Base project capital cost forecast(a)(b) | $ | 8.4 | | | Construction contingency estimate | 0.1 | | | | Total project capital cost forecast(a)(b) | Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million. |
| 8.5 | | Net investment as of September 30, 2020(b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.(6.9) | | Remaining estimate to complete(a) | $ | 1.6 | |
As(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $240 million, of which $71 million had been accrued through September 30, 2019,2020.
(b) Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $30$188 million of the construction contingency estimate was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program, and start-up; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.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$3.0 billion, of which $2.1$2.5 billion had been incurred through September 30, 2019.2020. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. As of June 30, 2020, assignments of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement, among other factors. As a result of these factors, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery. During the third quarter 2020, approximately $5 million of the construction contingency established in the second quarter 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support. 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. 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. 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, particularly in the installation of electrical and mechanical commodities, 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 aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approvedregulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. To support that strategy,Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values will continueduring 2020. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase significantly throughoutin, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan. To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. Through October 2020, the remainderproject has faced challenges in meeting the July 2020 aggressive site work plan targets including, but not limited to, overall construction and subcontractor labor productivity, which has resulted in a backlog of 2019activities and into 2020. To meetcompletion percentages below the July 2020 aggressive site work plan targets. In addition, while the number of active COVID-19 cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. After considering these increasing monthly targets, existing craftfactors, Southern Nuclear has further extended milestone dates from the July 2020 aggressive site work plan. Achievement of these extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity must improve and additionalproduction levels, including subcontractors, significantly improving and being sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, (particularlyparticularly electrical and pipefitter craft labor)labor, need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates. As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), as well asany of which may require additional supervisionlabor and/or materials; or other issues could arise and other fieldchange the projected schedule and estimated cost.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support resources, mustactivities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be retainedbetween $70 million and deployed.$115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. 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
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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. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On June 15, 2020, the NRC rejected Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. On August 10, 2020, the Atomic Safety and Licensing Board rejected the Blue Ridge Environmental Defense League's (BREDL) May 11, 2020 petition challenging a license amendment request. The staff of the NRC has issued the requested amendment to the combined construction and operating license for Plant Vogtle Unit 3. BREDL appealed the Atomic Safety and Licensing Board decision to the NRC. 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 $11$10 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 thean 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 in 2018, 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Amendments to the Vogtle Joint Ownership Agreements In connection with the vote to continue construction, Georgia Power entered into (i) the Vogtlea binding term sheet (Vogtle Owner Term SheetSheet) with the other Vogtle Owners and MEAG'sMEAG Power'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) thea term sheet (MEAG Term Sheet) with MEAG Term Sheet with MEAGPower and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. OnIn January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. OnIn February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'sMEAG Power'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.Sheet (Global Amendments). As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. 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
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billion. At September 30, 2019,2020, Georgia Power had recovered approximately $2.1$2.5 billion of financing costs. Financing costs related to capital costs above $4.418 billion willare being recognized through AFUDC and are expected
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) to be recovered through AFUDC;retail rates over the life of Plant Vogtle Units 3 and 4; 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 JanuaryOn October 1, 2019.2020, Georgia Power expects to file on November 1, 2019filed a request to decrease the NCCR tariff by approximately $65$142 million annually, effective January 1, 2020,2021, pending Georgia PSC approval. 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)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$75 million in 20182019 and are estimated to have negative earnings impacts of approximately $70$145 million, $255 million, and $200 million in 20192020, 2021, and an aggregate of approximately $650 million from 2020 to 2022. 2022, respectively. 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 two2 appeals. OnIn January 9, 2019, GIPL, PSE,
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and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. OnIn October 29, 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power believesPower's motion to dismiss the petitions have no merit; however, an adverse outcome in2 appeals. The petitioners filed a notice of appeal of the litigation combined with subsequent adverse action by the Georgia PSC could have a material impactdismissal on Southern Company's results of operations, financial condition, and liquidity.May 20, 2020, which was withdrawn on August 20, 2020. This matter is now concluded. The Georgia PSC has approved nineteen22 VCM reports covering the periodperiods through June 30, 2018,December 31, 2019, including total construction capital costs incurred through that date of $5.4$7.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds)customer refunds). On August 30, 2019, Georgia Power filed its twentieth VCM report concurrently with its twenty-firsttwenty-third VCM report with the Georgia PSC on August 31, 2020, which requestedreflects the capital cost forecast discussed above and requests approval of $1.2 billion$701 million of construction capital costs incurred from JulyJanuary 1, 20182020 through June 30, 2019. In the nineteenth VCM, the Georgia PSC deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. 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 also requested approval of $21.5 million of associated expenditures previously deferred for approval by the Georgia PSC. The remaining $30.1 million deferred for approval was refunded to Georgia Power and credited to the total construction capital costs.2020.
The ultimate outcome of these matters cannot be determined at this time. See RISK FACTORS
Mississippi Power 2019 Base Rate Case On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement). Under the terms of Southern Companythe Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment. Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the Form 10-Kapproved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for a discussion of certain riskscosts associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the licensing, construction,PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywherePEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021. Performance Evaluation Plan On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the world.Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause. DOE FinancingDeferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 26, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At September 30, 2019, Georgia Power had borrowed $3.46 billion related2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Municipal and 4Rural Associations Tariff On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020. Southern Company Gas Rate Proceedings On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of$49.6 million primarily to recover investments and increased costs as provided through the Amendedassociated with infrastructure, technology, and Restated Loan Guarantee Agreementworkforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowingsan equity ratio of up54%. Rate adjustments are expected to approximately $5.130 billion,be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the satisfactionrequested increase in the second quarter 2021. On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of certain conditions. See Note 8 to$37.6 million based on the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings"projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in Item 8its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021. The ultimate outcome of these matters cannot be determined at this time. Deferral of Incremental COVID-19 Costs Atlanta Gas PipelineLight On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its future GRAM filings, which would impact rates starting on January 1, 2022. The ultimate outcome of this matter cannot be determined at this time. Nicor Gas On March 18, 2020, in response to the COVID-19 pandemic, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and providing more flexible credit and collection plans. On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. Nicor Gas resumed late payment fees on July 27, 2020 and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts through the special purpose rider, which will continue over a 24-month period. In response to an Illinois Commission request, Nicor Gas will continue to voluntarily suspend residential customer disconnections for non-payment through March 31, 2021. At September 30, 2020, Nicor Gas' related regulatory asset was $13 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Virginia Natural Gas In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which expired on October 5, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At September 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time. Infrastructure Replacement Programs and Capital Projects In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time. (C) CONTINGENCIES See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern CompanyNote 3 to the financial statements in Item 78 of the Form 10-K for additional information.information relating to various lawsuits and other contingencies. In 2014, Southern Company Gas entered into a joint venture, whereby it holds a 5% ownership interest in the Atlantic Coast Pipeline, an interstate pipeline company which will develop and operate a 605-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with expected initial transportation capacity of 1.5 Bcf per day.
General Litigation Matters The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. The delays resulting from the permitting issues have impacted the cost and schedule for the project. As a result, total current project cost estimates have increased from between $7.0 billion
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and $7.8 billion ($350 million and $390 million for Southern Company Gas) to between $7.3 billion and $7.8 billion ($365 million and $390 million for Southern Company Gas), excluding financing costs. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.
Also in 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate a 118-mile natural gas pipeline between New Jersey and Pennsylvania. The expected initial transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly with public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York.
On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal court eminent domain authority over lands in which a state has property rights interests. The joint venture is pursuing appellate and other options and is evaluating further next steps.
The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, which could result in an impairment of one or both of Southern Company Gas' investments and could have a material impact on Southern Company's financial statements.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 for additional information.
Southern Company and its subsidiariesRegistrants are involved in various other matters that could affect future earnings, including matters being litigated as well as otherand regulatory matters and matters that could result in asset impairments. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters or potential asset impairmentsagainst each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company'ssuch Registrant's financial statements. See Notes (B) and (C) to The Registrants believe the Condensed Financial Statements herein for a discussionpending legal challenges discussed below have no merit; however, the ultimate outcome of various other contingencies, regulatorythese matters and other matters being litigated which may affect future earnings potential. Litigationcannot be determined at this time.
Southern Company In January 2017, a securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges thatnames as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismisseddismissing certain claims against certain officers of Southern Company and Mississippi Power and dismisseddismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. On August 22,In the third quarter 2019, the court certified the plaintiffs' proposed class. On September 5, 2019,class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines. On August 15, 2020, the parties reached a settlement. On September 8, 2020, the plaintiffs filed a stipulation of settlement and motion for preliminary approval to resolve the case on a class-wide basis, which the court granted on October 1, 2020. The settlement amount will be paid entirely through existing insurance policies and is not expected to have a material impact on Southern Company's financial statements. In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two2 shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On September 25, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020. In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. OnIn August 5, 2019, the court granted a motion filed by the plaintiff onin July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust. On September 30, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020. Southern Company believes these legal challenges have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Georgia Power In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari withone recent appeal, the Georgia Supreme Court which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case toand noted that the trial court for further proceedings.could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, onin February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. On October 23, 2019, the Georgia PSC issued an order that found and concluded that Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no merit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. Southern Company believes this legal challenge has no merit; however, an adverse outcome could have a material impact on Southern Company's financial statements. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Southern Company Gas
See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana.
As of September 30, 2019, management no longer plans to obtain the core samples during 2020 that are necessary to determine the composition of the sheath surrounding the edge of the salt dome. Core sampling is a requirement of the Louisiana Department of Natural Resources to put the cavern back in service; as a result, the cavern will not return to service by 2021. This change in plan, which affects the future operation of the entire storage facility, resulted in a pre-tax impairment charge of $92 million ($65 million after-tax). Southern Company Gas will continue to monitor the pressure and overall structural integrity of the entire facility pending any future decisions regarding decommissioning.
Southern Company Gas has two other natural gas storage facilities located in California and Texas, which could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Sustained diminished natural gas storage values could trigger impairment of either of these natural gas storage facilities, which have a combined net book value of $328 million at September 30, 2019.
The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at September 30, 2019. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $4.9 billion for the first nine months of 2019, a decrease of $0.7 billion from the corresponding period in 2018. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash used for investing activities totaled $1.1 billion for the first nine months of 2019 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, largely offset by the proceeds from the sale of Gulf Power. Net cash used for financing activities totaled $2.4 billion for the first nine months of 2019 primarily due to net repayments of short-term bank debt and commercial paper and common stock dividend payments, partially offset by net issuances of long-term debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Significant balance sheet changes for the first nine months of 2019 include:
decreases in assets and liabilities held for sale of $5.1 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power;
an increase of $0.9 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, net of $1.2 billion and $1.0 billion reclassified to other regulatory assets and regulatory assets associated with AROs, respectively, as a result of generating unit retirements at Alabama Power and Georgia Power;
an increase of $2.8 billion in total stockholders' equity primarily related to the gain on the sale of Gulf Power;
a decrease of $2.4 billion in notes payable related to net repayments of short-term bank debt and commercial paper;
| | • | increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.8 billion, recorded upon the adoption of FASB ASC Topic 842, Leases;
|
an increase of $1.5 billion in regulatory assets associated with AROs primarily related to the reclassification of $1.0 billion from property, plant, and equipment as a result of certain generating unit retirements at Alabama Power and Georgia Power, as discussed above, and ARO revisions at Alabama Power and Mississippi Power related to the CCR Rule;
an increase of $1.5 billion in long-term debt (including amounts due within one year) related to net issuances of long-term debt;
an increase in cash and cash equivalents of $1.5 billion primarily related to long-term debt issued during the third quarter 2019; and
an increase of $1.2 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power.
See Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional information.
At the end of the third quarter 2019, the market price of Southern Company's common stock was $61.77 per share (based on the closing price as reported on the NYSE) and the book value was $26.23 per share, representing a market-to-book ratio of 235%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the third quarter 2019 was $0.62 per share compared to $0.60 per share in the third quarter 2018.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements and contractual obligations. Approximately $3.3 billion will be required through September 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
execute its growth strategy. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; 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; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2019, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from its pending asset sale. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.
In addition, in 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities, under which Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that certain conditions are met. At September 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities. See Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information.
Southern Company's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
cash needs. As of September 30, 2019, Southern Company's current liabilities exceeded current assets by $0.6 billion, primarily due to long-term debt that is due within one year and notes payable totaling $3.9 billion (including approximately $0.6 billion at the parent company, $1.8 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.9 billion at Southern Power, and $0.3 billion at Southern Company Gas), partially offset by $2.9 billion of cash and cash equivalents. To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
Committed credit arrangements with banks at September 30, 2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | Expires | | | | | | Company | 2020 | 2022 | 2024 | | Total | | Unused | | Due within One Year | | | (in millions) | Southern Company(a) | $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | Alabama Power | 3 |
| 525 |
| 800 |
| | 1,328 |
| | 1,328 |
| | 3 |
| | Georgia Power | — |
| — |
| 1,750 |
| | 1,750 |
| | 1,733 |
| | — |
| | Mississippi Power | — |
| 150 |
| — |
| | 150 |
| | 150 |
| | — |
| Southern Power(b) | — |
| — |
| 600 |
| | 600 |
| | 591 |
| | — |
| Southern Company Gas(c) | — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| | — |
| | Other | 30 |
| — |
| — |
| | 30 |
| | 30 |
| | 30 |
| | Southern Company Consolidated | $ | 33 |
| $ | 675 |
| $ | 6,900 |
| | $ | 7,608 |
| | $ | 7,576 |
| | $ | 33 |
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| | (a) | Represents the Southern Company parent entity. |
| | (b) | Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at September 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement.
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| | (c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
|
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as the term loan arrangements of Alabama Power, Georgia Power, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2019 was approximately $1.4 billion. In addition, at September 30, 2019, Alabama Power had approximately $87 million of revenue bonds outstanding that are required to be remarketed within the next 12 months.
The registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | | | Short-term Debt at September 30, 2019 | | Short-term Debt During the Period(*) | | | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | | | (in millions) | | | | (in millions) | | | | (in millions) | | Commercial paper | | $ | 292 |
| | 2.2 | % | | $ | 976 |
| | 2.5 | % | | $ | 1,509 |
| | Short-term bank debt | | 250 |
| | 2.5 | % | | 250 |
| | 2.7 | % | | 250 |
| | Total | | $ | 542 |
| | 2.4 | % | | $ | 1,226 |
| | 2.6 | % | | |
| | (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2019. |
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At September 30, 2019, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2019 were as follows:
| | | | | | Credit Ratings | Maximum Potential
Collateral
Requirements | | | (in millions) | | At BBB and/or Baa2 | $ | 32 |
| | At BBB- and/or Baa3 | $ | 433 |
| At BB+ and/or Ba1(*) | $ | 1,894 |
|
| | (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $44 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On August 1, 2019, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to Baa2 from Baa3 and maintained the positive rating outlook.
On September 12, 2019, S&P upgraded the senior unsecured long-term debt rating of Alabama Power to A from A-, the long-term issuer rating of Nicor Gas to A from A-, and the senior secured debt rating of Nicor Gas to A+ from A. The ratings outlooks remained negative.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and most of its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions, including approvals and requests for additional or continued adjustments of capital structure related to the Tax Reform Legislation for Alabama Power, Georgia Power, Atlanta Gas Light, and Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
Financing Activities
During the first nine months of 2019, Southern Company issued approximately 15.0 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $623 million.
In August 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net proceeds from the issuance were approximately $1.682 billion. Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash. See Note (F) to the Condensed Financial Statements under "Equity Units" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | Company | Senior Note Issuances | | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | | | (in millions) | Southern Company(b) | $ | — |
| | $ | 2,400 |
| | $ | — |
| | $ | — |
| | $ | 1,725 |
| | $ | — |
| | Alabama Power | 600 |
| | 200 |
| | — |
| | — |
| | — |
| | 1 |
| | Georgia Power | 750 |
| | — |
| | 584 |
| | 223 |
| | 835 |
| | 11 |
| | Mississippi Power | — |
| | — |
| | 43 |
| | — |
| | — |
| | — |
| | Southern Company Gas | — |
| | 300 |
| | — |
| | — |
| | 200 |
| | 50 |
| | Other | — |
| | — |
| | — |
| | 25 |
| | — |
| | 14 |
| Elimination(c) | — |
| | — |
| | — |
| | — |
| | — |
| | (7 | ) | | Southern Company Consolidated | $ | 1,350 |
| | $ | 2,900 |
| | $ | 627 |
| | $ | 248 |
| | $ | 2,760 |
| | $ | 69 |
|
| | (a) | Includes reductions in finance lease obligations resulting from cash payments under finance leases. |
| | (b) | Represents the Southern Company parent entity. |
| | (c) | Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements. |
Except as otherwise described herein, Southern Company and its subsidiaries used or will use the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used or will use the proceeds for their construction programs.
In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.
Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.
In September 2019, Southern Company redeemed all $300 million aggregate principal amount of its Series 2017A Floating Rate Senior Notes due September 30, 2020.
As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.
In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.
In August 2019, Nicor Gas issued $200 million aggregate principal amount of first mortgage bonds in a private placement. Nicor Gas entered into an agreement to issue an additional $100 million aggregate principal amount of first mortgage bonds on October 30, 2019.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2019, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K. Also see Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
| | (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
| | (b) | Changes in internal controls over financial reporting. |
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Operating Revenues: | | | | | | | | | Retail revenues | $ | 1,694 |
| | $ | 1,584 |
| | $ | 4,286 |
| | $ | 4,208 |
| | Wholesale revenues, non-affiliates | 71 |
| | 74 |
| | 194 |
| | 213 |
| | Wholesale revenues, affiliates | 2 |
| | 14 |
| | 66 |
| | 96 |
| | Other revenues | 74 |
| | 68 |
| | 216 |
| | 199 |
| | Total operating revenues | 1,841 |
| | 1,740 |
| | 4,762 |
| | 4,716 |
| | Operating Expenses: | | | | | | | | | Fuel | 310 |
| | 356 |
| | 864 |
| | 1,028 |
| | Purchased power, non-affiliates | 77 |
| | 64 |
| | 160 |
| | 176 |
| | Purchased power, affiliates | 73 |
| | 69 |
| | 164 |
| | 149 |
| | Other operations and maintenance | 409 |
| | 401 |
| | 1,221 |
| | 1,191 |
| | Depreciation and amortization | 195 |
| | 192 |
| | 593 |
| | 570 |
| | Taxes other than income taxes | 101 |
| | 97 |
| | 301 |
| | 289 |
| | Total operating expenses | 1,165 |
| | 1,179 |
| | 3,303 |
| | 3,403 |
| | Operating Income | 676 |
| | 561 |
| | 1,459 |
| | 1,313 |
| | Other Income and (Expense): | | | | | | | | | Allowance for equity funds used during construction | 13 |
| | 16 |
| | 41 |
| | 43 |
| | Interest expense, net of amounts capitalized | (83 | ) | | (82 | ) | | (248 | ) | | (240 | ) | | Other income (expense), net | 11 |
| | 9 |
| | 36 |
| | 24 |
| | Total other income and (expense) | (59 | ) | | (57 | ) | | (171 | ) | | (173 | ) | | Earnings Before Income Taxes | 617 |
| | 504 |
| | 1,288 |
| | 1,140 |
| | Income taxes | 144 |
| | 127 |
| | 295 |
| | 272 |
| | Net Income | 473 |
| | 377 |
| | 993 |
| | 868 |
| | Dividends on Preferred Stock | 4 |
| | 4 |
| | 11 |
| | 11 |
| | Net Income After Dividends on Preferred Stock | $ | 469 |
| | $ | 373 |
| | $ | 982 |
| | $ | 857 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Net Income | $ | 473 |
| | $ | 377 |
| | $ | 993 |
| | $ | 868 |
| | Other comprehensive income (loss): | | | | | | | | | Qualifying hedges: | | | | | | | | Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 3 |
| | 3 |
| | Total other comprehensive income (loss) | 1 |
| | 1 |
| | 3 |
| | 3 |
| | Comprehensive Income | $ | 474 |
| | $ | 378 |
| | $ | 996 |
| | $ | 871 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | | | | | | | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | | (in millions) | | Operating Activities: | | | | | Net income | $ | 993 |
| | $ | 868 |
| | Adjustments to reconcile net income to net cash provided from operating activities — | | | | | Depreciation and amortization, total | 756 |
| | 683 |
| | Deferred income taxes | 148 |
| | 104 |
| | Allowance for equity funds used during construction | (41 | ) | | (43 | ) | | Pension, postretirement, and other employee benefits | (30 | ) | | (17 | ) | | Settlement of asset retirement obligations | (76 | ) | | (31 | ) | | Other, net | 17 |
| | 11 |
| | Changes in certain current assets and liabilities — | | | | | -Receivables | (115 | ) | | (207 | ) | | -Prepayments | (30 | ) | | (26 | ) | | -Materials and supplies | 11 |
| | (69 | ) | | -Other current assets | (30 | ) | | 66 |
| | -Accounts payable | (267 | ) | | (194 | ) | | -Accrued taxes | 149 |
| | 225 |
| | -Accrued compensation | (55 | ) | | (41 | ) | | -Other current liabilities | 41 |
| | 60 |
| | Net cash provided from operating activities | 1,471 |
| | 1,389 |
| | Investing Activities: | | | | | Property additions | (1,239 | ) | | (1,529 | ) | | Nuclear decommissioning trust fund purchases | (201 | ) | | (207 | ) | | Nuclear decommissioning trust fund sales | 201 |
| | 207 |
| | Cost of removal, net of salvage | (79 | ) | | (78 | ) | | Change in construction payables | (99 | ) | | 30 |
| | Other investing activities | (22 | ) | | (23 | ) | | Net cash used for investing activities | (1,439 | ) | | (1,600 | ) | | Financing Activities: | | | | | Proceeds — | | | | | Senior notes | 600 |
| | 500 |
| | Capital contributions from parent company | 1,252 |
| | 495 |
| | Redemptions — Senior notes | (200 | ) | | — |
| | Payment of common stock dividends | (633 | ) | | (602 | ) | | Other financing activities | (27 | ) | | (24 | ) | | Net cash provided from financing activities | 992 |
| | 369 |
| | Net Change in Cash, Cash Equivalents, and Restricted Cash | 1,024 |
| | 158 |
| | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 313 |
| | 544 |
| | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 1,337 |
| | $ | 702 |
| | Supplemental Cash Flow Information: | | | | | Cash paid during the period for — | | | | | Interest (net of $15 and $15 capitalized for 2019 and 2018, respectively) | $ | 246 |
| | $ | 220 |
| | Income taxes, net | 89 |
| | 30 |
| | Noncash transactions — Accrued property additions at end of period | 173 |
| | 275 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Assets | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Assets: | | | | | | Cash and cash equivalents | | $ | 1,337 |
| | $ | 313 |
| | Receivables — | | | | | | Customer accounts receivable | | 501 |
| | 403 |
| | Unbilled revenues | | 172 |
| | 150 |
| | Affiliated | | 48 |
| | 94 |
| | Other accounts and notes receivable | | 70 |
| | 51 |
| | Accumulated provision for uncollectible accounts | | (21 | ) | | (10 | ) | | Fossil fuel stock | | 163 |
| | 141 |
| | Materials and supplies | | 524 |
| | 546 |
| | Prepaid expenses | | 64 |
| | 66 |
| | Other regulatory assets | | 204 |
| | 137 |
| | Other current assets | | 24 |
| | 18 |
| | Total current assets | | 3,086 |
| | 1,909 |
| | Property, Plant, and Equipment: | | | | | | In service | | 29,648 |
| | 30,402 |
| | Less: Accumulated provision for depreciation | | 9,465 |
| | 9,988 |
| | Plant in service, net of depreciation | | 20,183 |
| | 20,414 |
| | Nuclear fuel, at amortized cost | | 304 |
| | 324 |
| | Construction work in progress | | 827 |
| | 1,113 |
| | Total property, plant, and equipment | | 21,314 |
| | 21,851 |
| | Other Property and Investments: | | | | | | Equity investments in unconsolidated subsidiaries | | 64 |
| | 65 |
| | Nuclear decommissioning trusts, at fair value | | 975 |
| | 847 |
| | Miscellaneous property and investments | | 127 |
| | 127 |
| | Total other property and investments | | 1,166 |
| | 1,039 |
| | Deferred Charges and Other Assets: | | | | | | Operating lease right-of-use assets, net of amortization | | 143 |
| | — |
| | Deferred charges related to income taxes | | 241 |
| | 240 |
| | Deferred under recovered regulatory clause revenues | | 45 |
| | 116 |
| | Regulatory assets – asset retirement obligations | | 1,047 |
| | 147 |
| | Other regulatory assets, deferred | | 1,788 |
| | 1,240 |
| | Other deferred charges and assets | | 189 |
| | 188 |
| | Total deferred charges and other assets | | 3,453 |
| | 1,931 |
| | Total Assets | | $ | 29,019 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Liabilities and Stockholder's Equity | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Liabilities: | | | | | | Securities due within one year | | $ | 1 |
| | $ | 201 |
| | Accounts payable — | | | | | | Affiliated | | 351 |
| | 364 |
| | Other | | 317 |
| | 614 |
| | Customer deposits | | 99 |
| | 96 |
| | Accrued taxes | | 167 |
| | 44 |
| | Accrued interest | | 74 |
| | 89 |
| | Accrued compensation | | 171 |
| | 227 |
| | Asset retirement obligations | | 153 |
| | 163 |
| | Other current liabilities | | 122 |
| | 161 |
| | Total current liabilities | | 1,455 |
| | 1,959 |
| | Long-term Debt | | 8,520 |
| | 7,923 |
| | Deferred Credits and Other Liabilities: | | | | | | Accumulated deferred income taxes | | 3,134 |
| | 2,962 |
| | Deferred credits related to income taxes | | 2,001 |
| | 2,027 |
| | Accumulated deferred ITCs | | 102 |
| | 106 |
| | Employee benefit obligations | | 296 |
| | 314 |
| | Operating lease obligations | | 109 |
| | — |
| | Asset retirement obligations, deferred | | 3,400 |
| | 3,047 |
| | Other cost of removal obligations | | 441 |
| | 497 |
| | Other regulatory liabilities | | 151 |
| | 69 |
| | Other deferred credits and liabilities | | 33 |
| | 58 |
| | Total deferred credits and other liabilities | | 9,667 |
| | 9,080 |
| | Total Liabilities | | 19,642 |
| | 18,962 |
| | Redeemable Preferred Stock | | 291 |
| | 291 |
| Common Stockholder's Equity (See accompanying statements) | | 9,086 |
| | 7,477 |
| | Total Liabilities and Stockholder's Equity | | $ | 29,019 |
| | $ | 26,730 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total | | | (in millions) | | Balance at December 31, 2017 | 31 |
| | $ | 1,222 |
| | $ | 2,986 |
| | $ | 2,647 |
| | $ | (26 | ) | | $ | 6,829 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 225 |
| | — |
| | 225 |
| | Capital contributions from parent company | — |
| | — |
| | 488 |
| | — |
| | — |
| | 488 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (202 | ) | | — |
| | (202 | ) | | Other | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) | | Balance at March 31, 2018 | 31 |
| | 1,222 |
| | 3,474 |
| | 2,670 |
| | (31 | ) | | 7,335 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 259 |
| | — |
| | 259 |
| | Capital contributions from parent company | — |
| | — |
| | 5 |
| | — |
| | — |
| | 5 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (200 | ) | | — |
| | (200 | ) | | Other | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | Balance at June 30, 2018 | 31 |
| | 1,222 |
| | 3,480 |
| | 2,729 |
| | (30 | ) | | 7,401 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 373 |
| | — |
| | 373 |
| | Capital contributions from parent company | — |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (200 | ) | | — |
| | (200 | ) | | Balance at September 30, 2018 | 31 |
| | $ | 1,222 |
| | $ | 3,490 |
| | $ | 2,902 |
| | $ | (29 | ) | | $ | 7,585 |
| | | | | | | | | | | | | | | Balance at December 31, 2018 | 31 |
| | $ | 1,222 |
| | $ | 3,508 |
| | $ | 2,775 |
| | $ | (28 | ) | | $ | 7,477 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 217 |
| | — |
| | 217 |
| | Capital contributions from parent company | — |
| | — |
| | 1,236 |
| | — |
| | — |
| | 1,236 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) | | Balance at March 31, 2019 | 31 |
| | 1,222 |
| | 4,744 |
| | 2,781 |
| | (27 | ) | | 8,720 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 296 |
| | — |
| | 296 |
| | Capital contributions from parent company | — |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) | | Balance at June 30, 2019 | 31 |
| | 1,222 |
| | 4,767 |
| | 2,866 |
| | (26 | ) | | 8,829 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 469 |
| | — |
| | 469 |
| | Return of capital to parent company | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (211 | ) | | — |
| | (211 | ) | | Balance at September 30, 2019 | 31 |
| | $ | 1,222 |
| | $ | 4,765 |
| | $ | 3,124 |
| | $ | (25 | ) | | $ | 9,086 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2019 vs. THIRD QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
On September 6, 2019, Alabama Power filed a petition for a CCN with the Alabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility and long-term contracts for the purchase of power from others, as well as the acquisition of an existing combined cycle facility. In addition, Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) |
| (% change) |
| (change in millions) |
| (% change) | | $96 | | 25.7 | | $125 | | 14.6 |
Alabama Power's net income after dividends on preferred stock for the third quarter 2019 was $469 million compared to $373 million for the corresponding period in 2018. Alabama Power's net income after dividends on preferred stock for year-to-date 2019 was $982 million compared to $857 million for the corresponding period in 2018. These increases were primarily due to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation as well as additional capital investments recovered through Rate CNP Compliance, partially offset by a reduction in customer usage. In addition, the increase in the third quarter 2019 was due to warmer weather compared to the corresponding period in 2018. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $110 | | 6.9 | | $78 | | 1.9 |
In the third quarter 2019, retail revenues were $1.69 billion compared to $1.58 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $4.29 billion compared to $4.21 billion for the corresponding period in 2018.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | Third Quarter 2019 |
| Year-to-Date 2019 | | | (in millions) |
| (% change) |
| (in millions) |
| (% change) | | Retail – prior year | $ | 1,584 |
| | | | $ | 4,208 |
| | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | 119 |
| | 7.4 | % | | 214 |
| | 5.1 | % | | Sales decline | (29 | ) | | (1.8 | ) | | (60 | ) | | (1.4 | ) | | Weather | 33 |
| | 2.1 |
| | 15 |
| | 0.4 |
| | Fuel and other cost recovery | (13 | ) | | (0.8 | ) | | (91 | ) | | (2.2 | ) | | Retail – current year | $ | 1,694 |
| | 6.9 | % | | $ | 4,286 |
| | 1.9 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 2.1% and 2.0% in the third quarter and year-to-date 2019, respectively, and weather-adjusted commercial KWH sales decreased 2.4% in each of the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. These decreases primarily resulted from more energy-efficient residential appliances and customer initiatives in energy savings for commercial customers. Industrial KWH sales decreased 3.0% in the third quarter 2019 when compared to the corresponding period in 2018 as a result of reductions in production levels, primarily in the primary metals sector, partially offset by an increase in demand in the chemicals sector. Industrial KWH sales decreased 3.1% year-to-date 2019 when compared to the corresponding period in 2018 as a result of reductions in production levels primarily in the primary metals, paper, and chemicals sectors, partially offset by an increase in demand in the mining sector.
Revenues increased in the third quarter and year-to-date 2019 due to warmer weather in the third quarter 2019 when compared to the corresponding period in 2018.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to a decrease in generation.
Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(3) | | (4.1) | | $(19) | | (8.9) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.
For year-to-date 2019, wholesale revenues from sales to non-affiliates were $194 million compared to $213 million for the corresponding period in 2018. The decrease was primarily due to a 4.9% decrease in KWH sales as a result of lower demand and a 4.5% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.
Wholesale Revenues – Affiliates
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(12) | | (85.7) | | $(30) | | (31.3) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the third quarter 2019, wholesale revenues from sales to affiliates were $2 million compared to $14 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to affiliates were $66 million compared to $96 million for the corresponding period in 2018. These decreases were primarily due to reductions in KWH sales as a result of decreased availability of coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a decrease in the price of energy as a result of lower natural gas prices.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | | (change in millions) |
| (% change) | | (change in millions) | | (% change) | | Fuel | $ | (46 | ) | | (12.9) | | $ | (164 | ) | | (16.0 | ) | | Purchased power – non-affiliates | 13 |
| | 20.3 | | (16 | ) | | (9.1 | ) | | Purchased power – affiliates | 4 |
| | 5.8 | | 15 |
| | 10.1 |
| | Total fuel and purchased power expenses | $ | (29 | ) | | | | $ | (165 | ) | | |
In the third quarter 2019, fuel and purchased power expenses were $460 million compared to $489 million for the corresponding period in 2018. For year-to-date 2019, fuel and purchased power expenses were $1.19 billion compared to $1.35 billion for the corresponding period in 2018. These decreases were primarily due to decreases of $60 million and $110 million, respectively, in the average cost of purchased power and fuel in the third quarter and year-to-date 2019, as well as a net decrease of $25 million in the volume of KWHs purchased and generated
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(excluding hydro) for year-to-date 2019. Partially offsetting the third quarter 2019 decrease was a net increase of $31 million in the volume of KWHs purchased and generated (excluding hydro).
In addition, fuel expense increased $30 million for year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs (Tax Reform Accounting Order). See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | Third Quarter 2019 | | Third Quarter 2018 | | Year-to-Date 2019 |
| Year-to-Date 2018 | Total generation (in billions of KWHs) | 15 | | 16 | | 43 | | 47 | Total purchased power (in billions of KWHs) | 4 | | 3 | | 8 | | 6 | Sources of generation (percent) — | | | | | | | | | Coal | 48 | | 54 | | 45 | | 52 | | Nuclear | 26 | | 24 | | 25 | | 22 | | Gas | 24 | | 18 | | 21 | | 19 | | Hydro | 2 | | 4 | | 9 | | 7 | Cost of fuel, generated (in cents per net KWH) — (a) | | | | | | | | | Coal | 2.67 | | 2.74 | | 2.76 | | 2.74 | | Nuclear | 0.75 | | 0.78 | | 0.77 | | 0.77 | | Gas | 2.40 | | 2.80 | | 2.48 | | 2.72 | Average cost of fuel, generated (in cents per net KWH)(a)(b) | 2.10 | | 2.27 | | 2.15 | | 2.27 | Average cost of purchased power (in cents per net KWH)(c) | 4.35 | | 5.43 | | 4.40 | | 5.59 |
| | (a) | For year-to-date 2018, cost of fuel and average cost of fuel, generated exclude a $30 million adjustment in accordance with an Alabama PSC accounting order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information. |
| | (b) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
| | (c) | Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2019, fuel expense was $310 million compared to $356 million for the corresponding period in 2018. The decrease was primarily due to an 18.0% decrease in the volume of KWHs generated by coal and a 14.3% decrease in the average cost of natural gas per KWHs generated, which excludes fuel associated with tolling agreements, partially offset by a 45.8% decrease in the volume of KWHs generated by hydro and a 20.2% increase in the volume of KWHs generated by natural gas.
For year-to-date 2019, fuel expense was $0.86 billion compared to $1.03 billion for the corresponding period in 2018. The decrease was primarily due to a 26.4% increase in the volume of KWHs generated by hydro, a 20.6% decrease in the volume of KWHs generated by coal, and an 8.8% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by a 7.0% increase in the volume of KWHs generated by natural gas.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition, fuel expense increased $30 million for year-to-date 2018 in accordance with the Tax Reform Accounting Order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
Purchased Power – Non-Affiliates
In the third quarter 2019, purchased power expense from non-affiliates was $77 million compared to $64 million for the corresponding period in 2018. The increase was primarily related to a 42% increase in the volume of KWHs purchased primarily due to warmer weather in the third quarter 2019 compared to the corresponding period in 2018, partially offset by a 15.5% decrease in the average cost per KWH purchased due to lower natural gas prices.
For year-to-date 2019, purchased power expense from non-affiliates was $160 million compared to $176 million for the corresponding period in 2018. The decrease was primarily related to a 12.6% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 6% increase in the volume of KWHs purchased primarily as a result of the retirement of Plant Gorgas Units 8, 9, and 10.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
For year-to-date 2019, purchased power expense from affiliates was $164 million compared to $149 million for the corresponding period in 2018. The increase was primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a decrease in coal generation as a result of the retirement of Plant Gorgas Units 8, 9, and 10. The increase was partially offset by a 25.2% decrease in the average cost per KWH purchased due to lower natural gas prices.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $8 | | 2.0 | | $30 | | 2.5 |
For year-to-date 2019, other operations and maintenance expenses were $1.22 billion compared to $1.19 billion for the corresponding period in 2018. This increase was primarily due to increases of $20 million in Rate CNP Compliance-related expenses, $18 million related to affiliate billing credits received in 2018, and $3 million in employee benefit expenses. These increases were partially offset by a $20 million decrease in overhead line maintenance expenses due to the timing and availability of contract labor. Operations and maintenance expenses associated with Rate CNP compliance do not have a significant impact on earnings since they are generally offset by Rate CNP revenues. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $3 | | 1.6 | | $23 | | 4.0 |
For year-to-date 2019, depreciation and amortization was $593 million compared to $570 million for the corresponding period in 2018. This increase was primarily due to additional plant in service.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), Net
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $2 | | 22.2 | | $12 | | 50.0 |
For year-to-date 2019, other income (expense), net was $36 million compared to $24 million for the corresponding period in 2018. This increase was primarily due to increases in interest income from temporary cash investments and non-service cost-related pension income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $17 | | 13.4 | | $23 | | 8.5 |
In the third quarter 2019, income taxes were $144 million compared to $127 million for the corresponding period in 2018. For year-to-date 2019, income taxes were $295 million compared to $272 million for the corresponding period in 2018. These increases were primarily due to higher pre-tax earnings in the third quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs, including the procurement of resources outlined in the September 6, 2019 petition for a CCN filed with the Alabama PSC and recovery of related costs, during a time of increasing costs and the weak pace of growth in new customers and electricity use per customer, especially in residential and commercial markets. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Alabama Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
decisions, results of operations, cash flows, and/or financial condition. These costs are being collected through existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the finalrule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.
Coal Combustion Residuals
During 2019, Alabama Power recorded increases totaling approximately $312 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs for all but one of its ash pond facilities. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facility will be updated within the next 12 months and the change could be material.
As further analysis is performed and additional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. Additionally, the closure designs and plans are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. 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 and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Alabama Power has ownership interests in seven coal-fired units (approximately 4,500 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.
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 (including Alabama Power) 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 Alabama Power.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.
Petition for Certificate of Convenience and Necessity
On September 6, 2019, Alabama Power filed a petition for a CCN with the Alabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility, the acquisition of an existing combined cycle facility, and long-term contracts for the purchase of power from others, as more fully described below. In addition, Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. This filing was predicated on the results of Alabama Power's 2019 IRP provided to the Alabama PSC, which identified an approximately 2,400-MW resource need for Alabama Power, driven by the need for additional winter reserve capacity.
The procurement of these resources is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC. The completion of the Autauga Combined Cycle Acquisition (defined below) is also subject to (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and (ii) approval by the FERC. All regulatory approvals are expected to be obtained by the end of the third quarter 2020.
On May 8, 2019, Alabama Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023.
On September 6, 2019, Alabama Power entered into a purchase and sale agreement to acquire all of the equity interests in Tenaska Alabama II Partners, L.P. (Autauga Combined Cycle Acquisition). Tenaska Alabama II Partners, L.P. owns and operates an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The transaction is expected to close by September 1, 2020. As part of the Autauga Combined Cycle Acquisition, Alabama Power will assume an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. The estimated revenues from the power sales agreement are expected to offset the associated costs of operation during the remaining term.
The capital investment associated with the construction of Plant Barry Unit 8 and the Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power also intends to procure through long-term PPAs approximately 640 MWs of additional generating capacity, which will consist of approximately 240 MWs of combined cycle generation expected to begin in 2020 and approximately 400 MWs of solar generation coupled with battery energy storage systems (solar/battery systems) expected to begin in 2022 through 2024. The terms of the agreements for the solar/battery systems permit Alabama Power to use the energy and retire the associated renewable energy credits (REC) in service of customers or to sell RECs, separately or bundled with energy.
Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 through its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through Rate RSE during the term of the existing power sales agreement and, on expiration of the agreement, through Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of Rate RSE. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Construction Work in Progress Accounting Order
On October 1, 2019, the Alabama PSC acknowledged that Alabama Power would begin certain limited preparatory activities associated with Plant Barry Unit 8 construction to meet the target in-service date by authorizing Alabama Power to record the related costs as CWIP prior to the issuance of an order on the CCN petition. Should a CCN not be granted and Alabama Power does not proceed with the related construction of Plant Barry Unit 8, Alabama Power may transfer those costs and any costs that directly result from the non-issuance of the CCN to a regulatory asset which would be amortized over a five-year period. If the balance of incurred costs reaches 5% of the estimated in-service cost of the total project prior to issuance of an order on the CCN petition, Alabama Power will confer with the Alabama PSC regarding the appropriateness of additional authorization.
