Docket No. 42516
In Re:

Georgia Power Company’s 2019 Rate Case
ORDER ADOPTING
SETTLEMENT AGREEMENT AS MODIFIED

Record Submitted:

November 27, 2019

Decided:

December 17, 2019

APPEARANCES
On behalf of Georgia Public Service Commission Public Interest Advocacy Staff:
JEFFREY STAIR, Esq., DANIEL WALSH, Esq., and PRESTON THOMAS, Esq.
On behalf of Georgia Power Company:
KEVIN C. GREENE, Esq., BRANDON MARZO, Esq., and STEVE HEWITSON, Esq.
On behalf of the City of Atlanta:
NINA R. HICKSON, Esq., and NEWTON GALLOWAY, Esq.
On behalf of The Commercial Group:
ALAN R. JENKINS, Esq.
On behalf of Georgia Association of Manufacturers:
CHARLES B. JONES, III, Esq.
Docket No. 42516
Order Adopting
Settlement Agreement
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 On behalf of Georgia Industrial Group:
RANDALL D. QUINTRELL, Esq.
On behalf of Georgia Interfaith Power & Light, Southface Energy Institute, and Vote Solar:
KURT EBERSBACH, Esq., and JILLIAN KYSOR, Esq.
On behalf of Georgia Solar Energy Industries Association, Inc.:
NEWTON M. GALLOWAY, Esq., and TERRI M. LYNDALL, Esq.
On behalf of Georgia Restaurant Association:
PERRY J. McGUIRE, Esq., and VICKIE C. RUSEK, Esq.
On behalf of Georgia Watch:
LIZ COYLE
On behalf of The Kroger Company:
KURT J. BOEHM, Esq., and JODY KYLER COHN, Esq.
On behalf of Metropolitan Atlanta Rapid Transit Authority:
ROBERT B. BAKER, JR., Esq.
On behalf of Resource Supply Management:
JIM CLARKSON
On behalf of Sierra Club:
ROBERT JACKSON, Esq., and ZACHERY M. FABISH, Esq.
On behalf of U.S. Department of Defense and other affected Federal Executive Agencies:
EMILY W. MEDLYN, Esq.

Docket No. 42516
Order Adopting
Settlement Agreement
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 BY THE COMMISSION:
I.

GEORGIA POWER COMPANY’S 2019 RATE CASE STATEMENT OF
PROCEEDINGS

Pursuant to the Rate Plan approved by the Georgia Public Service Commission
(“Commission”) in the December 17, 2013 Order Adopting Settlement Agreement in Docket No.
36989-U, Georgia Power Company’s 2013 Rate Case, the Commission ordered Georgia Power
Company (“GPC” or “Company”) to file by July 1, 2016, a general rate case for dealing with any
changes in revenue requirements. Subsequent to that decision, the Commission established in its
April 14, 2016 decision on the Joint Request of Atlanta Gas Light Company, AGL Resources
Inc., and The Southern Company for a Finding that Southern Company’s Merger with AGL
Resources Complies With Applicable Law And SouthStar Energy Services LLC d/b/a Georgia
Natural Gas; Application for a Natural Gas Marketer Certificate of Authority filed respectively in
Dockets 39971 and 9574 that the current 2013 Georgia Power accounting order would continue
in effect until December 31, 2019 and Georgia Power would file its next retail rate case, or
request for an accounting order, on July 1, 2019.
On May 21, 2019, in accordance O.C.G.A. § 50-13-13, the Commission entered a
Procedural and Scheduling Order (“PSO”) to govern the hearings. On June 28, 2019, pursuant to
the PSO, Georgia Power Company filed its 2019 Rate Case. On September 24, 2019, Georgia
Power filed an errata to reflect the revenue requirement impacts from various items included in
the amended Stipulation approved by the Commission in the Company’s 2019 Integrated
Resource Plan (“IRP”) and DSM Certification proceedings in Docket Nos. 42310 and 42311
(“Errata”).
Georgia Power’s 2019 Rate Case filing, as amended by the Errata, requested approval to
continue the three-year alternate rate plan (“ARP”) structure and requested rate increases of $560
million, $144 million and $233 million to be effective January 1, 2020, 2021 and 2022,
respectively. These proposed increases included a one-time levelized adjustment for traditional
base rates and Environmental Compliance Cost Recovery (“ECCR”) tariffs and annual increases
to recover compliance costs associated with ash pond closure as well as the Demand Side
Management (“DSM”) and Municipal Franchise Fee (“MFF”) tariffs. Hearings on Georgia
Power’s direct case in support of its filing were held September 30, 2019 through October 2,
2019.
In addition to the Commission’s Public Interest Advocacy Staff (“PIA Staff”), which has
a statutory right to participate in this proceeding, interventions were filed by a number of
interested parties. These interested parties included the City of Atlanta; the Commercial Group;
Concerned Ratepayers of Georgia; the U.S. Department of Defense (on behalf of all Other
Federal Executive Agencies) (“DOD/FEA”); Georgia Association of Manufacturers (“GAM”);
Georgia Industrial Group (“GIG”); Georgia Interfaith Power & Light, Inc. (“GIPL”), Southface
Energy Institute, Inc. (“Southface”), and Vote Solar, Inc.; the Georgia Solar Energy Association,
Inc. (“GSEA”) and Georgia Solar Energy Industries Association (“GSEIA”); Georgia Restaurant
Association (“GRA”); Georgia Watch; The Kroger Company (“Kroger”); Metropolitan Atlanta
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 Rapid Transit Authority (“MARTA”); Resource Supply Management (“RSM”); and the Sierra
Club. Thereafter, on October 17, 2019, PIA Staff and Intervenors filed testimony and exhibits
presenting their respective direct cases. With the exception of Concerned Ratepayers of Georgia,
GSEIA/GSEA, and Georgia Watch, all other parties to this case filed testimony in this
proceeding. Hearings on PIA Staff and Intervenors’ direct cases were held November 4, 2019
through November 6, 2019.
The Company filed its rebuttal testimony on November 15, 2019 in response to the
positions advocated by PIA Staff and various Intervenors. The Company presented its rebuttal
case on November 25, 2019, at which time the hearings in this matter were concluded. On
December 4, 2019, parties in this matter filed proposed orders and briefs.
At each phase of the hearings of evidence in this case the Commission also heard from
numerous public witnesses who expressed their views on the Company’s application, either
individually or on behalf of specific groups.
II.

