time on judicial review and that are not encompassed in the final decision of the administrative agency. Stated differently, a ... court will review an adjudicatory agency decision solely on the grounds relied upon by the agency.”

Id. at 4, 785 A.2d 747 (quoting Dep’t of Health v. Campbell, 364 Md. 108, 123, 771 A.2d 1051 (2001)). The Court concluded:

Since Brodie’s entire challenge to the administrative decision was based on an issue not raised before the agency, the Circuit Court should have affirmed the administrative decision without reaching the issue. Dept. of Health v. Campbell, supra, 364 Md. at 123-124, 771 A.2d at 1060 (“Because the issue ... [was] presented to the Circuit Court for the first time and never raised ... [before] the Administrative Law Judges, that court erred in” ruling upon the issue). Likewise, we shall uphold the decisions below without reaching the only issue presented to us.

Id. Accord Pub. Serv. Comm’n of Maryland v. Panda-Bran-dywine, L.P., 375 Md. 185, 204, 825 A.2d 462 (2003) (An issue that was not raised before the Commission or encompassed in the final decision of the agency should not be addressed by the appellate court on judicial review of that decision.).

In the present case, the record reflects that appellants did not argue before the Commission that the Commission did not have the statutory authority to impose the GRC. Indeed, as indicated, Mr. Dismukes, OPC’s witness, stated that, with respect to the GRC, the Commission could “do whatever it wants in the public interest.” Because the parties did not raise before the Commission the argument they raise on appeal, i.e., that the Commission did not have the statutory authority to approve the GRC, we will not address the argument.

We do not agree with AARP that this issue involves a question of jurisdiction that can be raised at any time. The Commission’s subject matter jurisdiction to consider electric utility rate adjustments is not being challenged, but rather, the challenge is whether the statutory scheme permitted the Commission to approve the GRC, a “tracker” surcharge. In Brodie, 367 Md. at 3-4, 785 A.2d 747, the Court of Appeals held that a challenge to the statutory authority of an administrative agency to take a certain action would not be reviewed by the appellate court if that argument was not made to the administrative agency. That holding compels our conclusion here.

We turn, therefore, to the issues that are preserved for this Court’s review.

C.

Arbitrary and Capricious

OPC argues that “the Commission acted arbitrarily and capriciously” in affirming the GRC. It asserts that, “without any valid reason, [the Commission] contradicted three years of its own previous decisions imposing a ‘known and measurable’ standard” on future test-year expenditures.¹⁵ It contends that the Commission ignored traditional utility rate-making principles, and instead, it “adopted an ‘accelerated and incremental’ standard for the GRC.”

The Commission has broad powers under the Public Utilities Article to regulate utility rates. See PU §§ 2-112, 2-113, 4-102. As this Court has explained, the “only statutory imperative is to construct and approve just and reasonable rates ... which, among other things, fully consider and are consistent with the public good.” Bldg. Owners & Managers Ass’n of Metro. Baltimore, Inc. v. Pub. Serv. Comm’n of Maryland, 93 Md.App. 741, 762, 614 A.2d 1006 (1992) (citation and quotations omitted).

As appellees note, the terms “known and measurable” are not included in the statute. OPC, therefore, does not allege in this argument that the Commission did not have authority to approve the GRC in the absence of costs that are known and measurable. Rather, OPC claims that the “known and measurable” standard is what the Commission has used for reliability projects, in this case with the RMA3 and in previous cases, and the Commission’s failure to do so in approving the GRC renders its decision arbitrary and capricious.

OPC acknowledges that the Commission may have some discretion to determine if a rate is “just and reasonable.” It argues, however, that the Commission does not have discretion “to arbitrarily adopt standards which appear to be irrational, inconsistent with previous agency decisions and enunciated policies adopted in prior cases regarding matters within its discretion, and without any adequate explanation for the inconsistency.”¹⁶

The Commission acknowledges that it previously has stated “that costs based only upon estimates are not known and measurable,” and it has denied recovery for such costs. Both the Commission and Pepeo, however, assert that the decision to approve the GRC in this, case was not arbitrary because the proposal was different from those other cases, and there were circumstances justifying the different result here. The Commission states that the proposal here was based on more specific, verifiable estimates of costs through prior proposals. Moreover, Pepeo notes that, unlike other proposals, the Commission approved the GRC only after imposing conditions, which included detailed reporting by Pepeo and a sunset, at which time the Commission would make a determination “whether the expenditures were prudent.” Moreover, both the Commission and Pepeo assert that the Commission gave a reasoned analysis why it approved the surcharge.

As OPC notes, in Harvey v. Marshall, 389 Md. 243, 302-03, 884 A.2d 1171 (2005), the Court of Appeals stated that an agency action may be “ ‘arbitrary or capricious’ if it is irrationally inconsistent with previous agency decisions.” Here, for the reasons set forth below, we conclude that the decision to approve the GRC was not arbitrary and capricious.