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.
Other Matters
Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power has closed 40 of its 86 payment offices as of September 30, 2019. Charges associated with these activities are not expected to have a material impact on Alabama Power's financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at September 30, 2019. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.5 billion for the first nine months of 2019, an increase of $82 million as compared to the first nine months of 2018. The increase in net cash provided from operating activities was primarily due to the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation and increased fuel cost recovery and materials and supplies, partially offset by fossil fuel stock purchases and the timing of vendor payments. Net cash used for investing activities totaled $1.4 billion for the first nine months of 2019 primarily related to additional capital expenditures. Net cash provided from financing activities totaled $992 million for the first nine months of 2019 primarily due to capital contributions from Southern Company and a long-term debt issuance, partially offset by a payment of common stock dividends and a long-term debt maturity. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2019 include increases of $1.6 billion in total common stockholder's equity primarily due to a $1.2 billion capital contribution from Southern Company, $1.0 billion in cash and cash equivalents, and $0.6 billion in long-term debt due to a senior note issuance in the third quarter 2019. See "Financing Activities" herein for additional information. Other significant changes include increases of $0.9 billion in regulatory assets associated with AROs and $0.5 billion in other regulatory assets, deferred and a decrease of $0.5 billion in property, plant, and equipment. These changes were primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through September 30, 2020.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
In October 2019, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $2.1 billion for 2020, $1.8 billion for each of 2021, 2022, and 2023, and $1.6 billion for 2024, including amounts contingent upon approval by the Alabama PSC related to the September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters– Petition for Certificate of Convenience and Necessity" herein for additional information. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are approximately $80 million for each of 2020, 2021, and 2022 and approximately $100 million for each of 2023 and 2024. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil-fuel-fired electric generating units.
Alabama Power anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change, could change materially as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities. These costs are currently estimated to be approximately $200 million for 2020, $217 million for 2021, $284 million for 2022, $363 million for 2023, and $386 million for 2024. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At September 30, 2019, Alabama Power had approximately $1.34 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2019 were as follows:
| | | | | | | | | | | | | | | | | | | Expires | | | | | | 2020 | 2022 | 2024 | | Total | | Unused | | (in millions) | | $ | 3 |
| $ | 525 |
| $ | 800 |
| | $ | 1,328 |
| | $ | 1,328 |
|
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2019 and September 2019, Alabama Power amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2022 to 2024 and 2020 to 2022, respectively. In addition, Alabama Power increased the borrowing capacity of its $500 million credit arrangement to $525 million.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2019, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of September 30, 2019. At September 30, 2019, Alabama Power also had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
| | | | | | | | | | | | | | Short-term Debt During the Period(*) | | | Average
Amount Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding | | | (in millions) | | | | (in millions) | | Commercial paper | $ | 10 |
| | 2.5 | % | | $ | 135 |
|
| | (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2019. No short-term debt was outstanding at September 30, 2019. |
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At September 30, 2019, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $342 million.
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (an affiliate of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On September 12, 2019, S&P upgraded the senior unsecured long-term debt rating of Alabama Power to A from A- and maintained the negative rating outlook.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Financing Activities
In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.
In September 2019, Alabama Power issued $600 million aggregate principal amount of Series 2019A 3.45% Senior Notes due October 1, 2049. The proceeds will be used for general corporate purposes, including Alabama Power's continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Operating Revenues: | | | | | | | | | Retail revenues | $ | 2,567 |
| | $ | 2,425 |
| | $ | 6,181 |
| | $ | 6,112 |
| | Wholesale revenues, non-affiliates | 36 |
| | 43 |
| | 98 |
| | 123 |
| | Wholesale revenues, affiliates | 3 |
| | 4 |
| | 9 |
| | 17 |
| | Other revenues | 149 |
| | 121 |
| | 418 |
| | 349 |
| | Total operating revenues | 2,755 |
| | 2,593 |
| | 6,706 |
| | 6,601 |
| | Operating Expenses: | | | | | | | | | Fuel | 443 |
| | 480 |
| | 1,132 |
| | 1,269 |
| | Purchased power, non-affiliates | 151 |
| | 106 |
| | 393 |
| | 338 |
| | Purchased power, affiliates | 150 |
| | 206 |
| | 460 |
| | 555 |
| | Other operations and maintenance | 473 |
| | 460 |
| | 1,385 |
| | 1,325 |
| | Depreciation and amortization | 250 |
| | 232 |
| | 733 |
| | 690 |
| | Taxes other than income taxes | 127 |
| | 118 |
| | 348 |
| | 332 |
| | Estimated loss on Plant Vogtle Units 3 and 4 | — |
| | — |
| | — |
| | 1,060 |
| | Total operating expenses | 1,594 |
| | 1,602 |
| | 4,451 |
| | 5,569 |
| | Operating Income | 1,161 |
| | 991 |
| | 2,255 |
| | 1,032 |
| | Other Income and (Expense): | | | | | | | | | Interest expense, net of amounts capitalized | (103 | ) | | (95 | ) | | (304 | ) | | (303 | ) | | Other income (expense), net | 36 |
| | 30 |
| | 113 |
| | 104 |
| | Total other income and (expense) | (67 | ) | | (65 | ) | | (191 | ) | | (199 | ) | | Earnings Before Income Taxes | 1,094 |
| | 926 |
| | 2,064 |
| | 833 |
| | Income taxes | 255 |
| | 262 |
| | 466 |
| | 212 |
| | Net Income | $ | 839 |
| | $ | 664 |
| | $ | 1,598 |
| | $ | 621 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Net Income | $ | 839 |
| | $ | 664 |
| | $ | 1,598 |
| | $ | 621 |
| | Other comprehensive income (loss): | | | | | | | | | Qualifying hedges: | | | | | | | | | Changes in fair value, net of tax of $(12), $-, $(21), and $-, respectively | (35 | ) | | — |
| | (62 | ) | | — |
| Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $1, respectively | — |
| | 1 |
| | 1 |
| | 3 |
| | Total other comprehensive income (loss) | (35 | ) | | 1 |
| | (61 | ) | | 3 |
| | Comprehensive Income | $ | 804 |
| | $ | 665 |
| | $ | 1,537 |
| | $ | 624 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | | | | | | | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | | (in millions) | | Operating Activities: | | | | | Net income | $ | 1,598 |
| | $ | 621 |
| | Adjustments to reconcile net income to net cash provided from operating activities — | | | | | Depreciation and amortization, total | 887 |
| | 854 |
| | Deferred income taxes | 145 |
| | (185 | ) | | Allowance for equity funds used during construction | (49 | ) | | (50 | ) | | Pension, postretirement, and other employee benefits | (85 | ) | | (46 | ) | | Settlement of asset retirement obligations | (110 | ) | | (82 | ) | | Estimated loss on Plant Vogtle Units 3 and 4 | — |
| | 1,060 |
| | Other, net | 61 |
| | 9 |
| | Changes in certain current assets and liabilities — | | | | | -Receivables | (128 | ) | | (205 | ) | | -Fossil fuel stock | (13 | ) | | 70 |
| | -Prepaid income taxes | 102 |
| | 231 |
| | -Other current assets | (35 | ) | | (36 | ) | | -Accounts payable | (134 | ) | | 109 |
| | -Accrued taxes | 138 |
| | 26 |
| | -Accrued compensation | (12 | ) | | (32 | ) | | -Other current liabilities | — |
| | (111 | ) | | Net cash provided from operating activities | 2,365 |
| | 2,233 |
| | Investing Activities: | | | | | Property additions | (2,581 | ) | | (2,276 | ) | | Nuclear decommissioning trust fund purchases | (483 | ) | | (638 | ) | | Nuclear decommissioning trust fund sales | 477 |
| | 633 |
| | Cost of removal, net of salvage | (136 | ) | | (71 | ) | | Change in construction payables, net of joint owner portion | (75 | ) | | 72 |
| | Payments pursuant to LTSAs | (17 | ) | | (52 | ) | | Proceeds from dispositions and asset sales | 9 |
| | 138 |
| | Other investing activities | 13 |
| | (19 | ) | | Net cash used for investing activities | (2,793 | ) | | (2,213 | ) | | Financing Activities: | | | | | Increase (decrease) in notes payable, net | (294 | ) | | 102 |
| | Proceeds — | | | | | FFB loan | 835 |
| | — |
| | Senior notes | 750 |
| | — |
| | Pollution control revenue bonds | 584 |
| | — |
| | Short-term borrowings | 250 |
| | — |
| | Capital contributions from parent company | 82 |
| | 2,335 |
| | Redemptions and repurchases — | | | | | Senior notes | — |
| | (1,000 | ) | | Pollution control revenue bonds | (223 | ) | | (469 | ) | | Short-term borrowings | — |
| | (150 | ) | | Other long-term debt | — |
| | (100 | ) | | Payment of common stock dividends | (1,182 | ) | | (1,043 | ) | | Premiums on redemption and repurchases of senior notes | — |
| | (152 | ) | | Other financing activities | (37 | ) | | (15 | ) | | Net cash provided from (used for) financing activities | 765 |
| | (492 | ) | | Net Change in Cash, Cash Equivalents, and Restricted Cash | 337 |
| | (472 | ) | | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 112 |
| | 852 |
| | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 449 |
| | $ | 380 |
| | Supplemental Cash Flow Information: | | | | | Cash paid during the period for — | | | | | Interest (net of $25 and $19 capitalized for 2019 and 2018, respectively) | $ | 296 |
| | $ | 315 |
| | Income taxes, net | 45 |
| | 141 |
| | Noncash transactions — Accrued property additions at end of period | 589 |
| | 670 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Assets | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Assets: | | | | | | Cash and cash equivalents | | $ | 449 |
| | $ | 4 |
| | Restricted cash and cash equivalents | | — |
| | 108 |
| | Receivables — | | | | | | Customer accounts receivable | | 767 |
| | 591 |
| | Unbilled revenues | | 282 |
| | 208 |
| | Under recovered fuel clause revenues | | — |
| | 115 |
| | Joint owner accounts receivable | | 152 |
| | 170 |
| | Affiliated | | 28 |
| | 39 |
| | Other accounts and notes receivable | | 205 |
| | 80 |
| | Accumulated provision for uncollectible accounts | | (2 | ) | | (2 | ) | | Fossil fuel stock | | 244 |
| | 231 |
| | Materials and supplies | | 499 |
| | 519 |
| | Prepaid expenses | | 15 |
| | 142 |
| | Other regulatory assets | | 270 |
| | 199 |
| | Other current assets | | 101 |
| | 70 |
| | Total current assets | | 3,010 |
| | 2,474 |
| | Property, Plant, and Equipment: | | | | | | In service | | 37,409 |
| | 37,675 |
| | Less: Accumulated provision for depreciation | | 11,670 |
| | 12,096 |
| | Plant in service, net of depreciation | | 25,739 |
| | 25,579 |
| | Nuclear fuel, at amortized cost | | 544 |
| | 550 |
| | Construction work in progress | | 5,690 |
| | 4,833 |
| | Total property, plant, and equipment | | 31,973 |
| | 30,962 |
| | Other Property and Investments: | | | | | | Equity investments in unconsolidated subsidiaries | | 51 |
| | 51 |
| | Nuclear decommissioning trusts, at fair value | | 990 |
| | 873 |
| | Miscellaneous property and investments | | 68 |
| | 72 |
| | Total other property and investments | | 1,109 |
| | 996 |
| | Deferred Charges and Other Assets: | | | | | | Operating lease right-of-use assets, net of amortization | | 1,461 |
| | — |
| | Deferred charges related to income taxes | | 520 |
| | 517 |
| | Regulatory assets – asset retirement obligations | | 3,181 |
| | 2,644 |
| | Other regulatory assets, deferred | | 2,763 |
| | 2,258 |
| | Other deferred charges and assets | | 398 |
| | 514 |
| | Total deferred charges and other assets | | 8,323 |
| | 5,933 |
| | Total Assets | | $ | 44,415 |
| | $ | 40,365 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Liabilities and Stockholder's Equity | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Liabilities: | | | | | | Securities due within one year | | $ | 1,504 |
| | $ | 617 |
| | Notes payable | | 250 |
| | 294 |
| | Accounts payable — | | | | | | Affiliated | | 540 |
| | 575 |
| | Other | | 756 |
| | 890 |
| | Customer deposits | | 282 |
| | 276 |
| | Accrued taxes | | 498 |
| | 377 |
| | Accrued interest | | 98 |
| | 105 |
| | Accrued compensation | | 192 |
| | 221 |
| | Operating lease obligations | | 143 |
| | — |
| | Asset retirement obligations | | 259 |
| | 202 |
| | Other regulatory liabilities | | 183 |
| | 169 |
| | Other current liabilities | | 234 |
| | 183 |
| | Total current liabilities | | 4,939 |
| | 3,909 |
| | Long-term Debt | | 10,440 |
| | 9,364 |
| | Deferred Credits and Other Liabilities: | | | | | | Accumulated deferred income taxes | | 3,216 |
| | 3,062 |
| | Deferred credits related to income taxes | | 3,079 |
| | 3,080 |
| | Accumulated deferred ITCs | | 257 |
| | 262 |
| | Employee benefit obligations | | 525 |
| | 599 |
| | Operating lease obligations, deferred | | 1,287 |
| | — |
| | Asset retirement obligations, deferred | | 5,680 |
| | 5,627 |
| | Other deferred credits and liabilities | | 228 |
| | 139 |
| | Total deferred credits and other liabilities | | 14,272 |
| | 12,769 |
| | Total Liabilities | | 29,651 |
| | 26,042 |
| Common Stockholder's Equity (See accompanying statements) | | 14,764 |
| | 14,323 |
| | Total Liabilities and Stockholder's Equity | | $ | 44,415 |
| | $ | 40,365 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total | | | (in millions) | | Balance at December 31, 2017 | 9 |
| | $ | 398 |
| | $ | 7,328 |
| | $ | 4,215 |
| | $ | (10 | ) | | $ | 11,931 |
| | Net income | — |
| | — |
| | — |
| | 352 |
| | — |
| | 352 |
| | Capital contributions from parent company | — |
| | — |
| | 1,476 |
| | — |
| | — |
| | 1,476 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (339 | ) | | — |
| | (339 | ) | | Other | — |
| | — |
| | 1 |
| | — |
| | (2 | ) | | (1 | ) | | Balance at March 31, 2018 | 9 |
| | 398 |
| | 8,805 |
| | 4,228 |
| | (11 | ) | | 13,420 |
| | Net loss | — |
| | — |
| | — |
| | (396 | ) | | — |
| | (396 | ) | | Capital contributions from parent company | — |
| | — |
| | 29 |
| | — |
| | — |
| | 29 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (352 | ) | | — |
| | (352 | ) | | Balance at June 30, 2018 | 9 |
| | 398 |
| | 8,834 |
| | 3,480 |
| | (10 | ) | | 12,702 |
| | Net income | — |
| | — |
| | — |
| | 664 |
| | — |
| | 664 |
| | Capital contributions from parent company | — |
| | — |
| | 836 |
| | — |
| | — |
| | 836 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (352 | ) | | — |
| | (352 | ) | | Balance at September 30, 2018 | 9 |
| | $ | 398 |
| | $ | 9,670 |
| | $ | 3,792 |
| | $ | (9 | ) | | $ | 13,851 |
| | | | | | | | | | | | | | | Balance at December 31, 2018 | 9 |
| | $ | 398 |
| | $ | 10,322 |
| | $ | 3,612 |
| | $ | (9 | ) | | $ | 14,323 |
| | Net income | — |
| | — |
| | — |
| | 311 |
| | — |
| | 311 |
| | Capital contributions from parent company | — |
| | — |
| | 29 |
| | — |
| | — |
| | 29 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | — |
| | — |
| | (394 | ) | | — |
| | (394 | ) | | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | | Balance at March 31, 2019 | 9 |
| | 398 |
| | 10,350 |
| | 3,529 |
| | (8 | ) | | 14,269 |
| | Net income | — |
| | — |
| | — |
| | 448 |
| | — |
| | 448 |
| | Capital contributions from parent company | — |
| | — |
| | 20 |
| | — |
| | — |
| | 20 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) | | Cash dividends on common stock | — |
| | — |
| | — |
| | (394 | ) | | — |
| | (394 | ) | | Other | — |
| | — |
| | 1 |
| | (1 | ) | | — |
| | — |
| | Balance at June 30, 2019 | 9 |
| | 398 |
| | 10,371 |
| | 3,582 |
| | (35 | ) | | 14,316 |
| | Net income | — |
| | — |
| | — |
| | 839 |
| | — |
| | 839 |
| | Capital contributions from parent company | — |
| | — |
| | 38 |
| | — |
| | — |
| | 38 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (35 | ) | | (35 | ) | | Cash dividends on common stock | — |
| | — |
| | — |
| | (394 | ) | | — |
| | (394 | ) | | Other | — |
| | — |
| | (1 | ) | | 1 |
| | — |
| | — |
| | Balance at September 30, 2019 | 9 |
| | $ | 398 |
| | $ | 10,408 |
| | $ | 4,028 |
| | $ | (70 | ) | | $ | 14,764 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2019 vs. THIRD QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including new generating facilities and expanding and improving transmission and distribution facilities, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
On June 28, 2019, Georgia Power filed a base rate case with the Georgia PSC. The filing, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information.
Georgia Power continues to focus on several key performance indicators, including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction. The current expected in-service dates remain November 2021 for Unit 3 and November 2022 for Unit 4.
In the second quarter 2018, Georgia Power revised its total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds), with respect to Georgia Power's ownership interest.
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, 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. 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 certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners 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 certain of MEAG's wholly-owned subsidiaries
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.
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 total estimated 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.
In March 2019, Georgia Power entered into the Amended and Restated Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4, up to approximately $5.130 billion. At September 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
RESULTS OF OPERATIONS
Net Income
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $175 | | 26.4 | | $977 | | 157.3 |
Georgia Power's net income for the third quarter 2019 was $839 million compared to $664 million for the corresponding period in 2018. The increase was primarily due to an increase in retail revenues associated with higher contributions from commercial and industrial customers with variable demand-driven pricing and warmer weather in the third quarter 2019 compared to the corresponding period in 2018.
For year-to-date 2019, net income was $1.60 billion compared to $621 million for the corresponding period in 2018. The increase was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, an increase in retail revenues associated with higher contributions from commercial and industrial customers with variable demand-driven pricing, warmer weather in the third quarter 2019 compared to the corresponding period in 2018, and an increase in other revenues primarily related to unregulated sales. Partially offsetting the increase were higher non-fuel operations and maintenance expenses and depreciation and amortization.
Retail Revenues
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $142 | | 5.9 | | $69 | | 1.1 |
In the third quarter 2019, retail revenues were $2.57 billion compared to $2.43 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $6.18 billion compared to $6.11 billion for the corresponding period in 2018.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | Third Quarter 2019 | | Year-to-Date 2019 | | | (in millions) | | (% change) | | (in millions) | | (% change) | | Retail – prior year | $ | 2,425 |
| | | | $ | 6,112 |
| | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | 116 |
| | 4.8 | % | | 177 |
| | 2.9 | % | | Sales decline | (41 | ) | | (1.7 | ) | | (52 | ) | | (0.9 | ) | | Weather | 89 |
| | 3.7 |
| | 61 |
| | 1.0 |
| | Fuel cost recovery | (22 | ) | | (0.9 | ) | | (117 | ) | | (1.9 | ) | | Retail – current year | $ | 2,567 |
| | 5.9 | % | | $ | 6,181 |
| | 1.1 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing and an increase in the NCCR tariff effective January 1, 2019. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.9% and 0.3% and weather-adjusted commercial KWH sales decreased 2.0% and 1.4% in the third quarter and year-to-date 2019, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 3.7% in the third quarter 2019 primarily due to decreases in the paper, textile, and chemical sectors. Weather-adjusted industrial KWH sales decreased 1.8% for year-to-date 2019 primarily due to decreases in the textile, stone, clay, and glass, and paper sectors. The decreases in weather-adjusted industrial KWH sales in the third quarter and year-to-date 2019 were partially offset by an increase in the pipeline sector.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. For year-to-date 2019, the decrease was primarily due to lower generation costs. Electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(7) | | (16.3) | | $(25) | | (20.3) |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2019, wholesale revenues from sales to non-affiliates were $36 million compared to $43 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to non-affiliates were $98 million compared to $123 million for the corresponding period in 2018. The decreases for third quarter and year-to-date 2019 were primarily due to a decrease in energy revenues primarily due to lower energy prices.
Other Revenues
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $28 | | 23.1 | | $69 | | 19.8 |
In the third quarter 2019, other revenues were $149 million compared to $121 million for the corresponding period in 2018. For year-to-date 2019, other revenues were $418 million compared to $349 million for the corresponding period in 2018. The increases were primarily due to revenue increases of $15 million and $22 million from power delivery construction and maintenance contracts and $7 million and $18 million from unregulated sales associated with new energy conservation projects in the third quarter and year-to-date 2019, respectively. Also contributing to the increase for year-to-date 2019 were revenue increases of $9 million from OATT sales and $8 million from outdoor lighting LED conversions and sales.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | | | Third Quarter 2019
vs.
Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (37 | ) | | (7.7 | ) | | $ | (137 | ) | | (10.8 | ) | | Purchased power – non-affiliates | 45 |
| | 42.5 |
| | 55 |
| | 16.3 |
| | Purchased power – affiliates | (56 | ) | | (27.2 | ) | | (95 | ) | | (17.1 | ) | | Total fuel and purchased power expenses | $ | (48 | ) | | | | $ | (177 | ) | | |
In the third quarter 2019, total fuel and purchased power expenses were $744 million compared to $792 million in the corresponding period in 2018. The decrease was primarily due to a $58 million decrease related to the average cost of fuel and purchased power primarily related to lower fuel and energy prices, partially offset by a net increase of $10 million related to the volume of KWHs generated and purchased.
For year-to-date 2019, total fuel and purchased power expenses were $1.99 billion compared to $2.16 billion in the corresponding period in 2018. The decrease was primarily due to a $171 million decrease related to the average cost of fuel and purchased power primarily related to lower fuel and energy prices.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased power were as follows:
| | | | | | | | | | | Third Quarter 2019 | | Third Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 | Total generation (in billions of KWHs) | 19 | | 18 | | 48 | | 49 | Total purchased power (in billions of KWHs) | 8 | | 8 | | 23 | | 22 | Sources of generation (percent) — | | | | | | | | | Gas | 46 | | 44 | | 47 | | 43 | | Coal | 31 | | 32 | | 26 | | 30 | | Nuclear | 22 | | 22 | | 24 | | 25 | | Hydro | 1 | | 2 | | 3 | | 2 | Cost of fuel, generated (in cents per net KWH) — | | | | | | | | | Gas | 2.33 | | 2.58 | | 2.45 | | 2.64 | | Coal | 3.00 | | 3.14 | | 3.10 | | 3.25 | | Nuclear | 0.82 | | 0.83 | | 0.81 | | 0.83 | Average cost of fuel, generated (in cents per net KWH) | 2.20 | | 2.36 | | 2.21 | | 2.36 | Average cost of purchased power (in cents per net KWH)(*) | 4.20 | | 4.52 | | 4.22 | | 4.70 |
| | (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the third quarter 2019, fuel expense was $443 million compared to $480 million in the corresponding period in 2018. The decrease was primarily due to a 6.8% decrease in the average cost of fuel, primarily related to lower natural gas and coal prices, partially offset by a 3.5% increase in the volume of KWHs generated, primarily due to warmer weather in the third quarter 2019 compared to the corresponding period in 2018.
For year-to-date 2019, fuel expense was $1.13 billion compared to $1.27 billion in the corresponding period in 2018. The decrease was primarily due to a 6.4% decrease in the average cost of fuel, primarily related to lower natural gas and coal prices, and a 3.0% decrease in the volume of KWHs generated, primarily due to scheduled generation outages, as well as milder weather in the first quarter 2019 compared to the corresponding period in 2018.
Purchased Power – Non-Affiliates
In the third quarter 2019, purchased power expense from non-affiliates was $151 million compared to $106 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from non-affiliates was $393 million compared to $338 million in the corresponding period in 2018. The increases were primarily due to 86.9% and 45.2% increases in the volume of KWHs purchased in the third quarter and year-to-date 2019, respectively, primarily due to warmer weather in the third quarter 2019 resulting in higher customer demand and scheduled generation outages at Georgia Power-owned generating units, partially offset by 23.2% and 21.0% decreases in the average cost per KWH purchased in the third quarter and year-to-date 2019, respectively, primarily due to lower energy prices.
The volume increases also reflect purchases from Gulf Power which were classified as affiliate prior to January 1, 2019. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2019, purchased power expense from affiliates was $150 million compared to $206 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $460 million compared to $555 million in the corresponding period in 2018. The decreases were primarily due to 25.5% and 9.7% decreases in the volume of KWHs purchased in the third quarter and year-to-date 2019, respectively, as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources and 8.3% and 9.9% decreases in the average cost per KWH purchased in the third quarter and year-to-date 2019, respectively, resulting from lower energy prices.
The decreases in purchased power expense from affiliates also reflect the classification of capacity expenses of $6 million and $18 million in the third quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, Leases (ASC 842). In 2019, these expenses are included in depreciation and amortization and interest expense, net of amounts capitalized. The decreases in the volume of KWHs purchased also include the effect of classifying purchases from Gulf Power as non-affiliate beginning January 1, 2019. See Notes (L) and (K) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842 and the sale of Gulf Power, respectively.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $13 | | 2.8 | | $60 | | 4.5 |
In the third quarter 2019, other operations and maintenance expenses were $473 million compared to $460 million in the corresponding period in 2018. The increase reflects increases in expenses of $8 million from unregulated power delivery construction and maintenance contracts and $7 million from unregulated sales associated with new energy conservation projects.
For year-to-date 2019, other operations and maintenance expenses were $1.39 billion compared to $1.33 billion in the corresponding period in 2018. The increase reflects increases in expenses of $16 million from unregulated sales associated with new energy conservation projects, $16 million related to an adjustment for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities, $11 million related to scheduled generation outages, $10 million related to affiliate labor billing credits received in 2018, $8 million from unregulated power delivery construction and maintenance contracts, and $8 million associated with generation maintenance. The increase was partially offset by decreases of $9 million in customer accounts and sales expenses and $8 million in employee benefit expenses.
Depreciation and Amortization
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $18 | | 7.8 | | $43 | | 6.2 |
In the third quarter 2019, depreciation and amortization was $250 million compared to $232 million in the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $733 million compared to
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$690 million in the corresponding period in 2018. The increases were primarily due to additional plant in service and the amortization of regulatory assets related to the retirement of certain generating units. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" herein for additional information on unit retirements.
The increases also reflect the classification of approximately $2 million and $7 million in the third quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.
Taxes Other Than Income Taxes
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $9 | | 7.6 | | $16 | | 4.8 |
In the third quarter 2019, taxes other than income taxes were $127 million compared to $118 million in the corresponding period in 2018. For year-to-date 2019, taxes other than income taxes were $348 million compared to $332 million in the corresponding period in 2018. The increases reflect higher property taxes of $7 million and $21 million for the third quarter and year-to-date 2019, respectively, as a result of an increase in the assessed value of property.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | (change in millions) | | (% change) | | (change in millions) | | (% change) | $— | | — | | $(1,060) | | N/M |
N/M - Not meaningful
In the second quarter 2018, an estimated probable loss of $1.1 billion was recorded to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information.
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $8 | | 8.4 | | $1 | | 0.3 |
In the third quarter 2019, interest expense, net of amounts capitalized was $103 million compared to $95 million in the corresponding period in 2018. The increase was primarily due to a $6 million increase in interest expense associated with an increase in average outstanding long-term borrowings and the reclassification of $4 million related to PPAs with Southern Power accounted for as finance leases following the adoption of ASC 842.
For year-to-date 2019, interest expense, net of amounts capitalized was $304 million compared to $303 million in the corresponding period in 2018. The increase was primarily due the reclassification of $11 million related to PPAs with Southern Power accounted for as finance leases following the adoption of ASC 842 and a $6 million increase in interest expense associated with an increase in outstanding short-term borrowings, largely offset by a $15 million decrease in interest expense associated with a decrease in average outstanding long-term borrowings.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In prior periods, the expenses related to the PPAs with Southern Power were included in purchased power, affiliates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.
Other Income (Expense), Net
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $6 | | 20.0 | | $9 | | 8.7 |
In the third quarter 2019, other income (expense), net was $36 million compared to $30 million in the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $113 million compared to $104 million in the corresponding period in 2018. The increases were primarily due to $4 million and $12 million increases for the third quarter and year-to-date 2019, respectively, in non-service cost-related pension income. Partially offsetting the increase for year-to-date 2019 was a $4 million decrease in interest income from temporary cash investments. See Note (H) to the Condensed Financial Statements herein for additional information on the qualified pension plan.
Income Taxes
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 |
| Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) |
| (% change) |
| (change in millions) | | (% change) | | $(7) |
| (2.7) |
| $254 | | 119.8 |
In the third quarter 2019, income taxes were $255 million compared to $262 million in the corresponding period in 2018. The decrease was primarily due to the recognition of a valuation allowance on certain state tax credit carryforwards in the third quarter 2018 and an increase in state ITCs, partially offset by higher pre-tax earnings.
For year-to-date 2019, income taxes were $466 million compared to $212 million in the corresponding period in 2018. The increase was primarily due to the reduction in pre-tax earnings (loss) in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction and higher pre-tax earnings in the third quarter 2019, partially offset by the recognition of a valuation allowance on certain state tax credit carryforwards in the third quarter 2018 and an increase in state ITCs. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
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For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
Environmental Matters
Georgia Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Georgia Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Georgia Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the finalrule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Georgia Power has ownership interests in nine coal-fired units (approximately 4,800 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals and Georgia Power has filed a motion to intervene in the litigation in support of the rule, as have others. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Georgia Power will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.
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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 (including Georgia Power) 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 Georgia Power.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information regarding regulatory matters.
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, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 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 | $ | 210 |
| $ | — |
| $ | — |
| | CCR AROs | 158 |
| 139 |
| 227 |
| | ECCR | 163 |
| — |
| — |
| | Demand-Side Management | 12 |
| 1 |
| 1 |
| | Municipal Franchise Fee | 17 |
| 3 |
| 5 |
| Total(*) | $ | 560 |
| $ | 144 |
| $ | 233 |
|
| | (*) | Totals may not add due to rounding. |
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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 IRP, 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 IRP (Georgia Power 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 Georgia Power 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), 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. Additionally, approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset.
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 September 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 timing of recovery of the related ARO costs will be determined in the Georgia Power 2019 Base Rate Case. The ultimate outcome of these matters cannot be determined at this time.
Also in the Georgia Power 2019 IRP, 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 $157 million at September 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.
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Additionally, 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 IRP. 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 financial statements.
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 the 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.
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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 September 30, 2019(b) | (5.5 | ) | Remaining estimate to complete(a) | $ | 2.9 |
|
| | (a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million. |
| | (b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds. |
As of September 30, 2019, approximately $30 million of the construction contingency estimate was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program, and start-up; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.1 billion had been incurred through September 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. 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.
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, particularly in the installation of electrical and mechanical commodities, 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 the remainder of 2019 and into 2020. 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
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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 $11 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) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries 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) the 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
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billion. At September 30, 2019, Georgia Power had recovered approximately $2.1 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 expects to file on November 1, 2019 to decrease the NCCR tariff by approximately $65 million annually, effective January 1, 2020, pending Georgia PSC approval.
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 $650 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,
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and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. On October 29, 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Georgia Power's results of operations, financial condition, and liquidity.
The Georgia PSC has approved nineteen VCM reports covering the period through June 30, 2018, including total construction capital costs incurred through that date 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 August 30, 2019, Georgia Power filed its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which requested approval of $1.2 billion of construction capital costs incurred from July 1, 2018 through June 30, 2019.
In the nineteenth VCM, the Georgia PSC deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. 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 also requested approval of $21.5 million of associated expenditures previously deferred for approval by the Georgia PSC. The remaining $30.1 million deferred for approval was refunded to Georgia Power and credited to the total construction capital costs.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia Power in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
DOE Financing
At September 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) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein 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.
Other Matters
Georgia Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial
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Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Litigation
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. OnAlso in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Appeals. In October 23, 2019, the Georgia PSC issued an order that found and concluded that Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal with11, 2020, the Georgia Court of Appeals regardingvacated the Superior Court of Fulton County's February 2019 order.order granting conditional class certification. The Court of Appeals remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power believeseach filed motions for summary judgment on all claims and the plaintiffs' claims have no merit.plaintiffs renewed their motion for class certification. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditionala class certification will be upheld andcertified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities. The ultimate outcome On July 29, 2020, a group of this matter cannot be determined at this time. ACCOUNTING POLICIES
Applicationindividual plaintiffs filed a complaint in the Superior Court of Critical Accounting Policies and Estimates
Fulton County, Georgia against Georgia Power prepares its financial statementsalleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in accordance with GAAP. Significant accounting policies are described in Notes 1, 5,alleged personal injuries and 6 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates. Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at September 30, 2019. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net cash provided from operating activities totaled $2.4 billion for the first nine months of 2019 compared to $2.2 billion for the corresponding period in 2018.property damage. The increase was primarily due to lower customer refunds and increased fuel cost recovery, partially offset by the timing of vendor payments. Net cash used for investing activities totaled $2.8 billion for the first nine months of 2019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including approximately $1.0 billion related to the construction of Plant Vogtle Units 3 and 4. Net cash provided from financing activities totaled $765 million for the first nine months of 2019 primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, and the reoffering of pollution control revenue bonds, partially offset by payment of common stock dividends and the redemption and repurchase of pollution control revenue bonds. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2019 includeplaintiffs seek an increase of $2.0 billion in long-term debt (including securities due within one year) primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, and the reoffering of pollution control revenue bonds previously purchased and held by Georgia Power; recording $1.5 billion in operating lease right-of-use assets, net of amortization and $1.4 billion in operating lease obligations related to the adoption of ASC 842; an increase of $1.1 billion in regulatory assets primarily due to the retirement of certain generating units as approved in the Georgia Power 2019 IRP; and an increase of $1.0 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, net of $835 million reclassified to regulatory assets due to unit retirements. See Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regarding Plant Vogtle Units 3 and 4 and the related Amended and Restated Loan Guarantee Agreement. Also see Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plan" and Note (L) to the Condensed Financial Statements herein for additional information on the Georgia Power 2019 IRP and the adoption of ASC 842, respectively.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements and contractual obligations. Approximately $1.5 billion will be required through September 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.
Sources of Capital
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, equity contributions from Southern Company, and borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approvals, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4.
Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds). At September 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities.
See Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. At September 30, 2019, Georgia Power's current liabilities exceeded current assets by $1.9 billion primarily due to long-term debt that is due within one year of $1.5 billion and notes payable of $250 million.
At September 30, 2019, Georgia Power had approximately $449 million of cash and cash equivalents and a multi-year committed credit arrangement with banks totaling $1.75 billion, of which $1.73 billion was unused. In May 2019, Georgia Power amended its bank credit arrangement which, among other things, extended the maturity date from 2022 to 2024. This credit arrangement, as well as Georgia Power's term loan arrangements, contain a covenant that limits debt levels and contain a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2019, Georgia Power was in compliance with this covenant. The bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement as needed prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the $1.73 billion unused bank credit arrangement is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. Theunspecified amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2019 was approximately $550 million.monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | Short-term Debt at September 30, 2019 | | Short-term Debt During the Period(*) | | | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | | (in millions) | | | | (in millions) | | | | (in millions) | | Commercial paper | $ | — |
| | — | % | | $ | 141 |
| | 2.5 | % | | $ | 350 |
| | Short-term bank debt | 250 |
| | 2.5 | % | | 250 |
| | 2.7 | % | | 250 |
| | Total | $ | 250 |
| | 2.5 | % | | $ | 391 |
| | 2.6 | % | | |
| | (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2019. |
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At September 30, 2019, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2019 were as follows:
| | | | | | Credit Ratings | Maximum Potential
Collateral
Requirements | | | (in millions) | | At BBB- and/or Baa3 | $ | 89 |
| | Below BBB- and/or Baa3 | $ | 1,021 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (an affiliate of Georgia Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Georgia Power, may be negatively impacted. A settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation, as approved by the Georgia PSC in April 2018, is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio through 2019, which Georgia Power has requested to extend in the Georgia Power 2019 Base Rate Case. See Note (B) to the Condensed Financial Statements and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans" for additional information, including requests for additional capital structure adjustments.
Financing Activities
In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.
In March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
Also in March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:
$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;
approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013; and
$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008.
In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.
$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;
$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and
$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994, which previously had been purchased and held by Georgia Power.
Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In August 2019, Georgia Power reoffered to the public approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013, which previously had been purchased and held by Georgia Power.