COMMISSION ACTION

Following its rebuttal testimony, the Company filed a proposed Settlement Agreement
(“Proposed Agreement”) intended to resolve the issues in the case except for the return on equity
(“ROE”) to be assumed in setting the Company’s retail rates and the appropriate level of equity
in the Company’s capital structure. Other than those two issues, the Proposed Agreement
provided that Company’s filing would be accepted with the modifications contained in the
Proposed Agreement. The Proposed Agreement was executed on behalf of the Company and
several Intervenors. The following parties executed the Proposed Agreement: the Commercial
Group, GIG, GAM, the City of Atlanta, MARTA, and Kroger.
Under the Proposed Agreement, rates would go into effect January 1, 2020 using a threeyear ARP with an earnings band of 9.50% to 12.00%. Rates under the ARP would be set as
described in the Settlement Agreement using an ROE and capital structure to be set by the
Commission. The Proposed Agreement further provided for the continuation of the ECCR Tariff
which would collect certain environmental costs that will be incurred by the Company including
compliance with Coal Combustion Residual Asset Retirement Obligations (“CCR ARO”). The
Proposed Agreement further provided for an increase in the MFF tariff as well as an increase in
the DSM tariffs.
The Proposed Agreement also provided that the traditional base tariffs would be adjusted
in 2021 and 2022 to recover the revenue requirements for traditional base rates, the ECCR tariff,
the DSM tariffs, and the MFF tariff. The Proposed Agreement also provided for continuation of
the Interim Cost Recovery (“ICR”) mechanism approved in the 2010 Rate Case in Docket No.
31958 throughout the term of this ARP utilizing the earnings band in Paragraph 6 of the
Proposed Agreement. For Annual Surveillance Reporting (“ASR”) purposes, beginning January
1, 2020, the earnings band would be set at 9.5% to 12.0% ROE and the Company would report
earnings based on the actual historic cost of debt and approved capital structure. The Company
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 would not file a general rate case unless its calendar year retail earnings are projected to be less
than 9.5% ROE.
At its regular Administrative Session held on December 17, 2019, the Commission voted
to adopt a Commissioner Motion (“Motion”) to accept the Proposed Agreement with certain
modifications set forth in the Motion, set the ROE at 10.50%, and set the capital structure at 56%
equity and 44% debt (referred to herein as the “Settlement Agreement as Modified”). At its
regular Administrative Session held on February 4, 2020, the Commission clarified its decision
to explain that the 32 MW threshold for installed rooftop solar capacity relating to Behind the
Meter netting was for newly installed capacity and did not include existing installed rooftop solar
capacity.
FINDINGS OF FACT
1.
The Commission finds that the resolution of the matters raised in this docket, as provided
in the Settlement Agreement as Modified, is appropriate and in the best interest of the State of
Georgia. It is supported by testimony and other evidence in the record and will result in just and
reasonable rates. In discussing the individual components of the Settlement Agreement as
Modified, the Commission remains mindful that the Proposed Agreement reflected a
compromise among a number of parties with disparate interest, and that the Settlement
Agreement as Modified must be considered as a whole. It is plain from reviewing the resolution
that no party to the proceeding, including every party that signed on to the Proposed Agreement,
prevailed on every issue. However, the Settlement Agreement as Modified offers a fair resolution
to the full range of issues presented in this docket.
2.
As set forth in the Motion, the Commission finds that rates shall be set using a 10.50%
ROE, which appropriately balances the interests of the Company and its customers, and which
the Commission finds to be just and reasonable. The difference between the respective ROE
recommendations of Georgia Power and those of PIA Staff and other Intervenors represented the
largest dollar amount of any single issue in the case. Georgia Power recommended a ROE of
10.9%.
PIA Staff recommended a 9.2% ROE with a range of 9 - 9.4%. PIA Staff argued that
authorization of a ROE of 9.2 percent would be consistent with the principles set forth in
Bluefield Waterworks and Improvement Co. v. Serv. Comm'n, 262 U.S. 679 (1923), and Fed.
Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591 (1944). PIA Staff stated that their
proposed ROE would reasonably balance just and reasonable rates to customers, the financial
integrity of the Company and fair compensation to investors. PIA Staff further stated that the
Company’s witness’ comparable earnings analysis should be rejected because the analysis does
not measure the market required return appropriate for the investment risk of Georgia Power. PIA
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 Staff pointed to the Federal Energy Regulatory Commission’s (“FERC”) decision in Docket
EL14-12-003, where FERC concluded that relying on the comparable earnings model would not
satisfy the requirements of the Fed. Power Comm'n v. Hope Natural Gas Co. decision. (Tr. 2575).
DOD/FEA recommended a ROE of 9.1%. The witness for DOD/FEA also stated that the
financial risk adjustment is not needed because the difference between Georgia Power’s bookvalue and capital structure and the proxy group’s market-value capital structure is already
captured in the various market-based ROE methodologies.
The Commission finds and concludes that a ROE of 10.5% will allow the Company
continued access to the capital markets at competitive rates and will allow the Company to
construct infrastructure necessary to serve customers and comply with environmental
regulations. Accordingly, the Commission finds that the appropriate ROE for setting rates is
10.50%.
3.
Additionally, the Commission approves a capital structure of 56% equity and 44% long
term debt for the test period. Georgia Power proposed that a capital structure containing
approximately 44% debt and 56% common equity be used for ratemaking purposes in this
proceeding. The Company maintained that the proposed ROE and 56% equity ratio will ensure
that Georgia Power has access to capital whenever necessary, provide the opportunity to earn a
fair return for its investors and will do so at rates favorable to customers.
PIA Staff proposed a capital structure for the Company composed of 49% long-term debt
and 51% common equity. (Tr. 1510). PIA Staff stated that the capital structure proposed by its
witness will comfortably support the Company’s current investment grade bond rating, but do so
at a much lower cost to ratepayers than the Company’s proposed ratemaking capital structure.
PIA Staff also argued that its witness’s proposed ratemaking capital structure is consistent with
the industry mix of debt and equity that is supportive of the Company’s current investment grade
bond rating. (Tr. 1508).
Based on the evidence presented, the Commission finds and concludes that a capital
structure of 56% common equity level is just and reasonable, and will help to mitigate the risk of a
credit rating downgrade.
4.
PIA Staff’s witness recommended a 4.07% cost of debt as shown in Staff
Exhibit_(RS/RT-2), Schedule D of Smith-Trokey Testimony. PIA Staff’s witness adjusted GPC’s
bond issues made in August 2019 to the actual interest rates GPC received and adjusted the bond
issues interest rates to 3.65% for the period of March 2020 through October 2022, (Gorman
Direct Testimony, Table 7).
The Company stated in its brief that PIA Staff’s witness’ adjustments were neither
necessary or appropriate adjustments. The Company argued first, PIA Staff’s recommended
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 adjustment to the cost of debt revises only one component of the Company’s filing impacted by
interest rates and creates inconsistencies with the interest rate assumptions throughout the
remainder of the Company’s filing. (Tr. 2629.) And second, PIA Staff’s adjustment of projected
cost of debt to 3.65% for the projected issuances beyond March 2020 is inappropriate for
forecasting the Company’s future cost of debt. (GPC Post Hearing Brief p. 17)
The Commission was not sufficiently swayed by PIA Staff’s position, therefore, PIA
Staff’s recommendation is denied.
5.
The Proposed Agreement provides that, effective January 1, 2020, the Company shall (1)
not increase its traditional base rate tariff in 2020, any increases in base rates in 2021 and 2022
shall not be levelized but adjusted year by year, (2) collect an additional $12 million through the
DSM tariffs, and as adjusted during the term of this ARP based on the DSM True up process
agreed to by the Company and Commission Staff with projected increases of $1 million effective
January 1, 2021, and $1 million effective January 1, 2022 and (3) collect an additional $12
million effective January 1, 2020, $5 million effective January 1, 2021, and $9 million effective
January 1, 2022 through the MFF tariff, which dollar amount will change as total revenues
change as allowed by this ARP, as well as with any future Fuel Cost Recovery (“FCR”) changes
and future Nuclear Construction Cost Recovery (“NCCR”) changes. (Proposed Agreement
Provisions 1, 3 and 4).
The Commission finds these tariff changes to be reasonable; therefore, the changes are
approved as provided for in the Proposed Agreement.
6.
The Proposed Agreement provides that the revenue requirement amount related to coal
ash pond AROs shall be collected through the ECCR tariff effective January 1, 2020. ECCR
shall include the cost for compliance with CCR ARO. The collection of CCR AROs through
ECCR will be in addition to compliance costs already included in the ECCR tariff. For purposes
of settlement, the forecasted contingency for CCR AROs and traditional ECCR has been
removed from the annual expenditure projections. For rate setting purposes the full weighted
average cost of capital will be applied to the under recovered balance of CCR AROs. Effective
January 1, 2020, it was estimated that the ECCR tariff would be adjusted to collect an additional
$324 million, an estimated $115 million effective January 1, 2021, and $180 million effective
January 1, 2022. These estimates will be adjusted in setting actual 2020 ECCR tariff rate and in
the Company’s compliance filings to incorporate the capital structure and rate setting return on
equity approved by the Commission. The projection of CCR ARO cost will be updated in 2020
and 2021 through compliance filings to set the actual ECCR tariff rates for 2021 and 2022.
(Proposed Agreement Provisions 2 & 5).
PIA Staff’s recommended CCR ARO revenue requirement deficiency for 2020 is $104.6
million, which is $53.5 million less than the Company’s proposed amount. (Tr. 1212). PIA Staff
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 did not object to the one-third amortization per year approach for cost recovery proposed by the
Company, but recommended three modifications to the Company’s proposal. First, PIA Staff
recommended that the Commission not pre-approve a level of cost recovery for 2021 and 2022
