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Regulatory Matters
 6 Months Ended
Jun. 30, 2019
Regulated Operations [Abstract]  
REGULATORY MATTERS REGULATORY MATTERS
See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.
The recovery balances for certain of Alabama Power's, Georgia Power's, and Mississippi Power's regulatory clauses at June 30, 2019 and December 31, 2018 were as follows:
Regulatory Clause
Balance Sheet Line Item
June 30,
2019
December 31,
2018
 
 
(in millions)
Alabama Power
 
 
 
Rate CNP Compliance
Deferred under recovered regulatory clause revenues
$
—

$
42

 
Customer accounts receivable
10

—

Rate CNP PPA
Deferred under recovered regulatory clause revenues
25

25

Retail Energy Cost Recovery(*)
Deferred under recovered regulatory clause revenues
—

109

 
Customer accounts receivable
8

—

Natural Disaster Reserve
Other regulatory liabilities, deferred
19

20

Georgia Power
 
 
 
Fuel Cost Recovery
Receivables – under recovered fuel clause revenues
$
69

$
115

Mississippi Power
 
 
 
Fuel Cost Recovery
Over recovered regulatory clause liabilities
$
9

$
8

(*)
In accordance with an accounting order issued on February 5, 2019 by the Alabama PSC, Alabama Power utilized $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
Alabama Power
Environmental Accounting Order
On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
Georgia Power
Rate Plans
On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.
Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:
Tariff
2020
2021
2022
 
(in millions)
Traditional base:
 
 
 
Levelized
$
209

$
—

$
—

CCR AROs
158

140

227

Environmental Compliance Cost Recovery
165

—

—

Demand-Side Management
14

2

1

Municipal Franchise Fee
17

3

5

Total(*)
$
563

$
145

$
234

(*)
Totals may not add due to rounding.
Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:
•
Continuation of an allowed retail ROE range of 10.00% to 12.00%.
•
Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.
•
Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.
Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.
On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.
In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.
For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book
values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.
Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's or Southern Company's financial statements.
Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.
The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.
See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.
Nuclear Construction
See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work,
certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
 
(in billions)
Base project capital cost forecast(a)(b)
$
8.0

Construction contingency estimate
0.4

Total project capital cost forecast(a)(b)
8.4

Net investment as of June 30, 2019(b)
(5.2
)
Remaining estimate to complete(a)
$
3.2

(a)
Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.
(b)
Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.
As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2019, Georgia Power had recovered approximately $2.0 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.
In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures
related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).
On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.
The ultimate outcome of these matters cannot be determined at this time.
DOE Financing
At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Municipal and Rural Association Tariff
On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA settlement agreement, base rates decreased $3.7 million annually, effective January 1, 2019.
Environmental Compliance Overview Plan
On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Note (C) under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.
Kemper County Energy Facility
As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020,
with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO2 pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO2 pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements and could have a material impact on Southern Company's financial statements.
In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's and Southern Company's financial statements.
Southern Company Gas
Rate Proceedings
Nicor Gas
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Atlanta Gas Light
On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In December 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide for timely recovery of capital expenditures for specific infrastructure replacement programs.
Virginia Natural Gas
On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its Steps to Advance Virginia's Energy program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.
Affiliate Asset Management Agreements
On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021.
FERC Matters
See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.
On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of any of the traditional electric operating companies or Southern Company.