In September 2019, Georgia Power issued $400 million aggregate principal amount of Series 2019A 2.20% Senior Notes due September 15, 2024 and $350 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Operating Revenues: | | | | | | | | | Retail revenues | $ | 251 |
| | $ | 254 |
| | $ | 669 |
| | $ | 660 |
| | Wholesale revenues, non-affiliates | 64 |
| | 70 |
| | 178 |
| | 197 |
| | Wholesale revenues, affiliates | 51 |
| | 28 |
| | 109 |
| | 81 |
| | Other revenues | 4 |
| | 6 |
| | 14 |
| | 18 |
| | Total operating revenues | 370 |
| | 358 |
| | 970 |
| | 956 |
| | Operating Expenses: | | | | | | | | | Fuel | 121 |
| | 116 |
| | 319 |
| | 312 |
| | Purchased power | 6 |
| | 11 |
| | 15 |
| | 27 |
| | Other operations and maintenance | 68 |
| | 80 |
| | 194 |
| | 222 |
| | Depreciation and amortization | 48 |
| | 42 |
| | 144 |
| | 126 |
| | Taxes other than income taxes | 30 |
| | 28 |
| | 85 |
| | 83 |
| | Estimated loss on Kemper IGCC | 4 |
| | 1 |
| | 10 |
| | 45 |
| | Total operating expenses | 277 |
| | 278 |
| | 767 |
| | 815 |
| | Operating Income | 93 |
| | 80 |
| | 203 |
| | 141 |
| | Other Income and (Expense): | | | | | | | | | Interest expense, net of amounts capitalized | (17 | ) | | (19 | ) | | (52 | ) | | (59 | ) | | Other income (expense), net | 4 |
| | — |
| | 15 |
| | 28 |
| | Total other income and (expense) | (13 | ) | | (19 | ) | | (37 | ) | | (31 | ) | | Earnings Before Income Taxes | 80 |
| | 61 |
| | 166 |
| | 110 |
| | Income taxes | 15 |
| | 14 |
| | 27 |
| | 23 |
| | Net Income | 65 |
| | 47 |
| | 139 |
| | 87 |
| | Dividends on Preferred Stock | — |
| | — |
| | — |
| | 1 |
| | Net Income After Dividends on Preferred Stock | $ | 65 |
| | $ | 47 |
| | $ | 139 |
| | $ | 86 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Net Income | $ | 65 |
| | $ | 47 |
| | $ | 139 |
| | $ | 87 |
| | Other comprehensive income (loss): | | | | | | | | | Qualifying hedges: | | | | | | | | | Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively | — |
| | — |
| | — |
| | (1 | ) | Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | 1 |
| | 1 |
| | Total other comprehensive income (loss) | — |
| | — |
| | 1 |
| | — |
| | Comprehensive Income | $ | 65 |
| | $ | 47 |
| | $ | 140 |
| | $ | 87 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | | | | | | | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | | (in millions) | | Operating Activities: | | | | | Net income | $ | 139 |
| | $ | 87 |
| | Adjustments to reconcile net income to net cash provided from operating activities — | | | | | Depreciation and amortization, total | 148 |
| | 129 |
| | Deferred income taxes | 10 |
| | 420 |
| | Settlement of asset retirement obligations | (28 | ) | | (22 | ) | | Estimated loss on Kemper IGCC | 12 |
| | 21 |
| | Other, net | (4 | ) | | 27 |
| | Changes in certain current assets and liabilities — | | | | | -Receivables | (11 | ) | | (46 | ) | | -Other current assets | 18 |
| | (6 | ) | | -Accounts payable | (26 | ) | | (3 | ) | | -Accrued taxes | (12 | ) | | 57 |
| | -Accrued compensation | (10 | ) | | (9 | ) | | -Other current liabilities | 6 |
| | 1 |
| | Net cash provided from operating activities | 242 |
| | 656 |
| | Investing Activities: | | | | | Property additions | (134 | ) | | (117 | ) | | Construction payables | (16 | ) | | (9 | ) | | Payments pursuant to LTSAs | (18 | ) | | (28 | ) | | Other investing activities | (30 | ) | | (16 | ) | | Net cash used for investing activities | (198 | ) | | (170 | ) | | Financing Activities: | | | | | Decrease in notes payable, net | — |
| | (4 | ) | | Proceeds — | | | | | Senior notes | — |
| | 600 |
| | Short-term borrowings | — |
| | 300 |
| | Pollution control revenue bonds | 43 |
| | — |
| | Redemptions — | | | | | Other long-term debt | — |
| | (900 | ) | | Short-term borrowings | — |
| | (300 | ) | | Pollution control revenue bonds | — |
| | (43 | ) | | Return of capital | (113 | ) | | — |
| | Other financing activities | 1 |
| | (8 | ) | | Net cash used for financing activities | (69 | ) | | (355 | ) | | Net Change in Cash, Cash Equivalents, and Restricted Cash | (25 | ) | | 131 |
| | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 293 |
| | 248 |
| | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 268 |
| | $ | 379 |
| | Supplemental Cash Flow Information: | | | | | Cash paid (received) during the period for — | | | | | Interest (net of $(1) and $- capitalized for 2019 and 2018, respectively) | $ | 55 |
| | $ | 57 |
| | Income taxes, net | — |
| | (483 | ) | | Noncash transactions — Accrued property additions at end of period | 20 |
| | 23 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Assets | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Assets: | | | | | | Cash and cash equivalents | | $ | 268 |
| | $ | 293 |
| | Receivables — | | | | | | Customer accounts receivable | | 45 |
| | 34 |
| | Unbilled revenues | | 44 |
| | 41 |
| | Affiliated | | 23 |
| | 21 |
| | Other accounts and notes receivable | | 27 |
| | 31 |
| | Fossil fuel stock | | 18 |
| | 20 |
| | Materials and supplies | | 54 |
| | 53 |
| | Other regulatory assets | | 102 |
| | 116 |
| | Other current assets | | 9 |
| | 19 |
| | Total current assets | | 590 |
| | 628 |
| | Property, Plant, and Equipment: | | | | | | In service | | 4,829 |
| | 4,900 |
| | Less: Accumulated provision for depreciation | | 1,450 |
| | 1,429 |
| | Plant in service, net of depreciation | | 3,379 |
| | 3,471 |
| | Construction work in progress | | 109 |
| | 103 |
| | Total property, plant, and equipment | | 3,488 |
| | 3,574 |
| | Other Property and Investments | | 136 |
| | 24 |
| | Deferred Charges and Other Assets: | | | | | | Deferred charges related to income taxes | | 32 |
| | 33 |
| | Regulatory assets – asset retirement obligations | | 208 |
| | 143 |
| | Other regulatory assets, deferred | | 324 |
| | 332 |
| | Accumulated deferred income taxes | | 141 |
| | 150 |
| | Other deferred charges and assets | | 27 |
| | 2 |
| | Total deferred charges and other assets | | 732 |
| | 660 |
| | Total Assets | | $ | 4,946 |
| | $ | 4,886 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Liabilities and Stockholder's Equity | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Liabilities: | | | | | | Securities due within one year | | $ | 300 |
| | $ | 40 |
| | Accounts payable — | | | | | | Affiliated | | 63 |
| | 60 |
| | Other | | 44 |
| | 90 |
| | Accrued taxes | | 82 |
| | 95 |
| | Accrued interest | | 14 |
| | 15 |
| | Accrued compensation | | 28 |
| | 38 |
| | Accrued plant closure costs | | 21 |
| | 29 |
| | Asset retirement obligations | | 17 |
| | 34 |
| | Other regulatory liabilities | | 21 |
| | 12 |
| | Over recovered regulatory clause liabilities | | 21 |
| | 14 |
| | Other current liabilities | | 52 |
| | 28 |
| | Total current liabilities | | 663 |
| | 455 |
| | Long-term Debt | | 1,316 |
| | 1,539 |
| | Deferred Credits and Other Liabilities: | | | | | | Accumulated deferred income taxes | | 392 |
| | 378 |
| | Deferred credits related to income taxes | | 357 |
| | 382 |
| | Employee benefit obligations | | 108 |
| | 115 |
| | Asset retirement obligations, deferred | | 178 |
| | 126 |
| | Other cost of removal obligations | | 189 |
| | 185 |
| | Other regulatory liabilities, deferred | | 79 |
| | 81 |
| | Other deferred credits and liabilities | | 25 |
| | 16 |
| | Total deferred credits and other liabilities | | 1,328 |
| | 1,283 |
| | Total Liabilities | | 3,307 |
| | 3,277 |
| Common Stockholder's Equity (See accompanying statements) | | 1,639 |
| | 1,609 |
| | Total Liabilities and Stockholder's Equity | | $ | 4,946 |
| | $ | 4,886 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | Number of
Common
Shares
Issued | | Common
Stock | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total | | | (in millions) | | Balance at December 31, 2017 | 1 |
| | $ | 38 |
| | $ | 4,529 |
| | $ | (3,205 | ) | | $ | (4 | ) | | $ | 1,358 |
| Net loss after dividends on
preferred stock | — |
| | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) | | Capital contributions from parent company | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
| | Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) | | Other | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) | | Balance at March 31, 2018 | 1 |
| | 38 |
| | 4,531 |
| | (3,213 | ) | | (5 | ) | | 1,351 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 46 |
| | — |
| | 46 |
| | Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | Balance at June 30, 2018 | 1 |
| | 38 |
| | 4,531 |
| | (3,166 | ) | | (5 | ) | | 1,398 |
| Net income after dividends on
preferred stock | — |
| | — |
| | — |
| | 47 |
| | — |
| | 47 |
| | Return of capital to parent company | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | Balance at September 30, 2018 | 1 |
| | $ | 38 |
| | $ | 4,529 |
| | $ | (3,119 | ) | | $ | (5 | ) | | $ | 1,443 |
| | | | | | | | | | | | | | | Balance at December 31, 2018 | 1 |
| | $ | 38 |
| | $ | 4,546 |
| | $ | (2,971 | ) | | $ | (4 | ) | | $ | 1,609 |
| | Net income | — |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
| | Return of capital to parent company | — |
| | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) | | Capital contributions from parent company | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
| | Balance at March 31, 2019 | 1 |
| | 38 |
| | 4,510 |
| | (2,934 | ) | | (4 | ) | | 1,610 |
| | Net income | — |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
| | Return of capital to parent company | — |
| | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) | | Capital contributions from parent company | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
| | Balance at June 30, 2019 | 1 |
| | 38 |
| | 4,480 |
| | (2,897 | ) | | (4 | ) | | 1,617 |
| | Net income | — |
| | — |
| | — |
| | 65 |
| | — |
| | 65 |
| | Return of capital to parent company | — |
| | — |
| | (43 | ) | | — |
| | — |
| | (43 | ) | | Balance at September 30, 2019 | 1 |
| | $ | 38 |
| | $ | 4,437 |
| | $ | (2,832 | ) | | $ | (4 | ) | | $ | 1,639 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2019 vs. THIRD QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and number of customers and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital and operations and maintenance expenditures, including expanding and improving transmission and distribution facilities, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future. Mississippi Power is scheduled to file a base rate case by the end of 2019 (Mississippi Power 2019 Base Rate Case).
On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base rates under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers (MRA Settlement Agreement) 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, wholesale base rates decreased $3.7 million annually, effective January 1, 2019. See Note 2 to the financial statements under "FERC Matters" in Item 8 of the Form 10-K for additional information.
Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income.
Mississippi Power also continues to focus on resolution of matters related to the abandonment of the Kemper IGCC, including final disposition of the CO2 pipeline and outstanding legal proceedings and investigations.
RESULTS OF OPERATIONS
Net Income
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $18 | | 38.3 | | $53 | | 61.6 |
Mississippi Power's net income for the third quarter 2019 was $65 million compared to $47 million for the corresponding period in 2018. This increase was primarily due to a decrease in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018 and an increase in base rates that became effective for the first billing cycle of September 2018.
For year-to-date 2019, net income was $139 million compared to $86 million for the corresponding period in 2018. This increase was primarily due to lower charges associated with the Kemper IGCC in 2019, an increase in base rates that became effective for the first billing cycle of September 2018, and a decrease in employee compensation
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and benefits due to an employee attrition plan implemented in the third quarter 2018, partially offset by the settlement of Mississippi Power's Deepwater Horizon claim in May 2018.
Retail Revenues
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(3) | | (1.2) | | $9 | | 1.4 |
In the third quarter 2019, retail revenues were $251 million compared to $254 million for the corresponding period in 2018. For year-to-date 2019, retail revenues were $669 million compared to $660 million for the corresponding period in 2018.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | | | Third Quarter 2019 | | Year-to-Date 2019 | | | (in millions) | | (% change) | | (in millions) | | (% change) | | Retail – prior year | $ | 254 |
| | | | $ | 660 |
| | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | 8 |
| | 3.1 | % | | 34 |
| | 5.2 | % | | Sales decline | — |
| | — |
| | — |
| | — |
| | Weather | 2 |
| | 0.8 |
| | (7 | ) | | (1.1 | ) | | Fuel and other cost recovery | (13 | ) | | (5.1 | ) | | (18 | ) | | (2.7 | ) | | Retail – current year | $ | 251 |
| | (1.2 | )% | | $ | 669 |
| | 1.4 | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018, partially offset by a new tolling arrangement accounted for as a sales-type lease effective January 2019. The year-to-date 2019 increase was also partially offset by a rate decrease related to the Kemper County energy facility that became effective for the first billing cycle of April 2018. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan," " – Environmental Compliance Overview Plan," and " – Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and Note (L) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales were immaterial in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales increased 0.8% and 0.9% in the third quarter and year-to-date 2019, respectively, due to increased customer usage. Weather-adjusted commercial KWH sales decreased 1.4% and 2.2% in the third quarter and year-to-date 2019, respectively, due to decreased customer usage. Industrial KWH sales decreased 2.0% and 3.0% in the third quarter and year-to-date 2019, respectively, primarily due to decreased customer usage by several large industrial customers.
Revenues associated with weather decreased for year-to-date 2019 when compared to the corresponding period in 2018 primarily due to milder weather in the first quarter 2019.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(6) | | (8.6) | | $(19) | | (9.6) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.
For year-to-date 2019, wholesale revenues from sales to non-affiliates were $178 million compared to $197 million for the corresponding period in 2018. This decrease primarily resulted from a $7 million decrease in energy prices related to lower natural gas prices, a $7 million decrease in cost-based electric tariff revenues resulting from decreased customer usage and a decrease in rates due to the MRA Settlement Agreement, and a $6 million decrease due to lower PPA capacity and energy sales. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein for additional information.
Wholesale Revenues – Affiliates
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $23 | | 82.1 | | $28 | | 34.6 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the third quarter 2019, wholesale revenues from sales to affiliates were $51 million compared to $28 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to affiliates were $109 million compared to $81 million for the corresponding period in 2018. These increases were primarily due to a $27 million and $54 million increase in the third quarter and year-to-date 2019, respectively, associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load, partially offset by a $4 million and $26 million decrease in energy prices associated with lower natural gas prices in the third quarter and year-to-date 2019, respectively.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | Third Quarter 2019
vs.
Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | 5 |
| | 4.3 | | $ | 7 |
| | 2.2 | | Purchased power | (5 | ) | | (45.5) | | (12 | ) | | (44.4) | | Total fuel and purchased power expenses | $ | — |
| | | | $ | (5 | ) | | |
Total fuel and purchased power expense was $127 million for the third quarter 2019 and 2018. An $18 million net increase associated with the volume of KWHs generated and purchased was fully offset by a lower average cost of fuel.
For year-to-date 2019, total fuel and purchased power expenses were $334 million compared to $339 million for the corresponding period in 2018. The decrease was primarily due to a $29 million decrease related to the average cost of fuel and purchased power primarily due to a lower average cost of natural gas, partially offset by a $24 million net increase associated with the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | | | | | | | Third Quarter 2019 | | Third Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 | Total generation (in millions of KWHs) | 5,554 | | 4,581 | | 14,125 | | 12,665 | Total purchased power (in millions of KWHs) | 99 | | 234 | | 238 | | 441 | Sources of generation (percent) – | | | | | | | | | Coal | 8 | | 8 | | 7 | | 7 | | Gas | 92 | | 92 | | 93 | | 93 | Cost of fuel, generated (in cents per net KWH) – | | | | | | | | | Coal | 3.88 | | 3.51 | | 3.98 | | 3.50 | | Gas | 2.16 | | 2.58 | | 2.29 | | 2.57 | Average cost of fuel, generated (in cents per net KWH) | 2.30 | | 2.66 | | 2.41 | | 2.63 | Average cost of purchased power (in cents per net KWH) | 6.42 | | 4.72 | | 6.50 | | 6.15 |
Fuel
In the third quarter 2019, fuel expense was $121 million compared to $116 million for the corresponding period in 2018. For year-to-date 2019, fuel expense was $319 million compared to $312 million for the corresponding period in 2018. These increases were due to a 21% and 12% increase in the volume of KWHs generated in the third quarter and year-to-date 2019, respectively, partially offset by a 16% and 11% decrease in the average cost of natural gas per KWH generated for the third quarter and year-to-date 2019, respectively.
Purchased Power
In the third quarter 2019, purchased power expense was $6 million compared to $11 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense was $15 million compared to $27 million for the corresponding period in 2018. These decreases were primarily due to a 58% and 46% decrease in the volume of KWHs purchased due to the availability of Mississippi Power's lower-cost generation resources in the third quarter
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and year-to-date 2019, respectively, partially offset by a 36% and 6% increase in the average cost per KWH purchased in the third quarter and year-to-date 2019, respectively.
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(12) | | (15.0) | | $(28) | | (12.6) |
In the third quarter 2019, other operations and maintenance expenses were $68 million compared to $80 million for the corresponding period in 2018. The decrease was primarily due to decreases of $15 million in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018.
For year-to-date 2019, other operations and maintenance expenses were $194 million compared to $222 million for the corresponding period in 2018. The decrease was primarily due to decreases of $20 million in employee compensation and benefit expenses primarily due to an employee attrition plan implemented in the third quarter 2018, $6 million related to Plant Ratcliffe waste water treatment, and $4 million related to lower amortization of previously deferred Plant Ratcliffe expenses as a result of the MRA Settlement Agreement. These decreases were partially offset by a $6 million increase related to additional overhead line maintenance and vegetation management. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein for additional information.
Depreciation and Amortization
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $6 | | 14.3 | | $18 | | 14.3 |
In the third quarter 2019, depreciation and amortization was $48 million compared to $42 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $144 million compared to $126 million for the corresponding period in 2018. These increases were primarily related to increases in amortization associated with ECO Plan regulatory assets. 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.
Estimated Loss on Kemper IGCC
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $3 | | N/M | | $(35) | | (77.8) |
N/M - Not meaningful
In the third quarter and year-to-date 2019, estimated losses on the Kemper IGCC were $4 million and $10 million, respectively, compared to $1 million and $45 million, respectively, for the corresponding periods in 2018. These charges relate to abandonment and closure activities for the mine and gasifier-related assets.
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power – Kemper County Energy Facility" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(2) | | (10.5) | | $(7) | | (11.9) |
In the third quarter 2019, interest expense, net of amounts capitalized was $17 million compared to $19 million for the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $52 million compared to $59 million for the corresponding period in 2018. These decreases primarily resulted from a decrease in outstanding long-term borrowings.
Other Income (Expense), Net
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $4 | | N/M | | $(13) | | (46.4) |
N/M - Not meaningful
For year-to-date 2019, other income (expense), net was $15 million compared to $28 million for the corresponding period in 2018. This decrease was primarily due to a $24 million decrease related to the settlement of Mississippi Power's Deepwater Horizon claim recorded in May 2018, partially offset by an increase of $9 million primarily due to higher interest income associated with a new tolling arrangement accounted for as a sales-type lease. See Note (L) to the Condensed Financial Statements herein and Note 3 to the financial statements under "Other Matters – Mississippi Power" in Item 8 of the Form 10-K for additional information.
Income Taxes
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $1 | | 7.1 | | $4 | | 17.4 |
In the third quarter 2019, income taxes were $15 million compared to $14 million for the corresponding period in 2018. For year-to-date 2019, income taxes were $27 million compared to $23 million for the corresponding period in 2018. These increases were primarily due to higher pre-tax earnings, partially offset by an increase in the flowback of excess deferred income taxes as a result of both the MRA Settlement Agreement and a new tolling arrangement accounted for as a sales-type lease.See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by continued customer growth and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. Mississippi Power is scheduled to file a base rate case by the end of 2019.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Mississippi Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Mississippi Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Mississippi Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Mississippi Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis or through long-term wholesale agreements. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Air Quality
On September 13, 2019, the D.C. Circuit Court of Appeals dismissed most challenges brought against the 2016 Cross-State Air Pollution Rule update (2016 CSAPR Update), including the application of the EPA's new emissions allowance budget methodology to the State of Mississippi, which had been challenged by Mississippi Power. However, the court agreed that the 2016 CSAPR Update was unlawful because it allows upwind states to continue their significant contributions to downwind air quality problems beyond statutory deadlines. Accordingly, the court remanded the 2016 CSAPR Update to the EPA. The 2016 CSAPR Update allowance budgets remain in place while the EPA considers how to address the court's remand. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the finalrule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Coal Combustion Residuals
In the second quarter 2019, Mississippi Power recorded an increase of approximately $58 million to its AROs for higher expected compliance costs related to the CCR Rule (and the related State of Alabama rule, as applicable). Approximately $49 million of the revised cost estimates are associated with an ash pond at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close this ash pond under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and an increase in the estimated ash volume.
As further analysis is performed and additional details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. Additionally, the closure designs and plans in the State of Alabama are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. 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 and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Global Climate Issues
On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. On September 17, 2019, the D.C. Circuit Court of Appeals dismissed litigation related to the CPP as moot. The ACE Rule requires states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Mississippi Power has ownership interests in two coal-fired units (approximately 500 MWs) to which the ACE Rule is applicable. The ACE Rule is being challenged in the D.C. Circuit Court of Appeals. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Mississippi Power will depend on state implementation plan requirements and the outcome of associated legal challenges and cannot be determined at this time.
FERC Matters
See Note 2 to the financial statements under "FERC Matters" in Item 8 of the Form 10-K for additional information.
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 rates under the MRA tariff as agreed upon in the MRA Settlement Agreement 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, wholesale base rates decreased $3.7 million annually, effective January 1, 2019.
Open Access Transmission Tariff
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 (including Mississippi Power) 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 Mississippi Power.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates under PEP and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
expected to be recovered through Mississippi Power's base rates. Mississippi Power is scheduled to file a base rate case by the end of 2019.
See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Environmental Compliance Overview Plan
On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9, 2019 request 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 (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information on AROs and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.
Fuel Cost Recovery
At September 30, 2019 and December 31, 2018, approximately $18 million and $8 million, respectively, of over-recovered fuel costs was included in over recovered regulatory clause liabilities on Mississippi Power's condensed balance sheet.
Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.
Kemper County Energy Facility
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
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 third quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $10 million ($7 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 $3 million for the remainder of 2019 and $2 million to $7 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 by year-end 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.
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 financial statements.
Other Matters
Mississippi Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.
Litigation
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two2 agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In the first quarterMay 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. Ondenied Mississippi Power's and Southern Company's motions to dismiss. In September 27, 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. During the third quarter 2020, the plaintiffs reduced their claim for damages to approximately $76 million. On October 12, 2020, the arbitration panel issued a unanimous award in favor of Mississippi Power on all claims. This matter is now concluded. In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three current3 then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint onin March 14, 2019. The amended complaint included four4 additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power believes these legal challenges have no merit; however, anand the Mississippi PSC, respectively, filed responses opposing the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) motion for leave to file a second amended complaint. On May 26, 2020, the court granted Mississippi Power's motion to dismiss the first amended complaint filed in 2019. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. On July 28, 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which includes the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. An adverse outcome in either of these proceedingsthis proceeding could have a material impact on Mississippi Power's resultsfinancial statements. See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of operations, financial condition,the Form 10-K for additional information. Environmental Remediation The Southern Company system must comply with environmental laws and liquidity. regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. Georgia Power's environmental remediation liability was $15 million at both September 30, 2020 and December 31, 2019. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. In December 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. Potential remediation activities and related cost estimates are pending the result of further site assessment and cannot be determined at this time. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates. Southern Company Gas' environmental remediation liability was $252 million and $269 million as of September 30, 2020 and December 31, 2019, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities. The ultimate outcome of these matters cannot be determined at this time. ACCOUNTING POLICIES
Applicationtime; however, as a result of Critical Accounting Policies and Estimates
Mississippi Power prepares itsthe regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
Nuclear Fuel Disposal Costs On August 13, 2020, Alabama Power and Georgia Power filed amended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2. The amended complaints add damages from January 1, 2018 to December 31, 2019 to the claim period. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of September 30, 2020 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) the benefit of customers in accordance with GAAP. Significant accounting policies are described indirection from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected. Other Matters Southern Company See Notes 1 5, and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through September 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease. In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax). If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill. Mississippi Power Kemper County Energy Facility See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information. 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 related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. 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. 10-K for additional information. For year-to-date 2020, Mississippi Power recorded pre-tax (and after-tax) charges to income totaling $2 million primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) for the mine and gasifier-related assets at the Kemper County energy facility. Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $3 million for the remainder of 2020 and $10 million to $15 million annually for 2021 through 2025. In December 2019, Mississippi Power transferred ownership of the applicationCO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of these policies, certain estimates are made that maythe CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement is expected to be treated as a finance lease for accounting purposes upon commencement. On September 3, 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request for property closeout certification under the contract related to the DOE grants received for the Kemper County energy facility, which enables Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. The execution of the agreement had no material impact on Mississippi Power's financial statements. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the $387 million of DOE grants received. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's resultsfinancial statements. Plant Daniel In conjunction with Southern Company's sale of operationsGulf Power, Mississippi Power and related disclosures. Different assumptionsGulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and measurements could produce estimates thatGulf Power amended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. The parties agreed not to select a specific unit by August 1, 2020 and are significantly different from those recorded incontinuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. Southern Company Gas See Notes 3 and 7 to the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Powerstatements in Item 78 of the Form 10-K under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, and Note (E) under "Southern Company Gas" for additional information. On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information. On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022. In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision. Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements. (D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME Revenue from Contracts with Customers The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2020 and 2019: | | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | (in millions) | | Three Months Ended September 30, 2020 | | | | | | | | Operating revenues | | | | | | | | Retail electric revenues | | | | | | | | Residential | $ | 2,019 | | $ | 752 | | $ | 1,183 | | $ | 84 | | $ | 0 | | $ | 0 | | | Commercial | 1,354 | | 447 | | 833 | | 74 | | 0 | | 0 | | | Industrial | 783 | | 358 | | 352 | | 73 | | 0 | | 0 | | | Other | 22 | | 5 | | 15 | | 2 | | 0 | | 0 | | | Total retail electric revenues | 4,178 | | 1,562 | | 2,383 | | 233 | | 0 | | 0 | | | Natural gas distribution revenues | | | | | | | | Residential | 170 | | 0 | | 0 | | 0 | | 0 | | 170 | | | Commercial | 41 | | 0 | | 0 | | 0 | | 0 | | 41 | | | Transportation | 224 | | 0 | | 0 | | 0 | | 0 | | 224 | | | Industrial | 4 | | 0 | | 0 | | 0 | | 0 | | 4 | | | Other | 35 | | 0 | | 0 | | 0 | | 0 | | 35 | | | Total natural gas distribution revenues | 474 | | 0 | | 0 | | 0 | | 0 | | 474 | | | Wholesale electric revenues | | | | | | | | PPA energy revenues | 214 | | 40 | | 13 | | 2 | | 165 | | 0 | | | PPA capacity revenues | 136 | | 26 | | 15 | | 1 | | 95 | | 0 | | | Non-PPA revenues | 59 | | 10 | | 3 | | 93 | | 68 | | 0 | | | Total wholesale electric revenues | 409 | | 76 | | 31 | | 96 | | 328 | | 0 | | | Other natural gas revenues | | | | | | | | | | | | | | | Wholesale gas services | 431 | | 0 | | 0 | | 0 | | 0 | | 431 | | | Gas marketing services | 38 | | 0 | | 0 | | 0 | | 0 | | 38 | | | Other natural gas revenues | 7 | | 0 | | 0 | | 0 | | 0 | | 7 | | | Total natural gas revenues | 476 | | 0 | | 0 | | 0 | | 0 | | 476 | | | Other revenues | 218 | | 33 | | 115 | | 6 | | 4 | | 0 | | | Total revenue from contracts with customers | 5,755 | | 1,671 | | 2,529 | | 335 | | 332 | | 950 | | Other revenue sources(a) | 968 | | 58 | | 88 | | 1 | | 191 | | 630 | | Other adjustments(b) | (1,103) | | 0 | | 0 | | 0 | | 0 | | (1,103) | | | Total operating revenues | $ | 5,620 | | $ | 1,729 | | $ | 2,617 | | $ | 336 | | $ | 523 | | $ | 477 | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | (in millions) | | Nine Months Ended September 30, 2020 | | | | | | | | Operating revenues | | | | | | | | Retail electric revenues | | | | | | | | Residential | $ | 4,802 | | $ | 1,839 | | $ | 2,760 | | $ | 203 | | $ | 0 | | $ | 0 | | | Commercial | 3,589 | | 1,152 | | 2,242 | | 195 | | 0 | | 0 | | | Industrial | 2,081 | | 956 | | 907 | | 218 | | 0 | | 0 | | | Other | 68 | | 16 | | 46 | | 6 | | 0 | | 0 | | | Total retail electric revenues | 10,540 | | 3,963 | | 5,955 | | 622 | | 0 | | 0 | | | Natural gas distribution revenues | | | | | | | | Residential | 906 | | 0 | | 0 | | 0 | | 0 | | 906 | | | Commercial | 229 | | 0 | | 0 | | 0 | | 0 | | 229 | | | Transportation | 723 | | 0 | | 0 | | 0 | | 0 | | 723 | | | Industrial | 21 | | 0 | | 0 | | 0 | | 0 | | 21 | | | Other | 179 | | 0 | | 0 | | 0 | | 0 | | 179 | | | Total natural gas distribution revenues | 2,058 | | 0 | | 0 | | 0 | | 0 | | 2,058 | | | Wholesale electric revenues | | | | | | | | PPA energy revenues | 550 | | 94 | | 38 | | 7 | | 425 | | 0 | | | PPA capacity revenues | 339 | | 78 | | 30 | | 3 | | 231 | | 0 | | | Non-PPA revenues | 159 | | 33 | | 7 | | 235 | | 184 | | 0 | | | Total wholesale electric revenues | 1,048 | | 205 | | 75 | | 245 | | 840 | | 0 | | | Other natural gas revenues | | | | | | | | | | | | | | | Wholesale gas services | 1,168 | | 0 | | 0 | | 0 | | 0 | | 1,168 | | | Gas marketing services | 258 | | 0 | | 0 | | 0 | | 0 | | 258 | | | Other natural gas revenues | 22 | | 0 | | 0 | | 0 | | 0 | | 22 | | | Total natural gas revenues | 1,448 | | 0 | | 0 | | 0 | | 0 | | 1,448 | | | Other revenues | 677 | | 117 | | 329 | | 19 | | 11 | | 0 | | | Total revenue from contracts with customers | 15,771 | | 4,285 | | 6,359 | | 886 | | 851 | | 3,506 | | Other revenue sources(a) | 2,604 | | 160 | | 12 | | 9 | | 486 | | 1,973 | | Other adjustments(b) | (3,117) | | 0 | | 0 | | 0 | | 0 | | (3,117) | | | Total operating revenues | $ | 15,258 | | $ | 4,445 | | $ | 6,371 | | $ | 895 | | $ | 1,337 | | $ | 2,362 | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | (in millions) | | Three Months Ended September 30, 2019 | | | | | | | | Operating revenues | | | | | | | | Retail electric revenues | | | | | | | | Residential | $ | 2,119 | | $ | 820 | | $ | 1,211 | | $ | 88 | | $ | 0 | | $ | 0 | | | Commercial | 1,563 | | 512 | | 965 | | 86 | | 0 | | 0 | | | Industrial | 953 | | 421 | | 450 | | 82 | | 0 | | 0 | | | Other | 26 | | 7 | | 16 | | 3 | | 0 | | 0 | | | Total retail electric revenues | 4,661 | | 1,760 | | 2,642 | | 259 | | 0 | | 0 | | | Natural gas distribution revenues | | | | | | | | Residential | 162 | | 0 | | 0 | | 0 | | 0 | | 162 | | | Commercial | 42 | | 0 | | 0 | | 0 | | 0 | | 42 | | | Transportation | 204 | | 0 | | 0 | | 0 | | 0 | | 204 | | | Industrial | 3 | | 0 | | 0 | | 0 | | 0 | | 3 | | | Other | 30 | | 0 | | 0 | | 0 | | 0 | | 30 | | | Total natural gas distribution revenues | 441 | | 0 | | 0 | | 0 | | 0 | | 441 | | | Wholesale electric revenues | | | | | | | | PPA energy revenues | 245 | | 43 | | 19 | | 2 | | 188 | | 0 | | | PPA capacity revenues | 134 | | 25 | | 13 | | 1 | | 100 | | 0 | | | Non-PPA revenues | 62 | | 2 | | 3 | | 111 | | 81 | | 0 | | | Total wholesale electric revenues | 441 | | 70 | | 35 | | 114 | | 369 | | 0 | | | Other natural gas revenues | | | | | | | | | | | | | | | Wholesale gas services | 425 | | 0 | | 0 | | 0 | | 0 | | 425 | | | Gas marketing services | 37 | | 0 | | 0 | | 0 | | 0 | | 37 | | | Other natural gas revenues | 10 | | 0 | | 0 | | 0 | | 0 | | 10 | | | Total natural gas revenues | 472 | | 0 | | 0 | | 0 | | 0 | | 472 | | | Other revenues | 267 | | 36 | | 113 | | 4 | | 3 | | 0 | | | Total revenue from contracts with customers | 6,282 | | 1,866 | | 2,790 | | 377 | | 372 | | 913 | | Other revenue sources(a) | 855 | | (25) | | (35) | | (7) | | 202 | | 727 | | Other adjustments(b) | (1,142) | | 0 | | 0 | | 0 | | 0 | | (1,142) | | | Total operating revenues | $ | 5,995 | | $ | 1,841 | | $ | 2,755 | | $ | 370 | | $ | 574 | | $ | 498 | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | (in millions) | | Nine Months Ended September 30, 2019 | | | | | | | | Operating revenues | | | | | | | | Retail electric revenues | | | | | | | | Residential | $ | 4,939 | | $ | 1,971 | | $ | 2,751 | | $ | 217 | | $ | 0 | | $ | 0 | | | Commercial | 3,951 | | 1,301 | | 2,427 | | 223 | | 0 | | 0 | | | Industrial | 2,428 | | 1,128 | | 1,074 | | 226 | | 0 | | 0 | | | Other | 69 | | 20 | | 41 | | 8 | | 0 | | 0 | | | Total retail electric revenues | 11,387 | | 4,420 | | 6,293 | | 674 | | — | | 0 | | | Natural gas distribution revenues | | | | | | | | Residential | 992 | | 0 | | 0 | | 0 | | 0 | | 992 | | | Commercial | 277 | | 0 | | 0 | | 0 | | 0 | | 277 | | | Transportation | 673 | | 0 | | 0 | | 0 | | 0 | | 673 | | | Industrial | 25 | | 0 | | 0 | | 0 | | 0 | | 25 | | | Other | 191 | | 0 | | 0 | | 0 | | 0 | | 191 | | | Total natural gas distribution revenues | 2,158 | | 0 | | 0 | | 0 | | 0 | | 2,158 | | | Wholesale electric revenues | | | | | | | | PPA energy revenues | 648 | | 110 | | 47 | | 8 | | 508 | | 0 | | | PPA capacity revenues | 350 | | 77 | | 41 | | 2 | | 272 | | 0 | | | Non-PPA revenues | 174 | | 65 | | 5 | | 275 | | 190 | | 0 | | | Total wholesale electric revenues | 1,172 | | 252 | | 93 | | 285 | | 970 | | 0 | | | Other natural gas revenues | | | | | | | | | | | | | | | Wholesale gas services | 1,590 | | 0 | | 0 | | 0 | | 0 | | 1,590 | | | Gas marketing services | 313 | | 0 | | 0 | | 0 | | 0 | | 313 | | | Other natural gas revenues | 32 | | 0 | | 0 | | 0 | | 0 | | 32 | | | Total natural gas revenues | 1,935 | | 0 | | 0 | | 0 | | 0 | | 1,935 | | | Other revenues | 763 | | 119 | | 298 | | 14 | | 10 | | 0 | | | Total revenue from contracts with customers | 17,415 | | 4,791 | | 6,684 | | 973 | | 980 | | 4,093 | | Other revenue sources(a) | 3,266 | | (29) | | 22 | | (3) | | 547 | | 2,744 | | Other adjustments(b) | (4,176) | | 0 | | 0 | | 0 | | 0 | | (4,176) | | | Total operating revenues | $ | 16,505 | | $ | 4,762 | | $ | 6,706 | | $ | 970 | | $ | 1,527 | | $ | 2,661 | |
(a)Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenue programs at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies. (b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Contract Balances The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2020 and December 31, 2019: | | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | (in millions) | | Accounts Receivables | | | | | | | | As of September 30, 2020 | $ | 2,344 | | $ | 686 | | $ | 901 | | $ | 93 | | $ | 100 | | $ | 385 | | | As of December 31, 2019 | 2,413 | | 586 | | 688 | | 79 | | 97 | | 749 | | | Contract Assets | | | | | | | | As of September 30, 2020 | $ | 159 | | $ | 5 | | $ | 103 | | $ | 0 | | $ | 0 | | $ | 0 | | | As of December 31, 2019 | 117 | | 0 | | 69 | | 0 | | 0 | | 0 | | | Contract Liabilities | | | | | | | | As of September 30, 2020 | $ | 56 | | $ | 1 | | $ | 24 | | $ | 0 | | $ | 3 | | $ | 1 | | | As of December 31, 2019 | 52 | | 10 | | 13 | | 0 | | 1 | | 1 | |
As of September 30, 2020 and December 31, 2019, Georgia Power had contract assets primarily related to fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a complete discussionone-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Southern Company's unregulated distributed generation business had $47 million and $40 million of contract assets and $22 million and $28 million of contract liabilities at September 30, 2020 and December 31, 2019, respectively, for outstanding performance obligations. Revenues recognized by Southern Company in the three and nine months ended September 30, 2020, which were included in contract liabilities at December 31, 2019, were $8 million and $29 million, respectively, and immaterial for all other applicable Registrants. Remaining Performance Obligations The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenue from contracts with customers related to these performance obligations remaining at September 30, 2020 are expected to be recognized as follows: | | | | | | | | | | | | | | | | | | | | | | 2020
(remaining) | 2021 | 2022 | 2023 | 2024 | 2025 and
Thereafter | | (in millions) | | Southern Company | $ | 170 | | $ | 487 | | $ | 362 | | $ | 339 | | $ | 319 | | $ | 3,062 | | | Alabama Power | 7 | | 33 | | 31 | | 24 | | 7 | | 5 | | | Georgia Power | 20 | | 71 | | 43 | | 35 | | 24 | | 62 | | | | | | | | | | Southern Power | 60 | | 290 | | 292 | | 282 | | 290 | | 3,013 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Revenue expected to be recognized for performance obligations remaining at September 30, 2020 was immaterial for Mississippi Power's critical accounting policiesPower. Lease Income Lease income for the three and estimates.nine months ended September 30, 2020 and 2019 is as follows: Recently Issued Accounting Standards | | | | | | | | | | | | | | | | | | | | | | Southern
Company | Alabama Power | Georgia Power | Mississippi
Power | Southern Power | Southern Company Gas | | | (in millions) | | For the Three Months Ended September 30, 2020 | | Lease income - interest income on sales-type leases | $ | 3 | | $ | 0 | | $ | 0 | | $ | 3 | | $ | 0 | | $ | 0 | | | Lease income - operating leases | 50 | | 11 | | 14 | | 0 | | 21 | | 9 | | | Variable lease income | 145 | | 0 | | 0 | | 0 | | 153 | | 0 | | | Total lease income | $ | 198 | | $ | 11 | | $ | 14 | | $ | 3 | | $ | 174 | | $ | 9 | | | | | | | | | | For the Nine Months Ended September 30, 2020 | | Lease income - interest income on sales-type leases | $ | 8 | | $ | 0 | | $ | 0 | | $ | 8 | | $ | 0 | | $ | 0 | | | Lease income - operating leases | 148 | | 24 | | 44 | | 1 | | 66 | | 26 | | | Variable lease income | 345 | | 0 | | 0 | | 0 | | 368 | | 0 | | | Total lease income | $ | 501 | | $ | 24 | | $ | 44 | | $ | 9 | | $ | 434 | | $ | 26 | | | | | | | | | | For the Three Months Ended September 30, 2019 | | Lease income - interest income on sales-type leases | $ | 2 | | $ | 0 | | $ | 0 | | $ | 2 | | $ | 0 | | $ | 0 | | | Lease income - operating leases | 64 | | 5 | | 18 | | 0 | | 31 | | 9 | | | Variable lease income | 141 | | 0 | | 0 | | 0 | | 151 | | 0 | | | Total lease income | $ | 207 | | $ | 5 | | $ | 18 | | $ | 2 | | $ | 182 | | $ | 9 | | | | | | | | | | For the Nine Months Ended September 30, 2019 | | Lease income - interest income on sales-type leases | $ | 7 | | $ | 0 | | $ | 0 | | $ | 7 | | $ | 0 | | $ | 0 | | | Lease income - operating leases | 216 | | 19 | | 57 | | 0 | | 111 | | 26 | | | Variable lease income | 324 | | 0 | | 0 | | 0 | | 349 | | 0 | | | Total lease income | $ | 547 | | $ | 19 | | $ | 57 | | $ | 7 | | $ | 460 | | $ | 26 | |
Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. As part of the Autauga Combined Cycle Acquisition, Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. These revenues are included above as lease income from operating leases. See Note (B) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Alabama Power" for additional information. Lease Receivables Mississippi Power completed construction of additional leased assets under an existing sales-type lease during the third quarter 2020. Upon completion of construction, the book value of $25 million was transferred from CWIP to lease receivables, of which $22 million and $3 million is included in other property and investments and other accounts and notes receivable, respectively, at September 30, 2020. The transfer represents a non-cash investing transaction for purposes of the statements of cash flows.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) (E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS See Note (A)7 to the Condensed Financial Statements herein for information regarding Mississippi Power's recently adopted accounting standards. FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Powerfinancial statements in Item 78 of the Form 10-K for additional information.
Mississippi Power's
Southern Power Variable Interest Entities Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. SP Solar and SP Wind At September 30, 2020 and December 31, 2019, SP Solar had total assets of $6.3 billion and $6.4 billion, respectively, and total liabilities of $382 million. Noncontrolling interests totaled $1.1 billion at both September 30, 2020 and December 31, 2019. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash requirements primarilyand SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. At September 30, 2020 and December 31, 2019, SP Wind had total assets of $2.4 billion and $2.5 billion, respectively, total liabilities of $129 million and $128 million, respectively, and noncontrolling interests of $44 million and $45 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the 3 financial investors in accordance with the limited liability agreement. Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of funding ongoing operations, common stock dividends,customary working capital expenditures,items and debt maturities. Capital expenditures anddo not include any long-term debt. Other Variable Interest Entities Southern Power has other investing activities include investments to maintain existing generation facilities, to comply with environmental regulations including adding environmental modificationsconsolidated VIEs that relate to certain existing generating unitssubsidiaries that have either sold noncontrolling interests to tax-equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and closuresthe noncontrolling members do not have substantive kick-out rights. At September 30, 2020 and December 31, 2019, the other VIEs had total assets of ash ponds, to expand$1.1 billion, total liabilities of $109 million and improve transmission$104 million, respectively, and distribution facilities,noncontrolling interests of $471 million and for restoration following major storms. Net cash provided from operating activities totaled $242$409 million, forrespectively. Under the first nine months of 2019, a decrease of $414 million as compared to the corresponding period in 2018. The decrease in net cash provided from operating activities is primarily related to higher income tax refunds in 2018 as a resultterms of the tax abandonmentpartnership agreements, distributions of the Kemper IGCC. Netall available cash used for investing activities totaled $198are required each month or quarter and additional distributions require partner consent.