because the actual costs may vary from the Company’s estimates. Instead, PIA Staff
recommended that the Company’s annual compliance filing as approved in the 2019 IRP.
Second, PIA Staff recommended that the Commission not approve contingency dollars included
by the Company in the estimates that the Company used to derive its requested CCR ARO
compliance revenue requirements for the test year, and for plan years 2020 through 2022. They
argued removal of the contingency dollars is appropriate here because the Company’s estimates
included a substantial contingency, the Company will have the opportunity to mitigate and offset
costs, and some portions of the Company’s contingency estimates have a low probability of
being incurred. (Tr. 1207-1208). Finally, PIA Staff recommended that the Company receive a
carrying cost allowance based on the cost of long-term debt with no ROE component, rather than
a full rate base return (including an equity return and income tax gross-up) on the CCR ARO
amounts while they are
being recovered.
DOD/FEA recommended that given the substantial size and uncertainty of the amount of
CCR costs to be recovered, the Commission should order that Georgia Power recovers these
costs through an exact cost recovery rider designed as a percent of base revenue structured in a
similar fashion as Georgia Power’s current base-rate recovery riders tariff, e.g. Nuclear
Construction Cost Recovery tariff. DOD/FEA further recommended that if the Commission does
not think transparency is necessary in relation to billing of CCR ARO costs, hence that cost
recovery through a new rider is unwarranted, the Commission should order CCR ARO costs to
be recovered through the ECCR tariff.
Sierra Club recommended that the Commission deny the Company’s request to recover
$525 million from its ratepayers for its CCR costs stating that Georgia Power failed to
demonstrate that its costs are just, reasonable and prudent. Sierra Club stated that the Company
failed to provide a cost accounting, cost breakdown or list of line item expenses breaking down
how or when the $525 million will be spent. Sierra Club also asserted that the CCR costs should
be disallowed as those future costs are uncertain. Since the Georgia EPD has yet to approve
Georgia Power’s CCR closure plans, Sierra Club argued that the Company is attempting to
recover, from ratepayers, costs that are indefinite, uncertain and could change.
This Commission has carefully considered the evidence and testimony presented on these
issues and finds that it is just and reasonable for Georgia Power to recover CCR ARO compliance
costs as provided for in the Proposed Agreement.
7.
For ASR purposes, beginning January 1, 2020, the earnings band shall be set at 9.5% to
12.0% ROE and the Company shall report earnings based on the actual historic cost of debt and
approved capital structure. The Company shall not file a general rate case unless its calendar
year retail earnings are projected to be less than 9.5% ROE. (Agreement Provision 6).
Docket No. 42516
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 PIA Staff has recommended an earnings band from 9.20 to 10.50% and recommended
that earnings above the band be applied to deferred costs instead of being split between
customers and the Company. (Tr. 1316.)
DOD/FEA’s witness recommended narrowing the ROE earnings band to +/- 50 basis
points around the authorized ROE based on the assumption that it would reduce the risk to the
Company. (Tr. 1015.) This assumption, however, fails to recognize that by reducing the risk to
the Company it would necessarily increase the risk to customers. (Tr. 2636.) Increasing the risk
to customers alters the fundamental nature of the ARPs that have been in place for the last 25
years. (Id.) Georgia Power has proposed an earnings band approximately +/-100 basis points
around the proposed ROE, consistent with the structure of the earnings bands previously
approved by the Commission for the last several decades.
The Commission finds that the earnings band for ASR purposes and the Company’s
agreement not to file a general rate case unless its calendar year retail earnings are projected to
be less than 9.5% are reasonable and is hereby approved.
8.
The Proposed Agreement provides that subsequent to finalization of PIA Staff’s review of
the respective ASR, any retail earnings above 12.0% ROE shall be shared, with forty percent
(40%) being applied to regulatory assets in the following priority: Accumulated CCR ARO,
Retired Generating Plant, Obsolete Inventory, Environmental Remediation, and Storm Damage,
forty percent (40%) being directly refunded to customers, allocated on a percentage basis to all
customer groups including the base revenue contribution of Real Time Pricing (“RTP”)
incremental usage, and the remaining twenty percent (20%) retained by the Company. The
Commission finds that it is fair and reasonable that in the event the Company is earning above
the top end of the earnings band, sharing occurs in accordance with the Settlement Agreement.
(Proposed Agreement Provision 7).
The Commission finds this provision of the Proposed Agreement to be reasonable and is
hereby approved.
9.
The Proposed Agreement provides that the Company shall make its ASR filings for this
ARP by March 15th of the following year. The Commission will consider the ASR filing and
determine any direct refunds and reduction of regulatory assets by July 31st of that year.
(Proposed Agreement Provision 8).
The Commission finds this provision of the Proposed Agreement to be reasonable and is
hereby approved.
10.
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 For purposes of the 2021 and 2022 rate adjustments, the Company shall make compliance
filings of the updated tariffs at least ninety (90) days prior to the effective date of the tariffs. The
Company’s compliance filings will include the following updates including updated estimates to
incorporate the capital structure and rate setting return on equity approved by the Commission on
December 17, 2019:
a) Effective January 1, 2021, (i) the traditional base tariffs shall be adjusted to collect an
additional estimated $93 million. This estimate shall be adjusted in the Company’s
compliance filing to incorporate the capital structure and rate setting return on equity
approved by the Commission; (ii) the ECCR tariff shall be increased based upon the
Compliance filing with updated CCR ARO costs as filed in the most recent semiannual report for calendar year 2020; (iii) the DSM tariff shall be increased to reflect
the additional approved DSM costs for calendar year 2021 as approved in Docket No.
42311 and as adjusted based on the DSM True up process agreed to by the Company
and PIA Staff; and (iv) the MFF tariff shall be adjusted to collect the municipal
franchise fee cost incurred by the Company. The 2021 increase to traditional base rate
tariffs, ECCR tariff, DSM tariff will use the most current kWh sales forecast for the
applicable year to set the rates.
b) Effective January 1, 2022, (i) the traditional base tariffs shall be adjusted to collect an
additional estimated $197 million. This estimate shall be adjusted in the Company’s
compliance filing to incorporate the capital structure and rate setting return on equity
approved by the Commission; (ii) the ECCR tariff shall be increased based upon the
Compliance filing with updated CCR ARO costs as filed in the most recent semiannual report for calendar year 2021; (iii) the DSM tariff shall be increased to reflect
the additional approved DSM costs for calendar year 2022 as approved in Docket No.
42311 and as adjusted based on the DSM True up process agreed to by the Company
and PIA Staff; and (iv) the MFF tariff shall be adjusted to collect the municipal
franchise fee cost incurred by the Company. The 2022 increase to traditional base rate
tariffs, ECCR tariff, DSM tariff will use the most current kWh sales forecast for the
applicable year to set the rates.
The Commission finds that the Proposed Agreement is reasonable as it pertains to the
above rate adjustments and compliance filing requirements.
11.
The Proposed Agreement provides that for book accounting and ASR purposes, the
schedule for the Nuclear Decommissioning Trust – Tax Funding (reference the “Proposed
Supplemental Order – Nuclear Decommissioning Costs” attached to the Proposed Agreement)
are approved. (Proposed Agreement Provision 10).
The Commission finds and concludes that the proposed Supplemental Order – Nuclear
Decommissioning Costs is reasonable and approved.
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 12.
Regarding earnings that the Company has reported above the earnings band in 2018 to
the Commission through the ASR process in Docket No. 36989, the Proposed Agreement
provides that fifty percent (50%) of the customer share (approximately $51 million) of earnings
above the band in 2018 shall be utilized to reduce the December 31, 2019, storm damage
regulatory asset. Regulatory assets are to be written down in the following priority: Obsolete
Inventory, Environmental Remediation, Accumulated CCR ARO, Retired Generating Plant, and
Storm Damage. The remaining fifty percent (50%) of the customer share shall be refunded to
customers in 2020 with a special line-item on the bill. (Proposed Agreement Provision 11).
In the Proposed Agreement, the Company anticipates earnings in excess of the earnings
band in 2019. The Company shall forego its share of the 2019 earnings over the top of the
earnings band. Fifty percent (50%) of all the earnings over the 2019 band shall be refunded to
customers with a special line item on the bill, and fifty percent (50%) shall be used for the early
retirement of regulatory assets including $49 million spent to investigate the Stewart County site
and other regulatory assets in the following priority: Accumulated CCR ARO, Retired
Generating Plant, Obsolete Inventory, Environmental Remediation, and Storm Damage.
(Proposed Agreement Provision 12).
The Commission finds that the treatment as set out in the Proposed Agreement for the
earnings above the band in 2018 and 2019 are reasonable and approved.
13.
The Proposed Agreement also provides that the Company shall accelerate amortization of
an estimated $88 million in regulatory assets in 2020 in the following priority: Accumulated
CCR ARO, Retired Generating Plant, Storm Damage, Obsolete Inventory, and Environmental
Remediation. The actual amount accelerated may be different than estimated in this paragraph
depending upon the capital structure and rate setting return on equity approved by the
Commission. The estimated $88 million shall be adjusted to reflect the updated projected
revenue sufficiency by incorporating the capital structure and rate setting return on equity
approved by the Commission and will be reflected in the Company’s compliance filing.
(Proposed Agreement Provision 13).
Additionally, the Proposed Agreement provides that, in the event the Company
determines that an asset is impaired or the Commission approves the retirement of a retail
generation asset as a result of any environmental regulation or legislation, the Company may
request that costs associated with such impairment or retirement be deferred as a regulatory
asset. (Proposed Agreement Provision 14).