The parties agree that, in recent years, the Commission has rejected requests for surcharges, and it typically has denied recovery for estimated costs that are not “known and measurable.” That does not, however, render the Commission’s decision in this case arbitrary, for a couple of reasons.

First, the Commission’s prior decisions were based on the specific facts of those cases, not a hard-and-fast rule that surcharges based on estimated expenses could never be approved. See, e.g., In re Delmarva Power & Light Co., 100 Md.P.S.C. 435, 443 (Dec. 30, 2009) (Case No. 9192, Order No. 83085) (“[A]s a general rule ” the Commission is “reluctant to deviate from the costs and revenues incurred in a test year,” but a “possible exception to the test year principle is reliability plant investment,” which would depend on “the nature of the improvements and the revenue they generate.”) (emphasis added); In re Delmarva Power & Light Co., 102 Md.P.S.C. 236, 241 (Jul. 8, 2011) (Case No. 9249, Order No. 84170) (“[N]ew and different circumstances might persuade [the Commission] to deviate from the principles that have driven our recent decisions not to allow infrastructure surcharges.”).

Second, a change in circumstances occurred. In 2012, the Derecho and Superstorm Sandy, and the power outages that ensued, revealed weaknesses in the electric grid infrastructure and the need to make accelerated repairs to achieve a more reliable system.¹⁷ One of the recommendations issued by the Task Force was to “allow a tracker cost recovery mechanism for accelerated and incremental investments.” To improve resiliency, the Task Force recommended:

Allowing utilities to recover costs through a tracker-like mechanism for the accelerated and incremental investment. Given that these investments would be above and beyond what is contemplated by the enhanced RM43 regulations, the Task Force believes that it would be appropriate to provide more contemporaneous cost recovery for these additional expenses. The tracker mechanism would not apply to the normal investment required to meet the enhanced RM43 regulations.

The Commission made clear that this was the context in which its decision was made. It clearly explained its rationale for approving the GRC in this case, when it had denied requests for a surcharge in the past. It stated that, “although the proposals for trackers presented to us to date have been lacking in certain areas, the need for accelerated reliability work coupled with an aligned cost recovery mechanism is in our view justified, and indeed beneficial to ratepayers, under certain circumstances.” The Commission noted that the GRC involved “specific infrastructure improvements that would produce acceleration and reliability benefits,” which were designed to exceed Pepco’s annual performance standards. It further found that “the remediation to the priority feeders will provide cost effective incremental reliability benefits to the end users associated with feeders particularly prone to outages due to major storm events.” Accordingly, it approved Pepco’s GRC proposal with respect to the Advanced Priority Feeders component, subject to conditions, set forth supra, that allowed the Commission to monitor the effectiveness of the GRC, including an annual report providing a reconciliation of projected costs and recoveries.

Thus, the Commission explained the reason why it departed from its prior practice of denying recovery of estimated costs that were not “known and measurable.” In light of the circumstances, including “the need for accelerated reliability work,” as well as the mechanism to monitor the cost-effectiveness of the tracker, we agree with the circuit court that the Commission did not act arbitrarily and capriciously in approving the GRC.

D.

Substantial Evidence

AARP’s next argument stems from the statement by the Commission that it was granting “a limited rate increase and the partial GRC due to the financial strain of Pepco’s increased reliability spending, and only while demanding specific and measurable improvements in Pepco’s reliability performance exceeding those set forth in our present COMAR standards.” (Emphasis added.). It asserts that there was “no substantial evidence in the record to suggest Pepeo would have suffered any financial strain by making the $24 million of improvements in its feeder project without the imposition of the GRC surcharge.”

Pepeo and the Commission argue that AARP’s focus on financial strain is misplaced. Pepeo asserts that “[n]o statute, regulation or Commission precedent requires the Commission to make a finding that a company would suffer undue financial pressure by undertaking a project on an accelerated basis without contemporaneous recovery through a tracker.” Rather, Pepeo contends, “under its plenary ratemaking authority, the Commission has the discretion to consider all relevant factors in determining whether to approve the GRC as a just and reasonable rate.” Similarly, the Commission argues that the “test for whether the Commission can impose the GRC surcharge is not whether Pepeo can demonstrate financial strain if it is compelled to complete the $24 million without cost recovery but whether the GRC surcharge meet[s] the definition of a just and reasonable rate under PU[ ] § 4-101.”

We agree with appellees. To be sure, this Court has said that the traditional formula for ratemaking “ensures that the utility can ‘make ends meet.’ ” Heintz, 69 Md.App. at 87, 516 A.2d 599. The required analysis, however, is whether approved rates are “just and reasonable.” Where, as here, the issue is whether a company should be permitted a surcharge to provide $24 million in reliability improvements that go above and beyond the legal requirements, the question is whether the requested surcharge is “just and reasonable,” not whether the company has the ability to borrow the money to make these voluntary improvements.