Equity Method Investments At September 30, 2020 and December 31, 2019, Southern Power had equity method investments in wind and battery storage projects totaling $19 million for the first nine months of 2019 primarily due to gross property additions related to distribution and transmission facilities. Net cash used for financing activities totaled $69$28 million, for the first nine months of 2019 primarily due to a return of capital to Southern Company, partially offset by $43 million of pollution control revenue bonds reoffered to the public. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(UNAUDITED)
Significant balance sheet changes forEquity Method Investments
On March 24, 2020, Southern Company Gas completed the first nine monthssale of 2019 include a decrease of $223 millionits interests in long-term debt, primarily due to the reclassification of $300 million in unsecured senior notes to securities due within one year, partially offset by $43 million in securities reoffered to the publicPivotal LNG and $40 million in variable rate revenue bonds reclassified from securities due within one year. Other significant changes include an increase of $112 million in other property and investments, partially offset by a $71 million decrease in plant in service primarily due to a new tolling arrangement, effective January 1, 2019, accounted for as a sales-type lease; increases of $65 million in regulatory assets – asset retirement obligations and $52 million in asset retirement obligations, deferred primarily due to ARO revisions; and a decrease of $46 million in accounts payable, other.Atlantic Coast Pipeline. See Notes (A) and (L) to the Condensed Financial Statements hereinNote (K) under "Southern Company Gas" for additional information. Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations"The carrying amounts of Mississippi Power in Item 7Southern Company Gas' equity method investments as of the Form 10-K for a description of Mississippi Power's capital requirements and contractual obligations. Approximately $300 million will be required through September 30, 2020 and December 31, 2019 and related income from those investments for the three and nine months ended September 30, 2020 and 2019 were as follows:
| | | | | | | | | | Investment Balance | September 30, 2020 | December 31, 2019(a) | | (in millions) | SNG(b) | $ | 1,180 | | $ | 1,137 | | PennEast Pipeline(c) | 89 | | 82 | | | Other | 32 | | 32 | | | Total | $ | 1,301 | | $ | 1,251 | |
(a)Excludes investments in Atlantic Coast Pipeline and Pivotal JAX LNG classified as held for sale at December 31, 2019. See Note 15 to fund maturities of long-term debt. See "Sources of Capital" hereinthe financial statements under "Assets Held for additional information. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Mississippi Power plans to obtain the funds to meet its future capital needs from operating cash flows, external securities issuances, borrowings from financial institutions, including commercial paper, and equity contributions from Southern Company. However, the amount, type, and timing of any future financing, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations"Sale" in Item 78 of the Form 10-K for additional information.
As(b)Increase primarily relates to a capital contribution, partially offset by the continued amortization of deferred tax assets established upon acquisition.
(c)See Note (C) under "Other Matters – Southern Company Gas" for additional information on the PennEast Pipeline. | | | | | | | | | | | | | | | | Earnings from Equity Method Investments | Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | | (in millions) | | SNG | $ | 30 | | $ | 30 | | $ | 95 | | $ | 104 | | Atlantic Coast Pipeline(a)(b) | 0 | | 3 | | 3 | | 9 | | PennEast Pipeline(a) | 2 | | 2 | | 5 | | 5 | | | Other | 1 | | 0 | | 3 | | (3) | | | Total | $ | 33 | | $ | 35 | | $ | 106 | | $ | 115 | |
(a)Amounts primarily result from AFUDC equity recorded by the project entity. (b)On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information. SNG Selected financial information of SNG for the three and nine months ended September 30, 2020 and 2019 Mississippi Power's current liabilities exceeded current assets by approximately $73 million primarilyis as a resultfollows: | | | | | | | | | | | | | | | | Income Statement Information | Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | | (in millions) | | Revenues | $ | 150 | | $ | 152 | | $ | 457 | | $ | 473 | | | Operating income | 85 | | 82 | | 262 | | 274 | | | Net income | 59 | | 60 | | 189 | | 208 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) (F) FINANCING Bank Credit Arrangements See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information. AllAt September 30, 2020, committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expires | | | | | | | | | | Company | | 2021 | 2022 | 2023 | 2024 | | Total | | Unused | | | | | | | | Due within One Year | | | (in millions) | | Southern Company parent | | $ | 0 | | $ | 0 | | $ | 0 | | $ | 2,000 | | | $ | 2,000 | | | $ | 1,999 | | | | | | | | | $ | 0 | | | Alabama Power | | 3 | | 525 | | 0 | | 800 | | | 1,328 | | | 1,328 | | | | | | | | | 3 | | | Georgia Power | | 0 | | 0 | | 0 | | 1,750 | | | 1,750 | | | 1,728 | | | | | | | | | 0 | | | Mississippi Power | | 0 | | 150 | | 125 | | 0 | | | 275 | | | 250 | | | | | | | | | 0 | | Southern Power(a) | | 0 | | 0 | | 0 | | 600 | | | 600 | | | 591 | | | | | | | | | 0 | | Southern Company Gas(b) | | 0 | | 0 | | 0 | | 1,750 | | | 1,750 | | | 1,745 | | | | | | | | | 0 | | | SEGCO | | 30 | | 0 | | 0 | | 0 | | | 30 | | | 30 | | | | | | | | | 30 | | | Southern Company | | $ | 33 | | $ | 675 | | $ | 125 | | $ | 6,900 | | | $ | 7,733 | | | $ | 7,671 | | | | | | | | | $ | 33 | |
(a)Does not include Southern Power Company's $120 million and $60 million continuing letter of thesecredit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $23 million and $40 million, respectively, was unused at September 30, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities. (b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. As reflected in the table above, in March 2020, Mississippi Power entered into a $125 million revolving credit facility that matures in March 2023. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder. These bank credit arrangements, as well as the term loan arrangements of the Registrants and SEGCO, contain covenants that limit debt levels and typically contain cross-acceleration or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Mississippi Power.the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Powerthe applicable borrower defaulted on
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
indebtedness, the payment of which was then accelerated. At September 30, 2019, Mississippi Power was2020, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.borrowings. SubjectA portion of the unused credit with banks is allocated to applicable market conditions, Mississippi Power expectsprovide liquidity support to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decreaserevenue bonds of the lending commitments thereunder.
Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional electric operating companies. Proceeds from such issuances forcompanies and the benefitcommercial paper programs of Mississippi Power are loaned directly to Mississippi Power.the Registrants, Nicor Gas, and SEGCO. The obligationsamount of eachvariable rate revenue bonds of the traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Short-term debt, including the average amount and maximum amountcompanies outstanding was immaterialrequiring liquidity support at September 30, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2020, Georgia Power had approximately $257 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Earnings per Share For Southern Company, the only differences in computing basic and diluted earnings per share are attributable to awards outstanding under stock-based compensation plans and the equity units issued in August 2019. Earnings per share dilution resulting from stock-based compensation plans and the equity units issuance is determined using the treasury stock method. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on the August 2019 equity units issuance and duringNote 12 to the three-month periodfinancial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows: | | | | | | | | | | | | | | | | Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | | | (in millions) | | As reported shares | 1,058 | | 1,048 | | 1,058 | | 1,043 | | | Effect of stock-based compensation | 6 | | 9 | | 6 | | 8 | | | | | | | | Diluted shares | 1,064 | | 1,057 | | 1,064 | | 1,051 | |
An immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive for the three and nine months ended September 30, 2020. There were 0 such amounts for the three and nine months ended September 30, 2019. Mississippi Power believesAn immaterial number of shares related to the needequity units issued in August 2019 was included in the calculation of diluted earnings per share for working capital can be adequately met by utilizing lines of credit, short-term bank notes, the commercial paper program, operating cash flows, andnine months ended September 30, 2020. There were no such amounts for all other cash.periods presented.
Credit Rating Risk
(G) INCOME TAXES See MANAGEMENT'S DISCUSSION AND ANALYSISNote 10 to the financial statements in Item 8 of the Form 10-K for additional tax information. Current and Deferred Income Taxes Tax Credit and Net Operating Loss Carryforwards Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.5 billion as of September 30, 2020 compared to $1.8 billion as of December 31, 2019. The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each Registrants' estimated tax credit and net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, potential impacts of the COVID-19 pandemic, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4. Effective Tax Rate Details of significant changes in the effective tax rate for the applicable Registrants are provided herein. Southern Company Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.
NOTES TO THE CONDENSED FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk"STATEMENTS (Continued) (UNAUDITED) Southern Company's effective tax rate was 13.9% for the nine months ended September 30, 2020 compared to 30.2% for the corresponding period in 2019. The effective tax rate decrease was primarily due to the tax impact from the sale of MississippiGulf Power in 2019, as well as an increase in the flowback of excess deferred income taxes in 2020 primarily at Georgia Power. See Note 15 to the financial statements under "Southern Company" in Item 78 of the Form 10-K for additional information. Georgia Power Georgia Power's effective tax rate was 12.3% for the nine months ended September 30, 2020 compared to 22.6% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP, as well as the second quarter 2020 charge to earnings associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information. Mississippi Power Mississippi Power's effective tax rate was 12.7% for the nine months ended September 30, 2020 compared to 16.3% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2020 as authorized in the Mississippi Power Rate Case Settlement Agreement. See Note (B) under "Mississippi Power – 2019 Base Rate Case" for additional information. Southern Power Southern Power's effective tax rate was 11.3% for the nine months ended September 30, 2020 compared to a benefit rate of (13.6)% for the corresponding period in 2019. The effective tax rate increase was primarily due to tax benefits resulting from ITCs recognized upon the sale of Plant Nacogdoches in 2019. See Note (K) under "Southern Power" for additional information. Southern Company Gas Southern Company Gas' effective tax rate was 21.4% for the nine months ended September 30, 2020 compared to 15.0% for the corresponding period in 2019. The effective tax rate increase was primarily due to higher flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019. See Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information. (H) RETIREMENT BENEFITS The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). NaN mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2020. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information. Effective January 1, 2020, Southern Company adopted a change in method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets will continue to use the calculated value approach in determining the market-related value. Southern Company considers the fair value approach to be preferable because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost. Southern Company evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements of all Registrants and therefore did not account for the change retrospectively. The change in accounting principle was recorded through earnings as a prior period adjustment for the amounts related to the unregulated businesses of Southern Company and Southern Power. Amounts related to the traditional electric operating companies and the natural gas distribution utilities have been reflected as adjustments to regulatory assets as appropriate, consistent with the expected regulatory treatment. On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2020 and 2019 are presented in the following tables. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2020 | Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 94 | | | $ | 23 | | | $ | 24 | | | $ | 3 | | | $ | 2 | | | $ | 8 | | | Interest cost | 108 | | | 25 | | | 33 | | | 5 | | | 1 | | | 8 | | | Expected return on plan assets | (274) | | | (66) | | | (87) | | | (13) | | | (4) | | | (20) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | (1) | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 4 | | | Net (gain)/loss | 67 | | | 17 | | | 22 | | | 4 | | | 1 | | | 2 | | | Net periodic pension cost (income) | $ | (5) | | | $ | 0 | | | $ | (8) | | | $ | (1) | | | $ | 0 | | | $ | 1 | | | Postretirement Benefits | | Service cost | $ | 6 | | | $ | 1 | | | $ | 2 | | | $ | (1) | | | $ | 1 | | | $ | 0 | | | Interest cost | 13 | | | 4 | | | 5 | | | 1 | | | 0 | | | 2 | | | Expected return on plan assets | (18) | | | (7) | | | (7) | | | 0 | | | 0 | | | (2) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 2 | | | Net (gain)/loss | 1 | | | 0 | | | 1 | | | 0 | | | 0 | | | (1) | | | Net periodic postretirement benefit cost | $ | 2 | | | $ | (2) | | | $ | 0 | | | $ | 0 | | | $ | 1 | | | $ | 1 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2020 | Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 282 | | | $ | 67 | | | $ | 72 | | | $ | 11 | | | $ | 6 | | | $ | 24 | | | Interest cost | 324 | | | 75 | | | 100 | | | 15 | | | 4 | | | 23 | | | Expected return on plan assets | (824) | | | (198) | | | (261) | | | (38) | | | (10) | | | (59) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 1 | | | 1 | | | 1 | | | 0 | | | 0 | | | (2) | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 12 | | | Net (gain)/loss | 201 | | | 53 | | | 65 | | | 10 | | | 2 | | | 7 | | | Net periodic pension cost (income) | $ | (16) | | | $ | (2) | | | $ | (23) | | | $ | (2) | | | $ | 2 | | | $ | 5 | | | | | | | | | | | | | | | Postretirement Benefits | | Service cost | $ | 17 | | | $ | 4 | | | $ | 5 | | | $ | 0 | | | $ | 1 | | | $ | 1 | | | Interest cost | 40 | | | 10 | | | 15 | | | 2 | | | 0 | | | 5 | | | Expected return on plan assets | (54) | | | (21) | | | (20) | | | (1) | | | 0 | | | (5) | | | Amortization: | | | | | | | | | | | | | Prior service costs | (1) | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 5 | | | Net (gain)/loss | 2 | | | 0 | | | 2 | | | 0 | | | 0 | | | (2) | | | Net periodic postretirement benefit cost | $ | 4 | | | $ | (7) | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 4 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2019 | Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 73 | | | $ | 17 | | | $ | 19 | | | $ | 3 | | | $ | 2 | | | $ | 7 | | | Interest cost | 123 | | | 28 | | | 38 | | | 6 | | | 1 | | | 9 | | | Expected return on plan assets | (222) | | | (51) | | | (73) | | | (10) | | | (2) | | | (15) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 3 | | | Net (gain)/loss | 30 | | | 9 | | | 11 | | | 1 | | | 0 | | | 1 | | | Net periodic pension cost (income) | $ | 5 | | | $ | 3 | | | $ | (5) | | | $ | 0 | | | $ | 1 | | | $ | 4 | | | Postretirement Benefits | | Service cost | $ | 5 | | | $ | 1 | | | $ | 2 | | | $ | 1 | | | $ | 0 | | | $ | 0 | | | Interest cost | 18 | | | 4 | | | 6 | | | 0 | | | 0 | | | 2 | | | Expected return on plan assets | (16) | | | (6) | | | (7) | | | 0 | | | 0 | | | (1) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1 | | | Net (gain)/loss | (1) | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | Net periodic postretirement benefit cost | $ | 6 | | | $ | 0 | | | $ | 2 | | | $ | 1 | | | $ | 0 | | | $ | 2 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2019 | Southern
Company | | Alabama
Power | | Georgia
Power | | Mississippi
Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 219 | | | $ | 51 | | | $ | 56 | | | $ | 9 | | | $ | 5 | | | $ | 19 | | | Interest cost | 369 | | | 85 | | | 116 | | | 17 | | | 4 | | | 27 | | | Expected return on plan assets | (664) | | | (154) | | | (219) | | | (30) | | | (7) | | | (45) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 2 | | | 1 | | | 1 | | | 0 | | | 0 | | | (2) | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 10 | | | Net (gain)/loss | 90 | | | 27 | | | 33 | | | 4 | | | 0 | | | 2 | | | Net periodic pension cost (income) | $ | 16 | | | $ | 10 | | | $ | (13) | | | $ | 0 | | | $ | 2 | | | $ | 11 | | | Postretirement Benefits | | Service cost | $ | 14 | | | $ | 3 | | | $ | 4 | | | $ | 1 | | | $ | 0 | | | $ | 1 | | | Interest cost | 52 | | | 12 | | | 19 | | | 2 | | | 0 | | | 7 | | | Expected return on plan assets | (49) | | | (19) | | | (19) | | | (1) | | | 0 | | | (4) | | | Amortization: | | | | | | | | | | | | | Prior service costs | 2 | | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | | | Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 4 | | | Net (gain)/loss | (2) | | | 0 | | | 1 | | | 0 | | | 0 | | | (2) | | | Net periodic postretirement benefit cost | $ | 17 | | | $ | (1) | | | $ | 5 | | | $ | 2 | | | $ | 0 | | | $ | 6 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) (I) FAIR VALUE MEASUREMENTS As of September 30, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | As of September 30, 2020: | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | | (in millions) | | Southern Company | | | | | | | | | | | Assets: | | | | | | | | | | Energy-related derivatives(a) | $ | 488 | | | $ | 218 | | | $ | 117 | | | $ | — | | | $ | 823 | | | Interest rate derivatives | 0 | | | 20 | | | 0 | | | — | | | 20 | | | Foreign currency derivatives | 0 | | | 29 | | | 0 | | | — | | | 29 | | Investments in trusts:(b)(c) | | | | | | | | | | | Domestic equity | 754 | | | 137 | | | 0 | | | — | | | 891 | | | Foreign equity | 71 | | | 220 | | | 0 | | | — | | | 291 | | | U.S. Treasury and government agency securities | 0 | | | 268 | | | 0 | | | — | | | 268 | | | Municipal bonds | 0 | | | 99 | | | 0 | | | — | | | 99 | | | Pooled funds – fixed income | 0 | | | 17 | | | 0 | | | — | | | 17 | | | Corporate bonds | 15 | | | 376 | | | 0 | | | — | | | 391 | | | Mortgage and asset backed securities | 0 | | | 79 | | | 0 | | | — | | | 79 | | | Private equity | 0 | | | 0 | | | 0 | | | 68 | | | 68 | | | Cash and cash equivalents | 1 | | | 0 | | | 0 | | | — | | | 1 | | | Other | 25 | | | 6 | | | 0 | | | — | | | 31 | | | Cash equivalents | 2,750 | | | 11 | | | 0 | | | — | | | 2,761 | | | Other investments | 9 | | | 19 | | | 0 | | | — | | | 28 | | | Total | $ | 4,113 | | | $ | 1,499 | | | $ | 117 | | | $ | 68 | | | $ | 5,797 | | | Liabilities: | | | | | | | | | | Energy-related derivatives(a) | $ | 521 | | | $ | 155 | | | $ | 75 | | | $ | — | | | $ | 751 | | | | | | | | | | | | | Foreign currency derivatives | 0 | | | 23 | | | 0 | | | — | | | 23 | | | Contingent consideration | 0 | | | 0 | | | 19 | | | — | | | 19 | | | Total | $ | 521 | | | $ | 178 | | | $ | 94 | | | $ | — | | | $ | 793 | | | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | As of September 30, 2020: | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | | (in millions) | | Alabama Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 23 | | | $ | 0 | | | $ | — | | | $ | 23 | | Nuclear decommissioning trusts:(b) | | | | | | | | | | | Domestic equity | 477 | | | 128 | | | 0 | | | — | | | 605 | | | Foreign equity | 71 | | | 64 | | | 0 | | | — | | | 135 | | | U.S. Treasury and government agency securities | 0 | | | 21 | | | 0 | | | — | | | 21 | | | Municipal bonds | 0 | | | 1 | | | 0 | | | — | | | 1 | | | Corporate bonds | 15 | | | 159 | | | 0 | | | — | | | 174 | | | Mortgage and asset backed securities | 0 | | | 27 | | | 0 | | | — | | | 27 | | | Private equity | 0 | | | 0 | | | 0 | | | 68 | | | 68 | | | Other | 6 | | | 0 | | | 0 | | | — | | | 6 | | | Cash equivalents | 825 | | | 11 | | | 0 | | | — | | | 836 | | | Other investments | 0 | | | 19 | | | 0 | | | — | | | 19 | | | Total | $ | 1,394 | | | $ | 453 | | | $ | 0 | | | $ | 68 | | | $ | 1,915 | | | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 6 | | | $ | 0 | | | $ | — | | | $ | 6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Georgia Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 31 | | | $ | 0 | | | $ | — | | | $ | 31 | | | | | | | | | | | | Nuclear decommissioning trusts:(b)(c) | | | | | | | | | | | Domestic equity | 277 | | | 1 | | | 0 | | | — | | | 278 | | | Foreign equity | 0 | | | 153 | | | 0 | | | — | | | 153 | | | U.S. Treasury and government agency securities | 0 | | | 247 | | | 0 | | | — | | | 247 | | | Municipal bonds | 0 | | | 98 | | | 0 | | | — | | | 98 | | | Corporate bonds | 0 | | | 217 | | | 0 | | | — | | | 217 | | | Mortgage and asset backed securities | 0 | | | 52 | | | 0 | | | — | | | 52 | | | Other | 19 | | | 6 | | | 0 | | | — | | | 25 | | | Cash equivalents | 485 | | | 0 | | | 0 | | | — | | | 485 | | | Total | $ | 781 | | | $ | 805 | | | $ | 0 | | | $ | — | | | $ | 1,586 | | | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 9 | | | $ | 0 | | | $ | — | | | $ | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | As of September 30, 2020: | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | | (in millions) | | Mississippi Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 18 | | | $ | 0 | | | $ | — | | | $ | 18 | | | | | | | | | | | | | Cash equivalents | 36 | | | 0 | | | 0 | | | — | | | 36 | | | Total | $ | 36 | | | $ | 18 | | | $ | 0 | | | $ | — | | | $ | 54 | | | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 7 | | | $ | 0 | | | $ | — | | | $ | 7 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Southern Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 5 | | | $ | 0 | | | $ | — | | | $ | 5 | | | Foreign currency derivatives | 0 | | | 29 | | | 0 | | | — | | | 29 | | | Cash equivalents | 149 | | | 0 | | | 0 | | | — | | | 149 | | | Total | $ | 149 | | | $ | 34 | | | $ | 0 | | | $ | — | | | $ | 183 | | | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | 0 | | | $ | 1 | | | $ | 0 | | | $ | — | | | $ | 1 | | | Foreign currency derivatives | 0 | | | 23 | | | 0 | | | — | | | 23 | | | Contingent consideration | 0 | | | 0 | | | 19 | | | — | | | 19 | | | Total | $ | 0 | | | $ | 24 | | | $ | 19 | | | $ | — | | | $ | 43 | | | | | | | | | | | | | Southern Company Gas | | | | | | | | | | | Assets: | | | | | | | | | | Energy-related derivatives(a) | $ | 488 | | | $ | 141 | | | $ | 117 | | | $ | — | | | $ | 746 | | | | | | | | | | | | | Non-qualified deferred compensation trusts: | | | | | | | | | | | Domestic equity | 0 | | | 8 | | | 0 | | | — | | | 8 | | | Foreign equity | 0 | | | 3 | | | 0 | | | — | | | 3 | | | Pooled funds – fixed income | 0 | | | 17 | | | 0 | | | — | | | 17 | | | Cash equivalents | 1 | | | 0 | | | 0 | | | — | | | 1 | | | Cash equivalents and restricted cash | 113 | | | 0 | | | 0 | | | — | | | 113 | | | | | | | | | | | | | Total | $ | 602 | | | $ | 169 | | | $ | 117 | | | $ | — | | | $ | 888 | | | Liabilities: | | | | | | | | | | Energy-related derivatives(a) | $ | 521 | | | $ | 132 | | | $ | 75 | | | $ | — | | | $ | 728 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(a)Energy-related derivatives exclude cash collateral of $70 million. (b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. (c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2020, approximately $25 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2020 and 2019. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively. | | | | | | | | | | | | | | | | Fair value increases (decreases) | Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | | (in millions) | | Southern Company | $ | 108 | | $ | 27 | | $ | 85 | | $ | 255 | | | Alabama Power | 66 | | 15 | | 24 | | 140 | | | Georgia Power | 42 | | 12 | | 61 | | 115 | |
Valuation Methodologies The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used. For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information. Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial. "Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds. As of September 30, 2020, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $68 million and unfunded commitments related to the private equity investments totaled $67 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. As of September 30, 2020, other financial instruments for which the carrying amount did not equal fair value were as follows: | | | | | | | | | | | | | | | | | | | | | | Southern
Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) | | (in millions) | | Long-term debt, including securities due within one year: | | | | | | Carrying amount | $ | 49,743 | | $ | 9,113 | | $ | 12,700 | | $ | 1,402 | | $ | 4,155 | | $ | 6,461 | | | Fair value | 56,739 | | 10,741 | | 15,052 | | 1,562 | | 4,535 | | 7,640 | |
(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds. The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants. Commodity Contracts with Level 3 Valuation Inputs As of September 30, 2020, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $42 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period. | | | | | | | | | | Three Months Ended September 30, 2020 | Nine Months Ended September 30, 2020 | | (in millions) | | Beginning balance | $ | 80 | | $ | 14 | | | Transfers to Level 3 | 0 | | 70 | | | Transfers from Level 3 | (2) | | (5) | | | Instruments realized or otherwise settled during period | (9) | | (16) | | | Changes in fair value | (27) | | (21) | | | Ending balance | $ | 42 | | $ | 42 | |
Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(1.11) to $0.24 per mmBtu). Forward price increases (decreases) as of September 30, 2020 would have resulted in higher (lower) values on a net basis. (J) DERIVATIVES Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. Energy-Related Derivatives The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations. Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Energy-related derivative contracts are accounted for under one of three methods: •Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. •Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions. •Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. At September 30, 2019,2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows: | | | | | | | | | | | | | | | | | | | Net
Purchased
mmBtu | | Longest
Hedge
Date | | Longest
Non-Hedge
Date | | (in millions) | | | | | Southern Company(*) | 877 | | 2024 | | 2031 | | Alabama Power | 78 | | 2024 | | — | | Georgia Power | 131 | | 2023 | | — | | Mississippi Power | 86 | | 2024 | | — | | Southern Power | 14 | | 2022 | | 2021 | Southern Company Gas(*) | 568 | | 2023 | | 2031 |
(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.1 billion mmBtu as of September 30, 2020, which is also included in Southern Company's total volume. At September 30, 2020, the net volume of Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2021. In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 12 million mmBtu for Southern Company, which includes 3 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, 1 million mmBtu for Mississippi Power, didand 4 million mmBtu for Southern Power. For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2021 are immaterial for all Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Interest Rate Derivatives Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. At September 30, 2020, the following interest rate derivatives were outstanding: | | | | | | | | | | | | | | | | | | | | | | | | | Notional
Amount | | Interest
Rate
Received | Weighted
Average
Interest
Rate Paid | Hedge
Maturity
Date | | Fair Value Gain (Loss) at September 30, 2020 | | �� | (in millions) | | | | | | (in millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Flow Hedges of Existing Debt | | | | | | | | Mississippi Power | $ | 60 | | | 1-month LIBOR | 0.58% | December 2021 | | $ | 0 | | | Fair Value Hedges of Existing Debt | | | | | | | | Southern Company parent | 1,500 | | | 2.35% | 1-month LIBOR + 0.87% | July 2021 | | 20 | | | | | | | | | | | | | | | | | | | Southern Company | $ | 1,560 | | | | | | | $ | 20 | |
For cash flow hedge interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2021 total $(25) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas. Foreign Currency Derivatives Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At September 30, 2020, the following foreign currency derivatives were outstanding: | | | | | | | | | | | | | | | | | | | | | | Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at September 30, 2020 | | (in millions) | | (in millions) | | | (in millions) | | Cash Flow Hedges of Existing Debt | | | | | | | Southern Power | $ | 677 | | 2.95% | € | 600 | | 1.00% | June 2022 | $ | 11 | | | Southern Power | 564 | | 3.78% | 500 | | 1.85% | June 2026 | (5) | | | Total | $ | 1,241 | | | € | 1,100 | | | | $ | 6 | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2021 are $(14) million. Derivative Financial Statement Presentation and Amounts Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows: | | | | | | | | | | | | | | | | As of September 30, 2020 | As of December 31, 2019 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | (in millions) | (in millions) | | Southern Company | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 52 | | $ | 13 | | $ | 3 | | $ | 70 | | | Other deferred charges and assets/Other deferred credits and liabilities | 30 | | 15 | | 6 | | 44 | | | | | | | | | | | | | Total derivatives designated as hedging instruments for regulatory purposes | $ | 82 | | $ | 28 | | $ | 9 | | $ | 114 | | | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 8 | | $ | 3 | | $ | 1 | | $ | 6 | | | Other deferred charges and assets/Other deferred credits and liabilities | 2 | | 0 | | 0 | | 0 | | | Interest rate derivatives: | | | | | | Other current assets/Other current liabilities | 19 | | 0 | | 2 | | 23 | | | Other deferred charges and assets/Other deferred credits and liabilities | 0 | | 0 | | 0 | | 1 | | | Foreign currency derivatives: | | | | | | Other current assets/Other current liabilities | 0 | | 23 | | 0 | | 24 | | | Other deferred charges and assets/Other deferred credits and liabilities | 29 | | 0 | | 16 | | 0 | | | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 58 | | $ | 26 | | $ | 19 | | $ | 54 | | | Derivatives not designated as hedging instruments | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 392 | | $ | 428 | | $ | 461 | | $ | 358 | | | Other deferred charges and assets/Other deferred credits and liabilities | 338 | | 291 | | 207 | | 225 | | | Total derivatives not designated as hedging instruments | $ | 730 | | $ | 719 | | $ | 668 | | $ | 583 | | | Gross amounts recognized | $ | 870 | | $ | 773 | | $ | 696 | | $ | 751 | | Gross amounts offset(a) | (636) | | (706) | | (463) | | (562) | | Net amounts recognized in the Balance Sheets(b) | $ | 234 | | $ | 67 | | $ | 233 | | $ | 189 | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | As of September 30, 2020 | As of December 31, 2019 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | (in millions) | (in millions) | | Alabama Power | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 14 | | $ | 2 | | $ | 2 | | $ | 14 | | | Other deferred charges and assets/Other deferred credits and liabilities | 9 | | 4 | | 2 | | 10 | | | Total derivatives designated as hedging instruments for regulatory purposes | $ | 23 | | $ | 6 | | $ | 4 | | $ | 24 | | | Gross amounts recognized | $ | 23 | | $ | 6 | | $ | 4 | | $ | 24 | | | Gross amounts offset | (5) | | (5) | | (2) | | (2) | | | Net amounts recognized in the Balance Sheets | $ | 18 | | $ | 1 | | $ | 2 | | $ | 22 | | | | | | | | Georgia Power | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 18 | | $ | 3 | | $ | 1 | | $ | 32 | | | Other deferred charges and assets/Other deferred credits and liabilities | 13 | | 6 | | 3 | | 21 | | | Total derivatives designated as hedging instruments for regulatory purposes | $ | 31 | | $ | 9 | | $ | 4 | | $ | 53 | | | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Interest rate derivatives: | | | | | | Other current assets/Other current liabilities | $ | 0 | | $ | 0 | | $ | 0 | | $ | 17 | | | | | | | | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 0 | | $ | 0 | | $ | 0 | | $ | 17 | | | Gross amounts recognized | $ | 31 | | $ | 9 | | $ | 4 | | $ | 70 | | | Gross amounts offset | (9) | | (9) | | (3) | | (3) | | | Net amounts recognized in the Balance Sheets | $ | 22 | | $ | 0 | | $ | 1 | | $ | 67 | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | As of September 30, 2020 | As of December 31, 2019 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | (in millions) | (in millions) | | Mississippi Power | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 10 | | $ | 2 | | $ | 0 | | $ | 15 | | | Other deferred charges and assets/Other deferred credits and liabilities | 8 | | 5 | | 1 | | 12 | | | Total derivatives designated as hedging instruments for regulatory purposes | $ | 18 | | $ | 7 | | $ | 1 | | $ | 27 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gross amounts recognized | $ | 18 | | $ | 7 | | $ | 1 | | $ | 27 | | | Gross amounts offset | (7) | | (7) | | (1) | | (1) | | | Net amounts recognized in the Balance Sheets | $ | 11 | | $ | 0 | | $ | 0 | | $ | 26 | | | | | | | | Southern Power | | | | | | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 4 | | $ | 1 | | $ | 1 | | $ | 2 | | | Other deferred charges and assets/Other deferred credits and liabilities | 1 | | 0 | | 0 | | 0 | | | Foreign currency derivatives: | | | | | | Other current assets/Other current liabilities | 0 | | 23 | | 0 | | 24 | | | Other deferred charges and assets/Other deferred credits and liabilities | 29 | | 0 | | 16 | | 0 | | | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 34 | | $ | 24 | | $ | 17 | | $ | 26 | | | Derivatives not designated as hedging instruments | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 0 | | $ | 0 | | $ | 2 | | $ | 1 | | | | | | | | | | | | | | | | | | Total derivatives not designated as hedging instruments | $ | 0 | | $ | 0 | | $ | 2 | | $ | 1 | | | Gross amounts recognized | $ | 34 | | $ | 24 | | $ | 19 | | $ | 27 | | | Gross amounts offset | (1) | | (1) | | 0 | | 0 | | | Net amounts recognized in the Balance Sheets | $ | 33 | | $ | 23 | | $ | 19 | | $ | 27 | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) | | | | | | | | | | | | | | | | As of September 30, 2020 | As of December 31, 2019 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | (in millions) | (in millions) | | Southern Company Gas | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | $ | 10 | | $ | 6 | | $ | 0 | | $ | 9 | | | Other deferred charges and assets/Other deferred credits and liabilities | 0 | | 0 | | 0 | | 1 | | | Total derivatives designated as hedging instruments for regulatory purposes | $ | 10 | | $ | 6 | | $ | 0 | | $ | 10 | | | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Energy-related derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | $ | 4 | | $ | 2 | | $ | 0 | | $ | 4 | | | Other deferred charges and assets/Other deferred credits and liabilities | 1 | | 0 | | 0 | | 0 | | | Interest rate derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | 0 | | 0 | | 2 | | 0 | | | | | | | | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 5 | | $ | 2 | | $ | 2 | | $ | 4 | | | Derivatives not designated as hedging instruments | | | | | | Energy-related derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | $ | 392 | | $ | 428 | | $ | 459 | | $ | 357 | | | Other deferred charges and assets/Other deferred credits and liabilities | 338 | | 291 | | 207 | | 225 | | | Total derivatives not designated as hedging instruments | $ | 730 | | $ | 719 | | $ | 666 | | $ | 582 | | | Gross amounts of recognized | $ | 745 | | $ | 727 | | $ | 668 | | $ | 596 | | Gross amounts offset(a) | (614) | | (684) | | (456) | | (555) | | Net amounts recognized in the Balance Sheets(b) | $ | 131 | | $ | 43 | | $ | 212 | | $ | 41 | |
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $70 million and $99 million as of September 30, 2020 and December 31, 2019, respectively. (b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $4 million as of September 30, 2020 and December 31, 2019, respectively. The traditional electric operating companies had no energy-related derivatives not designated as hedging instruments at September 30, 2020 and immaterial amounts at December 31, 2019.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) At September 30, 2020 and December 31, 2019, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows: | | | | | | | | | | | | | | | | | | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet | Derivative Category and Balance Sheet
Location | Southern
Company | Alabama
Power | Georgia
Power | Mississippi
Power | Southern Company Gas | | | (in millions) | | At September 30, 2020: | | | | | | | Energy-related derivatives: | | | | | | | Other regulatory assets, current | $ | (5) | | $ | 0 | | $ | 0 | | $ | 0 | | $ | (5) | | | | | | | | | | | | | | | | | | | | | Other regulatory liabilities, current | 41 | | 12 | | 15 | | 8 | | 6 | | | Other regulatory liabilities, deferred | 15 | | 5 | | 7 | | 3 | | 0 | | | Total energy-related derivative gains (losses) | $ | 51 | | $ | 17 | | $ | 22 | | $ | 11 | | $ | 1 | | | | | | | | | At December 31, 2019: | | | | | | | Energy-related derivatives: | | | | | | | Other regulatory assets, current | $ | (63) | | $ | (14) | | $ | (31) | | $ | (15) | | $ | (3) | | | Other regulatory assets, deferred | (37) | | (8) | | (18) | | (11) | | 0 | | | Other regulatory liabilities, current | 6 | | 2 | | 0 | | 0 | | 4 | | | | | | | | | Total energy-related derivative gains (losses) | $ | (94) | | $ | (20) | | $ | (49) | | $ | (26) | | $ | 1 | |
For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows: | | | | | | | | | | | | | | | | Gain (Loss) Recognized in OCI on Derivative | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | | 2020 | 2019 | 2020 | 2019 | | (in millions) | (in millions) | | Southern Company | | | | | | Energy-related derivatives | $ | 9 | | $ | (5) | | $ | 2 | | $ | (11) | | | Interest rate derivatives | 1 | | (52) | | (27) | | (88) | | | Foreign currency derivatives | 54 | | (68) | | (10) | | (107) | | | Total | $ | 64 | | $ | (125) | | $ | (35) | | $ | (206) | | | | | | | | | | | | | Georgia Power | | | | | | Interest rate derivatives | $ | 0 | | $ | (47) | | $ | (3) | | $ | (83) | | | | | | | | | | | | | | | | | | Southern Power | | | | | | Energy-related derivatives | $ | 5 | | $ | (3) | | $ | 2 | | $ | (5) | | | | | | | | Foreign currency derivatives | 54 | | (68) | | (10) | | (107) | | | Total | $ | 59 | | $ | (71) | | $ | (8) | | $ | (112) | | | Southern Company Gas | | | | | | Energy-related derivatives | $ | 4 | | $ | (2) | | $ | 0 | | $ | (6) | | | Interest rate derivatives | 1 | | (5) | | (24) | | (5) | | | Total | $ | 5 | | $ | (7) | | $ | (24) | | $ | (11) | |
For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows: | | | | | | | | | | | | | | | | Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | | | 2020 | 2019 | 2020 | 2019 | | (in millions) | (in millions) | | Southern Company | | | | | | Total cost of natural gas | $ | 71 | | $ | 79 | | $ | 654 | | $ | 956 | | Gain (loss) on energy-related cash flow hedges(a) | 0 | | 0 | | (8) | | 0 | | | Total depreciation and amortization | 889 | | 760 | | 2,619 | | 2,267 | | Gain (loss) on energy-related cash flow hedges(a) | (1) | | (1) | | (3) | | (5) | | | Total interest expense, net of amounts capitalized | (443) | | (434) | | (1,343) | | (1,294) | | Gain (loss) on interest rate cash flow hedges(a) | (6) | | (5) | | (19) | | (14) | | Gain (loss) on foreign currency cash flow hedges(a) | (6) | | (6) | | (18) | | (18) | | Gain (loss) on interest rate fair value hedges(b) | (3) | | 10 | | 27 | | 43 | | | Total other income (expense), net | 113 | | 61 | | 319 | | 239 | | Gain (loss) on foreign currency cash flow hedges(a)(c) | 56 | | (54) | | 52 | | (62) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Southern Power | | | | | | Total depreciation and amortization | $ | 129 | | $ | 120 | | $ | 367 | | $ | 357 | | Gain (loss) on energy-related cash flow hedges(a) | (1) | | (1) | | (3) | | (5) | | | Total interest expense, net of amounts capitalized | (36) | | (43) | | (114) | | (127) | | Gain (loss) on foreign currency cash flow hedges(a) | (6) | | (6) | | (18) | | (18) | | | Total other income (expense), net | 13 | | 6 | | 19 | | 48 | | Gain (loss) on foreign currency cash flow hedges(a)(c) | 56 | | (54) | | 52 | | (62) | | | | | | | | | | | | | | | | |
(a)Reclassified from accumulated OCI into earnings. (b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income. (c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas. As of September 30, 2020 and December 31, 2019, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges: | | | | | | | | | | | | | | | | | | | Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item | | Balance Sheet Location of Hedged Items | As of September 30, 2020 | As of December 31, 2019 | | As of September 30, 2020 | As of December 31, 2019 | | (in millions) | | (in millions) | | Southern Company | | | | | | | Securities due within one year | $ | (1,513) | | $ | (599) | | | $ | (15) | | $ | 0 | | | Long-term debt | 0 | | (1,494) | | | 0 | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows: | | | | | | | | | | | | | | | | | | | | | | | Gain (Loss) | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2020 | 2019 | | 2020 | 2019 | | | (in millions) | | (in millions) | | | | | | | | | Energy-related derivatives: | Natural gas revenues(*) | $ | (30) | | $ | (2) | | | $ | 54 | | $ | 81 | | | | | | | | | | Cost of natural gas | 5 | | 2 | | | 18 | | 5 | | | Total derivatives in non-designated hedging relationships | $ | (25) | | $ | 0 | | | $ | 72 | | $ | 86 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented. For the three and nine months ended September 30, 2020 and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants. Contingent Features Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contractsderivatives that have required or could require collateral, but not accelerated payment, in the event of avarious credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.changes of certain Southern Company subsidiaries. At September 30, 2019,2020, the Registrants had 0 collateral posted with derivative counterparties to satisfy these arrangements. For the Registrants with interest rate derivatives at September 30, 2020, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, equaled approximately $269 million. Included in these amounts arewas immaterial. At September 30, 2020, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that either Alabama Powerone or Georgia Power (affiliate companies of Mississippi Power)more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally,If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2020, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2020, cash collateral held on deposit in broker margin accounts was $70 million. The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating downgrade could impactand credit limit based on the abilitycounterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of Mississippi Power to access capital markets and would be likely to impactcredit before any transaction with the cost atcounterparty is executed. In most cases, the counterparty must have an investment grade rating, which it does so. On August 1, 2019, Moody's upgraded Mississippi Power's senior unsecuredincludes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to Baa2 from Baa3mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and maintainedit also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive rating outlook.and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. AsThe Registrants do not anticipate a material adverse effect on their respective financial statements as a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The settlement agreement approved by the Mississippi PSC in August 2018 with respect to the 2018 PEP filings and all unresolved PEP filings for prior years is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusion of the Mississippi Power 2019 Base Rate Case. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.counterparty nonperformance.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION(K) ACQUISITIONS AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Operating Revenues: | | | | | | | | | Wholesale revenues, non-affiliates | $ | 455 |