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 The Commission finds that Proposed Agreement provisions 13 and 14 are reasonable and
approved.

14.
The ICR mechanism approved in the 2010 Rate Case in Docket No. 31958 is continued
throughout the term of this ARP utilizing the earnings band of 9.5% to 12.0% as set for the ASR.
(Agreement Provision 15). Under the ICR mechanism, if at any time during the term of the ARP,
the Company projects that its retail earnings will be lower than 9.50% retail ROE for any
calendar year, based on the most recent budget, including the latest projections regarding rate
base, revenues, expenses, changes in projected debt and preferred security costs, it may petition
the Commission for the implementation of an ICR tariff which will be used to adjust the
Company’s earnings back to 9.50% ROE. Any ICR tariff approved by the Commission shall
expire at the earlier of the date upon which the next general rate case takes effect or the end of
the calendar year in which the ICR tariff becomes effective. Continuation of the ICR mechanism
also maintains certain procedural guidelines regarding the filing of any request for
implementation of an ICR tariff, and further maintains that in lieu of requesting implementation
of an ICR tariff, or if the Commission chooses not to implement the ICR, the Company may file
a full rate case. Georgia Power must file its request to implement the ICR tariff no less than 90
days prior to its proposed effective date.
As with prior Commission-approved plans, PIA Staff’s proposed ARP would also permit
the Company to petition the Commission to increase rates up to the lower end of the band if its
projected earnings would fall below the lower band over the upcoming calendar year. (Tr. 1301).
As discussed above, however, PIA Staff’s recommended earnings band was 9.2% ROE to 10.5%.
(Tr. 1305).
The Commission finds that the portion of the Proposed Agreement allowing for
continuation of the ICR mechanism during the term of the rate plan is just and reasonable.
15.
The Proposed Agreement provides that, with the exception of easements and right of
ways, Generation and Transmission property in Plant Held for Future Use (“PHFFU”) that has
been held in PHFFU account for 15 consecutive years shall undergo review during the first IRP
proceeding following the 15th year that such property has been held in PHFFU. Distribution
property in PHFFU that has been held in PHFFU account for 15 consecutive years shall undergo
review during the first base rate proceeding following the 15 th year that such property has been
held in PHFFU. In the respective proceeding, the Company will be required to present the
specific plan for the property(s) that has exceeded 15 consecutive years in PHFFU. The
Commission will decide the matter in that proceeding. (Agreement Provision 16).

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 PIA Staff cited three major concerns for the property held in PHFFU. First, there is a
substantial dollar amount of PHFFU in rate base. Second, the overwhelming majority of the land
in PHFFU is not expected to be used and useful in the provision of electric service for a
considerable amount of time. Third, the expected use dates are routinely being pushed further
into the future. Due to those concerns, PIA Staff proposed that, prospectively starting with this
rate case, the Commission order that if PHFFU has been held for more than 15 years and has not
yet been placed into service, that such PHFFU be removed from rate base until it is placed into
service.
Additionally, PIA Staff recommended that gains and losses on the sale of land held in
PHFFU be shared with ratepayers based on the amount of time the land was held in PHFFU
compared to the total time the land was held by the Company up to a maximum sharing of 80%
for customers. (Tr. 1255.)
The Commission finds that the method for reviewing PHFFU as laid out in the Proposed
Agreement is reasonable and makes no changes as it relates to the Commission’s treatment of
gains and losses on sales of property.
16.
The Proposed Agreement provides that beginning in 2021, with the adjustment to
traditional base rate tariffs, the rate increase shall be allocated by rate group, except as otherwise
provided in Proposed Agreement, with adjustments for balancing. Rates in Medium Business and
Large Business rate groups will receive 85% of the overall base rate increase with the resulting
revenue deficiency being spread to the other rate groups excluding the Small Business, Lighting
and Marginal rate groups which will receive the overall base rate increase. (Agreement Provision
17).
The Commission finds this provision of the Proposed Agreement to be just and
reasonable, and is hereby approved.
17.
The Proposed Agreement provides that the Basic Service Charge (“BSC”) for all tariffs in
the Domestic Group shall increase by $2 in 2021 and another $2 in 2022. Further, effective
January 1, 2021, the BSC for all tariffs in the Medium Business, Large Business and Marginally
priced tariff groups shall be increased to 100% of the levels shown in the Company's Exhibit
LTL-1 column labeled “Period 1 Cost of Service Study Customer Related Costs” rounded to the
nearest dollar. The remainder of tariff groups, with the exception of the Domestic Group
addressed in Paragraph 18 of the Proposed Agreement, shall have its BSC adjusted as proposed
by the Company in Exhibit LTL-1 column labeled “2021 Estimated Alternative Rate Plan Basic
Service Charge” starting in 2021. The kWh and/or demand charges in each rate shall be
correspondingly adjusted to collect the revenue requirement. (Agreement Provisions 18 & 19).
PIA Staff proposed an increase in the monthly BSC from $10.00 to $12.00 to become
effective January 1, 2021. (PIA Staff Post Hearing Brief p. 46). However, PIA Staff did not
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 recommend any further increase. PIA Staff contended that any large increase should not be
accelerated so that it is all assessed in the first year, but instead to adhere to the concept of
gradualism and slowly increase the amount of the BSC. Regardless of what was decided as the
appropriate amount for the BSC, PIA Staff asserted that multi-year phase-in should reflect an
even dollar increase over a period of up to 3 years, as opposed to the accelerated schedule
proposed by the Company. (Id.)
Sierra Club argued that the BSC should remain at $10. They stated that a change from
$10 to $17.95 is not necessary or in the public interest as it will result in rate shock, hurt lowusage and low-income customers disproportionally, reduce customer control over their bill, and
reduce incentives for energy efficiency, conservation and distributed generation. (Sierra Club
Post Hearing Brief p. 3-6).
GIPL/Southface/Vote Solar also maintained this position. The parties agree that a higher
fixed charge will more significantly impact customers that use less electricity. (See Tr. 707, 1670,
2049). It will result in disproportionate bill increases for low-income customers. (Tr. 2049-50).
Low-income customers tend to use less energy on average than the average residential customer,
as data provided by Georgia Power shows. (Tr. 2050). GIPL/Southface/Vote Solar state that
Georgia Power’s current residential BSC is equal to the national median fixed charge among
IOUs and just below the national average. (Tr. 2039, 2079-80; GIPL/Southface/Vote Solar Resp.
to Hearing Req.). GIPL/Southface/Vote Solar argued that Georgia Power is requesting an almost
$8/month increase in the residential BSC compared to the median fixed charge increase among
IOUs during the last five years at $0.50/month and the average increase is just below $2/month.
(Tr. 2040, GIPL/Southface/Vote Solar Post Hearing Brief p.7). They state that this increase will
result in rate shock.
The Commission concludes that the $2 increase in the BSC for 2021 and again in 2022
should alleviate some of the concerns voiced by PIA Staff and Intervenors because these
increases are more directly tied in with the concept of gradualism. The Commission finds that the
$2 increase to the BSC in 2021 and 2022 in the Proposed Agreement are reasonable and
adequately weigh the interests of both the Company and its ratepayers.
18.
The Proposed Agreement states that the Company will maintain the Residential Service
tariff, the R tariff, as a rate option available to all residential customers for the term of the ARP.
The Proposed Agreement also provides that the Company and Commission Staff shall
collaborate in 2020 to increase marketing of the TOU-RD rate. Beginning January 1, 2021, the
Company shall utilize the TOU-RD rate as the default rate for newly constructed residential
premises. The Company will report back to the Commission at the time of its next base rate case
regarding the adoption of TOU-RD and its use as the default rate for newly constructed
residential premises. (Proposed Agreement Provisions 20 & 21).
In its initial case, Georgia Power proposed to eliminate the R tariff as an option for
customers in new premises. GIPL/Southface/Vote Solar stated in its brief that Georgia Power
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 proposes to limit customer choice by transitioning a sizeable fraction of residential customers –
those moving into new premises – away from its most widely used tariff (the standard R tariff).
They argued further that the Company pushes this paradigm shift despite having done little in
recent years to promote its time-varying rates and despite having no defined plans to equip
customers with the tools and data needed to make informed decisions. Therefore, GIPL,
Southface & Vote Solar recommended that the Commission reject Georgia Power’s proposal to
eliminate the R tariff as an option for customers in new premises. GIPL/Southface/Vote Solar
further recommended that the Commission “direct the Company and Staff to design a
comprehensive, specific, and measurable plan to promote voluntary customer adoption of
modern rate design that send accurate price signals, are cost-reflective and align utility and
customer interests.”
PIA Staff also opposed the Company’s proposal to discontinue offering the R Rate to new
premises after January 2020 arguing that as the monopoly utility provider in the service territory,
eliminating a choice for customers is contrary to the public interest. PIA Staff recommended that
if the Commission were to close Rate R for any residential customer, in keeping with the
ratemaking principles of gradualism and customer satisfaction, PIA Staff proposed to either
exempt existing (prior to January 2020) Georgia Power customers from this new Rate R
foreclosure provision, even if they move to a new premises, or allow any existing Rate R
customers in Georgia Power territory that are moving into new premises an ability to opt-in to
Rate R.
The Commission finds that it is appropriate to maintain the R Tariff as a rate option
available to all residential customers for the term of the ARP with the TOU-RD tariff becoming
the default rate for newly constructed residential premises in 2021. Further, the Commission
finds and concludes that it is reasonable to allow a collaborative process as outlined above.
19.
The Proposed Agreement also requires the Company to work with Commission Staff to
develop options for customer access to usage data and submit those options to the PSC for
approval. Stipulating Parties will be provided an opportunity to provide comments on the
options proposed and upon approval, the Company will strive to implement the provisions of the
plan no later than January 1, 2022. The cost for providing additional options for access to
customer usage data shall be deferred as a regulatory asset and recovered in a future base rate
proceeding. (Proposed Agreement Provision 22).
PIA Staff recommended that the Commission require the Company to continue its
investigation of the costs and benefits of providing hourly usage information to its residential
customers and within six months provide an updated cost estimate to provide hourly usage data
to all residential customers.
GIPL/Southface/Vote Solar recommended that the Commission require Georgia Power to
work with PIA Staff and interested Intervenors to develop a data access implementation plan and