Under the circumstances here, the Commission found that, with the appropriate monitoring and regulatory mechanisms in place, it was just and reasonable to compensate Pepeo for the financial burden of accelerating reliability projects in accordance with the recommendations in the Task Force report. There was substantial evidence in the record to find that the GRC was a just and reasonable charge. The circuit court properly rejected appellants’ contention to the contrary.

III.

Return on Equity

OPC’s next argument involves the Commission’s determination granting Pepeo a ROE of 9.36%. It asserts that the Commission’s determination regarding the ROE was supported by substantial evidence, and therefore, “the circuit court’s decision should be reversed.”

Pepeo argues that the “circuit court correctly ruled that the Commission’s ROE award was arbitrary and capricious and not supported by substantial evidence.” It asserts that, although “[t]he Commission framed the question presented to be whether anything had changed since the 2011 Rate Case, it then proceeded to ignore undisputed record evidence of what had changed in awarding a 9.36% ROE.”

A.

As indicated, Pepeo requested a ROE of 10.25%. This was an increase from the 9.31% ROE that the Commission awarded in a Rate Case filed in 2011. See In re Potomac Electric Power Co., 103 Md.P.S.C. 293 (Jul. 20, 2012) (Case No. 9286, Order No. 85028). Robert B. Hevert, Managing Partner of Sussex Economic Advisor, LLC, summarized his analysis regarding his 10.25% ROE recommendation, stating that he began with a review of the Commission’s Order No. 85028 in the 2011 Rate Case. He explained that, in “keeping with the Commission’s preference for the use of multiple analytical methods, [he] relied on three widely-accepted approaches: the Constant Growth Discounted Cash Flow (DCF) model; two forms of the Capital Asset Pricing Model (CAPM); and the Bond Yield Plus Risk Premium approach.” He stated that his “recommendations and conclusions consider the Company’s relatively small size and the extent to which the [BSA] mechanism may have a measurable effect on Pepco’s Cost of Equity,” and that he “calculated the costs of issuing common stock, and reflected those flotation costs in [his] estimate of the Company’s Cost of Equity.”¹⁸

Mr. Hevert noted that the Commission had adjusted Pepco’s ROE 50 basis points in the 2011 Rate Case as a result of the BSA. He argued that there should be no such adjustment in this case in light of subsequent orders by the Commission that diluted the rate-stabilizing effect of the BSA. Mr. Hevert stated that, “[i]n the vast majority of cases, utility commissions have not made explicit adjustments to the authorized ROEs in response to the implementation of decoupling mechanisms,” and therefore, he did not believe an adjustment of 50 basis points to Pepco’s ROE was appropriate. He stated that a “downward adjustment of 10 basis points to, at most 25 basis points may be supported.”

Subsequently, one Commissioner asked: “[W]hat is the justification that indicates returns should increase really just kind of four months after we set a return of 9.31 percent ... what market indicators have revised so drastically” to support Pepco’s proposed increase? Mr. Hevert stated that he relied on a case giving another utility a 9.81% ROE, and then, “because there was the 50 basis point adjustment for the BSA, that would put us at 10.31 percent.”

Commission Brenner later questioned Mr. Hevert about what had changed since Pepco’s last rate case, in which the Commission set the ROE at 9.31%. Mr. Hevert acknowledged that interest rates were about the same, and the level of market volatility was “about the same as it was before.” He continued:

So I agree with you that the capital markets are not materially different than they were when the order came out. Certainly the data is different, certainly composition of some of the proxy groups are different____So when I put all those things together, I do think that the required return still would be in that range beginning with 10.25 percent.

Charles King, President Emeritus at Snavely King Majoros & Associates, Inc., testified on behalf of OPC regarding the appropriate ROE. Mr. King explained that, under the current statutory and common law scheme,

there are essentially three standards for determining an appropriate return on equity from the standpoint of the equity owners of a regulated utility. The first is the “comparable earnings” standard, i.e., that the earnings must be “commensurate with the returns on investments in other enterprises having corresponding risks.” The second is that earnings must be sufficient to assure “confidence in the financial integrity of the enterprise,” and the third is that they must allow the utility to attract capital.

Using a “classic DCF (Discounted Cash Flow) procedure,” Mr. King evaluated a selection of comparison utility companies and calculated a mean and median ROE of 9.61% and 9.34% respectively. With respect to the BSA, Mr. King agreed that the 50-basis point adjustment “might be too high,” noting that the risk-reducing effect of the BSA had been eroded by the Commission’s decision “not to incorporate the effects of major storms into that tracker. Without the assurance that the revenue lost from service interruptions resulting from major weather events, the BSA loses a portion of its risk-reducing potential.” Mr. King ultimately recommended a ROE of 9.1% if the GRC was not approved and a ROE between 8.19 and 8.85% if the GRC was approved.