| | $ | 496 |
| | $ | 1,197 |
| | $ | 1,363 |
| | Wholesale revenues, affiliates | 116 |
| | 134 |
| | 320 |
| | 326 |
| | Other revenues | 3 |
| | 5 |
| | 10 |
| | 10 |
| | Total operating revenues | 574 |
| | 635 |
| | 1,527 |
| | 1,699 |
| | Operating Expenses: | | | | | | | | | Fuel | 166 |
| | 190 |
| | 449 |
| | 511 |
| | Purchased power | 26 |
| | 37 |
| | 82 |
| | 137 |
| | Other operations and maintenance | 85 |
| | 94 |
| | 250 |
| | 278 |
| | Depreciation and amortization | 120 |
| | 130 |
| | 357 |
| | 370 |
| | Taxes other than income taxes | 10 |
| | 12 |
| | 32 |
| | 36 |
| | Asset impairment | — |
| | 36 |
| | — |
| | 155 |
| | Gain on dispositions, net | — |
| | — |
| | (23 | ) | | — |
| | Total operating expenses | 407 |
| | 499 |
| | 1,147 |
| | 1,487 |
| | Operating Income | 167 |
| | 136 |
| | 380 |
| | 212 |
| | Other Income and (Expense): | | | | | | | | | Interest expense, net of amounts capitalized | (43 | ) | | (45 | ) | | (127 | ) | | (138 | ) | | Other income (expense), net | 6 |
| | 17 |
| | 48 |
| | 22 |
| | Total other income and (expense) | (37 | ) | | (28 | ) | | (79 | ) | | (116 | ) | | Earnings Before Income Taxes | 130 |
| | 108 |
| | 301 |
| | 96 |
| | Income taxes (benefit) | 19 |
| | (38 | ) | | (41 | ) | | (210 | ) | | Net Income | 111 |
| | 146 |
| | 342 |
| | 306 |
| | Net income attributable to noncontrolling interests | 25 |
| | 54 |
| | 26 |
| | 71 |
| | Net Income Attributable to Southern Power | $ | 86 |
| | $ | 92 |
| | $ | 316 |
| | $ | 235 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Net Income | $ | 111 |
| | $ | 146 |
| | $ | 342 |
| | $ | 306 |
| | Other comprehensive income (loss): | | | | | | | | | Qualifying hedges: | | | | | | | | Changes in fair value, net of tax of
$(18), $(4), $(28), and $(7), respectively | (53 | ) | | (11 | ) | | (84 | ) | | (19 | ) | Reclassification adjustment for amounts included in net income,
net of tax of $15, $4, $21, and $16, respectively | 45 |
| | 11 |
| | 64 |
| | 46 |
| | Pension and other postretirement benefit plans: | | | | | | | | Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively | — |
| | — |
| | — |
| | 1 |
| | Total other comprehensive income (loss) | (8 | ) | | — |
| | (20 | ) | | 28 |
| | Comprehensive Income | 103 |
| | 146 |
| | 322 |
| | 334 |
| | Comprehensive income attributable to noncontrolling interests | 25 |
| | 54 |
| | 26 |
| | 71 |
| | Comprehensive Income Attributable to Southern Power | $ | 78 |
| | $ | 92 |
| | $ | 296 |
| | $ | 263 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | | | | | | | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | | (in millions) | | Operating Activities: | | | | | Net income | $ | 342 |
| | $ | 306 |
| | Adjustments to reconcile net income to net cash provided from operating activities — | | | | | Depreciation and amortization, total | 377 |
| | 394 |
| | Deferred income taxes | (122 | ) | | (337 | ) | | Utilization of federal investment tax credits | 705 |
| | — |
| | Amortization of investment tax credits | (136 | ) | | (43 | ) | | Asset impairment | — |
| | 155 |
| | Other, net | (43 | ) | | (2 | ) | | Changes in certain current assets and liabilities — | | | | | -Receivables | 15 |
| | (41 | ) | | -Prepaid income taxes | 33 |
| | 5 |
| | -Other current assets | (3 | ) | | 1 |
| | -Accounts payable | (5 | ) | | (27 | ) | | -Accrued taxes | 66 |
| | 256 |
| | -Other current liabilities | (8 | ) | | (1 | ) | | Net cash provided from operating activities | 1,221 |
| | 666 |
| | Investing Activities: | | | | | Business acquisitions, net of cash acquired | (50 | ) | | (64 | ) | | Property additions | (284 | ) | | (226 | ) | | Proceeds from dispositions and asset sales | 572 |
| | — |
| | Change in construction payables | (11 | ) | | 3 |
| | Investment in unconsolidated subsidiaries | (116 | ) | | — |
| | Payments pursuant to LTSAs | (85 | ) | | (57 | ) | | Other investing activities | 10 |
| | 20 |
| | Net cash provided from (used for) investing activities | 36 |
| | (324 | ) | | Financing Activities: | | | | | Decrease in notes payable, net | — |
| | (68 | ) | | Proceeds — | | | | | Short-term borrowings | — |
| | 200 |
| | Capital contributions from parent company | 59 |
| | — |
| | Redemptions — | | | | | Short-term borrowings | (100 | ) | | — |
| | Senior notes | — |
| | (350 | ) | | Other long-term debt | — |
| | (420 | ) | | Return of capital | (755 | ) | | (650 | ) | | Distributions to noncontrolling interests | (125 | ) | | (86 | ) | | Capital contributions from noncontrolling interests | 11 |
| | 1,333 |
| | Payment of common stock dividends | (154 | ) | | (234 | ) | | Other financing activities | (6 | ) | | (15 | ) | | Net cash used for financing activities | (1,070 | ) | | (290 | ) | | Net Change in Cash, Cash Equivalents, and Restricted Cash | 187 |
| | 52 |
| | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 181 |
| | 140 |
| | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 368 |
| | $ | 192 |
| | Supplemental Cash Flow Information: | | | | | Cash paid (received) during the period for — | | | | | Interest (net of $11 and $14 capitalized for 2019 and 2018, respectively) | $ | 133 |
| | $ | 138 |
| | Income taxes, net | (612 | ) | | (102 | ) | | Noncash transactions — Accrued property additions at end of period | 41 |
| | 37 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Assets | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Assets: | | | | | | Cash and cash equivalents | | $ | 368 |
| | $ | 181 |
| | Receivables — | | | | | | Customer accounts receivable | | 152 |
| | 111 |
| | Affiliated | | 49 |
| | 55 |
| | Other | | 41 |
| | 116 |
| | Materials and supplies | | 190 |
| | 220 |
| | Prepaid income taxes | | 296 |
| | 25 |
| | Other current assets | | 38 |
| | 37 |
| | Total current assets | | 1,134 |
| | 745 |
| | Property, Plant, and Equipment: | | | | | | In service | | 13,072 |
| | 13,271 |
| | Less: Accumulated provision for depreciation | | 2,374 |
| | 2,171 |
| | Plant in service, net of depreciation | | 10,698 |
| | 11,100 |
| | Construction work in progress | | 541 |
| | 430 |
| | Total property, plant, and equipment | | 11,239 |
| | 11,530 |
| | Other Property and Investments: | | | | | Intangible assets, net of amortization of $64 and $61
at September 30, 2019 and December 31, 2018, respectively | | 326 |
| | 345 |
| | Other investments | | 28 |
| | — |
| | Total other property and investments | | 354 |
| | 345 |
| | Deferred Charges and Other Assets: | | | | | | Operating lease right-of-use assets, net of amortization | | 368 |
| | — |
| | Prepaid LTSAs | | 145 |
| | 98 |
| | Accumulated deferred income taxes | | 318 |
| | 1,186 |
| | Income taxes receivable, non-current | | 32 |
| | 30 |
| | Assets held for sale | | 600 |
| | 576 |
| | Other deferred charges and assets | | 207 |
| | 373 |
| | Total deferred charges and other assets | | 1,670 |
| | 2,263 |
| | Total Assets | | $ | 14,397 |
| | $ | 14,883 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Liabilities and Stockholders' Equity | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Liabilities: | | | | | | Securities due within one year | | $ | 900 |
| | $ | 599 |
| | Notes payable | | — |
| | 100 |
| | Accounts payable — | | | | | | Affiliated | | 79 |
| | 92 |
| | Other | | 74 |
| | 77 |
| | Accrued taxes | | 21 |
| | 6 |
| | Accrued interest | | 31 |
| | 36 |
| | Other current liabilities | | 133 |
| | 121 |
| | Total current liabilities | | 1,238 |
| | 1,031 |
| | Long-term Debt | | 4,060 |
| | 4,418 |
| | Deferred Credits and Other Liabilities: | | | | | | Accumulated deferred income taxes | | 117 |
| | 105 |
| | Accumulated deferred ITCs | | 1,745 |
| | 1,832 |
| | Operating lease obligations | | 373 |
| | — |
| | Other deferred credits and liabilities | | 171 |
| | 213 |
| | Total deferred credits and other liabilities | | 2,406 |
| | 2,150 |
| | Total Liabilities | | 7,704 |
| | 7,599 |
| Total Stockholders' Equity (See accompanying statements) | | 6,693 |
| | 7,284 |
| | Total Liabilities and Stockholders' Equity | | $ | 14,397 |
| | $ | 14,883 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total Common
Stockholders' Equity | | Noncontrolling Interests | | Total | | | (in millions) | | Balance at December 31, 2017 | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
| | Net income attributable to Southern Power | — |
| | 121 |
| | — |
| | 121 |
| | — |
| | 121 |
| | Capital contributions from parent company | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | Other comprehensive income (loss) | — |
| | — |
| | 24 |
| | 24 |
| | — |
| | 24 |
| | Cash dividends on common stock | — |
| | (78 | ) | | — |
| | (78 | ) | | — |
| | (78 | ) | Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 9 |
| | 9 |
| | Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) | Net income (loss) attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) | | Other | — |
| | (2 | ) | | 5 |
| | 3 |
| | (1 | ) | | 2 |
| | Balance at March 31, 2018 | 3,663 |
| | 1,519 |
| | 27 |
| | 5,209 |
| | 1,349 |
| | 6,558 |
| | Net income attributable to Southern Power | — |
| | 22 |
| | — |
| | 22 |
| | — |
| | 22 |
| | Return of capital to parent company | (250 | ) | | — |
| | — |
| | (250 | ) | | — |
| | (250 | ) | | Capital contributions from parent company | 17 |
| | — |
| | — |
| | 17 |
| | — |
| | 17 |
| | Other comprehensive income (loss) | — |
| | — |
| | 4 |
| | 4 |
| | — |
| | 4 |
| | Cash dividends on common stock | — |
| | (78 | ) | | — |
| | (78 | ) | | — |
| | (78 | ) | Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 22 |
| | 22 |
| | Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) | Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 23 |
| | 23 |
| | Sale of noncontrolling interests | (407 | ) | | — |
| | — |
| | (407 | ) | | 1,690 |
| | 1,283 |
| | Other | — |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | 2 |
| | Balance at June 30, 2018 | 3,023 |
| | 1,464 |
| | 31 |
| | 4,518 |
| | 3,056 |
| | 7,574 |
| | Net income attributable to Southern Power | — |
| | 92 |
| | — |
| | 92 |
| | — |
| | 92 |
| | Return of capital to parent company | (415 | ) | | — |
| | — |
| | (415 | ) | | — |
| | (415 | ) | | Cash dividends on common stock | — |
| | (78 | ) | | — |
| | (78 | ) | | — |
| | (78 | ) | Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 123 |
| | 123 |
| | Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (45 | ) | | (45 | ) | Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 54 |
| | 54 |
| | Sale of noncontrolling interests | (4 | ) | | — |
| | — |
| | (4 | ) | | — |
| | (4 | ) | | Balance at September 30, 2018 | $ | 2,604 |
| | $ | 1,478 |
| | $ | 31 |
| | $ | 4,113 |
| | $ | 3,188 |
| | $ | 7,301 |
|
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | Paid-In
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total Common
Stockholders' Equity | | Noncontrolling Interests | | Total | | | (in millions) | | Balance at December 31, 2018 | $ | 1,600 |
| | $ | 1,352 |
| | $ | 16 |
| | $ | 2,968 |
| | $ | 4,316 |
| | $ | 7,284 |
| | Net income attributable to Southern Power | — |
| | 56 |
| | — |
| | 56 |
| | — |
| | 56 |
| | Capital contributions from parent company | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | Other comprehensive income (loss) | — |
| | — |
| | (4 | ) | | (4 | ) | | — |
| | (4 | ) | | Cash dividends on common stock | — |
| | (51 | ) | | — |
| | (51 | ) | | — |
| | (51 | ) | Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
| | Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (41 | ) | | (41 | ) | Net income (loss) attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) | | Other | (1 | ) | | (1 | ) | | — |
| | (2 | ) | | 1 |
| | (1 | ) | | Balance at March 31, 2019 | 1,600 |
| | 1,356 |
| | 12 |
| | 2,968 |
| | 4,250 |
| | 7,218 |
| | Net income attributable to Southern Power | — |
| | 174 |
| | — |
| | 174 |
| | — |
| | 174 |
| | Return of capital to parent company | (505 | ) | | — |
| | — |
| | (505 | ) | | — |
| | (505 | ) | | Capital contributions from parent company | 7 |
| | — |
| | — |
| | 7 |
| | — |
| | 7 |
| | Other comprehensive income (loss) | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | (8 | ) | | Cash dividends on common stock | — |
| | (52 | ) | | — |
| | (52 | ) | | — |
| | (52 | ) | Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| | Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (47 | ) | | (47 | ) | Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 29 |
| | 29 |
| | Other | — |
| | 1 |
| | — |
| | 1 |
| | (1 | ) | | — |
| | Balance at June 30, 2019 | 1,102 |
| | 1,479 |
| | 4 |
| | 2,585 |
| | 4,233 |
| | 6,818 |
| | Net income attributable to Southern Power | — |
| | 86 |
| | — |
| | 86 |
| | — |
| | 86 |
| | Return of capital to parent company | (250 | ) | | — |
| | — |
| | (250 | ) | | — |
| | (250 | ) | | Capital contributions from parent company | 53 |
| | — |
| | — |
| | 53 |
| | — |
| | 53 |
| | Other comprehensive income (loss) | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | (8 | ) | | Cash dividends on common stock | — |
| | (51 | ) | | — |
| | (51 | ) | | — |
| | (51 | ) | Capital contributions from
noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 63 |
| | 63 |
| | Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (43 | ) | | (43 | ) | Net income attributable
to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 25 |
| | 25 |
| | Balance at September 30, 2019 | $ | 905 |
| | $ | 1,514 |
| | $ | (4 | ) | | $ | 2,415 |
| | $ | 4,278 |
| | $ | 6,693 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2019 vs. THIRD QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW
Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
In the second quarter 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a cash purchase price of approximately $461 million.
In the third quarter 2019, Southern Power completed a transaction to acquire a majority interest in DSGP, an affiliate of Bloom Energy that owns and operates fuel cell generation facilities, for a total purchase price of approximately $166 million.
In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not close by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time.
During the nine months ended September 30, 2019, Southern Power continued construction of the 100-MW Wildhorse Mountain and the 200-MW Reading wind facilities. Subsequent to September 30, 2019, Southern Power acquired the 136-MW Skookumchuck wind facility and is continuing construction. See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.
At September 30, 2019, Southern Power's average investment coverage ratio for its generating assets (including Plant Mankato), based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 93% through 2023 and 91% through 2028, with an average remaining contract duration of approximately 15 years.
Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income Attributable to Southern Power
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(6) | | (6.5) | | $81 | | 34.5 |
Net income attributable to Southern Power for the third quarter 2019 was $86 million compared to $92 million for the corresponding period in 2018. The decrease is primarily due to PPA capacity revenue decreases from the dispositions of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) in 2018 and Plant Nacogdoches in the second quarter 2019 totaling approximately $20 million and reductions in net income of approximately $10 million, net, related to the SP Wind tax equity partnership entered into in 2018, partially offset by a $27 million wind turbine equipment impairment charge in 2018.
Net income attributable to Southern Power for year-to-date 2019 was $316 million compared to $235 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of the Florida Plants in 2018 and Plant Nacogdoches in the second quarter 2019 (including an asset impairment charge in 2018 and gains on sale in 2019, partially offset by PPA capacity revenue decreases in 2019) totaling approximately $142 million, a $27 million wind turbine equipment impairment charge in 2018, and net gains totaling $25 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. These increases were partially offset by $65 million in state income tax benefits recorded in 2018 arising from the reorganization of Southern Power's legal entities that own and operate certain solar facilities and reductions in net income of approximately $54 million related to the SP Wind tax equity partnership entered into in 2018.DISPOSITIONS
See Notes 7, 10, andNote 15 to the financial statements in Item 8 of the Form 10-K for additional information, including details of assets and liabilities held for sale at December 31, 2019 for Southern Company, Southern Power, and Southern Company Gas. The Registrants had no material assets or liabilities held for sale at September 30, 2020. Alabama Power On August 31, 2020, Alabama Power completed the Autauga Combined Cycle Acquisition. The total purchase price was $461 million, of which $452 million was related to net assets recorded within property, plant, and equipment on the tax equity partnerships, the legal entity reorganization,balance sheet and the Florida Plants dispositions, respectively. Also see Note (C)remainder primarily related to inventory, current receivables, and accounts payable. Alabama Power assumed an existing power sales agreement under which the Condensed Financial Statements herein for additional information onfull output of the Roserock solar facility litigation settlement and Note (K) to the Condensed Financial Statements herein for additional information on the disposition of Plant Nacogdoches and sales of wind equipment. Operating Revenues
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(61) | | (9.6) | | $(172) | | (10.1) |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (throughremains committed to another third party for its remaining term of approximately three years. During the second quarter 2019 sale of Plant Nacogdoches), and PPA energyremaining term, the estimated revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the power pool.
Natural Gassales agreement are expected to offset the associated costs of operation. See Notes (B) and Biomass Capacity(D) under "Alabama Power" and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements"Lease Income," herein for additional information regarding Southern Power's PPAs.
Details of Southern Power's operating revenues were as follows:
| | | | | | | | | | | | | | | | | | | Third Quarter 2019 | | Third Quarter 2018 | | Year-to-Date 2019 | | Year-to-Date 2018 | | | (in millions) | | PPA capacity revenues | $ | 131 |
| | $ | 168 |
| | $ | 384 |
| | $ | 450 |
| | PPA energy revenues | 339 |
| | 336 |
| | 857 |
| | 892 |
| | Total PPA revenues | 470 |
| | 504 |
| | 1,241 |
| | 1,342 |
| | Non-PPA revenues | 101 |
| | 126 |
| | 276 |
| | 347 |
| | Other revenues | 3 |
| | 5 |
| | 10 |
| | 10 |
| | Total operating revenues | $ | 574 |
| | $ | 635 |
| | $ | 1,527 |
| | $ | 1,699 |
|
In the third quarter 2019, total operating revenues were $574 million, reflecting a $61 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $37 million, or 22%, primarily due to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019. In addition, the change reflects a reduction of $15 million from the contractual expiration of an affiliate natural gas PPA, partially offset by a $13 million increase in new PPA capacity revenues from existing gas facilities.
PPA energy revenues increased $3 million, or 1%, due to a $15 million increase in sales primarily driven by the volume of KWHs generated by solar and wind facilities, partially offset by a $12 million decrease in sales from natural gas facilities primarily driven by a decrease in the average cost of fuel and purchased power.
Non-PPA revenues decreased $25 million, or 20%, due to a $15 million decrease in the volume of KWHs sold through short-term sales and a $10 million decrease in the market price of energy.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2019, total operating revenues were $1.5 billion, reflecting a $172 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $66 million, or 15%, primarily due to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019. In addition, the change reflects a reduction of $20 million from the contractual expiration of an affiliate natural gas PPA, offset by a $26 million increase in new PPA capacity revenues from existing natural gas facilities.
PPA energy revenues decreased $35 million, or 4%, primarily due to a $42 million decrease in sales from natural gas facilities primarily driven by a $66 million decrease in the average cost of fuel and purchased power, partially offset by a $24 million increase in the volume of KWHs sold due to increased customer load.
Non-PPA revenues decreased $71 million, or 20%, primarily due to a $52 million decrease in the volume of KWHs sold through short-term sales and an $18 million decrease in the market price of energy.
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
| | | | | | | | | Third Quarter 2019 | Third Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 | | | (in billions of KWHs) | | Generation | 13.8 | 13.3 | | 35.7 | 35.3 | | Purchased power | 0.8 | 0.9 | | 2.5 | 3.1 | | Total generation and purchased power | 14.6 | 14.2 | | 38.2 | 38.4 | | | | | | | | | Total generation and purchased power, excluding solar, wind, and tolling agreements | 8.6 | 8.2 | | 22.3 | 22.2 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | | | | | | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (24 | ) | | (12.6) | | $ | (62 | ) | | (12.1) | | Purchased power | (11 | ) | | (29.7) | | (55 | ) | | (40.1) | | Total fuel and purchased power expenses | $ | (35 | ) | | | | $ | (117 | ) | | |
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2019, total fuel and purchased power expenses decreased $35 million, or 15%, compared to the corresponding period in 2018. Fuel expense decreased $24 million due to a $38 million decrease in the average cost of fuel per KWH generated, partially offset by a $14 million increase associated with the volume of KWHs generated. Purchased power expense decreased $11 million due to an $8 million decrease associated with the volume of KWHs purchased and a $3 million decrease associated with the average cost of purchased power.
For year-to-date 2019, total fuel and purchased power expenses decreased $117 million, or 18%, compared to the corresponding period in 2018. Fuel expense decreased $62 million due to a $78 million decrease in the average cost of fuel per KWH generated, partially offset by a $16 million increase associated with the volume of KWHs generated. Purchased power expense decreased $55 million due to a $28 million decrease associated with the average cost of purchased power and a $27 million decrease associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(9) | | (9.6) | | $(28) | | (10.1) |
In the third quarter 2019, other operations and maintenance expenses were $85 million compared to $94 million for the corresponding period in 2018. The decrease was primarily due to lower scheduled outage and maintenance expenses and a gain on the sale of wind turbine equipment.
For year-to-date 2019, other operations and maintenance expenses were $250 million compared to $278 million for the corresponding period in 2018. The decrease was primarily due to gains totaling $17 million on the sale of wind turbine equipment, lower scheduled outage and maintenance expenses, and the recovery of legal costs related to the Roserock litigation settlement in the first quarter 2019.
See Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" herein for additional information on the sale of wind turbine equipment. Also see Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information on the Roserock solar facility litigation settlement.
Asset Impairment
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(36) | | (100.0) | | $(155) | | (100.0) |
In the second quarter 2018, a $119 million asset impairment charge was recorded in anticipation of the sale of the Florida Plants. In addition, in the third quarter 2018, a $36 million asset impairment charge was recorded on wind turbine equipment held for development projects. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" and Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" hereinrespectively, for additional information.
Gain on Dispositions, netIn the second quarter 2019, the sale of Plant Nacogdoches resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OFNOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), net
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(11) | | N/M | | $26 | | N/M |
N/M - Not meaningful
In the third quarter 2019, other income (expense), net was $6 million compared to $17 million for the corresponding period in 2018. The decrease was primarily due to a $14 million gain from a joint-development wind project in 2018, which was attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.
For year-to-date 2019, other income (expense), net was $48 million compared to $22 million for the corresponding period in 2018. The increase was primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility in the second quarter 2019, partially offset by a $14 million gain from a joint-development wind project in 2018, which was attributable to Southern Power's partner in the project and fully offset within noncontrolling interests. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information regarding the litigation settlement.
Income Taxes (Benefit)
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $57 | | 150.0 | | $169 | | 80.5 |
In the third quarter 2019, income tax expense was $19 million compared to a $38 million benefit for the corresponding period in 2018. This change was primarily due to a $25 million reduction of tax benefits from wind PTCs primarily as a result of the 2018 sale of a noncontrolling tax equity interest in SP Wind, a $13 million increase in income tax expense as a result of higher pre-tax earnings, and $11 million in tax benefits recorded in 2018 related to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain wind facilities.
For year-to-date 2019, income tax benefit was $41 million compared to $210 million for the corresponding period in 2018. This change was primarily due to a $105 million reduction of tax benefits from wind PTCs primarily following the sale of a noncontrolling tax equity interest in SP Wind, $65 million in tax benefits related to changes in state apportionment rates following the 2018 reorganizations of certain legal entities, and a $63 million increase in income tax expense as a result of higher pre-tax earnings, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.
See Note (G) to the Condensed Financial Statements herein for additional information.
Net Income Attributable to Noncontrolling Interests
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(29) | | (53.7) | | $(45) | | (63.4) |
In the third quarter 2019, net income attributable to noncontrolling interests was $25 million compared to $54 million for the corresponding period in 2018. The decrease was primarily due to an allocation of approximately $22 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.
For year-to-date 2019, net income attributable to noncontrolling interests was $26 million compared to $71 million for the corresponding period in 2018. The decrease was primarily due to $70 million of losses attributable to
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.
See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, and Note (E) to the Condensed Financial Statements under "Southern Power – Consolidated Variable Interest Entities" herein for additional information regarding the tax equity partnerships. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information regarding the Roserock solar facility litigation settlement.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. Future earnings potential will be impacted by the sales of noncontrolling interests in renewable facilities and the Florida Plants in 2018, the sale of Plant Nacogdoches in the second quarter 2019, and the pending sale of Plant Mankato expected to close by January 20, 2020. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects.
In the second quarter 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a cash purchase price of approximately $461 million. The pre-tax income related to Plant Nacogdoches was $16 million and $20 million for
Asset Acquisitions During the nine months ended September 30, 2019 and 2018, respectively. In the third quarter 2019, Southern Power completed a transaction to acquire a majority interest in DSGP, an affiliate of Bloom Energy that owns and operates fuel cell generation facilities, for a total purchase price of approximately $166 million. Pre-tax income for this project was immaterial for the three months ended September 30, 2019. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power" and "Southern Power – Development Projects," respectively, herein for additional information.
In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not close by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time. Pre-tax income for Plant Mankato was immaterial for both the nine months ended September 30, 2019 and 2018.
Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings. Other factors that could influence future earnings include weather, transmission constraints, cost of generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Laws and Regulations
Water Quality
On October 22, 2019, the EPA and the U.S. Army Corps of Engineers jointly published a final rule that repealed the 2015 Waters of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019. The impact of the WOTUS rule will depend on the content of the finalrule redefining WOTUS and the outcome of any associated legal challenges and cannot be determined at this time.
Acquisitions
During the third quarter 2019,2020, Southern Power acquired a controlling interest in the fuel cell generationwind facility listed below. Acquisition-related costs were expensed as incurred and were not material.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Project Facility | Resource | Seller | Approximate Nameplate Capacity (MW) | Location | Southern Power
Ownership Percentage Ownership | COD | | PPA Counterparty | PPA RemainingContract Period | DSGPBeech Ridge II(a)
| Fuel CellWind | 28Invenergy Renewables LLC | Delaware56 | Greenbrier County,
West Virginia | 100% of Class BA | N/A(b)
(*) | Delmarva Power & LightMay 2020 | 15 | 12 years |
| | (a) | During the second and third quarters 2019, Southern Power made a total investment of approximately $166 million in DSGP and now holds a controlling interest and consolidates 100% of DSGP's operating results. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility. |
| | (b) | Approximately 18 MWs of the 28-MW facility was repowered between June and August 2019. |
(*)In May 2020, Southern Power purchased 100% of the Class A membership interests and now owns the controlling interest in the project, with the Class B member, Invenergy Renewables LLC, owning the noncontrolling interest. In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in the first quarter 2021. The facility's output is contracted under 2 long-term PPAs. The ultimate outcome of this matter cannot be determined at this time. Construction Projects See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
During the nine months ended September 30, 2019,2020, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion andReading wind facility, continued construction of the Wildhorse MountainSkookumchuck wind facility, and Readingcommenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405$475 million and $450$545 million for the two facilities under construction. At September 30, 2019,2020, total costs of construction incurred for these projects were $337$244 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties | PPA Contract Period | Projects Completed During the Nine Months Ended September 30, 2019 | | 2020 | Mankato expansionReading(a)
| Natural GasWind | 385200 | Mankato, MNOsage and Lyon Counties, KS | May 20192020 | Northern States Power Company | 2012 years | Projects Under Construction as of September 30, 2019 | | 2020 | Wildhorse MountainSkookumchuck(b)
| Wind | 100136 | Pushmataha County, OKLewis and Thurston Counties, WA | Fourth quarter 2019November 2020 | Arkansas Electric Cooperative | 20 years | ReadingGarland Solar Storage(c)
| WindBattery energy storage system | 20088 | Osage and Lyon Counties, KSKern County, CA | Second quarter 20202021 | Royal Caribbean Cruises LTD20 years | Tranquillity Solar Storage(c) | 12Battery energy storage system | 72 | Fresno County, CA | Second quarter 2021 | 20 years |
| | (a) | Southern Power has an agreement with a subsidiary of Xcel to sell all of its equity interests in Plant Mankato, including the expansion. The transaction is subject to FERC approval and is expected to close by January 20, 2020. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. |
| | (b) | In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.
|
| | (c) | In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.
|
Subsequent(a)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to September 30,a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests.
(b)In October 2019, Southern Power purchased 100% of the membership interests of the 136-MW Skookumchuck wind facility located in Lewis and Thurston Counties, Washington from thepursuant to a joint development arrangement with Renewable Energy Systems Americas, Inc. and is continuing construction. The facility's output is contracted under a 20-year PPA with Puget Sound Energy, Inc. Upon commercial operation, which is expected to occur in the first quarter 2020,arrangement. Southern Power may enter intoexpects to complete a tax equity partnership astransaction upon commercial operation and retain the Class B member and, shortly thereafter,membership interests. Shortly after the completed tax equity transaction, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. Southern Power would retain the controlling ownership interest in the facility. The ultimate outcome of these matters cannot be determined at this time. (c)Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Development Projects Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the nine months ended September 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain. Sales of Natural Gas and Biomass Plants On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). The assets and liabilities of Plant Mankato were classified as held for sale on Southern Company's and Southern Power's balance sheets at December 31, 2019. Plants Nacogdoches (sold in June 2019) and Mankato represented individually significant components of Southern Power; therefore, pre-tax income for these components for the three months ended September 30, 2019 and the nine months ended September 30, 2020 and 2019 is presented below: | | | | | | | | | | | | | Three Months Ended
September 30, 2019 | Nine Months Ended September 30, | | 2020 | 2019 | | (in millions) | Southern Power's earnings before income taxes:(*) | | | | | Plant Nacogdoches | $ | 0 | | N/A | $ | 16 | | | Plant Mankato | $ | 12 | | $ | 2 | | $ | 20 | |
(*)Earnings before income taxes for components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively. Southern Company Gas On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The loss associated with the transactions was immaterial. Southern Company Gas also expects to receive payments in February 2021 and September 2021 of $5 million each contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. The assets and liabilities of Pivotal LNG and the interest in Atlantic Coast Pipeline were classified as held for sale at December 31, 2019. See Notes 3 and 7 under "Other Matters – Southern Company Gas – Gas Pipeline Projects" and "Southern Company Gas – Equity Method Investments," respectively, in Item 8 of the Form 10-K and Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively. (L) SEGMENT AND RELATED INFORMATION Southern Company The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in 3 Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $101 million and $279 million for the three and nine months ended September 30, 2020, respectively, and $116 million and $320 million for the three and nine months ended September 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for the three and nine months ended September 30, 2020 and $9 million and $13 million for the three and nine months ended September 30, 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $9 million and $22 million for the three and nine months ended September 30, 2020, respectively, and $20 million and $53 million for the three and nine months ended September 30, 2019, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Financial data for business segments and products and services for the three and nine months ended September 30, 2020 and 2019 was as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Utilities | | | | | | Traditional
Electric Operating
Companies | Southern
Power | Eliminations | Total | Southern Company Gas | All
Other | Eliminations | Consolidated | | (in millions) | | Three Months Ended September 30, 2020 | | | | | | | | | Operating revenues | $ | 4,629 | | $ | 523 | | $ | (103) | | $ | 5,049 | | $ | 477 | | $ | 132 | | $ | (38) | | $ | 5,620 | | Segment net income (loss)(a) | 1,284 | | 74 | | 0 | | 1,358 | | 14 | | (122) | | 1 | | 1,251 | | | Nine Months Ended September 30, 2020 | | | | | | | | | Operating revenues | $ | 11,576 | | $ | 1,337 | | $ | (285) | | $ | 12,628 | | $ | 2,362 | | $ | 380 | | $ | (112) | | $ | 15,258 | | Segment net income (loss)(a)(b)(c)(d) | 2,571 | | 212 | | 0 | | 2,783 | | 360 | | (420) | | 9 | | 2,732 | | | At September 30, 2020 | | | | | | | | | | Goodwill | $ | 0 | | $ | 2 | | $ | 0 | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | 0 | | $ | 5,280 | | | Total assets | 85,218 | | 13,424 | | (671) | | 97,971 | | 21,932 | | 4,116 | | (861) | | 123,158 | | | Three Months Ended September 30, 2019 | | | | | | | | | Operating revenues | $ | 4,908 | | $ | 574 | | $ | (119) | | $ | 5,363 | | $ | 498 | | $ | 146 | | $ | (12) | | $ | 5,995 | | Segment net income (loss)(a)(e)(f) | 1,373 | | 86 | | 0 | | 1,459 | | (29) | | (110) | | (4) | | 1,316 | | | Nine Months Ended September 30, 2019 | | | | | | | | | Operating revenues | $ | 12,252 | | $ | 1,527 | | $ | (331) | | $ | 13,448 | | $ | 2,661 | | $ | 514 | | $ | (118) | | $ | 16,505 | | Segment net income (loss)(a)(e)(f)(g) | 2,719 | | 316 | | 0 | | 3,035 | | 347 | | 931 | | (15) | | 4,298 | | | At December 31, 2019 | | | | | | | | | | Goodwill | $ | 0 | | $ | 2 | | $ | 0 | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | 0 | | $ | 5,280 | | | Total assets | 81,063 | | 14,300 | | (713) | | 94,650 | | 21,687 | | 3,511 | | (1,148) | | 118,700 | |
(a)Attributable to Southern Company. (b)Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge of $149 million ($111 million after tax) related to Plant Vogtle Units 3 and 4. See Note 15(B) under "Georgia Power – Nuclear Construction" for additional information. (c)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $154 million ($74 million after tax) related to a leveraged lease investment. See Note (C) under "Other Matters – Southern Company" for additional information. (d)Segment net income (loss) for Southern Power includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note (K) under "Southern Power" for additional information. (e)Segment net income (loss) for Southern Company Gas includes a pre-tax impairment charge of $92 million ($65 million after tax) related to a natural gas storage facility in Louisiana. See Note 3 to the financial statements under "Southern Power "Other Matters – Development Projects" Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information. Southern(f)Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power continues to evaluate and refineof $2.5 billion ($1.3 billion after tax) for the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projectsnine months ended September 30, 2019, as well as the amount of MW capacity to be constructed. During 2019, certain wind turbine equipment was sold, resultingimpairment charges in gains totaling approximately $17 million.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" and "Power Sales Agreements – General" of Southern Power in Item 7 for additional information.
Southern Power is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory and business matters. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation, regulatory matters, or other business matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the ownercontemplation of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy),sales of two of PowerSecure's business units totaling $18 million and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26$50 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc.three and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18,nine months ended September 30, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net, with a portion allocated to noncontrolling interests. As a result, Southern Power recognized a $12 million after-tax gain in the second quarter 2019.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 4, and 10respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K. In10-K under "Southern Company" for additional information.
(g)Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the applicationsale of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded inPlant Nacogdoches. See Note 15 to the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Powerstatements in Item 78 of the Form 10-K under "Southern Power – Sale of Natural Gas and Biomass Plants" for a complete discussionadditional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Products and Services | | | | | | | | | | | | | | | | | Electric Utilities' Revenues | | Retail | Wholesale | Other | Total | | (in millions) | | Three Months Ended September 30, 2020 | $ | 4,243 | | $ | 584 | | $ | 222 | | $ | 5,049 | | | Three Months Ended September 30, 2019 | 4,512 | | 625 | | 226 | | 5,363 | | | Nine Months Ended September 30, 2020 | $ | 10,503 | | $ | 1,473 | | $ | 652 | | $ | 12,628 | | | Nine Months Ended September 30, 2019 | 11,136 | | 1,667 | | 645 | | 13,448 | |
| | | | | | | | | | | | | | | | | | | | Southern Company Gas' Revenues | | Gas
Distribution
Operations | Wholesale Gas Services(*) | Gas
Marketing
Services | Other | Total | | (in millions) | | Three Months Ended September 30, 2020 | $ | 476 | | $ | (51) | | $ | 39 | | $ | 13 | | $ | 477 | | | Three Months Ended September 30, 2019 | 445 | | (2) | | 39 | | 16 | | 498 | | | Nine Months Ended September 30, 2020 | $ | 2,072 | | $ | (19) | | $ | 272 | | $ | 37 | | $ | 2,362 | | | Nine Months Ended September 30, 2019 | 2,169 | | 132 | | 326 | | 34 | | 2,661 | |
(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information. Southern Company Gas Southern Company Gas manages its business through 4 reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other. Gas distribution operations is the largest component of Southern Power's critical accounting policiesCompany Gas' business and estimates.includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in 4 states. Recently Issued Accounting Standards
See Note (A)Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, a 20% ownership interest in the PennEast Pipeline construction project, a 50% joint ownership interest in the Dalton Pipeline, and a 5% ownership interest in the Atlantic Coast Pipeline construction project through its sale on March 24, 2020. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview"customers of Southern Power in Item 7Company Gas.
Wholesale gas services provides natural gas asset management and/or related logistics services for each of the Form 10-K for additional information. Southern Power's financial condition remained stable at September 30, 2019. Southern Power intends to continue to monitor its access to short-term and long-term capital marketsCompany Gas' utilities except Nicor Gas as well as bank credit agreements as neededfor non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities. Gas marketing services provides natural gas marketing to meet future capitalend-use customers primarily in Georgia, Illinois, and liquidity needs.Ohio through SouthStar. The all other column includes segments below the quantitative threshold for separate disclosure, including natural gas storage businesses, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See "Sources of Capital" hereinNotes (E) and (K) under "Southern Company Gas" for additional information on linesinformation.