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 data privacy policy, and to submit the plan and policy to the Commission for approval by June
30, 2020 for implementation no later than January 1, 2021.
The Commission finds that the requirements in the Proposed Agreement sufficiently
address the recommendations on this issue.

20.
The Proposed Agreement provides that within ninety (90) days of the Final Order in this
docket, the Company, Georgia Watch, and Commission Staff shall collaborate on a process to
consider potential options for the expansion of income qualified discount opportunities to assist
customers. This process will allow for parties to provide input on the options to be considered.
The Proposed Agreement further provides that within 270 days of the Final Order in this docket,
the Company after having taken input from other parties will report back to the Commission on
their findings and may recommend additional action. Any potential program options must
consider cost impacts to non-participating customers as well as the impacts of any revenue
erosion. (Proposed Agreement Provision 23).
The Commission approves the process set out in the Proposed Agreement.
21.
The Proposed Agreement provides that the Company agrees to further promote Project
Share to customers and increase the Company’s matching to 150% of customer contributions up
to $1.5 million annually. (Proposed Agreement Provision 24).
The Commission approves the Company’s promotion of and increased contribution to
Project Share.
22.
The Proposed Agreement provides that the Electric Transportation (“ET”) tariff shall be
allocated 70% of the base rate increase in 2021 and 2022. The revenue deficiency for this
adjustment shall be accounted for within the Governmental/Institutional tariff group. (Proposed
Agreement Provision 25).
The Commission finds and concludes that this tariff change is reasonable.
23.
In accordance with the Proposed Agreement, the Time of Use – Medium Business
(“TOU-MB”) rate shall be made available to all food services and drinking places identified as
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 722 of the North American Classification System (NAICS). A franchise with multiple accounts
shall no longer be an applicability requirement. Any existing customers on TOU-MB not
qualifying as 722 will be considered grandfathered on TOU-MB an allowed to remain on the
rate. During the term of the ARP, qualifying food services and drinking places will be accepted
on TOU-MB on a first come, first allowed basis until the number of accounts on the rate equals
6,000. The rate will be reviewed in the next base rate case. Any revenue erosion from the TOUMB rate conversion during the term of the ARP will be captured in a regulatory asset account
and recovered through rates in 2021 and 2022. All revenue loss resulting from the
implementation of this provision shall be recovered by the Company from the TOU- MB rate.
(Agreement Provision 26).
GRA stated in their post hearing brief that it is unfair and anti-competitive for the TOUMB rate schedule to only be offered to large chain restaurants. (GRA Post-Hearing Brief at p. 1).
GRA also requested that the TOU-MB rate be frozen until the next rate case in order to move
towards parity. (Id.).
The Commission concludes that by opening the TOU-MB rate schedule to all food
service and drinking places identified as 722 of the NAICS, smaller restaurants will be able to be
more competitive with larger chain restaurants. GRA stated in their brief that there are currently
approximately 3,000 customers currently on the TOU-MB rate. (Id. at 2). By allowing
approximately 3,000 more customers to join the rate, the Proposed Agreement allows for smaller
restaurants to be more competitive while balancing the interests of other ratepayers. As such, the
Commission finds this provision of the Proposed Agreement to be reasonable.
24.
The Proposed Agreement provides that the Company agrees to evaluate an enhanced
demand response program for Industrial Customers (spinning reserves, etc.) to determine if such
a program would provide any value to all customers. The Company will provide the results of
the evaluation to interested Stipulating Parties within 180 days of the Order date. The
Company’s evaluation will include analysis quantifying the potential benefits and costs to
interested customers including whether any additional steps are justified by the results of the
evaluation. If interested Stipulating Parties and the Company agree that an enhanced demand
response program brings value to all customers, the Company agrees to seek Commission
approval for a pilot program at least 12 months prior to the 2022 IRP. (Agreement Provision 27).
The Commission finds and concludes that this evaluation process is reasonable.
25.
The Proposed Agreement provides that the tariff language changes proposed by the
Company to the RTP Tariff in the Company’s filing shall be modified as follows: The definition
for “Existing Load” shall be defined as load previously served by Georgia Power and shall
include load moved from one location to another provided that the operation at the new location
is substantially identical to the operation at the former location. The definition of “New Load”
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 shall mean load not defined as “Existing Load.” “New Load” shall also include load at a location
that has been vacant less than twenty-four months provided that the operation is not substantially
identical to the previous operation at that location. Finally, CBL reductions shall be allowed to
reflect the impact of equipment removal/replacement and energy efficiency improvements
implemented during the initial Term of Contract that result in measurable reduction in electric
power demand and/or energy usage, provided that the Company’s financial requirements are met.
This language shall be incorporated into the appropriate places within the RTP tariff. (Proposed
Agreement Provision 28).
DOD/FEA requested that the Commission deny the Company’s request to lengthen the
time period for an RTP customer to establish a lower CBL without approved load removal.
DOD/FEA stated that the increased time period requirement is unnecessary because a customer
must remove itself from the RTP tariff for twelve months, which serves as sufficient credible
commitment that it has achieved the reduced load.
RSM recommended that for every 1000 MW of solar in the system the Company utilize
150 MW of customer response via the marginal cost pricing mechanism already in place with its
RTP rate. (RSM Brief at p. 1).
The Commission finds and concludes that the Proposed Agreement’s modifications to the
RTP Tariff language changes are reasonable. The proposal to extend the length of time a
customer must stay off RTP before rejoining RTP and setting a new CBL is also approved.
26.
The Proposed Agreement provides that the Multiple Load Management (“MLM”) rate
shall be eliminated as proposed by the Company, and customers moving from MLM will be
moved in a revenue neutral manner to the Time of Use – Revenue Neutral (“TOU-RN”) tariff. If
a customer on MLM with RTP prefers to move their CBL to a rate other than TOU-RN, they will
be permitted to select any tariff for which they meet the applicability requirements and move
their CBL to that rate in a revenue neutral manner. (Proposed Agreement Provision 29).
The Commission finds and concludes that this tariff change is reasonable.
27.
The Proposed Agreement provides that funds for electric vehicle infrastructure will be
allowed as proposed by the Company with an additional $6 million per year to be invested in
support of wire and transformer upgrades for customer sited charging stations. (Proposed
Agreement Provision 30). The Commission finds and concludes that the projected capital and
Operation & Maintenance (“O&M”) costs associated with electric vehicle (“EV”) infrastructure
proposed in the Company’s filing should be included in the Company’s cost of service. In
addition, the Company should invest an additional $6 million per year in support of wire and
transformer upgrades for customer sited charging stations. Whether costs for electric vehicle
charging facilities or costs for infrastructure supporting such facilities should be included in the
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 Company’s cost of service is a matter of policy to be decided by this Commission. This