The Commission’s Staff presented testimony from Dr. Ozlen D. Luznar, Regulatory Economist in the Commission’s Division of Electricity, who recommended that a ROE for Pepeo “be set at 9.36% ... to earn a just and reasonable return to provide reliable service to its customers.” With respect to the BSA, Dr. Luznar stated that, although the Commission in the past had approved a “50 basis [point] adjustment to the final ROE due to the risk mitigating effects of the BSA,” it recently had noted “the risk mitigating limitations of the BSA in the current regulatory environment.” Accordingly, Dr. Luznar did not make an adjustment for the BSA in arriving at his recommended ROE of 9.36%.

The Commission, in making its decision regarding the ROE, noted that it had issued a decision addressing Pepco’s application for a rate increase approximately four months prior to the application at issue here. In that case, it “found Pepco’s request for a 10.75% ROE ‘excessive and totally unjustified,’ ” noting “that Pepeo faced minimal risk because of its status as a monopoly provider of electric distribution service, its lack of ownership of any generating facilities, and its stable service territory.” It further “found that the low interest rate environment that existed at the time of the Order provided Pepeo with ample opportunity to attract necessary capital at reasonable rates.” After considering the economic factors Pepeo faced at the time, the Company’s need for capital, and its poor service reliability performance at the time, the Commission granted Pepco, in Case No. 9286, a ROE of 9.31%.

The Commission turned to the present case. It stated:

The obvious question in this case, therefore, regarding Pepco’s request for a 10.25% ROE is, what has changed in less than one year since we last established a just and reasonable ROE, that now might justify a higher return?

Pepeo has not demonstrated any significant changes in the economic environment faced by the Company. It is still a monopolistic provider of electric distribution service that operates in a stable service territory. Its customer base is heavily residential, which alleviates the risk of large scale closures or relocations faced by utilities operating in heavily dense commercial or industrial service territories. It does not own generation, which reduces the danger of market price fluctuations and environmental compliance issues faced by generation owners. Moreover, while the Company has taken certain actions to improve its reliability service, it is noteworthy that only four months passed between our determination on July 20, 2012 that Pepco’s ROE should be 9.31%, and the Company’s current filing for a new rate case on November 30, 2012.

Pepeo is currently facing a low-interest rate environment, regardless of whether the cause is Federal Reserve policy, a continued slow recovery from a historic recession, or both. Given Pepco’s predilection for filing rate cases frequently with the Commission, we see no logic in inflating Pepco’s ROE today, during a time of historic low interest rates, based on speculation that those rates could increase sometime beyond the Company’s likely rate effective period. Moreover, as Mr. Hevert and Mr. King testified, PHI had no difficulty raising a significant quantity of capital in its recent debt issuances. To the contrary, the Company generated $450 million of new long-term debt between April 2012 and March 2013. For that reason, OPC argues that Pepco’s current ROE of 9.31% should be viewed as a ceiling on any ROE award. While we may not agree with OPC’s strict ceiling, we do agree that Pepeo has demonstrated its access to necessary capital on reasonable terms through its recent debt issuances and capital infusions, and conversely has not demonstrated a need for an increase in its ROE.

“Finding no significant factors that justified] a radical departure from the ROE previously granted to Pepeo,” the Commission addressed the methodologies utilized by the parties to evaluate a just and reasonable ROE for Pepeo. The Commission then stated:

Considering all of the methodologies presented, we will accept Staffs recommended ROE of 9.36% as just and reasonable. In reaching this conclusion, we are guided by the principles of Bluefield Water Works and Hope Natural Gas, which require a return that is sufficient to attract capital on reasonable terms, maintain the financial integrity of the utility, and provide an opportunity to achieve a level of revenue commensurate with that available in other investments of similar risk. Both OPC and AOBA advocated for a lower ROE (9.1% and 9.3%, respectively), while Pepco’s 10.25% proposal is anomalously high in relation to the other recommendations and well above the 9.31% ROE approved by the Commission less than one year ago.[¹⁹]

Order No. 85724, at 105-06 (footnotes omitted). The Commission explained that its approval of a 9.36% ROE included flotation costs, i.e., “expenses associated with the sale of new issues of common stock.”

The Commission then stated that it would “not reduce Pepco’s ROE by a specific amount because of its [BSA].” It explained:

The BSA was designed to account for changes in electricity usage due to variations in weather and state-mandated energy-efficiency and conservation programs, and to remove the disincentive a utility would otherwise have to promote such programs, which, in the absence of the BSA, could reduce the company’s sales revenue. In Pepco’s last rate case, we upheld a 50 basis point reduction to the Company’s ROE as a result of the previous approval of Pepco’s BSA. The BSA stabilizes Pepco’s earnings by decoupling its distribution revenues from its volumetric sales, thereby helping ensure recovery of the Company’s revenue requirement and reducing regulatory lag. Without the BSA, “Pepeo would see more dramatic swings in its earnings than currently.” Because of those benefits, OPC and AOBA argue that Pepco’s current ROE award should be reduced by a similar amount.