Southern Power also utilizes tax equity partnerships, where
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) (UNAUDITED) Business segment financial data for the tax partner takes significantly all of the federal tax benefits, as a financing source. These tax equity partnerships are consolidated in Southern Power's financial statementsthree and are accounted for using HLBV methodology to allocate partnership gains and losses. During the first nine months ended September 30, 2020 and 2019 was as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(a) | Gas Marketing Services | Total | All Other(b) | Eliminations | Consolidated | | (in millions) | | Three Months Ended September 30, 2020 | | | | | | | | Operating revenues | $ | 479 | | $ | 8 | | $ | (51) | | $ | 39 | | $ | 475 | | $ | 8 | | $ | (6) | | $ | 477 | | | Segment net income (loss) | 46 | | 23 | | (45) | | (3) | | 21 | | (7) | | 0 | | 14 | | | Nine Months Ended September 30, 2020 | | | | | | | | Operating revenues | $ | 2,086 | | $ | 24 | | $ | (19) | | $ | 272 | | $ | 2,363 | | $ | 24 | | $ | (25) | | $ | 2,362 | | | Segment net income (loss) | 284 | | 74 | | (45) | | 59 | | 372 | | (12) | | 0 | | 360 | | | Total assets at September 30, 2020 | 18,715 | | 1,609 | | 650 | | 1,461 | | 22,435 | | 10,979 | | (11,482) | | 21,932 | | | Three Months Ended September 30, 2019 | | | | | | | | Operating revenues | $ | 448 | | $ | 8 | | $ | (2) | | $ | 39 | | $ | 493 | | $ | 10 | | $ | (5) | | $ | 498 | | | Segment net income (loss) | 37 | | 6 | | (9) | | (4) | | 30 | | (59) | | 0 | | (29) | | | Nine Months Ended September 30, 2019 | | | | | | | | | Operating revenues | $ | 2,188 | | $ | 24 | | $ | 132 | | $ | 326 | | $ | 2,670 | | $ | 34 | | $ | (43) | | $ | 2,661 | | | Segment net income (loss) | 228 | | 63 | | 61 | | 54 | | 406 | | (59) | | 0 | | 347 | | | Total assets at December 31, 2019 | 18,204 | | 1,678 | | 850 | | 1,496 | | 22,228 | | 10,759 | | (11,300) | | 21,687 | |
(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. | | | | | | | | | | | | | | | | | | | Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues | | (in millions) | | Three Months Ended September 30, 2020 | $ | 1,050 | | $ | 33 | | $ | 1,083 | | $ | 1,134 | | $ | (51) | | | Three Months Ended September 30, 2019 | 1,138 | | 72 | | 1,210 | | 1,212 | | (2) | | | Nine Months Ended September 30, 2020 | $ | 3,089 | | $ | 81 | | $ | 3,170 | | $ | 3,189 | | $ | (19) | | | Nine Months Ended September 30, 2019 | 4,287 | | 223 | | 4,510 | | 4,378 | | 132 | |
(b)Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $92 million ($65 million after tax) for the three and nine months ended September 30, 2019 Southern Power did not receive any material tax equity funding amounts.related to a natural gas storage facility in Louisiana. See Note 13 to the
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
financial statements under "Hypothetical Liquidation at Book Value""Other Matters – Southern Company Gas – Natural Gas Storage Facilities" in Item 8 of the Form 10-K for additional information.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. | | | | | | | Page | | Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | | | | | | | | | | | | | | | | | | | | | | | |
The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on the HLBV methodology. Net cash provided from operating activities totaled $1.2 billion for the first nine months of 2019 comparedits own behalf and each Registrant makes no representation as to $666 million for the first nine months of 2018. The increase in net cash provided from operating activities was primarily due to the utilization of federal ITCs of $705 million in 2019. Net cash provided from investing activities totaled $36 million for the first nine months of 2019 primarily due to proceeds from the disposition of Plant Nacogdoches and wind equipment sales, largely offset by Southern Power's investment in DSGP and ongoing construction activities. Net cash used for financing activities totaled $1.1 billion for the first nine months of 2019 primarily due to returns of capital to Southern Company, common stock dividends, the repayment of a short-term bank loan, and distributions to noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2019 include a $271 million increase in prepaid income taxes and an $868 million decrease in accumulated deferred income tax assetsinformation related to the utilization of tax credits for the 2019 tax year, a $402 million decrease in plant in service primarily as a result of the sale of Plant Nacogdoches, partially offset by the acquisition of DSGP, a $368 million increase in operating lease right-of-use assets along with a corresponding increase in operating lease obligations of $373 million due to the adoption of ASU No. 2016-02, Leases (Topic 842), and a $591 million decrease in stockholder's equity primarily due to returns of capital to Southern Company. See Note (K) under "Southern Power" and Note (L) to the Condensed Financial Statements herein for additional information.
See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements and contractual obligations. Approximately $900 million will be required through September 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
Southern Power's construction program includes estimates for potential plant acquisitions and placeholder growth, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Actual construction costs, including acquisitions, may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, divestitures, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs due to seasonality. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
defined below), borrowings from financial institutions, equity contributions from Southern Company, external securities issuances, and operating cash flows.
As of September 30, 2019, Southern Power had cash and cash equivalents of approximately $368 million.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt.
Southern Power had no short-term loans or commercial paper outstanding during the three-month period ended September 30, 2019.
In May 2019, Southern Power amended and restated its committed credit facility (Facility) to extend the maturity date to 2024 and decrease the borrowing capacity from $750 million to $600 million. At September 30, 2019, $9 million of the Facility had been used for letters of credit and $591 million remains unused. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At September 30, 2019, Southern Power was in compliance with all covenants in the Facility. The Facility does not contain a material adverse change clause at the time of borrowing.
Southern Power also has a $120 million continuing letter of credit facility expiring in 2021 for standby letters of credit. At September 30, 2019, $90 million has been used for letters of credit, primarily as credit support for PPA requirements, and $30 million remains unused.
In addition, at September 30, 2019, Southern Power had $104 million of cash collateral posted related to PPA requirements.
Southern Power's subsidiaries do not borrow under the commercial paper program and are not parties to, and do not borrow under, the Facility or the continuing letter of credit facility.
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, transmission, and interest rate management.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maximum potential collateral requirements under these contracts at September 30, 2019 were as follows:
| | | | | | Credit Ratings | Maximum Potential
Collateral
Requirements | | | (in millions) | | At BBB and/or Baa2 | $ | 29 |
| | At BBB- and/or Baa3 | $ | 340 |
| At BB+ and/or Ba1(*) | $ | 1,015 |
|
| | (*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $44 million. |
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate companies of Southern Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
Financing Activities
In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
SOUTHERN COMPANY GAS
AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Operating Revenues: | | | | | | | | Natural gas revenues (includes revenue taxes of
$10, $9, $88, and $83, respectively) | $ | 498 |
| | $ | 487 |
| | $ | 2,661 |
| | $ | 2,829 |
| | Alternative revenue programs | — |
| | 5 |
| | — |
| | (23 | ) | | Other revenues | — |
| | — |
| | — |
| | 55 |
| | Total operating revenues | 498 |
| | 492 |
| | 2,661 |
| | 2,861 |
| | Operating Expenses: | | | | | | | | | Cost of natural gas | 79 |
| | 104 |
| | 956 |
| | 1,053 |
| | Cost of other sales | — |
| | — |
| | — |
| | 12 |
| | Other operations and maintenance | 208 |
| | 216 |
| | 642 |
| | 730 |
| | Depreciation and amortization | 121 |
| | 119 |
| | 359 |
| | 374 |
| | Taxes other than income taxes | 33 |
| | 32 |
| | 161 |
| | 157 |
| | Impairment charges | 92 |
| | — |
| | 92 |
| | 42 |
| (Gain) loss on dispositions, net
| — |
| | (353 | ) | | — |
| | (317 | ) | | Total operating expenses | 533 |
| | 118 |
| | 2,210 |
| | 2,051 |
| | Operating Income (Loss) | (35 | ) | | 374 |
| | 451 |
| | 810 |
| | Other Income and (Expense): | | | | | | | | | Earnings from equity method investments | 35 |
| | 34 |
| | 115 |
| | 108 |
| | Interest expense, net of amounts capitalized | (56 | ) | | (52 | ) | | (174 | ) | | (170 | ) | | Other income (expense), net | 5 |
| | 6 |
| | 16 |
| | 21 |
| | Total other income and (expense) | (16 | ) | | (12 | ) | | (43 | ) | | (41 | ) | | Earnings (Loss) Before Income Taxes | (51 | ) | | 362 |
| | 408 |
| | 769 |
| | Income taxes (benefit) | (22 | ) | | 316 |
| | 61 |
| | 475 |
| | Net Income (Loss) | $ | (29 | ) | | $ | 46 |
| | $ | 347 |
| | $ | 294 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | 2019 | | 2018 | | | (in millions) | | (in millions) | | Net Income (Loss) | $ | (29 | ) | | $ | 46 |
| | $ | 347 |
| | $ | 294 |
| | Other comprehensive income (loss): | | | | | | | | | Qualifying hedges: | | | | | | | | Changes in fair value, net of tax of
$(3), $-, $(4), and $1, respectively | (3 | ) | | — |
| | (6 | ) | | 2 |
| Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $1, respectively | — |
| | — |
| | — |
| | 2 |
| | Pension and other postretirement benefit plans: | | | | | | | | Reclassification adjustment for amounts included in net income,
net of tax of $-, $2, $(1), and $2, respectively | — |
| | 6 |
| | (1 | ) | | 5 |
| | Total other comprehensive income (loss) | (3 | ) | | 6 |
| | (7 | ) | | 9 |
| | Comprehensive Income (Loss) | $ | (32 | ) | | $ | 52 |
| | $ | 340 |
| | $ | 303 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | | | | | | | | For the Nine Months Ended September 30, | | | 2019 | | 2018 | | | (in millions) | | Operating Activities: | | | | | Net income | $ | 347 |
| | $ | 294 |
| | Adjustments to reconcile net income to net cash provided from operating activities — | | | | | Depreciation and amortization, total | 359 |
| | 374 |
| | Deferred income taxes | 96 |
| | (83 | ) | | Mark-to-market adjustments | 44 |
| | 23 |
| | Impairment charges | 92 |
| | 42 |
| | (Gain) loss on dispositions, net | — |
| | (317 | ) | | Other, net | (58 | ) | | (41 | ) | | Changes in certain current assets and liabilities — | | | | | -Receivables | 832 |
| | 445 |
| | -Natural gas for sale | 49 |
| | 87 |
| | -Other current assets | 45 |
| | (2 | ) | | -Accounts payable | (607 | ) | | (59 | ) | | -Accrued taxes | (68 | ) | | (64 | ) | | -Accrued compensation | (34 | ) | | 2 |
| | -Other current liabilities | (48 | ) | | 35 |
| | Net cash provided from operating activities | 1,049 |
| | 736 |
| | Investing Activities: | | | | | Property additions | (1,008 | ) | | (1,029 | ) | | Cost of removal, net of salvage | (59 | ) | | (67 | ) | | Change in construction payables, net | 57 |
| | (14 | ) | | Investment in unconsolidated subsidiaries | (25 | ) | | (90 | ) | | Proceeds from dispositions and asset sales | 32 |
| | 2,631 |
| | Other investing activities | 14 |
| | 18 |
| | Net cash provided from (used for) investing activities | (989 | ) | | 1,449 |
| | Financing Activities: | | | | | Decrease in notes payable, net | (383 | ) | | (1,382 | ) | | Proceeds — | | | | | First mortgage bonds | 200 |
| | 100 |
| | Capital contributions from parent company | 820 |
| | 35 |
| | Redemptions — | | | | | Gas facility revenue bonds | — |
| | (200 | ) | | First mortgage bonds | (50 | ) | | — |
| | Senior notes | (300 | ) | | — |
| | Return of capital | — |
| | (400 | ) | | Payment of common stock dividends | (353 | ) | | (351 | ) | | Other financing activities | (2 | ) | | (3 | ) | | Net cash used for financing activities | (68 | ) | | (2,201 | ) | | Net Change in Cash, Cash Equivalents, and Restricted Cash | (8 | ) | | (16 | ) | | Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 70 |
| | 78 |
| | Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 62 |
| | $ | 62 |
| | Supplemental Cash Flow Information: | | | | | Cash paid during the period for — | | | | | Interest (net of $5 and $5 capitalized for 2019 and 2018, respectively) | $ | 180 |
| | $ | 175 |
| | Income taxes, net | 48 |
| | 682 |
| | Noncash transactions — Accrued property additions at end of period | 154 |
| | 121 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Assets | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Assets: | | | | | | Cash and cash equivalents | | $ | 59 |
| | $ | 64 |
| | Receivables — | | | | | | Energy marketing receivables | | 336 |
| | 801 |
| | Customer accounts receivable | | 186 |
| | 370 |
| | Unbilled revenues | | 55 |
| | 213 |
| | Affiliated | | 12 |
| | 11 |
| | Other accounts and notes receivable | | 103 |
| | 142 |
| | Accumulated provision for uncollectible accounts | | (18 | ) | | (30 | ) | | Natural gas for sale | | 475 |
| | 524 |
| | Prepaid expenses | | 86 |
| | 118 |
| | Assets from risk management activities, net of collateral | | 112 |
| | 219 |
| | Other regulatory assets | | 82 |
| | 73 |
| | Other current assets | | 43 |
| | 50 |
| | Total current assets | | 1,531 |
| | 2,555 |
| | Property, Plant, and Equipment: | | | | | | In service | | 16,058 |
| | 15,177 |
| | Less: Accumulated depreciation | | 4,590 |
| | 4,400 |
| | Plant in service, net of depreciation | | 11,468 |
| | 10,777 |
| | Construction work in progress | | 546 |
| | 580 |
| | Total property, plant, and equipment | | 12,014 |
| | 11,357 |
| | Other Property and Investments: | | | | | | Goodwill | | 5,015 |
| | 5,015 |
| | Equity investments in unconsolidated subsidiaries | | 1,487 |
| | 1,538 |
| Other intangible assets, net of amortization of $168 and $145
at September 30, 2019 and December 31, 2018, respectively | | 78 |
| | 101 |
| | Miscellaneous property and investments | | 20 |
| | 20 |
| | Total other property and investments | | 6,600 |
| | 6,674 |
| | Deferred Charges and Other Assets: | | | | | | Operating lease right-of-use assets, net of amortization | | 92 |
| | — |
| | Other regulatory assets, deferred | | 621 |
| | 669 |
| | Other deferred charges and assets | | 189 |
| | 193 |
| | Total deferred charges and other assets | | 902 |
| | 862 |
| | Total Assets | | $ | 21,047 |
| | $ | 21,448 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | | | | | | | | | Liabilities and Stockholder's Equity | | At September 30, 2019 | | At December 31, 2018 | | | | (in millions) | | Current Liabilities: | | | | | | Securities due within one year | | $ | — |
| | $ | 357 |
| | Notes payable | | 267 |
| | 650 |
| | Energy marketing trade payables | | 368 |
| | 856 |
| | Accounts payable — | | | | | | Affiliated | | 42 |
| | 45 |
| | Other | | 334 |
| | 402 |
| | Customer deposits | | 96 |
| | 133 |
| | Accrued taxes — | | | | | | Accrued income taxes | | — |
| | 66 |
| | Other accrued taxes | | 72 |
| | 75 |
| | Accrued interest | | 63 |
| | 55 |
| | Accrued compensation | | 64 |
| | 100 |
| | Liabilities from risk management activities, net of collateral | | 50 |
| | 76 |
| | Other regulatory liabilities | | 100 |
| | 79 |
| | Other current liabilities | | 127 |
| | 130 |
| | Total current liabilities | | 1,583 |
| | 3,024 |
| | Long-term Debt | | 5,755 |
| | 5,583 |
| | Deferred Credits and Other Liabilities: | | | | | | Accumulated deferred income taxes | | 1,108 |
| | 1,016 |
| | Deferred credits related to income taxes | | 890 |
| | 940 |
| | Employee benefit obligations | | 353 |
| | 357 |
| | Operating lease obligations | | 77 |
| | — |
| | Other cost of removal obligations | | 1,601 |
| | 1,585 |
| | Accrued environmental remediation | | 241 |
| | 268 |
| | Other deferred credits and liabilities | | 46 |
| | 105 |
| | Total deferred credits and other liabilities | | 4,316 |
| | 4,271 |
| | Total Liabilities | | 11,654 |
| | 12,878 |
| Common Stockholder's Equity (See accompanying statements) | | 9,393 |
| | 8,570 |
| | Total Liabilities and Stockholder's Equity | | $ | 21,047 |
| | $ | 21,448 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (UNAUDITED)
| | | | | | | | | | | | | | | | | | | Paid-In
Capital | | Retained
Earnings (Accumulated Deficit) | | Accumulated
Other
Comprehensive
Income (Loss) | | Total | | | (in millions) | | Balance at December 31, 2017 | $ | 9,214 |
| | $ | (212 | ) | | $ | 20 |
| | $ | 9,022 |
| | Net income | — |
| | 279 |
| | — |
| | 279 |
| | Capital contributions from parent company | 14 |
| | — |
| | — |
| | 14 |
| | Other comprehensive income (loss) | — |
| | — |
| | 2 |
| | 2 |
| | Cash dividends on common stock | — |
| | (118 | ) | | — |
| | (118 | ) | | Other | — |
| | (4 | ) | | 4 |
| | — |
| | Balance at March 31, 2018 | 9,228 |
| | (55 | ) | | 26 |
| | 9,199 |
| | Net loss | — |
| | (31 | ) | | — |
| | (31 | ) | | Capital contributions from parent company | 8 |
| | — |
| | — |
| | 8 |
| | Other comprehensive income (loss) | — |
| | — |
| | 1 |
| | 1 |
| | Cash dividends on common stock | — |
| | (117 | ) | | — |
| | (117 | ) | | Other | — |
| | 1 |
| | — |
| | 1 |
| | Balance at June 30, 2018 | 9,236 |
| | (202 | ) | | 27 |
| | 9,061 |
| | Net income | — |
| | 46 |
| | — |
| | 46 |
| | Return of capital to parent company | (400 | ) | | — |
| | — |
| | (400 | ) | | Capital contributions from parent company | 27 |
| | — |
| | — |
| | 27 |
| | Other comprehensive income (loss) | — |
| | — |
| | 6 |
| | 6 |
| | Cash dividends on common stock | — |
| | (116 | ) | | — |
| | (116 | ) | | Other | — |
| | (1 | ) | | — |
| | (1 | ) | | Balance at September 30, 2018 | $ | 8,863 |
| | $ | (273 | ) | | $ | 33 |
| | $ | 8,623 |
| | | | | | | | | | | Balance at December 31, 2018 | $ | 8,856 |
| | $ | (312 | ) | | $ | 26 |
| | $ | 8,570 |
| | Net income | — |
| | 270 |
| | — |
| | 270 |
| | Capital contributions from parent company | 17 |
| | — |
| | — |
| | 17 |
| | Other comprehensive income (loss) | — |
| | — |
| | (1 | ) | | (1 | ) | | Cash dividends on common stock | — |
| | (118 | ) | | — |
| | (118 | ) | | Balance at March 31, 2019 | 8,873 |
| | (160 | ) | | 25 |
| | 8,738 |
| | Net income | — |
| | 106 |
| | — |
| | 106 |
| | Capital contributions from parent company | 35 |
| | — |
| | — |
| | 35 |
| | Other comprehensive income (loss) | — |
| | — |
| | (3 | ) | | (3 | ) | | Cash dividends on common stock | — |
| | (117 | ) | | — |
| | (117 | ) | | Balance at June 30, 2019 | 8,908 |
| | (171 | ) | | 22 |
| | 8,759 |
| | Net loss | — |
| | (29 | ) | | — |
| | (29 | ) | | Capital contributions from parent company | 784 |
| | — |
| | — |
| | 784 |
| | Other comprehensive income (loss) | — |
| | — |
| | (3 | ) | | (3 | ) | | Cash dividends on common stock | — |
| | (118 | ) | | — |
| | (118 | ) | | Balance at September 30, 2019 | $ | 9,692 |
| | $ | (318 | ) | | $ | 19 |
| | $ | 9,393 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2019 vs. THIRD QUARTER 2018
AND
YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018
OVERVIEW Southern Company Gas is an energy servicesa holding company whosethat owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), as well as Southern Power and Southern Company Gas, and owns other direct and indirect subsidiaries. The primary business isbusinesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas through utilities in four states – Nicor Gas in Illinois, Atlanta Gas Light in Georgia, Virginia Natural Gas in Virginia, and Chattanooga Gas in Tennessee.by Southern Company Gas is also involvedGas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in severalthe competitive wholesale market by Southern Power, and the sale of natural gas and other complementary businesses. products and services by Southern Company Gas manages its business through fourGas. Southern Company Gas' reportable segments –are gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services – and one non-reportable segment, all other.services. See Note (M)(L) to the Condensed Financial Statements herein and "BUSINESSfor additional information on segment reporting. For additional information on the Registrants' primary business activities, see BUSINESS – The"The Southern Company System – Southern Company Gas"System" in Item 1 of the Form 10-K for additional information.10-K. Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain safety, to maintain constructive regulatory environments, to maintain and grow natural gas sales and number of customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, environmental standards, safety, reliability, resilience, natural gas, and capital expenditures, including updating and expanding the natural gas distribution systems. The natural gas distribution utilities have various regulatory mechanisms that address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices willRegistrants continue to challengefocus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, forthese indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the foreseeable future.equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments COVID-19 During 2019,March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. The Southern Company system provides a critical service to its customers; therefore, it is essential that Southern Company system employees are able to continue to perform their critical duties safely and effectively. The Southern Company system has implemented applicable business continuity plans, including teleworking, canceling non-essential business travel, increasing cleaning frequency at business locations, implementing applicable safety and health guidelines issued by federal and state officials, and establishing protocols for required work on customer premises. To date, these procedures have been effective in maintaining the Southern Company system's critical operations. As a result of the COVID-19 pandemic, there have been economic disruptions in the Registrants' operating territories. The traditional electric operating companies and the natural gas distribution utilities have been involvedtemporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein for information regarding deferral of certain incremental COVID-19-related costs, including bad debt, to a regulatory asset by certain of the traditional electric operating companies and the natural gas distribution utilities. In addition, the COVID-19 pandemic has resulted in a reduction in workforce at Plant Vogtle Units 3 and 4, as discussed further herein. Additional information regarding COVID-19 and its past and potential future impacts on the Registrants is provided throughout Management's Discussion and Analysis of Financial Condition and Results of Operations and in Item 1A herein. Alabama Power On August 14, 2020, the Alabama PSC issued an order granting Alabama Power a certificate of convenience and necessity (CCN) to procure additional capacity, and, on August 31, 2020, Alabama Power completed the Autauga Combined Cycle Acquisition. On August 7, 2020, the Alabama PSC issued an order authorizing Alabama Power to reduce its over-collected fuel balance by $100 million and return that amount to customers in the followingform of bill credits for the billing month of October 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information. Georgia Power Plant Vogtle Units 3 and 4 Status In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power holds a 45.7% ownership interest. As of June 30, 2020, assignments of contingency to the base capital cost forecast exceeded the remaining balance of the construction contingency originally established in the second quarter 2018. As a result, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings:proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery. | | • | On October 2, 2019, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, including $65 million related to the recovery of investments under the Investing in Illinois program, based on a ROE of 9.73% and an equity ratio of 54.2%, which became effective October 8, 2019. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery. The Illinois Commission's order is subject to any rehearing request filed by any party to the proceeding within 30 days of service of the order on such party.In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site. In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This workforce reduction lowered absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase in, construction contingency described above. To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. In October 2020, Southern Nuclear further extended milestone dates from the July 2020 aggressive site work plan. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information. Mississippi Power |
On September 25, 2019,March 17, 2020, the Virginia CommissionMississippi PSC approved Virginia Natural Gas' Stepsa settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Advance Virginia's Energy (SAVE) program request to amend and extend the program through 2024 with estimated capital spend totaling approximately $365 million. Atlanta Gas Light filed aMississippi Power's base rate case on June 3, 2019.filed in November 2019 (Mississippi Power Rate Case Settlement Agreement). Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Southern Power During the nine months ended September 30, 2020, Southern Power completed construction of and placed in service the 200-MW Reading wind facility, continued construction of the 136-MW Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" herein for additional information. On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The Georgia PSCacquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to rule onoccur in the case in December 2019.first quarter 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time. On May 1, 2020, Southern Power purchased a controlling interest in the 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from Invenergy Renewables LLC. The facility's output is contracted under a 12-year PPA. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Note 2(K) to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Rate Proceedings"Condensed Financial Statements herein for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIESSouthern Company Gas
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
During 2018,On March 24, 2020, Southern Company Gas completed the following sales, resulting in approximately $2.7 billion in aggregate proceeds.
On June 4, 2018, Southern Company Gas completed the stock sale of its interests in Pivotal Home Solutions to American Water Enterprises LLC.
On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the salesLNG and Atlantic Coast Pipeline with aggregate proceeds of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy.
$178 million, including working capital adjustments. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on these dispositions. In the third quarter 2019, Southern Company Gas recorded a pre-tax impairment charge of $92 million ($65 million after tax) related to a natural gas storage facility in Louisiana. See Note (C)(K) to the Condensed Financial Statements under "Other Matters – Southern"Southern Company Gas" herein for additional information.
Operating Metrics
Southern CompanyOn June 1, 2020, Virginia Natural Gas continuesfiled a general rate case with the Virginia Commission seeking an increase in rates ofapproximately $49.6 million based on a ROE of 10.35% and an equity ratio of 54%. Rate adjustments are expected to focusbe effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory, including Nicor Gas following the approval of a revenue decoupling mechanism for residential customers in its recent rate case. However, the operating revenues from utility customers in Illinois and gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges to limit the negative income impactsrequested increase in the event of warmer-than-normal weather, while retaining a significant portion of the positive benefits of colder-than-normal weather for these businesses.second quarter 2021.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
See RESULTS OF OPERATIONS herein for additional information on these operating metrics.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and payables. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income (Loss)
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(75) | | (163.0) | | $53 | | 18.0 |
In the third quarter 2019, net loss was $29 million compared to net income of $46 million for the corresponding period in 2018. This change includes a $42 million net gain in 2018 from the Southern Company Gas Dispositions and a $65 million after-tax impairment charge in 2019 related to a natural gas storage facility in Louisiana. The change in net income also includes increases related to $10 million in additional revenues from continued investment in infrastructure replacement programs, $12 million in disposition-related costs in 2018, and a $9 million increase at wholesale gas services primarily due to lower hedge losses.
For year-to-date 2019, net income was $347 million compared to $294 million for the corresponding period in 2018. This change includes a $39 million net loss in 2018 from the Southern Company Gas Dispositions, a $65 million after-tax impairment charge in 2019 related to a natural gas storage facility in Louisiana, and $7 million of net income in 2019 from the sale of Triton. The change in net income also includes increases related to $16 million in disposition-related costs in 2018, $39 million in continued investment in infrastructure replacement programs and base rate changes, $24 million in lower income taxes primarily atOn July 1, 2020, Atlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized byfiled its 2020 GRAM filing with the Georgia PSC a $9 million impact from adopting a new paid time off policy to align with the Southern Company system in first quarter 2018, and a $5 millionrequesting an increase in earnings from equity method investments in 2019. Partially offsetting these increases were an $8 million contractor litigation settlement recorded inannual base rates of $37.6 million. Resolution of the first quarter 2018 and an increase of $9 million in depreciation and amortization primarily due to continued infrastructure investments at gas distribution operations.2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.
See Note (C) to the Condensed Financial Statements under "OtherFUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" herein for additional information onregarding Southern Company Gas' regulatory filings. The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) RESULTS OF OPERATIONS Southern Company Net Income | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(65) | | (4.9) | | $(1,566) | | (36.4) |
Consolidated net income attributable to Southern Company was $1.25 billion ($1.18 per share) for the third quarter 2020 compared to $1.32 billion ($1.26 per share) for the corresponding period in 2019. The decrease was primarily due to a decrease in retail revenues associated with milder weather in the third quarter 2020 compared to the corresponding period in 2019 and higher depreciation and amortization expenses, partially offset by an impairment charge in 2019 recorded at Southern Company Gas related to a natural gas storage facility and lower income tax expense. Consolidated net income attributable to Southern Company was $2.7 billion ($2.58 per share) for year-to-date 2020 compared to $4.3 billion ($4.12 per share) for the corresponding period in Louisiana and2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power recorded in 2019. See Note 215 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP"Company" in Item 8 of the Form 10-K for additional information on Atlanta Gas Light's stipulation reflectingregarding the impactssale of the Tax Reform Legislation and the contractor litigation settlement, respectively.Gulf Power. Natural GasRetail Electric Revenues including Alternative Revenue Programs
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $6 | | 1.2 | | $(145) | | (5.2) |
| | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(269) | | (6.0) | | $(633) | | (5.7) |
In the third quarter 2020, retail electric revenues were $4.2 billion compared to $4.5 billion for the corresponding period in 2019. For year-to-date 2020, retail electric revenues were $10.5 billion compared to $11.1 billion for the corresponding period in 2019. Details of the changes in retail electric revenues were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Year-to-Date 2020 | | (in millions) | | (% change) | | (in millions) | | (% change) | | Retail electric – prior year | $ | 4,512 | | | | | $ | 11,136 | | | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | 32 | | | 0.7 | % | | 299 | | | 2.7 | % | | Sales decline | (23) | | | (0.5) | | | (122) | | | (1.1) | | | Weather | (141) | | | (3.1) | | | (300) | | | (2.7) | | | Fuel and other cost recovery | (137) | | | (3.0) | | | (510) | | | (4.6) | | | Retail electric – current year | $ | 4,243 | | | (5.9) | % | | $ | 10,503 | | | (5.7) | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 natural gasprimarily due to an increase in revenue at Georgia Power related to the recovery of environmental compliance costs and the impacts of accruals for customer refunds in 2019 related to Tax Reform, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing. The year-to-date 2020 increase was also due to the rate pricing effects of decreased customer usage at Georgia Power and customer bill credits at Alabama Power in the first quarter 2019 related to Tax Reform. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to work-from-home policies related to the COVID-19 pandemic and reluctance of consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 3.5% and 3.7% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and work-from-home policies. Weather-adjusted commercial KWH sales decreased 5.1% and 5.9% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 7.3% and 7.8% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession. Fuel and other cost recovery revenues decreased $137 million and $510 million in the third quarter and year-to-date 2020, respectively, compared to the corresponding periods in 2019 primarily due to decreases in generation and the average cost of fuel and purchased power. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including alternative revenue programs,the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs. Wholesale Electric Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(41) | | (6.6) | | $(194) | | (11.6) |
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy. In the third quarter 2020, wholesale electric revenues were $498$584 million compared to $492$625 million for the corresponding period in 2018.2019. For year-to-date 2019, natural gas2020, wholesale electric revenues including alternative revenue programs, were $2.7$1.5 billion compared to $2.8$1.7 billion for the corresponding period in 2018.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural Gas Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(21) | | (4.2) | | $(299) | | (11.2) |
In the third quarter 2020, natural gas revenues were $477 million compared to $498 million for the corresponding period in 2019. For year-to-date 2020, natural gas revenues were $2.4 billion compared to $2.7 billion for the corresponding period in 2019. Details of the changes in natural gas revenues including alternative revenue programs, were as follows: | | | | Third Quarter 2019 | | Year-to-Date 2019 | | Third Quarter 2020 | | Year-to-Date 2020 | | | (in millions) | | (% change) | | (in millions) | | (% change) | | (in millions) | | (% change) | | (in millions) | | (% change) | | Natural gas revenues – prior year | $ | 492 |
|
|
|
| $ | 2,806 |
|
|
|
| Natural gas revenues – prior year | $ | 498 | | | $ | 2,661 | | | | Estimated change resulting from – | | | | | | | | Estimated change resulting from – | | | Infrastructure replacement programs and base rate changes | 15 |
|
| 3.0 | % |
| 57 |
|
| 2.0 | % | Infrastructure replacement programs and base rate changes | 34 | | | 6.8 | % | | 153 | | | 5.7 | % | | Gas costs and other cost recovery | (14 | ) |
| (2.8 | ) |
| 35 |
|
| 1.2 |
| Gas costs and other cost recovery | (8) | | | (1.6) | | | (298) | | | (11.2) | | | Weather | (1 | ) |
| (0.2 | ) |
| (1 | ) |
| — |
| Weather | 2 | | | 0.4 | | | (6) | | | (0.2) | | | Wholesale gas services | 6 |
|
| 1.2 |
|
| (10 | ) |
| (0.4 | ) | Wholesale gas services | (49) | | | (9.8) | | | (151) | | | (5.6) | | | Southern Company Gas Dispositions | (8 | ) | | (1.6 | ) | | (245 | ) | | (8.7 | ) | | | Other | 8 |
|
| 1.6 |
|
| 19 |
|
| 0.7 |
| Other | — | | | — | | | 3 | | | 0.1 | | | Natural gas revenues – current year | $ | 498 |
| | 1.2 | % | | $ | 2,661 |
| | (5.2 | )% | Natural gas revenues – current year | $ | 477 | | | (4.2) | % | | $ | 2,362 | | | (11.2) | % |
Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 20192020 compared to the corresponding periods in 20182019 primarily due to base rate increases of $11 million and $36 million, respectively, at Nicor Gas and $2 million and $16 million, respectively, at Atlanta Gas Light. These amounts include gas distribution operations'Light and continued investments recovered through infrastructure replacement programs and base rate increases as well as the effect of revenues deferred in 2018 as a result of the Tax Reform Legislation.programs. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information. Revenues associated with gas costs and other cost recovery decreased in the third quarter 2019 and increased year-to-date 20192020 compared to the corresponding periods in 2018. The decrease in the third quarter 2019 is primarily due to lower natural gas prices and decreasedprices. The year-to-date decrease also reflects lower sales volumes in 2020 compared to the corresponding period in 2019 primarily as a result of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019.warmer weather. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impactsutilities. Revenues from weather and customer growth are described further below. Revenues fromSouthern Company Gas' wholesale gas services increasedbusiness decreased in the third quarter 2019 and decreased year-to-date 20192020 compared to the corresponding periodsperiod in 2018. The increase in the third quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. Foractivity as a result of milder weather and derivative losses and for year-to-date 2019,2020 compared to the decrease iscorresponding period in 2019 primarily due to decreased commercial activity partially offset byas a result of warmer weather and a decrease in derivative gains. See "Segment Information – Wholesale Gas Services" herein for additional information.
Other natural gas revenues increased in the third quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases in customers at gas distribution operations and recovery of prior period hedge losses at gas marketing services.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
During Heating Season, natural gas usage and operating | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(45) | | (22.8) | | $(113) | | (20.6) |
In the third quarter 2020, other revenues are generally higher. Weather typically does not havewere $152 million compared to $197 million for the corresponding period in 2019. For year-to-date 2020, other revenues were $436 million compared to $549 million for the corresponding period in 2019. These decreases primarily relate to the wind-down of a significant net income impact other than during the Heating Season. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather. | | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter | | 2019
vs.
2018 | 2019
vs.
normal | | Year-to-Date | | 2019 vs. 2018 | 2019 vs. normal | | | Normal(*) | 2019 | 2018 | | (warmer) | (warmer) | | Normal(*) | 2019 | 2018 | | colder (warmer) | colder (warmer) | | Illinois | 61 |
| 2 |
| 49 |
| | (95.9 | )% | (96.7 | )% | | 3,740 |
| 3,958 |
| 3,858 |
| | 2.6 | % | 5.8 | % | | Georgia | 2 |
| — |
| — |
| | — |
| (100.0 | )% | | 1,568 |
| 1,298 |
| 1,542 |
| | (15.8 | )% | (17.2 | )% |
| | (*) | Normal represents the 10-year average from January 1, 2009 through September 30, 2018 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
Southern Company Gas hedged its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. The remaining impactssegment of weather on earnings were immaterial for all periods presented.
The following table provides the number of customers served by Southern Company Gas at September 30, 2019 and 2018:
| | | | | | | | | | | | September 30, | | | | | 2019 | | 2018 | | 2019 vs. 2018 | | | (in thousands, except market share %) | | (% change) | | Gas distribution operations | 4,208 |
| | 4,177 |
| | 0.7 | % | | Gas marketing services | | | | | | Energy customers(*) | 611 |
| | 685 |
| | (10.8 | )% | | Market share of energy customers in Georgia | 28.5 | % | | 29.2 | % | |
|
|
| | (*) | Gas marketing services' customers are primarily located in Georgia and Illinois. Also included as of September 30, 2018 were approximately 70,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018. |
Southern Company Gas anticipates overall customer growth trends at the four natural gas distribution utilities in gas distribution operations to continue as it expects continued improvementPowerSecure's distributed infrastructure business in the new housing market and low natural gas prices. Southern Company Gas uses a varietyfirst quarter 2020. Additionally, the year-to-date 2020 decrease reflects the sale of targeted marketing programs to attract new customers and to retain existing customers.
Other Revenues
| | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | (change in millions) | | (% change) | | (change in millions) | | (% change) | $— | | — | | $(55) | | N/M |
N/M - Not meaningful
Other revenues relate to revenues from Pivotal Home Solutions, which was soldPowerSecure's utility infrastructure services business in June 2018.July 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (139) | | | (13.0) | | $ | (646) | | | (22.8) | | Purchased power | (24) | | | (9.4) | | (14) | | | (2.2) | | Total fuel and purchased power expenses | $ | (163) | | | | | $ | (660) | | | |
In the third quarter 2020, total fuel and purchased power expenses were $1.2 billion compared to $1.3 billion for the corresponding period in 2019. The decrease was primarily the result of a $120 million decrease in the volume of KWHs generated and purchased and a $43 million decrease in the average cost of fuel and purchased power. For year-to-date 2020, total fuel and purchased power expenses were $2.8 billion compared to $3.5 billion for the corresponding period in 2019. The decrease was primarily the result of a $329 million decrease in the average cost of fuel and purchased power and a $331 million net decrease in the volume of KWHs generated and purchased. Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | Third Quarter 2020 | Third Quarter 2019 | Year-to-Date 2020 | Year-to-Date 2019 | Total generation (in billions of KWHs) | 50 | 54 | 132 | 143 | Total purchased power (in billions of KWHs) | 5 | 6 | 14 | 14 | Sources of generation (percent) — | | | | | | Gas | 52 | 54 | 53 | 51 | | Nuclear | 16 | 15 | 17 | 16 | | Coal | 24 | 24 | 17 | 23 | | Hydro | 2 | 1 | 5 | 4 | | Other | 6 | 6 | 8 | 6 | Cost of fuel, generated (in cents per net KWH)— | | | | | | Gas | 1.98 | 2.25 | 1.94 | 2.39 | | Nuclear | 0.78 | 0.79 | 0.78 | 0.79 | | Coal | 3.01 | 2.85 | 2.96 | 2.93 | Average cost of fuel, generated (in cents per net KWH) | 2.04 | 2.18 | 1.91 | 2.24 | Average cost of purchased power (in cents per net KWH)(*) | 4.94 | 4.78 | 4.53 | 4.75 |
(*)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. Fuel In the third quarter 2020, fuel expense was $0.9 billion compared to $1.1 billion for the corresponding period in 2019. The decrease was primarily due to a 10.0% decrease in the volume of KWHs generated by coal, a 12.0% decrease in the average cost of natural gas per KWH generated, and a 6.3% decrease in the volume of KWHs generated by natural gas, partially offset by a 5.6% increase in the average cost of coal per KWH generated. For year-to-date 2020, fuel expense was $2.2 billion compared to $2.8 billion for the corresponding period in 2019. The decrease was primarily due to a 30.3% decrease in the volume of KWHs generated by coal, an 18.8% decrease in the average cost of natural gas per KWH generated, and a 2.8% decrease in the volume of KWHs generated by natural gas, partially offset by a 1.0% increase in the average cost of coal per KWH generated. Purchased Power In the third quarter 2020, purchased power expense was $230 million compared to $254 million for the corresponding period in 2019. The decrease was primarily due to a 15.6% decrease in the volume of KWHs purchased, partially offset by a 3.3% increase in the average cost per KWH purchased. For year-to-date 2020, purchased power expense was $611 million compared to $625 million for the corresponding period in 2019. The decrease was primarily due to a 4.6% decrease in the average cost per KWH purchased. Cost of Natural Gas | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(8) | | (10.1) | | $(302) | | (31.6) |
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(25) | | (24.0) | | $(97) | | (9.2) |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) the natural gas distribution operations.utilities. Cost of natural gas at the natural gas distribution operationsutilities represented 80% and 85%and 86% of total cost of natural gas for the third quarter and year-to-date 2019,2020, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information. In the third quarter 2019,2020, cost of natural gas was $79$71 million compared to $104$79 million for the corresponding period in 2018. Excluding a $2 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $23 million. This2019. The decrease reflects a 23%an 11.3% decrease in natural gas prices and a decrease in the volume of natural gas sold in the third quarter 20192020 compared to the corresponding period in 2018.2019. For year-to-date 2019,2020, cost of natural gas was $956$654 million compared to $1.05 billion$956 million for the corresponding period in 2018. Excluding a $106 million2019. The decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $9 million. This increase reflects a 4.9% increase29.6% decrease in natural gas prices in the first quartercompared to 2019 partially offsetand decreased volumes primarily as a result of warmer weather, as determined by a decrease in the volume of natural gas soldHeating Degree Days, for year-to-date 20192020 compared to the corresponding period in 2018.2019. The following table details the volumes of natural gas sold during all periods presented.
| | | | | | | | | | | | | | | | | Third Quarter | 2019
vs.
2018 | | Year-to-Date | 2019
vs.
2018 | | | 2019 | 2018 | | 2019 | 2018 | Gas distribution operations (mmBtu in millions) | | | | | | | | Firm | 66 |
| 69 |
| (4.3 | )% | | 462 |
| 503 |
| (8.2 | )% | | Interruptible | 22 |
| 22 |
| — |
| | 68 |
| 71 |
| (4.2 | ) | Total(*) | 88 |
| 91 |
| (3.3 | )% | | 530 |
| 574 |
| (7.7 | )% | Wholesale gas services (mmBtu in millions/day) | | | | | | | | Daily physical sales | 6.3 |
| 6.8 |
| (7.4 | )% | | 6.3 |
| 6.7 |
| (6.0 | )% | Gas marketing services (mmBtu in millions) | |
| | | |
| | Firm: | | |
|
| | | |
|
| | Georgia | 3 |
| 3 |
| — | % | | 22 |
| 25 |
| (12.0 | )% | | Illinois | 1 |
| 1 |
| — |
| | 8 |
| 9 |
| (11.1 | ) | | Ohio | — |
| 1 |
| (100.0 | ) | | 8 |
| 12 |
| (33.3 | ) | | Other | 1 |
| 1 |
| — |
| | 3 |
| 3 |
| — |
| | Interruptible large commercial and industrial | 3 |
| 3 |
| — |
| | 10 |
| 10 |
| — |
| | Total | 8 |
| 9 |
| (11.1 | )% | | 51 |
| 59 |
| (13.6 | )% |
| | (*) | Includes total volumes of natural gas sold of 38 mmBtu for the nine months ended September 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" for additional information.