Commission finds that such costs must not be examined in isolation: EV charging stations serve
as much more than an additional source of revenue for the Company or any other business for
that matter. EV charging stations provide public benefits above and beyond dollars and cents. For
example, the overall grid benefits from EV drivers who routinely shift their load and place a
positive benefit onto the grid. In addition, evidence presented by the Company indicates that
residential and business/workplace rebate programs have positive rate impact measure (“RIM”)
values, which helps all customers by putting downward pressure on rates.
The Sierra Club argued that the $6 million per year in spending is just, reasonable, and
prudent. (Sierra Club Post Hearing Brief p. 13). The Sierra Club also agree that sufficient public
charging infrastructure provides a “backbone of infrastructure” necessary to support the
emerging demand for EVs. (Tr. 2648; Poroch Rebuttal at 34.)
PIA Staff opposed the inclusion of EV related spending in rate base and cost of service
and asserted that “the [public] charging stations will not generate enough revenue to cover O&M
expense and depreciation and allowing rate recovery would mean non-EV drivers would be
subsidizing investments that only benefits EV-driving ratepayers.” (Tr. 1228; Smith and Trokey
Direct at 73).
The Commission concludes that this policy decision extends beyond cost considerations
and accordingly, finds that allowing the proposed EV charging station costs, as well as the
additional supporting infrastructure costs, into rate base strikes the right balance between the
monetary and non-monetary benefits associated with EV infrastructure deployment.
28.
The Proposed Agreement provides that the method for bi directional metering utilized by
Georgia Power under the Georgia Cogeneration and Distributed Generation Act of 2001 (“Cogen
Act”) O.C.G.A. § 46-3-51, to be considered as part of the PIA Staff review of the Company’s
methodology and computation of avoided cost in Docket No. 4822 that was provided for in the
Commission’s Final Order issued in Docket Nos. 42310 and 42311. It further provides that to the
extent Parties continue to raise such issues, the Commission will consider the Company’s bidirectional metering practice as part of that review. (Agreement Provision 31).
During the proceeding and in their Post Hearing Brief, GIPL/Southface/Vote Solar
maintained that the Cogen Act required monthly netting. They argued that monthly netting
allows solar customers to properly receive full value from their private investments.
(GIPL/Southface/Vote Solar Post Hearing Brief p. 15).
GSEA/GSEIA stated that the Company’s Renewable and Non-Renewable (“RNR”)
tariffs, including RNR-10 if approved, are consistently silent on netting and that since RNR
tariffs never identified a netting methodology, the Company cannot credibly claim that its netting
methodology was approved as a part thereof. GSEA/GSEIA urged the Commission to reject the
Company’s instantaneous netting methodology and direct it to implement monthly netting
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 consistent with normal metering practices during the billing period as required by the Co-Gen
Act.
Georgia Power stated that the Company’s implementation of the RNR tariff is compliant
with the Co-Gen Act and should not be overhauled to institute policy changes to increase
payments to customer generators as argued by Intervenors.
The Commission finds and concludes that the Proposed Agreement should be modified to
provide that the “Behind the Meter” netting period length shall be changed from instant to
monthly for the first 5000 rooftop solar ratepayers or until the new installed capacity reaches 32
MW, whichever comes first. Following that, any new rooftop solar ratepayers would be subject
to the current scheme of instant net metering. This will be re-evaluated in the next rate case.
29.
The Commission finds that the Proposed Agreement should be modified to provide that
the fee for Analog Meter Ratepayers shall be dropped by $1.00 per month. The Commission will
reevaluate the fee and this change in the next rate case.
The Commission finds and concludes that this reduction to the analog meter fee is
reasonable.
30.
In its filing, which the Proposed Agreement accepts by reference, the Company proposed
to convert the basic service charge in the tariffs within the Domestic Group to a daily amount.
Currently, a bill can be generated with the service period ranging from 25 to 36 days without
being prorated. This means that customers that experience a 36-day bill period incur the same
basic service charge as a customer whose bill only includes 25 days of service. Conversely, if a
bill is calculated using a daily basic service charge amount, the result will be based on the exact
number of days of service, which will make this portion of the bill more accurate and simpler for
customer to understand. (Tr. 757).
PIA Staff stated that the Company had not justified its request to prorate the BSC on a
daily basis. Currently, the BSC is the same for each month; it does not vary based on the number
of days in the month. (Tr. 2919). PIA Staff contended the Commission should require the
Company to continue the standard practice of 12 evenly monthly payments for customers who
pay monthly bills. (PIA Staff Brief at p. 46).
GIPL/Southface/Vote Solar stated that the Commission should reject the Company’s
request to switch from a monthly BSC to a daily BSC. Changing to a daily basic service charge
would “exacerbate monthly bill volatility, result in a charge that is less transparent and less
understandable for customers,” and the Company “did not identify any clear need for the
change.” Tr. 2082). Further, the Company stated that over the course of a year, any differences in

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 billing period will even out-meaning, all customers will ultimately pay the same total amount in
basic service charges without a switch to a daily charge. (Tr. 2920).
The Commission finds that converting the BSC in the tariffs within the Domestic Group
to a daily amount is reasonable is thus accepted.
31.
Although PIA Staff accepted the Company’s proposed $63.5 million for the projection of
storm damage charges for the test year and ARP years, they recommended a review of the
recovery mechanisms and that the Company’s storm damage costs be reviewed in detail. PIA
Staff also adjusted the Company’s estimate of the December 31, 2019 deferred storm damage
cost balance using actual charges for January through June 2019 in place of the Company’s
estimates for those months. The adjustment resulted in a slightly lower December 31, 2019
balance, which PIA Staff recommended be amortized over a three-year period. (Tr. 1158; Smith
and Trokey Direct at pp. 85-87).
PIA Staff’s recommendation that the Company’s storm damage costs be reviewed in a
separate investigation apart from the rate case stems from the fact that the Company’s deferred
amount has built up to over $400 million and most of that from storms occurring in recent years
since the Company’s 2013 rate case. The Company argued that a separate review and audit is
unnecessary because existing internal and external review channels provide sufficient
opportunity for the Company and Commission to audit the Company’s storm damage account
balance.
DOD/FEA recommended that the Commission approve an annual deferred cost recovery
mechanism and recovery rider for storm damage costs, rather than the past and proposed
Company practice in which it incorporates storm damage recovery directly in base rates.
(DOD/FEA Brief at p 9).
The Commission finds that it is appropriate to approve the continuation of the current
ratemaking treatment of such costs.
32.
PIA Staff recommended that the Company’s revenue requirement be adjusted by
$272,000 on a retail jurisdictional basis to reflect interest credits on minimum bank balances
stating that these interest credits offset its bank fees. The Company did not reflect these interest
credits in its rate case filing because the amount of the credits is uncertain since it cannot exactly
predict the minimum bank balances. (Tr. 309, 1226-27). PIA Staff argued that since the bank fees
the Company must pay are included in revenue requirement and collected from ratepayers, it
would be unfair for the Company to be able to keep the interest credits that offset the bank fees.