As noted by Pepeo and Staff, however, we have recently issued two orders in Case No. 9257 that have somewhat altered the Company’s risk as it relates to decoupling. In Order No. 84653, we determined that Maryland utilities with BSAs, including Pepeo, will be prohibited from collecting lost utility revenue through their decoupling mechanisms if the utilities are unable to restore service to their customers within 24 hours of the onset of a Major Storm. We stated that the BSA suspension will exist for the time period beginning 24 hours after the onset of a Major Storm and continuing until all Major Storm-related interruptions are restored. In the more recent Order No. 85177, we determined that utilities will be prevented from collecting decoupling revenue even during the first 24 hours of a Major Outage Event. As a result of these orders, the risk-reducing benefits of the BSA to Pepeo are somewhat diminished, and the rationale for an explicit reduction in the ROE less certain.

Id. at 106-07.

The Commission then noted that, in a prior order issued on February 22, 2013, it had found that, although the BSA “serves to limit the risk, and therefore the appropriate ROE,” id. at 108 n. 463, given “the issuance of Order Nos. 84653 and 85177, and the greater prevalence of BSAs in electric utility proxy groups ... ‘a strict basis point reduction of 50 points may no longer be warranted.’ ” Id. at 108. The Commission then concluded: “We find so here as well. We will not reduce Pepco’s ROE by an express amount as a result of its BSA, though we will, as in BGE’s proceeding, consider the BSA as one of many relevant variables that informs our determination of a just and reasonable return.” Id.

The circuit court reversed the Commission’s decision on the ROE, stating that the Commission framed the issue as “what has changed” since Pepco’s last rate case, in which the Commission penalized Pepeo with a 100-point basis reduction, 50 points for the BSA and 50 points for service problems, but the Commission then “failed to make findings about improvements Pepeo had made to service or how much the BSA should reduce the ROE in the current case.” The circuit court stated:

Had the Commission simply based its ruling on the evidence presented at the April 2013 evidentiary hearings, then [ ] under the deferential substantial evidence test, the [c]ourt would likely uphold the Commission’s decision. But the Commission instead linked its decision in this case to the prior 2011 rate case while ignoring evidence of Pepeo’s service reliability improvements and not specifying how the BSA would impact Pepco’s ROE beyond being a “relevant factor” in the Commission’s discretion. The Commission therefore failed to act reasonably.

Accordingly, the circuit court reversed on this issue and “remand[ed] the case to the Commission with instructions to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE.”

Just and Reasonable Rate

OPC contends that the Commission’s determination regarding the ROE was supported by substantial evidence, and therefore, the circuit court’s decision should be reversed. It asserts that the circuit court exceeded its “scope of review in speculating that the Commission’s decision somehow incorporated a 50 basis point (0.5%) penalty that was imposed upon Pepeo in its prior rate case ... for providing poor service,” but a review of the record reveals that the Commission’s decision “was based upon, and supported by, the expert evidence in this case.” OPC states that there are only two questions involved in review of the Commission’s determination regarding the ROE: (1) “was there substantial evidence to support the Commission’s determination that Pepeo should be authorized a 9.36% return on equity?”; and (2) “is the final rate afforded to Pepeo just and reasonable, or, not so low as to be confiscatory?” OPC asserts that, if the answer to both questions is yes, the Commission’s decision was proper and the circuit court’s decision should be reversed.

Pepeo argues that the circuit court “correctly ruled that the Commission’s ROE award was arbitrary and capricious and not supported by substantial evidence.” It notes that, in 2011, the Commission awarded it a 9.31% ROE, which was the result of a full percentage point reduction, a 50 basis point penalty for service reliability issues and a 50 basis point reduction to account for the “risk reducing effects of the BSA.” It argues that, “without these two 50 basis point reductions, the Commission in 2011 would have awarded Pep-eo an ROE of 10.31%,” as opposed to 9.31%. Pepeo contends that, although “the Commission framed the question presented to be whether anything had changed since the 2011 Rate Case, it then proceeded to ignore undisputed record evidence of what had changed in awarding a 9.36% ROE.” In particular, Pepeo states that the Commission: (1) “ignored the undisputed evidence of Pepco’s dramatically improved service quality and failed to make any findings as to service quality”; and (2) “failed to explain or make findings regarding the BSA’s impact on the ROE it awarded,” asserting that the Commission’s “statement that it was taking the BSA into account in establishing [the] ROE cannot be reconciled with the testimony of the Staff witness Dr. Luznar whose specific recommendation the Commission expressly adopted.”