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Other Sales | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(42) | | (36.8) | | $(115) | | (36.4) |
In the third quarter 2020, cost of other sales was $72 million compared to $114 million for the corresponding period in 2019. For year-to-date 2020, cost of other sales was $201 million compared to $316 million for the corresponding period in 2019. These decreases primarily relate to the wind-down of a segment of PowerSecure's distributed infrastructure business in the first quarter 2020. Additionally, the year-to-date 2020 decrease reflects the sale of PowerSecure's utility infrastructure services business in July 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information. Other Operations and Maintenance Expenses | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(10) | | (0.8) | | $(113) | | (2.9) |
In the third quarter 2020, other operations and maintenance expenses were $1.29 billion compared to $1.30 billion for the corresponding period in 2019. The decrease primarily results from decreases of $38 million in transmission and distribution maintenance expenses, primarily at Alabama Power and Georgia Power, including $9 million of reliability NDR credits at Alabama Power, $23 million in scheduled generation outage and maintenance expenses, and $11 million in compliance and environmental expenses at the traditional electric operating companies, substantially offset by a $46 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP and an increase in employee compensation and benefit expenses. For year-to-date 2020, other operations and maintenance expenses were $3.8 billion compared to $3.9 billion for the corresponding period in 2019. The decrease reflects the impacts of cost containment activities implemented in 2020 to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. The decrease primarily results from decreases of $128 million in scheduled generation outage and maintenance expenses, $81 million in transmission and distribution expenses at the traditional electric operating companies, including $31 million of reliability NDR credits at Alabama Power, $37 million in compliance and environmental expenses at the traditional electric operating companies, and $21 million primarily related to the sale of PowerSecure's utility infrastructure services business in July 2019 and lighting business in December 2019, partially offset by a $138 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP and a $54 million increase in employee compensation and benefit expenses. The decrease was also due to a $32 million increase in nuclear property insurance refunds at Alabama Power and Georgia Power. See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" and "Georgia Power – Storm Damage Recovery" and Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Depreciation and Amortization | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $129 | | 17.0 | | $352 | | 15.5 |
In the third quarter 2020, depreciation and amortization was $889 million compared to $760 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $2.6 billion compared to $2.3 billion for the corresponding period in 2019. These increases primarily reflect increased amortization of regulatory assets related to CCR AROs of $51 million and $152 million for the third quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $133 million for the third quarter and year-to-date 2020, respectively, as authorized in Georgia Power's 2019 ARP. Also contributing to the increases were $45 million and $92 million increases in depreciation for the third quarter and year-to-date 2020, respectively, associated with additional plant in service. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan" in Item 8 of the Form 10-K for additional information. Estimated Loss on Plant Vogtle Units 3 and 4 | | | | | | | | | | | | | | | | | | | | | Third Quarter 20192020 vs. Third Quarter 20182019 | | Year-to-Date 20192020 vs. Year-to-Date 20182019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $— | | —N/M | | $(12)149 | | N/M |
N/M - Not meaningful In the second quarter 2020, an estimated probable loss of $149 million was recorded at Georgia Power to reflect its revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information. Impairment Charges | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(110) | | N/M | | $(142) | | N/M |
N/M - Not meaningful In the third quarter 2019, an asset impairment charge of $92 million was recorded at Southern Company Gas related to a natural gas storage facility in Louisiana. In the third quarter and year-to-date 2019, goodwill and asset impairment charges totaling $18 million and $50 million, respectively, were recorded related to the sale of PowerSecure's utility infrastructure services business and in contemplation of the sale of its lighting business. See Notes 3 and 15 to the financial statements under "Other Matters – Southern Company Gas – Natural Gas Storage Facilities" and "Southern Company," respectively, in Item 8 of the Form 10-K for additional information. (Gain) Loss on Dispositions, Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(6) | | N/M | | $(2,473) | | N/M |
N/M - Not meaningful For year-to-date 2020, gain on dispositions, net was $39 million compared to $2.5 billion for the corresponding period in 2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) preliminary gain on the sale of Gulf Power recorded in the first quarter 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Interest Expense, Net of Amounts Capitalized | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $9 | | 2.1 | | $49 | | 3.8 |
In the third quarter 2020, interest expense, net of amounts capitalized was $443 million compared to $434 million for the corresponding period in 2019. For year-to-date 2020, interest expense, net of amounts capitalized was $1.34 billion compared to $1.29 billion for the corresponding period in 2019. These increases were primarily due to an increase in average outstanding long-term borrowings primarily at the parent company. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 8 to the financial statements in Item 8 of the Form 10-K for additional information. Impairment of Leveraged Lease | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $— | | N/M | | $154 | | N/M |
N/M - Not meaningful For year-to-date 2020, an impairment charge of $154 million was recorded related to a leveraged lease investment at Southern Holdings. See Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company" herein for additional information. Other Income (Expense), Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $52 | | 85.2 | | $80 | | 33.5 |
In the third quarter 2020, other income (expense), net was $113 million compared to $61 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $319 million compared to $239 million for the corresponding period in 2019. These increases were primarily related to increases in non-service cost-related retirement benefits income of $30 million and $88 million for the third quarter and year-to-date 2020, respectively, as well as $12 million of additional benefits associated with a litigation settlement at Southern Power in the second quarter 2019. The year-to-date 2020 increase was partially offset by the $36 million gain on the litigation settlement that was recorded in the second quarter 2019. See Note 3 to the financial statements under "General Litigation Matters – Southern Power" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information. Income Taxes | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(74) | | (20.2) | | $(1,429) | | (76.3) |
In the third quarter 2020, income taxes were $293 million compared to $367 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $0.4 billion compared to $1.9 billion for the corresponding period in 2019. These decreases were primarily due to the flowback of excess deferred income taxes in 2020 as authorized in Georgia Power's 2019 ARP and lower pre-tax earnings. The year-to-date 2020 decrease also reflects the tax impacts of the sale of Gulf Power in 2019. See Notes 2, 3, and 15 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement," "Other Matters – Southern Company Gas – Natural Gas Storage Facilities," and "Southern Company," respectively, in Item 8 of the Form 10-K and Notes (B) and (G) to the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "Effective Tax Rate," respectively, herein for additional information. Net Income Attributable to Noncontrolling Interests | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $3 | | 12.0 | | $(23) | | (88.5) |
For year-to-date 2020, net income attributable to noncontrolling interests was $3 million compared to $26 million for the corresponding period in 2019. The change was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to a litigation settlement at Southern Power in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information. Alabama Power Net Income | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(25) | | (5.3) | | $40 | | 4.1 |
Alabama Power's net income after dividends on preferred stock for the third quarter 2020 was $444 million compared to $469 million for the corresponding period in 2019. This decrease was primarily due to a decrease in retail revenues associated with milder weather in the third quarter 2020 compared to the corresponding period in 2019 and lower customer usage, partially offset by a decrease in operations and maintenance expenses and an increase in non-service cost-related retirement benefits income. Alabama Power's net income after dividends on preferred stock for year-to-date 2020 was $1.02 billion compared to $0.98 billion for the corresponding period in 2019. This increase was primarily due to a decrease in operations and maintenance expenses, an increase in retail revenues associated with the impact of customer bill credits issued in 2019 related to Tax Reform, and an increase in non-service cost-related retirement benefits income. These increases to income were partially offset by decreases in retail revenues associated with milder weather in 2020 compared to the corresponding period in 2019 and lower customer usage. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information. Retail Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(119) | | (7.0) | | $(283) | | (6.6) |
In the third quarter 2020, retail revenues were $1.58 billion compared to $1.69 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $4.00 billion compared to $4.29 billion for the corresponding period in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Details of the changes in retail revenues were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Year-to-Date 2020 | | (in millions) | | (% change) | | (in millions) | | (% change) | | Retail – prior year | $ | 1,694 | | | | | $ | 4,286 | | | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | (9) | | | (0.5) | % | | 53 | | | 1.2 | % | | Sales decline | (9) | | | (0.5) | | | (54) | | | (1.3) | | | Weather | (51) | | | (3.0) | | | (104) | | | (2.4) | | | Fuel and other cost recovery | (50) | | | (3.0) | | | (178) | | | (4.1) | | | Retail – current year | $ | 1,575 | | | (7.0) | % | | $ | 4,003 | | | (6.6) | % |
Revenues associated with changes in rates and pricing decreased in the third quarter 2020 and increased year-to-date 2020 when compared to the corresponding periods in 2019. The third quarter 2020 decrease was due to a decrease in Rate CNP Compliance-related revenue. The year-to-date 2020 increase was primarily due to customer bill credits issued in the first quarter 2019 related to Tax Reform and an increase in year-to-date 2020 Rate CNP Compliance-related revenue. Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to social distancing and safer-at-home guidelines related to the COVID-19 pandemic and reluctance from consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 2.6% and 3.2% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to customer growth and an increase in average customer usage primarily due to the temporary suspension of customer disconnections for nonpayment and safer-at-home guidelines related to the COVID-19 pandemic. Weather-adjusted commercial KWH sales decreased 4.8% and 6.3% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 10.7% and 9.4% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession. Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to decreases in generation and the average cost of fuel. Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information. Wholesale Revenues – Affiliates | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $9 | | N/M | | $(30) | | (45.5) |
N/M - Not meaningful Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) For year-to-date 2020, wholesale revenues from sales to affiliates were $36 million compared to $66 million for the corresponding period in 2019. The decrease was primarily due to a 28.7% decrease in KWH sales as a result of decreased coal generation largely due to lower natural gas prices and a 22.5% decrease in the price of energy due to lower natural gas prices in 2020 compared to the corresponding period in 2019. Fuel and Purchased Power Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (4) | | | (1.3) | | | $ | (143) | | | (16.6) | | | Purchased power – non-affiliates | (13) | | | (16.9) | | | (7) | | | (4.4) | | | Purchased power – affiliates | (29) | | | (39.7) | | | (71) | | | (43.3) | | | Total fuel and purchased power expenses | $ | (46) | | | | | $ | (221) | | | |
In the third quarter 2020, total fuel and purchased power expenses were $414 million compared to $460 million for the corresponding period in 2019. The decrease was primarily due to a $54 million decrease in the volume of KWHs generated (excluding hydro) and purchased, partially offset by an $8 million net increase in the average cost of generation and purchased power. For year-to-date 2020, total fuel and purchased power expenses were $0.97 billion compared to $1.19 billion for the corresponding period in 2019. The decrease was primarily due to a $193 million decrease in the volume of KWHs generated (excluding hydro) and purchased and a $28 million net decrease in the average cost of generation and purchased power. Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information. Details of Alabama Power's generation and purchased power were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Third Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 | Total generation (in billions of KWHs) | 15 | | 15 | | 41 | | 43 | Total purchased power (in billions of KWHs) | 2 | | 4 | | 5 | | 8 | Sources of generation (percent) — | | | | | | | | | Coal | 47 | | 48 | | 38 | | 45 | | Nuclear | 25 | | 26 | | 28 | | 25 | | Gas | 24 | | 24 | | 23 | | 21 | | Hydro | 4 | | 2 | | 11 | | 9 | Cost of fuel, generated (in cents per net KWH) — | | | | | | | | | Coal | 2.86 | | 2.67 | | 2.78 | | 2.76 | | Nuclear | 0.76 | | 0.75 | | 0.76 | | 0.77 | | Gas | 1.80 | | 2.40 | | 1.96 | | 2.48 | Average cost of fuel, generated (in cents per net KWH) | 2.04 | | 2.10 | | 1.93 | | 2.15 | Average cost of purchased power (in cents per net KWH)(*) | 5.12 | | 4.35 | | 4.76 | | 4.40 |
(*)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Fuel In the third quarter 2020, fuel expense was $306 million compared to $310 million for the corresponding period in 2019. The decrease was primarily due to a 64.0% increase in the volume of KWHs generated by hydro and a 25.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by an 8.0% increase in the volume of KWHs generated by natural gas and a 7.1% increase in the average cost of coal per KWH generated. For year-to-date 2020, fuel expense was $721 million compared to $864 million for the corresponding period in 2019. The decrease was primarily due to a 21.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, an 18.6% decrease in the volume of KWHs generated by coal, and a 15.7% and an 8.5% increase in the volume of KWHs generated by hydro and nuclear, respectively. Purchased Power – Non-Affiliates In the third quarter 2020, purchased power expense from non-affiliates was $64 million compared to $77 million for the corresponding period in 2019. This decrease was primarily due to a 29.3% decrease in the amount of energy purchased due to milder weather in the third quarter 2020 as compared to the corresponding period in 2019, partially offset by a 14.1% increase in the average cost of purchased power per KWH as a result of fixed capacity costs for PPAs. Purchased Power – Affiliates In the third quarter 2020, purchased power expense from affiliates was $44 million compared to $73 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from affiliates was $93 million compared to $164 million for the corresponding period in 2019. These decreases were primarily due to reductions of 45.4% and 44.5%, respectively, in the amount of energy purchased due to milder weather during 2020 as compared to 2019. Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC. Other Operations and Maintenance Expenses | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(22) | | (5.4) | | $(143) | | (11.7) |
In the third quarter 2020, other operations and maintenance expenses were $387 million compared to $409 million for the corresponding period in 2019. For year-to-date 2020, other operations and maintenance expenses were $1.08 billion compared to $1.22 billion for the corresponding period in 2019. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. The decreases primarily result from decreases of $22 million and $100 million in generation expenses associated with scheduled outages and CNP Compliance-related expenses for the third quarter and year-to-date 2020, respectively. Also contributing were decreases of $15 million and $44 million in transmission and distribution maintenance expenses primarily related to reliability NDR credits for the third quarter and year-to-date 2020, respectively. Partially offsetting the third quarter 2020 decrease was a $13 million increase in bad debt expense. See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Other Income (Expense), Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $19 | | 172.7 | | $42 | | 116.7 |
In the third quarter 2020, other income (expense), net was $30 million compared to $11 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $78 million compared to $36 million for the corresponding period in 2019. These increases were primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information. Income Taxes | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(14) | | (9.7) | | $12 | | 4.1 |
In the third quarter 2020, income taxes were $130 million compared to $144 million for the corresponding period in 2019. This decrease was primarily due to lower pre-tax earnings and the finalization of the 2019 tax return. For year-to-date 2020, income taxes were $307 million compared to $295 million for the corresponding period in 2019. This increase was primarily due to higher pre-tax earnings. Georgia Power Net Income | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(66) | | (7.9) | | $(187) | | (11.7) |
Georgia Power's net income for the third quarter 2020 was $773 million compared to $839 million for the corresponding period in 2019. For year-to-date 2020, net income was $1.41 billion compared to $1.60 billion for the corresponding period in 2019. These decreases were primarily due to lower retail revenues associated with milder weather as compared to the corresponding periods in 2019 and decreased customer usage resulting from the COVID-19 pandemic, partially offset by related cost containment activities. The year-to-date decrease was also due to a $111 million after-tax charge in the second quarter 2020 related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the construction of Plant Vogtle Units 3 and 4. Retail Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(132) | | (5.1) | | $(311) | | (5.0) |
In the third quarter 2020, retail revenues were $2.44 billion compared to $2.57 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $5.87 billion compared to $6.18 billion for the corresponding period in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Details of the changes in retail revenues were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Year-to-Date 2020 | | (in millions) | | (% change) | | (in millions) | | (% change) | | Retail – prior year | $ | 2,567 | | | | | $ | 6,181 | | | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | 51 | | | 2.0 | % | | 260 | | | 4.2 | % | | Sales decline | (9) | | | (0.4) | | | (56) | | | (0.9) | | | Weather | (87) | | | (3.4) | | | (194) | | | (3.1) | | | Fuel cost recovery | (87) | | | (3.4) | | | (321) | | | (5.2) | | | Retail – current year | $ | 2,435 | | | (5.2) | % | | $ | 5,870 | | | (5.0) | % |
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2020, when compared to the corresponding periods in 2019. These increases were primarily due to an increase in revenue recognized under the Environmental Compliance Cost Recovery (ECCR) tariff effective January 1, 2020 as authorized in the 2019 ARP and the impacts of accruals in 2019 for customer refunds related to Tax Reform. The increase for year-to-date 2020 was also due to the rate pricing effects of decreased customer usage in the first and second quarters 2020. Partially offsetting these increases were lower contributions from commercial and industrial customers with variable demand-driven pricing. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information. Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to work-from-home policies related to the COVID-19 pandemic and reluctance of consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 4.0% and 4.1% in the third quarter and year-to-date 2020, respectively, when compared to corresponding periods in 2019 due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and work-from-home policies. Weather-adjusted commercial KWH sales decreased 5.2% and 5.6% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic. Weather-adjusted industrial KWH sales decreased 3.6% and 6.7% in the third quarter and year-to-date 2020, respectively, when compared to the corresponding periods in 2019 primarily as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession. Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 due to lower fuel and purchased power costs. Electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information. Wholesale Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(5) | | (12.8) | | $(22) | | (20.6) |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy. Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal costs. In the third quarter 2020, wholesale revenues were $34 million compared to $39 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues were $85 million compared to $107 million for the corresponding period in 2019. These decreases were primarily due to lower market demand largely resulting from the expiration of a non-affiliate PPA and lower energy prices. Fuel and Purchased Power Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (75) | | | (16.9) | | | $ | (306) | | | (27.0) | | | Purchased power – non-affiliates | (5) | | | (3.3) | | | 16 | | | 4.1 | | | Purchased power – affiliates | (8) | | | (5.3) | | | (67) | | | (14.6) | | | Total fuel and purchased power expenses | $ | (88) | | | | | $ | (357) | | | |
In the third quarter 2020, total fuel and purchased power expenses were $656 million compared to $744 million for the corresponding period in 2019. The decrease was due to decreases of $44 million each related to the average cost of fuel and purchased power and the net volume of KWHs generated and purchased. For year-to-date 2020, total fuel and purchased power expenses were $1.63 billion compared to $1.99 billion for the corresponding period in 2019. The decrease was due to a decrease of $239 million related to the average cost of fuel and purchased power and a net decrease of $118 million related to the volume of KWHs generated and purchased. Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Details of Georgia Power's generation and purchased power were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Third Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 | Total generation (in billions of KWHs) | 17 | | 19 | | 42 | | 48 | Total purchased power (in billions of KWHs) | 8 | | 8 | | 25 | | 23 | Sources of generation (percent) — | | | | | | | | | Gas | 48 | | 46 | | 53 | | 47 | | Nuclear | 24 | | 22 | | 27 | | 24 | | Coal | 26 | | 31 | | 15 | | 26 | | Hydro and other | 2 | | 1 | | 5 | | 3 | Cost of fuel, generated (in cents per net KWH) — | | | | | | | | | Gas | 2.14 | | 2.33 | | 2.12 | | 2.45 | | Nuclear | 0.81 | | 0.82 | | 0.81 | | 0.81 | | Coal | 3.19 | | 3.00 | | 3.31 | | 3.10 | Average cost of fuel, generated (in cents per net KWH) | 2.09 | | 2.20 | | 1.93 | | 2.21 | Average cost of purchased power (in cents per net KWH)(*) | 3.76 | | 4.20 | | 3.50 | | 4.22 |
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. Fuel In the third quarter 2020, fuel expense was $368 million compared to $443 million for the corresponding period in 2019. For year-to-date 2020, fuel expense was $0.83 billion compared to $1.13 billion for the corresponding period in 2019. The decreases for the third quarter and year-to-date 2020 were primarily due to decreases of 25.7% and 50.3%, respectively, in the volume of KWHs generated by coal and decreases of 8.2% and 13.5%, respectively, in the average cost of natural gas per KWH generated. Purchased Power – Affiliates For year-to-date 2020, purchased power expense from affiliates was $393 million compared to $460 million for the corresponding period in 2019. The decrease was primarily due to a decrease of 24.7% in the average cost per KWH purchased primarily resulting from lower energy prices, as well as the expiration of a PPA, partially offset by an increase of 5.8% in the volume of KWHs purchased as Georgia Power units generally dispatched at a higher cost than other Southern Company system resources. Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC. Other Operations and Maintenance Expenses | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $10 | | 2.1 | | $26 | | 1.9 |
In the third quarter 2020, other operations and maintenance expenses were $483 million compared to $473 million for the corresponding period in 2019. The increase was primarily due to increases of $46 million in storm damage recovery as authorized in the 2019 ARP and $7 million in employee benefit expenses, partially offset by decreases of $24 million in distribution- and transmission-related expenses and $11 million associated with generation
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) maintenance. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Also contributing to the offset was a decrease of $6 million in expenses from unregulated sales relatesassociated with new energy conservation projects. For year-to-date 2020, other operations and maintenance expenses were $1.41 billion compared to $1.39 billion for the corresponding period in 2019. The increase was primarily due to increases of $138 million in storm damage recovery as authorized in the 2019 ARP and $15 million in employee benefit expenses, partially offset by decreases of $42 million in distribution- and transmission-related expenses, $34 million associated with generation maintenance and scheduled outages, and $13 million associated with generation environmental projects. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Other expense reductions include a decrease of $15 million related to an adjustment in 2019 for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities, an $11 million increase in nuclear property insurance refunds, and a decrease of $9 million associated with workers compensation and legal expenses. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information. Depreciation and Amortization | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $108 | | 43.2 | | $331 | | 45.2 |
In the third quarter 2020, depreciation and amortization was $358 million compared to $250 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $1.06 billion compared to $0.73 billion for the corresponding period in 2019. These increases primarily reflect increased amortization of regulatory assets related to CCR AROs of $51 million and $152 million for the third quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $133 million for the third quarter and year-to-date 2020, respectively, as authorized in the 2019 ARP. Also contributing to the increases were $16 million and $52 million increases in depreciation for the third quarter and year-to-date 2020, respectively, associated with additional plant in service. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan" in Item 8 of the Form 10-K for additional information. Estimated Loss on Plant Vogtle Units 3 and 4 | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $— | | N/M | | $149 | | N/M |
N/M - Not meaningful In the second quarter 2020, an estimated probable loss of $149 million was recorded to reflect Georgia Power's revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information. Interest Expense, Net of Amounts Capitalized | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $3 | | 2.9 | | $18 | | 5.9 |
For year-to-date 2020, interest expense, net of amounts capitalized was $322 million compared to $304 million for the corresponding period in 2019. The increase was primarily due to a $32 million increase in interest expense associated with an increase in average outstanding long-term borrowings, partially offset by a $15 million increase
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) in amounts capitalized in connection with the construction of Plant Vogtle Units 3 and 4. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4. Other Income (Expense), Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $18 | | 50.0 | | $43 | | 38.1 |
In the third quarter 2020, other income (expense), net was $54 million compared to $36 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $156 million compared to $113 million for the corresponding period in 2019. The third quarter and year-to-date 2020 increases were primarily due to increases of $10 million and $32 million, respectively, in non-service cost-related retirement benefits income and increases in AFUDC equity of $5 million and $14 million, respectively, primarily associated with the construction of Plant Vogtle Units 3 and 4. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4. Income Taxes | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(83) | | (32.5) | | $(268) | | (57.5) |
In the third quarter 2020, income taxes were $172 million compared to $255 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $198 million compared to $466 million for the corresponding period in 2019. These decreases were primarily due to the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP and lower pre-tax earnings, which includes, for year-to-date 2020, the charge in the second quarter 2020 associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Nuclear Construction" and Note (G) to the Condensed Financial Statements herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement" in Item 8 of the Form 10-K for additional information. Mississippi Power Net Income | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $2 | | 3.1 | | $(1) | | (0.7) |
Mississippi Power's net income for the third quarter 2020 was $67 million compared to $65 million for the corresponding period in 2019. The increase was primarily due to a decrease in amortization associated with ECO Plan regulatory assets, a decrease in income taxes associated with the flowback of excess deferred income taxes, and a decrease in scheduled generation outage costs, partially offset by a decrease in revenues as a result of Pivotal Home Solutions,a base rate reduction that became effective for the first billing cycle of April 2020, as well as a decrease in customer usage due to the COVID-19 pandemic, and an increase in depreciation. For year-to-date 2020, net income was $138 million compared to $139 million for the corresponding period in 2019. The decrease was primarily due to a decrease in revenues as a result of a base rate reduction that became effective for the first billing cycle of April 2020, as well as a decrease in customer usage due to the COVID-19 pandemic,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) and an increase in depreciation, substantially offset by a decrease in amortization associated with ECO Plan regulatory assets and a decrease in income taxes associated with the flowback of excess deferred income taxes. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information. Retail Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(19) | | (7.6) | | $(39) | | (5.8) |
In the third quarter 2020, retail revenues were $232 million compared to $251 million for the corresponding period in 2019. For year-to-date 2020, retail revenues were $630 million compared to $669 million for the corresponding period in 2019. Details of the changes in retail revenues were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Year-to-Date 2020 | | | (in millions) | | (% change) | | (in millions) | | (% change) | | Retail – prior year | $ | 251 | | | | | $ | 669 | | | | | Estimated change resulting from – | | | | | | | | | Rates and pricing | (10) | | | (4.0) | % | | (15) | | | (2.2) | % | | Sales decline | (5) | | | (2.0) | | | (12) | | | (1.8) | | | Weather | (4) | | | (1.6) | | | (2) | | | (0.3) | | | Fuel and other cost recovery | — | | | — | | | (10) | | | (1.5) | | | Retail – current year | $ | 232 | | | (7.6) | % | | $ | 630 | | | (5.8) | % |
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to decreases in rates in accordance with the Mississippi Power Rate Case Settlement Agreement. The third quarter 2020 decrease was also due to a decrease in revenue associated with a tolling arrangement. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information. Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2020 when compared to the corresponding periods in 2019 largely due to lower overall customer usage resulting from work-from-home policies related to the COVID-19 pandemic and reluctance of consumers and businesses to resume pre-pandemic levels of activity. Weather-adjusted residential KWH sales increased 3.3% and 2.7% in the third quarter and year-to-date 2020, respectively, primarily due to customer growth and an increase in average customer usage as a result of changes in customer behavior and work-from-home policies in response to the COVID-19 pandemic. Weather-adjusted commercial KWH sales decreased 5.8% and 7.1% in the third quarter and year-to-date 2020, respectively, primarily due to lower customer usage resulting from changes in consumer and business behavior, including the temporary closure of casinos, in response to the COVID-19 pandemic. Industrial KWH sales decreased 7.9% and 3.6% in the third quarter and year-to-date 2020, respectively, as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession. Fuel and other cost recovery revenues decreased for year-to-date 2020 when compared to the corresponding period in 2019 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Wholesale Revenues – Non-Affiliates | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(3) | | (4.7) | | $(14) | | (7.9) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power" in Item 7 of the Form 10-K for additional information. For year-to-date 2020, wholesale revenues from sales to non-affiliates were $164 million compared to $178 million for the corresponding period in 2019. This decrease was primarily due to decreases in revenue from MRA customers as a result of lower fuel costs, milder weather, and decreased customer usage as a result of the COVID-19 pandemic, and from fewer opportunity sales. Wholesale Revenues – Affiliates | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(15) | | (29.4) | | $(27) | | (24.8) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost. In the third quarter 2020, wholesale revenues from sales to affiliates were $36 million compared to $51 million for the corresponding period in June 2018. 2019. This decrease was primarily due to an $8 million decrease associated with lower KWH sales and a $7 million decrease primarily associated with lower natural gas prices. For year-to-date 2020, wholesale revenues from sales to affiliates were $82 million compared to $109 million for the corresponding period in 2019. This decrease was primarily due to a $34 million decrease associated with lower natural gas prices, partially offset by a $7 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Fuel and Purchased Power Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (18) | | | (14.9) | | $ | (53) | | | (16.6) | | Purchased power | — | | | — | | 3 | | | 20.0 | | Total fuel and purchased power expenses | $ | (18) | | | | | $ | (50) | | | |
In the third quarter 2020, total fuel and purchased power expenses were $109 million compared to $127 million for the corresponding period in 2019. The decrease was primarily due to a $9 million decrease associated with the volume of KWHs generated and a $9 million decrease primarily related to the lower average cost of natural gas. For year-to-date 2020, total fuel and purchased power expenses were $284 million compared to $334 million for the corresponding period in 2019. The decrease was primarily due to a $47 million decrease related to the cost of fuel and purchased power primarily due to the lower average cost of natural gas. Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause. Details of Mississippi Power's generation and purchased power were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Third Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 | Total generation (in millions of KWHs) | 5,011 | | 5,554 | | 13,662 | | 14,125 | Total purchased power (in millions of KWHs) | 162 | | 161 | | 558 | | 403 | Sources of generation (percent) – | | | | | | | | | Coal | 11 | | 8 | | 6 | | 7 | | Gas | 89 | | 92 | | 94 | | 93 | Cost of fuel, generated (in cents per net KWH) – | | | | | | | | | Coal | 3.52 | | 3.88 | | 3.70 | | 3.98 | | Gas | 1.99 | | 2.16 | | 1.94 | | 2.29 | Average cost of fuel, generated (in cents per net KWH) | 2.16 | | 2.30 | | 2.06 | | 2.41 | Average cost of purchased power (in cents per net KWH) | 3.66 | | 3.96 | | 3.17 | | 3.84 |
Fuel In the third quarter 2020, fuel expense was $103 million compared to $121 million for the corresponding period in 2019. This decrease was primarily due to a 12.2% decrease in the volume of KWHs generated by natural gas, a 9.3% decrease in the average cost of coal per KWH generated, and a 7.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 24.7% increase in the volume of KWHs generated by coal. For year-to-date 2020, fuel expense was $266 million compared to $319 million for the corresponding period in 2019. This decrease was due to a 15.1% decrease in the average cost of natural gas per KWH generated, a 10.8% decrease in the volume of KWHs generated by coal, a 6.9% decrease in the average cost of coal per KWH generated, and a 2.0% decrease in the volume of KWHs generated by natural gas.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Other Operations and Maintenance Expenses | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(10) | | (13.9) | | $(2) | | (1.0) |
In the third quarter 2020, other operations and maintenance expenses were $62 million compared to $72 million for the corresponding period in 2019. The decrease was primarily due to a $6 million decrease associated with the Kemper IGCC primarily related to an increase in salvage proceeds and the settlement of litigation and a decrease of $3 million in scheduled generation outage costs. For year-to-date 2020, other operations and maintenance expenses were $202 million compared to $204 million for the corresponding period in 2019. The decrease was primarily due to an $8 million decrease associated with the Kemper IGCC primarily related to an increase in salvage proceeds, largely offset by increases of $3 million in certain employee compensation expenses deferred in 2019, $2 million in vegetation management expenses, and $2 million in scheduled generation outage costs. See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power – Kemper County Energy Facility" herein for additional information. Depreciation and Amortization | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(1) | | (2.1) | | $(9) | | (6.3) |
In the third quarter 2020, depreciation and amortization was $47 million compared to $48 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization was $135 million compared to $144 million for the corresponding period in 2019. These decreases were related to decreases in amortization of $5 million and $17 million in the third quarter and year-to-date 2020, respectively, primarily as a result of the ECO Plan regulatory assets being fully amortized in 2019, partially offset by amortization of a regulatory asset associated with an ARO. These decreases were partially offset by increases in depreciation of $4 million and $8 million in the third quarter and year-to-date 2020, respectively, primarily related to additional plant in service and an increase in depreciation rates in accordance with the Mississippi Power Rate Case Settlement Agreement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information. Interest Expense, Net of Amounts Capitalized | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(3) | | (17.6) | | $(7) | | (13.5) |
For year-to-date 2020, interest expense, net of amounts capitalized was $45 million compared to $52 million for the corresponding period in 2019. The decrease primarily resulted from a decrease in outstanding long-term borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Income Taxes | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(3) | | (20.0) | | $(7) | | (25.9) |
For year-to-date 2020, income taxes were $20 million compared to $27 million for the corresponding period in 2019. The decrease was primarily due to a decrease of $9 million associated with the flowback of excess deferred income taxes as a result of the Mississippi Power Rate Case Settlement Agreement. See Note (G) to the Condensed Financial Statements herein for additional information. Southern Power Net Income Attributable to Southern Power | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(12) | | (14.0) | | $(104) | | (32.9) |
Net income attributable to Southern Power for the third quarter 2020 was $74 million compared to $86 million for the corresponding period in 2019. The decrease was primarily due to reduced net income related to the disposition of Plant Mankato in the first quarter 2020. Net income attributable to Southern Power for year-to-date 2020 was $212 million compared to $316 million for the corresponding period in 2019. The decrease was primarily due to the gain on the sale of Plant Nacogdoches in the second quarter 2019 of $88 million after tax, partially offset by the gain on sale of Plant Mankato in the first quarter 2020 of $23 million after tax. In addition, the decrease reflects the reduced net income related to these dispositions. See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information. Operating Revenues | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(51) | | (8.9) | | $(190) | | (12.4) |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through the second quarter 2019 sale of Plant Nacogdoches), and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool. Natural Gas and Biomass Capacity and Energy Revenue Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment. Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Solar and Wind Energy Revenue Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein for additional information regarding Southern Power's PPAs. Operating Revenues Details Details of Southern Power's operating revenues were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Third Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 | | (in millions) | | PPA capacity revenues | $ | 116 | | | $ | 131 | | | $ | 297 | | | $ | 384 | | | PPA energy revenues | 319 | | | 339 | | | 794 | | | 857 | | | Total PPA revenues | 435 | | | 470 | | | 1,091 | | | 1,241 | | | Non-PPA revenues | 84 | | | 101 | | | 235 | | | 276 | | | Other revenues | 4 | | | 3 | | | 11 | | | 10 | | | Total operating revenues | $ | 523 | | | $ | 574 | | | $ | 1,337 | | | $ | 1,527 | |
In the third quarter 2020, total operating revenues were $523 million, reflecting a $51 million, or 9%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following: •PPA capacity revenues decreased $15 million, or 11%, due to the disposition of Plant Mankato in the first quarter 2020. •PPA energy revenues decreased $20 million, or 6%, due to a $29 million decrease in sales from natural gas facilities resulting from a $26 million decrease in the volume of KWHs sold due to reduced demand and a $3 million decrease in the average cost of fuel and purchased power. This decrease was partially offset by a $9 million increase in sales from a fuel cell project acquired in late 2019. •Non-PPA revenues decreased $17 million, or 17%, due to a $20 million decrease in the market price of energy, partially offset by a $3 million increase in the volume of KWHs sold through short-term sales. For year-to-date 2020, total operating revenues were $1.3 billion, reflecting a $190 million, or 12%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following: •PPA capacity revenues decreased $87 million, or 23%, primarily due to decreases of $60 million related to the dispositions of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in the first quarter 2020 and $24 million from the contractual expiration of an affiliate natural gas PPA. •PPA energy revenues decreased $63 million, or 7%, due to a $115 million decrease in sales from natural gas facilities resulting from a $64 million decrease in the volume of KWHs sold due to decreased demand and a $51 million decrease in the price of fuel and purchased power. This decrease was partially offset by increases of $22 million in sales primarily driven by the volume of KWHs generated by solar and wind facilities and $29 million in sales from a fuel cell project acquired in late 2019. •Non-PPA revenues decreased $41 million, or 15%, due to a $95 million decrease in the market price of energy, partially offset by a $54 million increase in the volume of KWHs sold through short-term sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Fuel and Purchased Power Expenses Details of Southern Power's generation and purchased power were as follows: | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | Third Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 | | (in billions of KWHs) | | Generation | 12.3 | 13.8 | | 34.3 | 35.7 | | Purchased power | 0.7 | 0.8 | | 2.3 | 2.5 | | Total generation and purchased power | 13.0 | 14.6 | | 36.6 | 38.2 | | | | | | | | Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.4 | 8.6 | | 21.9 | 22.3 |
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power. Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues. Details of Southern Power's fuel and purchased power expenses were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | Fuel | $ | (29) | | | (17.5) | | $ | (103) | | | (22.9) | | Purchased power | (7) | | | (26.9) | | (30) | | | (36.6) | | Total fuel and purchased power expenses | $ | (36) | | | | | $ | (133) | | | |
In the third quarter 2020, total fuel and purchased power expenses decreased $36 million, or 19%, compared to the corresponding period in 2019. Fuel expense decreased $29 million due to a $26 million decrease associated with the volume of KWHs generated and a $3 million decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $7 million due to a $6 million decrease associated with the average cost of purchased power and a $1 million decrease associated with the volume of KWHs purchased. For year-to-date 2020, total fuel and purchased power expenses decreased $133 million, or 25%, compared to the corresponding period in 2019. Fuel expense decreased $103 million due to a $97 million decrease in the average cost of fuel per KWH generated and a $6 million decrease associated with the volume of KWHs generated. Purchased power expense decreased $30 million due to a $22 million decrease associated with the average cost of purchased power and an $8 million decrease associated with the volume of KWHs purchased.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) (Gain) Loss on Dispositions, Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $— | | N/M | | $(16) | | N/M |
N/M - Not meaningful For year-to-date 2020, gain on dispositions, net was $39 million compared to $23 million for the corresponding period in 2019, reflecting the sale of Plant Mankato in the first quarter 2020 and the sale of Plant Nacogdoches in the second quarter 2019. See Note (K) to the Condensed Financial Statements herein and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sales of Natural Gas and Biomass Plants" for additional information. Interest Expense, Net of Amounts Capitalized | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(7) | | (16.3) | | $(13) | | (10.2) |
In the third quarter 2020, interest expense, net of amounts capitalized was $36 million compared to $43 million for the corresponding period in 2019. For year-to-date 2020, interest expense, net of amounts capitalized was $114 million compared to $127 million for the corresponding period in 2019. The decreases were primarily due to lower outstanding debt. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information. Other Income (Expense), Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $7 | | 116.7 | | $(29) | | (60.4) |
In the third quarter 2020, other income (expense), net was $13 million compared to $6 million for the corresponding period in 2019. The increase was primarily due to the resolution of certain contingencies in the third quarter 2020 associated with the Roserock solar facility litigation settlement in 2019. For year-to-date 2020, other income (expense), net was $19 million compared to $48 million for the corresponding period in 2019. The decrease was primarily due to a $36 million gain arising from the Roserock solar facility litigation settlement in the second quarter 2019, partially offset by the resolution of certain related contingencies in the third quarter 2020. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information. Income Taxes (Benefit) | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(5) | | (26.3) | | $68 | | 165.9 |
For year-to-date 2020, income tax expense was $27 million compared to a $41 million benefit for the corresponding period in 2019. The change was primarily due to a $75 million income tax benefit in 2019 resulting from ITCs recognized upon the sale of Plant Nacogdoches, partially offset by a decrease in income tax expense as a result of lower pre-tax earnings. See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Net Income Attributable to Noncontrolling Interests | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $3 | | N/M | | $(23) | | N/M |
For year-to-date 2020, net income attributable to noncontrolling interests was $3 million compared to $26 million for the corresponding period in 2019. The change was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information. Southern Company Gas Operating Metrics Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory, including Nicor Gas following the approval of a revenue decoupling mechanism for residential customers in its base rate case that concluded in 2019. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather. The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio. Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers. Seasonality of Results During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter. Net Income (Loss) | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $43 | | 148.3 | | $13 | | 3.7 |
In the third quarter 2020, net income was $14 million compared to a $29 million net loss for the corresponding period in 2019. This increase was primarily due to a $65 million after-tax impairment charge in 2019 related to a natural gas storage facility in Louisiana, partially offset by a $36 million decrease at wholesale gas services in 2020
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) as a result of lower commercial activity and derivative losses. Also contributing to the increase was a $9 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020. For year-to-date 2020, net income was $360 million compared to $347 million for the corresponding period in 2019. This increase was primarily due to a $65 million after-tax impairment charge in 2019 related to a natural gas storage facility in Louisiana and a $56 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020. The increase was partially offset by a $106 million decrease at wholesale gas services in 2020 primarily due to lower commercial activity and lower derivative gains. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information. Natural Gas Revenues, including Alternative Revenue Programs | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(21) | | (4.2) | | $(299) | | (11.2) |
In the third quarter 2020, natural gas revenues, including alternative revenue programs, were $477 million compared to $498 million for the corresponding period in 2019. For year-to-date 2020, natural gas revenues, including alternative revenue programs, were $2.4 billion compared to $2.7 billion for the corresponding period in 2019. Details of the changes in natural gas revenues, including alternative revenue programs, were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Year-to-Date 2020 | | (in millions) | | (% change) | | (in millions) | | (% change) | | Natural gas revenues – prior year | $ | 498 | | | | | $ | 2,661 | | | | | Estimated change resulting from – | | | | | | | | | Infrastructure replacement programs and base rate changes | 34 | | | 6.8 | % | | 153 | | | 5.7 | % | | Gas costs and other cost recovery | (8) | | | (1.6) | | | (298) | | | (11.2) | | | Weather | 2 | | | 0.4 | | | (6) | | | (0.2) | | | Wholesale gas services | (49) | | | (9.8) | | | (151) | | | (5.6) | | | | | | | | | | | Other | — | | | — | | | 3 | | | 0.1 | | | Natural gas revenues – current year | $ | 477 | | | (4.2) | % | | $ | 2,362 | | | (11.2) | % |
Revenues from infrastructure replacement programs and base rate changes increased in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs. See Note 2 to the financial statements under "Southern Company Gas – SaleRate Proceedings" in Item 8 of Pivotal Home Solutions"the Form 10-K for additional information. Revenues associated with gas costs and other cost recovery decreased in the third quarter and year-to-date 2020 compared to the corresponding periods in 2019 primarily due to lower natural gas prices. The year-to-date decrease also reflects lower sales volumes in 2020 compared to the corresponding period in 2019 primarily as a result of warmer weather. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Revenues from wholesale gas services decreased in the third quarter 2020 compared to the corresponding period in 2019 due to decreased commercial activity as a result of milder weather and derivative losses and for year-to-date 2020 compared to the corresponding period in 2019 primarily due to decreased commercial activity as a result of warmer weather and a decrease in derivative gains. See "Segment Information – Wholesale Gas Services" herein for additional information. Southern Company Gas hedged the majority of its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter | | 2020
vs.
normal | 2020
vs.