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 The Proposed Agreement does not include this adjustment and the Commission finds that
the Settlement Agreement as Modified is reasonable as a whole. Therefore, PIA Staff’s
recommendation is denied.
33.
The Company stated that the total compensation plan, including stock-based at-risk
compensation is market competitive and appropriately balances operational with financial focus
for both short-term and longer term to drive employee behavior in ways that balance the interests
of customers and shareholders alike. (GPC Post Hearing Brief pp. 49-55). Furthermore, the
Company stated that moving at-risk pay to base pay would not be in the best interest of
customers, however, as it would encourage employees to focus solely on short-term operational
performance with no balance or accountability to long-term operational costs and efficiencies.
(Id.). Therefore, the Company believes that stock-based compensation should be included in the
Company’s revenue requirements and recovered in retail rates.
PIA Staff stated in its post hearing brief that the Company incurs the costs of these
incentive compensation programs in an effort to improve the Southern Company financial
performance for the benefit of shareholders, not for the benefit of ratepayers. “For instance, the
purpose of these incentives is not to improve customer service or meet other regulated utility
service requirements. To the contrary, the objectives of maximizing shareholder value on the one
hand and minimizing costs to ratepayers on the other hand, are generally opposed to each other.
And the fact that maximizing shareholder value frequently does not serve the ratepayer interest
of lower rates for the service shows the fatal flaw in the argument that these financial incentives
should be seen as merely part of a compensation package, and as such, should be recovered from
ratepayers.”
The Proposed Agreement does not include this adjustment and the Commission finds that
the Settlement Agreement as Modified is reasonable as a whole. Therefore, PIA Staff’s
recommendation to remove the stock compensation plan from rate base is denied.
In conjunction with its adjustment to remove stock-based compensation, PIA Staff
recommended that the Company’s proposed ARP payroll tax expense be reduced by $1.484
million, $1.629 million and $1.732 million in 2020, 2021 and 2022, respectively. (Tr. 1239, PIA
Staff Exhibit 9).
For the same reasons that PIA Staff’s adjustment to remove stock-based compensation
was not adopted by the Commission, the corresponding payroll tax expense adjustment is denied.
34.
PIA Staff recommended removal of expenses related to Georgia Power’s executive
financial planning program, which provides personal financial planning, estate planning,
investment advice and tax planning and preparation to Georgia Power’s Chief Executive Officer,
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 Chief Operating Officer, Vice-Presidents and Directors. (Tr. 1234). PIA Staff’s position does not
prohibit the Company from offering its program to top executives. The Company’s position is
that ratepayers should pay for this cost for its top executives as those executives provide value to
the ratepayers. PIA Staff recommends that shareholders be held responsible for paying for the
program because this program is not necessary for the provision of safe and reliable electric
service.
The Proposed Agreement does not include this adjustment and the Commission finds that
the Settlement Agreement as Modified is reasonable as a whole. Therefore, PIA Staff’s
recommendation is denied.
35.
PIA Staff recommended that the Commission reject the Company’s requested
uncollectibles expense stating that it is inconsistent with its experience in recent years. Even
though the Company has incurred less than $12 million in uncollectibles expense in 2017 and
2018, it requested an uncollectibles expense of $13.445 million in the test year, $14.003 million
in 2020 and 2021 and $14.004 million in 2022. (Tr. 1240). PIA Staff argued that the Company
failed to identify a key driver for the inconsistency.
The Proposed Agreement does not include this adjustment and the Commission finds that
the Settlement Agreement as Modified is reasonable as a whole. Therefore, PIA Staff’s
recommendation is denied.
36.
PIA Staff proposed an adjustment to revenue requirement for property tax true-up.
Georgia Power has booked a property tax true-up in 14 of the past 17 years. (Tr. 1235, 2718).
Yet, Georgia Power declined to account for such a true-up in its rate case filing because it
claimed that the true-up cannot be predicted with certainty. (Tr. 2715). PIA Staff argued that the
Company’s approach is inconsistent both with Commission precedent and with how the
Company has addressed other items within this very rate case. The Commission adopted an
adjustment for property tax refunds in the 2010 rate case (Docket No. 31958). Therefore, the
PIA Staff recommended that the Commission adopt PIA Staff’s recommended $2.604 million
adjustment to reflect a reduction in the Company’s revenue requirement equal to the 17-year
average for property tax refunds received by Georgia Power.
The Proposed Agreement does not include this adjustment and the Commission finds that
the Settlement Agreement as Modified is reasonable as a whole. Therefore, PIA Staff’s
recommendation is denied.
37.
PIA Staff’s proposed recommendation regarding sharing of responsibility for the CCR
ARO amount for Plant Kraft and the benefits of donating Plant Kraft land to the Georgia Port
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 Authority stems from the authorization received by the Company from the Commission, in
Docket No. 36989, to donate a parcel of land at Plant Kraft to the Georgia Ports Authority. PIA
Staff argued that both the State of Georgia (through the receipt of the land by the Ports
Authority) and Georgia Power (through a boost to its reputation as a good corporate citizen) will
benefit from the donation of the land. PIA Staff argued that ratepayers should receive a benefit
as well. The Plant Kraft land that is to be donated includes the site of the coal ash pond which
appears to have been remediated. In order to provide some benefit to ratepayers as well as the
Company and the State, PIA Staff recommended that the Commission and the Company should
consider applying some of the donation-related tax savings that would otherwise be assigned
below-the-line to addressing the Plant Kraft ash pond clean-up cost. In the alternative, if the full
benefit of donating that land is to be retained by shareholders, PIA Staff's alternative
recommendation was that the related ash pond remediation costs also be allocated to
shareholders. PIA Staff asserted that this is equitable because the clean-up appears to have
increased the market value of the plant land that is to be donated and that it would be unfair for
ratepayers to pay for the clean-up and shareholders reap the full benefit of donating the land that
increased in value as a result of the clean-up. (PIA Staff Brief p. 37)
The Company proposed to follow the accounting requirements and process outlined in
the Commission’s October 16, 2018 Order Approving Donation of Tract-1 Land at Plant Kraft in
Docket No. 36989, which the Company argued approved the Company’s donation and the
proposed accounting treatment for the Plant Kraft land. See Order on Georgia Power Company’s
2016 Annual Surveillance Report, Docket No. 36989 (Jan. 19, 2018) at 2.
The Proposed Agreement does not include this adjustment and the Commission finds that
the Settlement Agreement as Modified is reasonable as a whole. Therefore, PIA Staff’s
recommendation is denied.
38.
The Company used the minimum distribution system (“MDS”) methodology in its Cost
of Service Study (“COSS”) to separate customer-related distribution system costs from demandrelated costs that customers place on the system. The Company explained that the MDS is a key
input of its COSS as it separates the cost of line transformers, primary and secondary lines, and
equipment, into demand-related costs, which are directly related to customer’s peak load
requirements, and customer-related costs, which are independent of customers’ peak load
requirements. Company Witness Vogt explained that Bonbright, NARUC, and several utilities
around the country acknowledge MDS as an acceptable method for allocating customer-related
distribution costs.
PIA Staff, GIPL/Southface/Vote Solar, and Sierra Club recommended that the
Commission require that the Company use the Basic Customer Method instead of MDS. PIA
Staff disagreed with the Company’s use of MDS for determining distribution costs caused by the
need to serve customers separate from customer demand placed on the system. Citing Bonbright,
PIA Staff faults the MDS technique because it does not vary with the number of customers and
loads customers with more fixed system costs. PIA Staff estimated that close to $8 of the
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 $20.87/month customer costs calculated in the COSS are MDS related. PIA Staff recommended
the Company remove the allocation of the MDS costs to customer service or strip out the MDS
effects on the monthly basic service charge it proposes.
The Company, in its rebuttal testimony, argued that MDS is more comprehensive than the
Basic Customer Method. According to the Company, MDS includes the costs identified using the
Basic Customer Method, and also includes the cost of equipment necessary to provide safe and
reliable service, which is not based on a customer’s demand and should be allocated as customerrelated. (See Tr. 2870.) The Company opposes classifying or collecting fixed customer-related
costs through the variable energy portion of customer rates. The Company requests permission to
continue relying upon the MDS methodology arguing that this approach yields a fair and
equitable assignment of costs to customers.
Commission approval of the Settlement Agreement as modified allows for the Company’s
continued use of the MDS methodology to determine the customer-related portion of distribution
costs.
39.
PIA Staff recommended that the Commission “require Georgia Power to perform an
evaluation of the use of monthly coincident peaks to reflect more precisely the months where
there is the potential for summer and winter peak demands to occur.” PIA Staff further explained
that “this could be done by utilization of an up to 8 CP approach, reflecting a proper balance of
assignment of fixed costs to both summertime and wintertime peaks.” (PIA Staff Brief at pp. 4344).
The Company refutes the idea that a non-coincident peak is an inappropriate base for
setting a demand charge. There are multiple demand costs to cover in a demand charge,
including distribution costs, which are based on a non-coincident peak. (Id.) Using the
Company’s existing time of use price signal keeps the rate simpler and easy to understand and
helps customers avoid extreme bill swings in summer months. (Id.) (Company Brief at p. 70).
The Commission accepts the Settlement Agreement as modified and requires no changes
at this time as it relates to this issue.
40.
PIA Staff requested that the Commission “order the Company to revise its wintertime
declining block rates to a flat energy rate. Just as the inclining block rate structure during the
summer sends a price signal that as consumption increases, so likely do system costs, a declining
block rate structure sends the opposite price signal that as consumption increases, system costs
decline.” (PIA Staff Post Hearing Brief at p. 44).
In response to PIA Staff, the Company stated that it “originally designed the residential
rate to reflect the seasonality of costs to serve residential customers.” (Tr. 2889.) “The
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 increasing price blocks in June through September reflect the fact that the Company’s costs are
higher in the summer months. (Id.) The declining block structure in the non-summer months
recognizes that off peak costs are lower and provides price signals to reflect this reality. (Id.) The
prices are set to more than cover the Company’s marginal costs and resulting revenues place
downward pressure on rates for all customers. (Id.) The Commission should reject requests to
change the declining block rate structure.” (Company Brief at p. 61).
GIPL/Southface/Vote Solar witnesses argued that Georgia Power should eliminate the
non-summer declining block portion and replace it with a flat tariff.
The Commission finds that non-summer declining block portion is reasonable as filed
and thus any change is denied.
41.
The Company has proposed several changes in the wording of its Flat-5 tariff. PIA Staff
stated that the Company’s proposed changes would remove the 12-month history requirement.
The effect would require “new Georgia Power customers, when establishing their account, to
choose the FlatBill tariff and be charged a monthly bill based on that premises, another
household’s, previous 12- month usage.” (Tr. 2924). PIA Staff recommended that “the
Commission reject these proposed revisions because the customer could end up with a higher or
lower bill as compared to the Residential service rate because usage is not based on that
resident’s actual historical 12-month usage.” (PIA Staff Brief at p. 49).
GIPL/Southface/Vote Solar believe that “FlatBill encourages wasteful use of electric
service contrary to basic principles of rate design.” GIPL/Southface/Vote Solar go on to argue
that the “flat monthly amount is determined by billing under the R tariff (plus a “risk” adder of
up to 10%), the very tariff the Company considers “antiquated” and proposes to move away
from.” (Tr. 1955). GIPL/Southface/Vote Solar further recommend that the Commission “reject
these less than ‘modern’ proposals.” (GIPL/Southface/Vote Solar Brief at pp. 8-11).
In accordance with the Commission’s approval of the Settlement Agreement as Modified,
the Company’s proposed changes are accepted.
42.
The Commission finds that the date on which the rates pursuant to the Settlement
Agreement as Modified shall become effective is January 1, 2020.
43.
The Commission finds that a three-year term for the Settlement Agreement as Modified
ending December 31, 2022 is reasonable. By July 1, 2022, the Company shall file testimony and
exhibits required in a general rate case along with supporting schedules required by the
Commission to support a “traditional” rate case. The test period utilized by the Company in its
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 rate case filing shall be from August 1, 2022 to July 31, 2023. The Company may propose to
continue, modify or discontinue this Alternate Rate Plan. The Company shall also file projected
revenue requirements for calendar years 2023, 2024, and 2025. (Proposed Agreement Provision
32).