In assessing the parties’ contentions, it is important to keep in mind the purpose of the ROE, as well as the scope of judicial review of the Commission’s determination regarding this factual issue. As indicated, utilities are entitled to a rate that will yield a reasonable return on the value of property used to render service:

A public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties.

Bluefield Waterworks, 262 U.S. at 692, 43 S.Ct. 675. Whether a rate of return is reasonable depends on many circumstances, including the money market, business conditions, and the amount of risk involved. Id. at 693, 43 S.Ct. 675.

In Federal Power Commission, 320 U.S. at 603, 64 S.Ct. 281 the United States Supreme Court made clear that judicial review of a Commission ratemaking order focuses on whether the rate order is “just and reasonable.” The Court explained:

Under the statutory standard of ‘just and reasonable’ it is the result reached not the method employed which is controlling. It is not theory but the impact of the rate order which counts. If the total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end. The fact that the method employed to reach that result may contain infirmities is not then important. Moreover, the Commission’s order does not become suspect by reason of the fact that it is challenged. It is the product of expert judgment which carries a presumption of validity. And he who would upset the rate order under the Act carries the heavy burden of making a convincing showing that it is invalid because it is unjust and unreasonable in its consequences.

Id. at 602, 64 S.Ct. 281 (citations omitted).

The Court of Appeals similarly has recognized the discretion of the Commission in determining the rate of return, as well as “the limited nature of our role on judicial review.” Potomac Edison Co. v. Pub. Serv. Comm’n, 279 Md. 573, 581, 369 A.2d 1035 (1977). As long as the ROE is within “the zone of reasonableness,” judicial scrutiny in the ratemaking process ends. Id. at 582-83, 369 A.2d 1035.

Here, there is no argument that the rate approved, including the ROE, was not in the zone of reasonableness. Rather, the argument is a procedural one, i.e., that the Commission framed the issue as what had changed since the last rate proceeding, but then it failed to address why the previous 100 basis point reduction was inapplicable to the present case. We do not agree that there was any impropriety here.

To be sure, the Commission discussed the prior rate case that was decided approximately one year earlier, but it did so in the context of the economic factors relevant to addressing the appropriate ROE in this case. The Commission found that there were not “significant changes in the economic environment,” noting that Pepeo still was “a monopolistic provider of electric distribution service that operates in a stable service territory,” its customer base was “heavily residential, which alleviates the risk of large scale closures or relocations faces by utilities operating in heavily dense commercial or industrial service territories,” Pepeo was facing a “low-interest rate environment,” and it had generated “a significant quantity of capital in its recent debt issuances.” In light of those factors, the Commission found that there was no showing justifying “a radical departure from the ROE previously granted to Pepeo.”

The Commission then turned to the testimony of the witnesses, who “provided similar analytical methods for evaluating a just and reasonable ROE.” It rejected OPC’s argument that, because Pepeo had not demonstrated a need for an increase in its ROE, the 9.31% current rate should be the ceiling, and it rejected Pepco’s “anomalously high” proposal of 10.25%, noting that Pepco’s unreasonable “use of weighting factors and overreliance on generation-owning utilities” in its proxy group contributed to its excessive proposal, as did its proposal for flotation costs using a premise that the Commission repeatedly had rejected. Instead, the Commission accepted the recommendation of Dr. Luznar of a 9.36% ROE as just and reasonable. In so finding, the Commission noted that Pepeo was entitled to “a return that is sufficient to attract capital on reasonable terms, maintain the financial integrity of the utility, and provide an opportunity to achieve a level of revenue commensurate with that available in other investments of similar risk.”

Applying the principles of judicial review of a decision of the Commission on the rate of return, we cannot say that the decision here was arbitrary or unsupported by substantial evidence. The Commission set forth the factors that it considered in arriving at the ROE, and there was substantial evidence to support its decision.

Pepeo contends, however, that the decision was defective because the Commission stated that it adopted the ROE recommended by Dr. Luznar, but Dr. Luznar did not include any reduction for the BSA in her recommended 9.36% ROE, whereas the Commission did take the BSA into account as a “variable.” We are not persuaded.

The Commission clearly explained that, although it previously had upheld a 50 basis point reduction to the ROE as a result of the BSA because it helped to stabilize a utility’s earnings, its recent orders preventing the collection of lost revenue after a major storm had diminished the risk-reducing benefits of the BSA. Nevertheless, the Commission stated that, although the BSA did not warrant a reduction of the ROE “by an express amount,” the BSA would be considered “as one of many relevant variables that informs our determination of a just and reasonable return.” The Commission noted that its decision in this case was similar to that in a previous case, where it found that the BSA, although limited by recent orders, continues to “limit the risk, and therefore the appropriate ROE.” We perceive no abuse of discretion by the Commission in considering the BSA as a factor in determining a just and reasonable return for Pepeo.

In sum, appellants have failed to show that the 9.36% ROE awarded was not just and reasonable based on this evidence presented to the Commissioner. Accordingly, the decision should be upheld, and the circuit court erred in reversing it.

JUDGMENT AFFIRMED IN PART AND REVERSED IN PART. COSTS TO BE PAID 25% BY MARYLAND OFFICE OF PEOPLE’S COUNCIL, 25% BY AARP MARYLAND, AND 50% BY POTOMAC ELECTRIC POWER COMPANY.

1 . In the Matter of the Application of Potomac Electric Power Company for an Increase in Its Retail Rates for the Distribution of Electric, Case No. 9311, Order No. 85724 (2013) (‘‘Order No. 85724”).

2 . AARP appealed only the circuit court’s decision to affirm the Commission’s decision to permit the Grid Resiliency Charge (‘‘GRC”), and therefore, it posed only one question related to that issue. OPC contends that the circuit court erred in its ruling on both the GRC and the Return on Equity ("ROE”).

3 . This Court has jurisdiction to hear this appeal pursuant to Md.Code (2010 Repl.Vol.) § 3-209 of the Public Utilities Article ("PU”), which states: "A party aggrieved by a final judgment in any proceeding under this subtitle may appeal the judgment to the Court of Special Appeals in the manner provided by law for appeals in other civil cases.”

4 . " 'Public service company’ means a common carrier company, electric company, gas company, sewage disposal company, telegraph company, telephone company, water company, or any combination of public service companies.” PU § 1—101(x)(1).

5 . CAIDI "represents the average outage duration any customer who experienced an outage would experience over the course of a year. It can also be viewed as the average customer restoration time. CAIDI is measured in units of time.” SAIDI "represents the average outage duration for each customer in the service territory over the course of a year. SAIDI is measured in units of time.” SAIFI "represents the average number of interruptions that a customer would experience over the course of a year. Unlike CAIDI and SAIDI figures, which represent interruption durations, SAIFI is measured in units of interruptions per customer.” Weathering the Storm: Report of the Grid Resiliency Task Force 19 (Sep. 24, 2012), available at http://perma.cc/LBB4-YAH6.

6 . The parties cite the Grid Resiliency Task Force Report as Commission Exhibit 1, and Pepeo suggests that the document was entered into evidence. The record transmitted to this Court, however, indicates that the report was only marked for identification. In any event, the report, which was included in the record extract without objection, is a document of which we can take judicial notice. See Homan v. Branstad, 864 N.W.2d 321, 323 n. 1 (Iowa 2015) (taking judicial notice of a government task force report); In re Mandate of Funds for Ctr. Twp. of Marion County Small Claims Court, 989 N.E.2d 1237, 1239 (Ind.2013) (same); Reilly v. City & County of San Francisco, 142 Cal.App.4th 480, 48 Cal.Rptr.3d 291, 295 n. 3 (2006) (same).

7 . A "tracker” is a concurrent surcharge allowing a utility to begin recovering costs from its ratepayers immediately upon expenditure, rather than waiting until its next rate case. Order No. 85724, at 135 n. 597.

8 . The complete list of proposed areas of rate base and operating income adjustments included the following: (1) Reliability Plant Additions; (2) Net Operating Loss Carry-Forward (NOLC); (3) Depreciation; (4) Amortization of 2012 Major Storms; (5) Vegetation Management; (6) Cash Working Capital; (7) Annual Incentive Plan; (8) Energy Advisors and Energy Engineers; (9) AMI Meters; (10) Average Overtime Expense; (11) Rate Case Expense; (12) Uncollectibles; (13) Employee Activity Costs; (14) Supplemental Executive Retirement Plan Expense; (15) Directors and Officers Liability Insurance; (16) Materials and Supplies; (17) Excess Outside Legal Expense; (18) Accenture Expenses; (19) Case No. 9214 Expense; (20) "Excess” Long-Term Debt Costs; (21) Allowance for Funds Used During Construction; and (22) Interest Synchronization. We will address only the issues presented the appeal.

9 . Although the circuit court’s decision regarding RMA1, RMA2, and RMA3 is not the subject of this appeal, we mention the RMAs because the Maryland Office of the People’s Counsel ("OPC”) compares the standard the Commission used to approve and reject these adjustments with the standard the Commission applied when approving the GRC.

10 . “Feeders” are relatively low voltage distribution lines that originate at distribution substations and deliver electricity to end users (i.e., customers) attached to the feeder grid. Order No. 85724, at 16.

11 . Commissioner Lawrence Brenner filed a separate statement, concurring in part. He stated that, although he would have preferred an approach other than the GRC, he nonetheless concurred because he believed that the Accelerated Priority Feeders project was ''worthwhile,” and he wanted to avoid a Commission stalemate that would have resulted in the project not being approved. Commissioner Harold D. Williams also filed a separate statement, in which he dissented regarding the decision to allow the GRC.