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 CONCLUSIONS OF LAW
1.
The Georgia Public Service Commission has general ratemaking jurisdiction over
Georgia Power Company under O.C.G.A. Ch. 2, T. 46. The Georgia Public Service Commission
has general supervision over electric light and power companies. O.C.G.A. §§ 46-2-20(a) and
46-2-21. The Commission has “exclusive power to determine what are just and reasonable rates
and charges to be made by any person, firm, or corporation subject to its jurisdiction.” O.C.G.A.
§ 26-2-23; see also O.C.G.A. §§ 46-1-1(5), 46-2-24, 46-2-25, 46-2-26.1, and 46-2-26.2.
2.
The Settlement Agreement as Modified complies with the test year statute for electric
utilities which provides in relevant part:
In any proceeding to determine the rates to be charged by an electric utility, the
electric utility shall file jurisdictionally allocated cost of service data on the basis
of a test period, and the commission shall utilize a test period, consisting of actual
data for the most recent 12- month period for which data are available, fully
adjusted separately to reflect estimated operations during the 12 months following
the utility's proposed effective date of the rates. After the initial filing and until
new rates go into effect, the utility shall file actual cost of service data as they
become available for each month following the actual data which were filed. The
utility shall have the burden of explaining and supporting the reasonableness of all
estimates and adjustments contained in its cost of service data.
(O.C.G.A. § 46-2-26.1(b))
Georgia Power filed the requisite data on the basis of a test period, and the Settlement
Agreement as Modified uses the test period as a starting point and then makes necessary and
appropriate adjustments to reflect operations during the 12 months following the utility’s
proposed effective date of the rate. The test period data serves as the benchmark from which
adjustments are made for each year of the Alternative Rate Plan. This methodology is consistent
both with the statute and with Commission precedent in rate case proceedings dating back to
1998.
3.
The rates resulting from the Settlement Agreement as Modified are fair, just and
reasonable. By adopting the Settlement Agreement as Modified, the Commission retains its
jurisdiction to ensure that the Company’s rates are fair, just and reasonable.
4.

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 The remaining terms and conditions of the Settlement Agreement as Modified are
reasonable and appropriate. By adopting the Settlement Agreement as Modified, the
Commission adopts a reasonable resolution of the remaining issues in this docket.
5.
The Commission retains its jurisdiction to ensure that the Company abides by and
implements the rates, terms and conditions set forth in the Settlement Agreement as Modified
adopted herein, and to issue such further order or orders as this Commission may deem proper.
III.

ORDERING PARAGRAPHS

WHEREFORE, IT IS ORDERED, that the Settlement Agreement as Modified shall be
and the same hereby is adopted, that its terms and conditions are fully incorporated herein, and
that Georgia Power Company shall comply with said terms and conditions.
ORDERED FURTHER, that the terms and conditions set forth in the Settlement
Agreement as modified are just and reasonable and shall take effect for service rendered from
and after January 1, 2020.
ORDERED FURTHER, that the tariffs implemented by Georgia Power to implement
the aforesaid annual rate increase in the years 2020, the adjustments contemplated in 2021 and
2022, as well as the terms and conditions of the Settlement Agreement as Modified shall be
subject to review by the Commission to ensure that such tariffs, as implemented, are proper and
just.
ORDERED FURTHER, that for purposes of the rate increase in the year 2020, Georgia
Power shall file compliance tariffs within 30 days of the issuance of this Order, reflecting rates to
implement the rate increases ordered herein. These tariffs shall reflect the rate allocations
adopted in this Order, and shall be subject to the Commission's review for final approval.
ORDERED FURTHER, that for purposes of the rate adjustments specified in the
Settlement Agreement as Modified, the Company shall make compliance filings of the updated
tariffs at least 90 days prior to the effective date of the tariffs. Compliance filings shall be served
upon all parties of record to this proceeding. Upon receipt of such compliance filing, parties may
offer input relative to the filing to the Commission.
ORDERED FURTHER, that all findings, conclusions and decisions contained within
the preceding sections of this Order are adopted as findings of fact, conclusions of law, and
decisions of regulatory policy of this Commission.
ORDERED FURTHER, that jurisdiction over this proceeding is expressly retained for
the purpose of entering such further order or orders as this Commission may deem proper.

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 ORDERED FURTHER, any motion for reconsideration, rehearing, or oral argument
shall not stay the effectiveness of this order unless expressly ordered by the Commission.
The above by action of the Commission in Administrative Session on the 17th of
December, 2019, as clarified by action of the Commission in Administrative Session on the 4th
of February 2020.

_________________________
Reece McAlister
Executive Secretary

_________________________
Chuck Eaton
Chairman

_________________________
Date

__________________________
Date

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