12 . The circuit court listed the issues raised by the parties are as follows: (1) Pepco’s ROE; (2) the inclusion of AMI meters in Pepco’s rate base; (3) Pepco’s cash working capital allowance; (4) the inclusion of Pepco’s supplemental executive retirement plan in the rate base; (5) the inclusion of Pepco’s directors’ and officers’ liability insurance in the rate base; (6) the limitation of test year data to no more than four months of projected data (the "8 and 4 rule”); (7) the grid resiliency charge (GRC); (8) the inclusion of net operating loss carryforward in Pepco’s rate base; and (9) accumulated depreciation.

13 . In its initial brief to the Commission, Pepeo described the "true-up” process as follows:

To address any potential variance between actual expenditures and the projections on which the Grid Resiliency Charge is based, the Company has built in a monthly over/under recovery calculation to track as a deferred balance any difference between projected expenditures and actual expenditures, and the balance would be reconciled upon termination of the Grid Resiliency Charge. The deferred balance will accrue interest calculated monthly at the Company’s short-term debt rate.

(footnotes omitted).

14 . Although both AARP and OPC filed reply briefs, only AARP addressed Pepco's preservation argument.

15 . In support, OPC cites several cases. See e.g. In re Potomac Electric Power Co., 103 Md.P.S.C. 293, 304 (July 20, 2012) (Case No. 9286, Order No. 85028) (rejecting Pepco’s request for "a new monthly surcharge to recover, in advance, before a new rate case, certain reliability-oriented capital projects”); In Re Washington Gas Light, 102 Md.P.S.C. 332, 341-42 (Nov. 14, 2011) (Case No. 9267, Order No. 84475) (rejecting BGE's request to impose a surcharge to finance a project to replace its piping infrastructure); In re Baltimore Gas & Elec. Co., 101 Md.P.S.C. 149, 154, 164-65 (June 21, 2010) (Case No. 9208, Order No. 83410) (rejecting Baltimore Gas and Electric Company's request to impose a "tracker” surcharge to pay for the installation of smart meters, and noting the narrow range of circumstances in which surcharges are appropriate to include "very large, non-recurring expense items that have the potential to seriously impair a utility’s financial well-being and that do not contribute to the Company’s rate base”).

16 . OPC contends that, if the Commission had applied the "known and measurable standard to the GRC, as it did in its rejection of RMA3, the GRC would have failed to meet the standard because Pepeo could give only estimates for the work involved to upgrade the feeders involved.

17 . On June 29, 2012, a powerful line of thunderstorms known as a derecho (deh-REY-cho), caused more than 4 million customers to lose power during a prolonged heat wave, resulting in 34 heat-related deaths that occurred in areas that lost power. National Oceanic and Atmospheric Administration, Service Assessment—The Historic Derecho of June 29, 2012, at ix (2013), available at http://perma.cc/92MW-D5A3. Hurricane Sandy, known as “Superstorm Sandy,” made landfall on October 29, 2012, causing approximately $50 billion worth of damage, and leaving approximately 8.5 million customers without power. National Oceanic and Atmospheric Administration, Service Assessment—Hurricane/Post-Tropical Cyclone Sandy October 22-29, 2012, at iv, 1 (2013), available at http://perma.cc/N6FA-VZ5P.

18 . A Bill Stabilization Adjustment Rider ("BSA”) allows an electric company to decouple its electric rate from sales volume. Dep't of Legis. Servs., Fiscal and Policy Note, H.B. 29 at 2 (2013), available at http://perma.cc/C6ZQ-EK5X. It is "a lagged addition to or reduction from a customer’s monthly bill that aligns actual revenues with expected revenues set in rate cases.” Id. For example, if there is a lower-than-expected revenue in one month, an increase is applied to a subsequent billing period, and if there is a higher-than-expected revenue in one month, a reduction is applied to the customer’s bill in a subsequent month. Id. at 4. The BSA protects electric companies from being financially impacted by energy conservation and efficiency programs, as well as unanticipated charges due to severe weather. Id. In 2012, given a concern that revenue decoupling may have eliminated incentive to restore electrical services quickly, the Commission issued orders that limited the ability to collect lost sales revenue after a "major outage event.” Id. Electric companies were "still allowed to collect revenue for lost energy sales for blue sky outages, short-term outages of less than 24 hours, and for storms that do not meet the ‘major outage event’ threshold.” Id.

19 . As indicated, OPC recommended that Pepco’s ROE be reduced if the Commission granted Pepco’s request for a GRC because the surcharge would reduce Pepco's revenue risk. The Commission did not address this recommendation given "the limited scope of the GRC approved.”