2019 | | Year-to-Date | | 2020
vs.
normal | 2020
vs.
2019 | | Normal(*) | 2020 | 2019 | | colder | colder | | Normal(*) | 2020 | 2019 | | (warmer) | (warmer) | | (in thousands) | | | | | (in thousands) | | | | | Illinois | 54 | | 54 | | 2 | | | — | % | N/M | | 3,773 | | 3,548 | | 3,958 | | | (6.0) | % | (10.4) | % | | Georgia | 2 | | 15 | | — | | | N/M | — | % | | 1,530 | | 1,294 | | 1,298 | | | (15.4) | % | (0.3) | % |
(*)Normal represents the 10-year average from January 1, 2010 through September 30, 2019 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. The following table provides the number of customers served by Southern Company Gas at September 30, 2020 and 2019: | | | | | | | | | | | | | | | | | | | September 30, | | | | 2020 | | 2019 | | 2020 vs. 2019 | | (in thousands, except market share %) | | (% change) | | Gas distribution operations | 4,258 | | | 4,208 | | | 1.2 | % | | Gas marketing services | | | | | | Energy customers(*) | 659 | | | 611 | | | 7.9 | % | | Market share of energy customers in Georgia | 28.9 | % | | 28.5 | % | | 1.4 | % | | | | | | | | | | | | |
(*)Gas marketing services' customers are primarily located in Georgia, Ohio, and Illinois. Also included as of September 30, 2020 were approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2020. Southern Company Gas anticipates continued customer growth as it expects continued low natural gas prices. The number of customers served by Southern Company Gas' natural gas distribution utilities at September 30, 2020 was positively impacted by the suspension of disconnections during the COVID-19 pandemic, which resulted in a higher than historical average year-over-year change. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers. Cost of Natural Gas | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(8) | | (10.1) | | $(302) | | (31.6) |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 80% and 86% of total cost
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) of natural gas for the third quarter and year-to-date 2020, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information. In the third quarter 2020, cost of natural gas was $71 million compared to $79 million for the corresponding period in 2019. This decrease reflects an 11.3% decrease in natural gas prices in the third quarter 2020 compared to the corresponding period in 2019. For year-to-date 2020, cost of natural gas was $654 million compared to $956 million for the corresponding period in 2019. This decrease reflects a 29.6% decrease in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather for year-to-date 2020 compared to the corresponding period in 2019. The following table details the volumes of natural gas sold during all periods presented. | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter | 2020 vs. 2019 | | Year-to-Date | 2020 vs. 2019 | | 2020 | 2019 | | 2020 | 2019 | Gas distribution operations (mmBtu in millions) | | | | | | | | Firm | 68 | | 66 | | 3.0 | % | | 425 | | 462 | | (8.0) | % | | Interruptible | 21 | | 22 | | (4.5) | | | 67 | | 68 | | (1.5) | | | Total | 89 | | 88 | | 1.1 | % | | 492 | | 530 | | (7.2) | % | Wholesale gas services (mmBtu in millions/day) | | | | | | | | Daily physical sales | 7.1 | | 6.3 | | 12.7 | % | | 6.8 | | 6.3 | | 7.9 | % | Gas marketing services (mmBtu in millions) | | | | | | | | Firm: | | | | | | | | | Georgia | 3 | | 3 | | — | % | | 21 | | 22 | | (4.5) | % | | Illinois | 1 | | 1 | | — | | | 6 | | 8 | | (25.0) | | | | | | | | | | | Ohio and other | 2 | | 1 | | 100.0 | | | 9 | | 11 | | (18.2) | | | Interruptible large commercial and industrial | 3 | | 3 | | — | | | 10 | | 10 | | — | | | Total | 9 | | 8 | | 12.5 | % | | 46 | | 51 | | (9.8) | % |
Other Operations and Maintenance Expenses | | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(8) | | (3.7) | | $(88) | | (12.1) |
| | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $9 | | 4.3 | | $54 | | 8.4 |
In the third quarter 2019,2020, other operations and maintenance expenses were $208$217 million compared to $216$208 million for the corresponding period in 2018. Excluding a $2 million decrease related to the Southern Company Gas Dispositions,2019. For year-to-date 2020, other operations and maintenance expenses decreased $6 million. This decrease waswere $696 million compared to $642 million for the corresponding period in 2019. These increases were primarily due to $21 million of disposition-related costs incurred during 2018, partially offset by increases of $11 millionin compensation and benefit expenses and pipeline repair, compliance, and maintenance activities. The year-to-date 2020 increase also reflects an increase in expenses passed through directly to customers and $4 million in pipeline compliance and maintenance activities.primarily related to bad debt.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Depreciation and Amortization | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $4 | | 3.3 | | $9 | | 2.5 |
For year-to-date 2019, other operations2020, depreciation and maintenance expenses were $642amortization was $368 million compared to $730$359 million for the corresponding period in 2018. Excluding a $65 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased $23 million. This decrease was primarily due to a $12 million one-time adjustment in 2018 for the adoption of a new paid time off policy, $29 million of disposition-related costs incurred during 2018, and a $16 million decrease in compensation and benefits costs, partially offset by increases of $8 million in pipeline compliance and maintenance activities and $14 million in expenses passed through directly to customers. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information. Depreciation and Amortization
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $2 | | 1.7 | | $(15) | | (4.0) |
For year-to-date 2019, depreciation and amortization was $359 million compared to $374 million for the corresponding period in 2018. Excluding a $27 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $12 million. This2019. The increase was primarily due to continued infrastructure investments at gas distribution operations, partially offset by accelerated depreciation related to assets retired in 2018.operations.
Taxes Other Than Income Taxes | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $2 | | 6.1 | | $(7) | | (4.3) |
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $1 | | 3.1 | | $4 | | 2.5 |
For year-to-date 2019,2020, taxes other than income taxes were $161$154 million compared to $157$161 million for the corresponding period in 2018. Excluding2019. The decrease primarily relates to a $6 million decrease related to the Southern Company Gas Dispositions,
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
taxes other than income taxes increased $10 million. This increase primarily reflects increases in Nicor Gas' invested capital tax as a result of increased infrastructure investments and increased revenue tax expenses as a result of higherlower natural gas revenues at Nicor Gas, both of whichGas. These revenue tax expenses are passed through directly to customers.customers and have no impact on net income.
Impairment Charges | | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $92 | | N/M | | $50 | | N/M |
N/M - Not meaningful | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(92) | | (100.0) | | $(92) | | (100.0) |
In the third quarter 2019, a $92 million impairment charge was recorded related to a natural gas storage facility in Louisiana. In the first quarter 2018, a goodwill impairment charge of $42 million was recorded in contemplation of the sale of Pivotal Home Solutions. See Note (C)3 to the Condensed Financial Statementsfinancial statements under "Other Matters – Southern Company Gas" herein and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information. (Gain) Loss on Dispositions, Net
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $353 | | N/M | | $317 | | N/M |
N/M - Not meaningful
As a result of the sales of ElizabethtownNatural Gas Elkton Gas, and Pivotal Utility Holdings in July 2018 and the final working capital adjustments for the sale of Pivotal Home Solutions, a $353 million gain on dispositions, net was recorded in the third quarter 2018. The year-to-date amount also reflects a $36 million pre-tax loss as a result of the sale of Pivotal Home Solutions recorded in the second quarter 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.
Earnings from Equity Method Investments
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $1 | | 2.9 | | $7 | | 6.5 |
For year-to-date 2019, earnings from equity method investments were $115 million compared to $108 million for the corresponding period in 2018 and reflect higher earnings from SNG as a result of rate increases implemented by SNG that became effective September 2018, partially offset by a $6 million pre-tax loss on the sale of Triton in May 2019. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Other Income (Expense), Net
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(1) | | (16.7) | | $(5) | | (23.8) |
For year-to-date 2019, other income (expense), net was $16 million compared to $21 million for the corresponding period in 2018. This decrease was primarily due to a contractor litigation settlement in the first quarter 2018. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP"Storage Facilities" in Item 8 of the Form 10-K for additional information.
Table of Contents | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(2) | | (5.7) | | $(9) | | (7.8) |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes (Benefit)
| | | | | | | | | Third Quarter 2019 vs. Third Quarter 2018 | | Year-to-Date 2019 vs. Year-to-Date 2018 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $(338) | | (107.0) | | $(414) | | (87.2) |
In the third quarter 2019, income tax benefit was $22For year-to-date 2020, earnings from equity method investments were $106 million compared to income tax expense of $316$115 million for the corresponding period in 2018. Excluding a $312 million2019. The decrease relatedprimarily relates to lower earnings at SNG due to lower demand and firm revenues, the sale of Atlantic Coast Pipeline in the first quarter 2020, and the sale of Triton in the second quarter 2019. See Note (E) to the Southern Company Gas Dispositions and a $27 million decreaseCondensed Financial Statements herein for an impairment charge related to a natural gas storage facility in Louisiana,additional information.
Other Income (Expense), Net | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $7 | | 140.0 | | $17 | | 106.3 |
In the third quarter 2020, other income taxes increased $1 million due to higher pre-tax earnings, partially offset by the impact of the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC. For year-to-date 2019, income taxes were $61(expense), net was $12 million compared to $475$5 million for the corresponding period in 2018. Excluding a $3632019. For year-to-date 2020, other income (expense), net was $33 million decrease relatedcompared to $16 million for the Southern Company Gas Dispositions and a $27 million decrease for an impairment charge related to a natural gas storage facilitycorresponding period in Louisiana, income taxes decreased $24 million. This decrease was2019. These increases were primarily due to an increaseincreases in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Income Taxes (Benefit) | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 vs. Third Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | $25 | | 113.6 | | $37 | | 60.7 |
In the third quarter 2020, income taxes were $3 million compared to a $22 million benefit for the corresponding period in 2019. For year-to-date 2020, income taxes were $98 million compared to $61 million for the corresponding period in 2019. These increases were primarily due to a decrease in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and higher pre-tax earnings. The year-to-date 2020 increase also includes the reversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sale of Triton, Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein for additional information on the natural gas storage facility and Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the Atlanta Gas Light stipulation reflecting the impacts of the Tax Reform Legislation. Also see Note (G) to the Condensed Financial Statements herein for additional information. Performance and Non-GAAP Measures Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and impairment charges, and (gain) loss on disposition, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from base rate changes, infrastructure replacement programs and capital projects, and customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein. Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.
Reconciliations of operating income to adjusted operating margin are as follows: | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | Third Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 | | (in millions) | | Operating Income | $ | 29 | | $ | (35) | | | $ | 490 | | $ | 451 | | Other operating expenses(a) | 377 | | 454 | | | 1,218 | | 1,254 | | Revenue taxes(b) | (10) | | (9) | | | (77) | | (85) | | | Adjusted Operating Margin | $ | 396 | | $ | 410 | | | $ | 1,631 | | $ | 1,620 | |
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and impairment charges. (b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | Third Quarter 2019 | Third Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 | | | (in millions) | | Operating Income | $ | (35 | ) | $ | 374 |
| | $ | 451 |
| $ | 810 |
| Other operating expenses(a) | 454 |
| 14 |
| | 1,254 |
| 986 |
| Revenue taxes(b) | (9 | ) | (8 | ) | | (85 | ) | (81 | ) | | Adjusted Operating Margin | $ | 410 |
| $ | 380 |
| | $ | 1,620 |
| $ | 1,715 |
|
| | (a) | Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, impairment charges, and (gain) loss on disposition. |
| | (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
Segment Information Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (M)(L) to the Condensed Financial Statements under "Southern"Southern Company Gas"Gas" herein for additional information. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Third Quarter 2019 | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss)(b) | | (in millions) | | (in millions) | | Gas distribution operations | $ | 412 | | | $ | 317 | | | $ | 46 | | | $ | 376 | | | $ | 294 | | | $ | 37 | | | Gas pipeline investments | 8 | | | 3 | | | 23 | | | 8 | | | 3 | | | 6 | | | Wholesale gas services | (51) | | | 11 | | | (45) | | | (3) | | | 11 | | | (9) | | | Gas marketing services | 21 | | | 27 | | | (3) | | | 21 | | | 28 | | | (4) | | | All other | 8 | | | 11 | | | (7) | | | 9 | | | 110 | | | (59) | | | Intercompany eliminations | (2) | | | (2) | | | — | | | (1) | | | (1) | | | — | | | Consolidated | $ | 396 | | | $ | 367 | | | $ | 14 | | | $ | 410 | | | $ | 445 | | | $ | (29) | |
(*)Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year-to-Date 2020 | | Year-to-Date 2019 | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | (in millions) | | (in millions) | | Gas distribution operations | $ | 1,448 | | | $ | 971 | | | $ | 284 | | | $ | 1,294 | | | $ | 895 | | | $ | 228 | | | Gas pipeline investments | 24 | | | 9 | | | 74 | | | 24 | | | 9 | | | 63 | | | Wholesale gas services | (20) | | | 39 | | | (45) | | | 122 | | | 40 | | | 61 | | | Gas marketing services | 163 | | | 85 | | | 59 | | | 163 | | | 90 | | | 54 | | | All other | 21 | | | 42 | | | (12) | | | 22 | | | 140 | | | (59) | | | Intercompany eliminations | (5) | | | (5) | | | — | | | (5) | | | (5) | | | — | | | Consolidated | $ | 1,631 | | | $ | 1,141 | | | $ | 360 | | | $ | 1,620 | | | $ | 1,169 | | | $ | 347 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2019 |
| Third Quarter 2018 |
| Adjusted Operating Margin(a) | | Operating Expenses(a) | | Net Income (Loss) | | Adjusted Operating Margin(a)(b) | | Operating Expenses(a)(b) | | Net Income (Loss)(b) | | | (in millions) | | (in millions) | | Gas distribution operations | $ | 376 |
|
| $ | 294 |
|
| $ | 37 |
|
| $ | 355 |
|
| $ | (80 | ) |
| $ | 74 |
| | Gas pipeline investments | 8 |
|
| 3 |
|
| 6 |
|
| 8 |
| | 3 |
| | 20 |
| | Wholesale gas services | (3 | ) |
| 11 |
|
| (9 | ) |
| (8 | ) |
| 14 |
|
| (18 | ) | | Gas marketing services | 21 |
|
| 28 |
|
| (4 | ) |
| 19 |
| | 28 |
| | (8 | ) | | All other | 9 |
|
| 110 |
|
| (59 | ) |
| 8 |
|
| 43 |
|
| (22 | ) | | Intercompany eliminations | (1 | ) |
| (1 | ) |
| — |
|
| (2 | ) |
| (2 | ) |
| — |
| | Consolidated | $ | 410 |
| | $ | 445 |
| | $ | (29 | ) | | $ | 380 |
| | $ | 6 |
| | $ | 46 |
|
| | (a) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
| | (b) | 2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | | | | | | | | Year-to-Date 2019 | | Year-to-Date 2018 | | | Adjusted Operating Margin(a) | | Operating Expenses(a) | | Net Income (Loss) | | Adjusted Operating Margin(a)(b) | | Operating Expenses(a)(b) | | Net Income (Loss)(b) | | | (in millions) | | (in millions) | | Gas distribution operations | $ | 1,294 |
| | $ | 895 |
| | $ | 228 |
| | $ | 1,341 |
| | $ | 540 |
| | $ | 290 |
| | Gas pipeline investments | 24 |
| | 9 |
| | 63 |
| | 24 |
| | 9 |
| | 68 |
| | Wholesale gas services | 122 |
| | 40 |
| | 61 |
| | 139 |
| | 50 |
| | 65 |
| | Gas marketing services | 163 |
| | 90 |
| | 54 |
| | 194 |
| | 209 |
| | (71 | ) | | All other | 22 |
| | 140 |
| | (59 | ) | | 23 |
| | 103 |
| | (58 | ) | | Intercompany eliminations | (5 | ) | | (5 | ) | | — |
| | (6 | ) | | (6 | ) | | — |
| | Consolidated | $ | 1,620 |
| | $ | 1,169 |
| | $ | 347 |
| | $ | 1,715 |
| | $ | 905 |
| | $ | 294 |
|
| | (a) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
| | (b) | 2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
Gas Distribution Operations Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments. With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weatherregulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. In July 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. Also in July 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table details the results of gas distribution operations in the third quarter and year-to-date 2019 compared to the corresponding periods in 2018, including and excluding the impact of the utilities sold in 2018.
| | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2019 | | Year-to-Date 2019 | | Favorable (Unfavorable) | Variance to Prior Period | Impact of Utilities Sold in 2018 | Variance Excluding Utilities Sold in 2018 | | Variance to Prior Period | Impact of Utilities Sold in 2018 | Variance Excluding Utilities Sold in 2018 | | | (in millions) | | (in millions) | | Adjusted Operating Margin | $ | 21 |
| $ | 6 |
| $ | 27 |
| | $ | (47 | ) | $ | 139 |
| $ | 92 |
| | Operating expenses | (374 | ) | 347 |
| (27 | ) | | (355 | ) | 272 |
| (83 | ) | | Other income (expense), net | 3 |
| — |
| 3 |
| | (4 | ) | — |
| (4 | ) | | Interest expense | (6 | ) | — |
| (6 | ) | | (10 | ) | (13 | ) | (23 | ) | | Income tax expense | 319 |
| (312 | ) | 7 |
| | 354 |
| (324 | ) | 30 |
| | Net Income | $ | (37 | ) | $ | 41 |
| $ | 4 |
| | $ | (62 | ) | $ | 74 |
| $ | 12 |
|
Third Quarter 2019 vs. Third Quarter 2018
In the third quarter 2019,2020, net income increased $4$9 million, or 12.1%24.3%, compared to the corresponding period in 2018.2019. The $27$36 million increase in adjusted operating margin primarily reflects additional revenue frombase rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs and a decrease in refunds associated with bad debt riders compared to the corresponding period in 2018.programs. The $27$23 million increase in operating expenses includes increases infor compensation costs,and benefit expenses passed through directly to customers, and expenses for pipeline compliancerepair and maintenance activities, as well as additionalhigher depreciation primarily due to additional assets placed in service. The $6$8 million increase in interest expense results from the issuance of first mortgage bonds at Nicor Gas.other income is primarily due to an increase in non-service cost-related retirement benefits income. Income tax expense decreased $7increased $12 million primarily due to an increasehigher pre-tax earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light in 2019 and lower pre-tax earnings.as authorized by the Georgia PSC. Year-to-Date 2019 vs. Year-to-Date 2018Fo
Forr year-to-date 2019,2020, net income increased $12$56 million or 5.6%24.6%, compared to the corresponding period in 2018.2019. The $92$154 million increase in adjusted operating margin primarily reflects additional revenue frombase rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs, and base rate increases, a decrease in refunds associated with bad debt riders, and the effectpartially offset by warmer weather, net of revenues deferred in 2018 as a result of the Tax Reform Legislation.weather normalization mechanisms. The $83$76 million increase in operating expenses includes increases infor compensation and benefit costs, expenses passed through directly to customers, and expenses for pipeline compliance and maintenance activities, as well as additionalbad debt costs passed through directly to customers. The increase also reflects higher depreciation primarily due to additional assets placed in service.service, partially offset by lower revenue tax expense. The $4$20 million decreaseincrease in other income (expense), net is primarily due to a contractor litigation settlement in the first quarter 2018. The $23 millionan increase in interest expense is primarily from the issuance of first mortgage bonds at Nicor Gas.non-service cost-related retirement benefits income. The $30$43 million decreaseincrease in income tax expense is primarily due to an increasehigher pre-tax earnings and a decrease in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light and lower pre-tax earnings.as authorized by the Georgia PSC.
See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information on Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively.information. Gas Pipeline Investments Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline PennEast Pipeline,(until its sale on March 24, 2020). See Notes (E) and a 50% joint ownership interest in the Dalton Pipeline. See Note (E)(K) to the Condensed Financial Statements under "Southern Company Gas" herein and Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter and year-to-date 2019,2020, net income decreased $14increased $17 million, or 70.0%283.3%, and $5 million, or 7.4%, respectively, compared to the corresponding periodsperiod in 2018. These decreases2019. This increase primarily relaterelates to an $18 million decrease in income taxes primarily related to a 2019 increase associated with changes in taxstate apportionment rates. For year-to-date 2020, net income increased $11 million, or 17.5%, compared to the corresponding period in 2019. This increase primarily relates to a $5 million decrease in interest expense, duenet of amounts capitalized and a $21 million decrease in income taxes primarily related to a 2019 increase associated with changes in state apportionment rates in 2019, partially offset by highera $15 million decrease in earnings fromprimarily at SNG. Wholesale Gas Services Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits. In the third quarter 2019,2020, net income increased $9income decreased $36 million, or 50.0%400.0%, compared to the corresponding period in 2018. This increase primarily relates to a $5 million increase in adjusted operating margin and a $3 million decrease in operating expenses. For year-to-date 2019, net income decreased $4 million, or 6.2%, compared to the corresponding period in 2018.2019. This decrease primarily relates to a $17$48 million decrease in adjusted operating margin, partially offset by a $10$12 million decrease in income tax expense due to lower pre-tax earnings. For year-to-date 2020, net income decreased $106 million, or 173.8%, compared to the corresponding period in 2019. This decrease primarily relates to a $142 million decrease in adjusted operating expenses.margin, partially offset by a $34 million decrease in income tax expense due to lower pre-tax earnings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Details of the changes in adjusted operating margin are provided in the table below. The decreases in operating expenses primarily reflect lower compensation and benefit expenses. | | | | Third Quarter 2019 | Third Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 | | Third Quarter 2020 | Third Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 | | | (in millions) | | (in millions) | | Commercial activity recognized | $ | 2 |
| $ | 33 |
| | $ | 43 |
| $ | 212 |
| Commercial activity recognized | $ | (23) | | $ | 2 | | | $ | (55) | | $ | 43 | | | Gain on storage derivatives | 2 |
| (3 | ) | | 7 |
| (2 | ) | | | Gain (loss) on storage derivatives | | Gain (loss) on storage derivatives | (21) | | 2 | | | (33) | | 7 | | | Gain (loss) on transportation and forward commodity derivatives | (4 | ) | (33 | ) | | 68 |
| (70 | ) | Gain (loss) on transportation and forward commodity derivatives | (7) | | (4) | | | 69 | | 68 | | | LOCOM adjustments, net of current period recoveries | — |
| — |
| | (6 | ) | — |
| LOCOM adjustments, net of current period recoveries | — | | — | | | — | | (6) | | | Purchase accounting adjustments to fair value inventory and contracts | (3 | ) | (5 | ) | | 10 |
| (1 | ) | Purchase accounting adjustments to fair value inventory and contracts | — | | (3) | | | (1) | | 10 | | | Adjusted operating margin | $ | (3 | ) | $ | (8 | ) | | $ | 122 |
| $ | 139 |
| Adjusted operating margin | $ | (51) | | $ | (3) | | | $ | (20) | | $ | 122 | |
Change in Commercial Activity The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generatedgenerated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur.occur. The decrease in commercial activity in the third quarter and year-to-date 20192020 compared to the corresponding periodperiods in 20182019 was primarily due to significant natural gas price volatility that resulted from prolonged coldwarmer-than-normal weather during 2018 coupled with low natural gas supply.conditions and tightening transportation spreads. Change in Storage and Transportation Derivatives Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 20192020 resulted in storage derivative gains.losses. Transportation and forward commodity derivative losses for the third quarter 2020 are a result of widening transportation spreads. Transportation and forward commodity derivative gains in 2019for year-to-date 2020 are primarily the result of narrowing transportation spreads due to supply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Withdrawal Schedule and Physical Transportation Transactions The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at September 30, 2019.2020. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) | | | | | | | | | | | | | | Storage withdrawal schedule | | | | | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) | | | (in mmBtu in millions) | | (in millions) | | (in millions) | | 2019 | 10 |
| | $ | 3 |
| | $ | — |
| | 2020 | 39 |
| | 15 |
| | (68 | ) | | Total at September 30, 2019 | 49 |
| | $ | 18 |
| | $ | (68 | ) |
| | | | | | | | | | | | | | | | | | | | Storage withdrawal schedule | | | | Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) | | (in mmBtu in millions) | | (in millions) | | (in millions) | | 2020 | 10 | | | $ | 10 | | | $ | (5) | | | 2021 and thereafter | 46 | | | 60 | | | (64) | | | Total at September 30, 2020 | 56 | | | $ | 70 | | | $ | (69) | |
| | (a) | At September 30, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.99 per mmBtu. |
| | (b) | Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. |
| | (c) | Represents the transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses previously recognized. |
(a)At September 30, 2020, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.72 per mmBtu. (b)Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. (c)Represents the transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses previously recognized. The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Gas Marketing Services Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions to American Water Enterprises LLC. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.
Third Quarter 2019 vs. Third Quarter 2018
In theFor the third quarter 2019,and year-to-date 2020, net loss decreased $4$1 million, or 25%, and net income increased $5 million, or 9%, respectively, compared to the corresponding periodperiods in 2018. This decrease2019. These changes primarily relatesrelate to a $2 million increase in adjusted operating margin and a $2 million decrease in income tax expense due to changes in state income tax apportionment factors in several states.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Year-to-Date 2019 vs. Year-to-Date 2018
For year-to-date 2019, net income increased $125 million compared to the corresponding period in 2018. This increase primarily relates to a $119 million decreasedecreases in operating expenses and a $35 million decrease in income tax expense, partially offset by a $31 million decrease in adjusted operating margin.
Excluding a $43 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, adjusted operating margin increased $12 million, which primarily reflects favorable margins and recovery of prior period hedge losses. Excluding a $116 million decrease attributable to the 2018 disposition of Pivotal Home Solutions that includes the related goodwill impairment charge, operating expense decreased $3 million due to lower amortization. Excluding a $39 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, income tax expense increased $4 million.expenses.
All Other All other includes natural gas storage businesses, fuels operations through the sale of Southern Company Gas' storage and fuels operations and itsinterest in Pivotal LNG on March 24, 2020, the investment in Triton through completion of its sale on May 29, 2019, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sale of its interest in Pivotal LNG. Third Quarter 2019 vs. Third Quarter 2018
In the third quarter 2019,2020, net loss increased $37decreased $52 million compared to the corresponding period in 2018.2019. This increasedecrease primarily reflects a $67$99 million increasedecrease in operating expenses and a $35 million decrease in income taxes. The increase in operating expenses was primarily duerelated to an impairment charge in 2019 related to a natural gas storage facility in Louisiana, and disposition-related costs incurred during 2018. The decreasepartially offset by a $42 million increase in income taxes is due to the impairment charge related to a natural gas storage facility in Louisiana,associated with changes in state income tax apportionment factorsrates in several states during 2019 and deferred tax expenses related to the enactment of the State of Illinois income tax legislation in 2018. See Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein for additional information on the natural gas storage facility. Year-to-Date 2019 vs. Year-to-Date 2018
For year-to-date 2019, net loss increased $1 million compared to the corresponding period in 2018. This increase primarily reflects a $37 million increase in operating expenses and a $45 million decrease in income taxes. The increase in operating expenses primarily reflects an impairment charge related to a natural gas storage facility in Louisiana, a one-time adjustment in the first quarter 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and a decrease in depreciation and amortization. The decrease in income taxes reflects lower taxes due to the impairment charge related to a natural gas storage facility in Louisiana, the reversal of a related federal income tax valuation allowance in connection with the sale of Triton deferred taxin 2019.
For year-to-date 2020, net loss decreased $47 million compared to the corresponding period in 2019. This decrease includes a $98 million decrease in operating expenses primarily related to an impairment charge in 2019 related to a natural gas storage facility in Louisiana and a $6 million increase in earnings from equity method investments primarily due to a pre-tax loss on the enactmentsale of the State of IllinoisTriton in 2019, partially offset by a $48 million increase in income tax legislation in 2018, and taxes associated with changes in state apportionment rates in 2019 and the reversal of a related federal income tax apportionment factorsvaluation allowance in several states during 2019. See Note (C)connection with the sale of Triton in 2019, a $3 million decrease in other income (expenses), and a $5 million increase in interest expense, net of amounts capitalized.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Segment Reconciliations Reconciliations of operating income to adjusted operating margin for the third quarter and year-to-date 20192020 and 20182019 are reflected in the following tables. See Note (M)(L) to the Condensed Financial Statements herein for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | (in millions) | | Operating Income (Loss) | $ | 95 | | $ | 5 | | $ | (62) | | $ | (6) | | $ | (3) | | $ | — | | $ | 29 | | Other operating expenses(a) | 327 | | 3 | | 11 | | 27 | | 11 | | (2) | | 377 | | Revenue tax expense(b) | (10) | | — | | — | | — | | — | | — | | (10) | | | Adjusted Operating Margin | $ | 412 | | $ | 8 | | $ | (51) | | $ | 21 | | $ | 8 | | $ | (2) | | $ | 396 | |
| | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2019 | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | (in millions) | | Operating Income (Loss) | $ | 82 | | $ | 5 | | $ | (14) | | $ | (7) | | $ | (101) | | $ | — | | $ | (35) | | Other operating expenses(a) | 303 | | 3 | | 11 | | 28 | | 110 | | (1) | | 454 | | Revenue tax expense(b) | (9) | | — | | — | | — | | — | | — | | (9) | | | Adjusted Operating Margin | $ | 376 | | $ | 8 | | $ | (3) | | $ | 21 | | $ | 9 | | $ | (1) | | $ | 410 | |
| | | | | | | | | | | | | | | | | | | | | | | | | Year-to-Date 2020 | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | (in millions) | | Operating Income (Loss) | $ | 477 | | $ | 15 | | $ | (59) | | $ | 78 | | $ | (21) | | $ | — | | $ | 490 | | Other operating expenses(a) | 1,048 | | 9 | | 39 | | 85 | | 42 | | (5) | | 1,218 | | Revenue tax expense(b) | (77) | | — | | — | | — | | — | | — | | (77) | | | Adjusted Operating Margin | $ | 1,448 | | $ | 24 | | $ | (20) | | $ | 163 | | $ | 21 | | $ | (5) | | $ | 1,631 | |
| | | | | | | | | | | | | | | | | | | | | | | | | Year-to-Date 2019 | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | (in millions) | | Operating Income (Loss) | $ | 399 | | $ | 15 | | $ | 82 | | $ | 73 | | $ | (118) | | $ | — | | $ | 451 | | Other operating expenses(a) | 980 | | 9 | | 40 | | 90 | | 140 | | (5) | | 1,254 | | Revenue tax expense(b) | (85) | | — | | — | | — | | — | | — | | (85) | | | Adjusted Operating Margin | $ | 1,294 | | $ | 24 | | $ | 122 | | $ | 163 | | $ | 22 | | $ | (5) | | $ | 1,620 | |
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and impairment charges. (b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2019 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) | | Operating Income (Loss) | $ | 82 |
| $ | 5 |
| $ | (14 | ) | $ | (7 | ) | $ | (101 | ) | $ | — |
| $ | (35 | ) | Other operating expenses(a) | 303 |
| 3 |
| 11 |
| 28 |
| 110 |
| (1 | ) | 454 |
| Revenue tax expense(b) | (9 | ) | — |
| — |
| — |
| — |
| — |
| (9 | ) | | Adjusted Operating Margin | $ | 376 |
| $ | 8 |
| $ | (3 | ) | $ | 21 |
| $ | 9 |
| $ | (1 | ) | $ | 410 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Third Quarter 2018 | | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | | (in millions) | | Operating Income (Loss) | $ | 435 |
| $ | 5 |
| $ | (22 | ) | $ | (9 | ) | $ | (35 | ) | $ | — |
| $ | 374 |
| Other operating expenses(a) | (72 | ) | 3 |
| 14 |
| 28 |
| 43 |
| (2 | ) | 14 |
| Revenue tax expense(b) | (8 | ) | — |
| — |
| — |
| — |
| — |
| (8 | ) | | Adjusted Operating Margin | $ | 355 |
| $ | 8 |
| $ | (8 | ) | $ | 19 |
| $ | 8 |
| $ | (2 | ) | $ | 380 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Year-to-Date 2019 | | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | | (in millions) | | Operating Income (Loss) | $ | 399 |
| $ | 15 |
| $ | 82 |
| $ | 73 |
| $ | (118 | ) | $ | — |
| $ | 451 |
| Other operating expenses(a) | 980 |
| 9 |
| 40 |
| 90 |
| 140 |
| (5 | ) | 1,254 |
| Revenue tax expense(b) | (85 | ) | — |
| — |
| — |
| — |
| — |
| (85 | ) | | Adjusted Operating Margin | $ | 1,294 |
| $ | 24 |
| $ | 122 |
| $ | 163 |
| $ | 22 |
| $ | (5 | ) | $ | 1,620 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Year-to-Date 2018 | | | Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated | | | (in millions) | | Operating Income (Loss) | $ | 801 |
| $ | 15 |
| $ | 89 |
| $ | (15 | ) | $ | (80 | ) | $ | — |
| $ | 810 |
| Other operating expenses(a) | 621 |
| 9 |
| 50 |
| 209 |
| 103 |
| (6 | ) | 986 |
| Revenue tax expense(b) | (81 | ) | — |
| — |
| — |
| — |
| — |
| (81 | ) | | Adjusted Operating Margin | $ | 1,341 |
| $ | 24 |
| $ | 139 |
| $ | 194 |
| $ | 23 |
| $ | (6 | ) | $ | 1,715 |
|
| | (a) | Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, impairment charges, and (gain) loss on disposition. |
| | (b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUTURE EARNINGS POTENTIAL TheEach Registrant's results of operations discussed above are not necessarily indicative of Southern Company Gas'its future earnings potential. In the third quarterRecent disposition activities described under "Acquisitions and year-to-date 2018,net income attributableDispositions" herein, in Note (K) to the Southern Company Gas Dispositions, excludingCondensed Financial Statements herein, and in Note 15 to the related goodwill impairment and gain on disposition, was $2 million and $5 million, respectively.financial statements in Item 8 of the Form 10-K will impact future earnings for the applicable Registrants. The level of Southern Company Gas'the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.
For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and commercial markets. Other major factors include completing construction of Plant Vogtle Units 3 and 4 and related cost recovery proceedings for Georgia Power and the ability to prevail against legal challenges associated with the Kemper County energy facility for Mississippi Power. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage. Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that have caused a global and national economic recession. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and global demand for goods and services and public policy responses of social distancing and closing non-essential businesses have further restricted economic activity. The drivers, speed, and depth of this economic contraction are unprecedented and have reduced energy demand across the Southern Company system's service territory, primarily in the commercial and industrial classes. The negative impacts, which started in late-March 2020, of the COVID-19 pandemic and related recession on the Southern Company system's retail electric sales began to improve in the middle of May 2020; however, retail electric revenues have declined slightly compared to 2019. Recovery is expected to continue for the remainder of 2020 and into 2021, but responses to the COVID-19 pandemic by both customers and governments could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction in the Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first nine months of 2020. The traditional electric operating companies have established installment payment plans to allow customers to repay over a period of time past due accounts resulting from the COVID-19 pandemic. See "Regulatory Matters" herein for additional information on the status of disconnections and the deferral of costs resulting from the COVID-19 pandemic at Georgia Power, Mississippi Power, and the natural gas distribution utilities. The ultimate outcome of these matters cannot be determined at this time. The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs, as well as regulatory matters, creditworthiness of customers, total electric generating capacity available in Southern Power's market areas, and Southern Power's ability to successfully remarket capacity as current contracts expire. In addition, renewable portfolio standards, transmission constraints, cost of generation from units within the Southern Company power pool, and operational limitations could influence Southern Power's future earnings. The level of future earnings for Southern Company Gas' primary business of distributing natural gas distribution and its complementary businesses in the gas pipeline investments, wholesale gas services, and gas marketing services sectors.sectors depends on numerous factors. These factors include Southern Company Gas'the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, its
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) and Southern Company Gas' ability to optimize its transportation and storage positions and its ability to re-contract storage rates at favorable prices. Future earnings will be driven by customer growth and are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Volatility The volatility of natural gas prices has a significantan impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of itsSouthern Company Gas' gas marketing services and wholesale gas services segmentsbusinesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are further delayed or not built, volatility could increase. See "Other Matters""Construction Programs" herein for additional information on permitting challenges experienced by the Atlantic Coast Pipeline and the PennEast Pipeline. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further,In addition, if the COVID-19 pandemic results in a continued economic conditions continue to improve, including the new housing market, thedownturn for a sustained period, demand for natural gas may increase, which may causedecrease, resulting in further downward pressure on natural gas prices to rise and drive higherlower volatility in the natural gas markets on a longer-term basis.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings. As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategy,strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly considersconsider and evaluatesevaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets.assets as part of their business strategies. DueFor additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Acquisitions and Dispositions See Note 15 to the seasonal naturefinancial statements in Item 8 of the natural gas businessForm 10-K and Note (K) to the Condensed Financial Statements herein for additional information. Alabama Power On August 31, 2020, Alabama Power completed the Autauga Combined Cycle Acquisition. See "Regulatory Matters – Alabama Power" herein and Note (K) to the Condensed Financial Statements under "Alabama Power" herein for additional information. Southern Power On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). Pre-tax income for Plant Mankato was immaterial for all periods presented.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other factorscustomary conditions to closing, including but not limited to, weather, regulation, competition, customer demand, and general economic conditions, the third quarter and year-to-date 2019 results are not necessarily indicativecommercial operation of the resultsfacility, which is expected to be expected for any other period. Environmental Matters
New or revised environmental laws and regulations could affect many areasoccur in the first quarter 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of Southern Company Gas' operations. The impact of any such changesthis matter cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered
On May 1, 2020, Southern Power purchased a controlling interest in rates onthe 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from Invenergy Renewables LLC. The facility's output is contracted under a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for natural gas.12-year PPA. See Note (C)(K) to the Condensed Financial Statements herein for additional information. Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the nine months ended September 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain. Southern Company Gas On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The loss associated with the transactions was immaterial. Southern Company Gas also expects to receive payments in February 2021 and September 2021 of $5 million each contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. See Note (K) to the Condensed Financial Statements under ""Southern Company Gas" herein for additional information. Environmental RemediationMatters " herein andSee MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "Environmental Remediation" herein, for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Laws and Regulations Water Quality On October 22, 2019,13, 2020, the EPA published the final effluent limitations guidelines reconsideration rule, which extends the latest applicability date to comply with the generally applicable limits for both flue gas desulfurization wastewater and the U.S. Army Corpsbottom ash transport water to December 31, 2025. The rule also provides exemptions for low utilization of Engineers jointly published a final rule that repealed the 2015 Waterselectric generating units and permanent cessation of the United States (WOTUS) rule. This final rule will be effective December 23, 2019 and will bring all states back under the pre-2015 regulations until a new WOTUS rule is finalized. A revised definition of WOTUS is anticipated to be finalized by the end of 2019.coal combustion. The impact of the WOTUSfinal rule on the traditional electric operating companies and SEGCO will depend on the contentincorporation of the finalrule redefining WOTUSthese new requirements into each generating unit's National Pollutant Discharge Elimination System permit and the outcome of any associated legal challenges and cannot be determined at this time. Regulatory MattersCoal Combustion Residuals
See Note 2On August 28, 2020, the EPA published the final Part A CCR Rule that requires facilities to cease placement of both CCR and non-CCR waste in unlined surface impoundments as soon as technically feasible, but no later than April 11, 2021. The rule allows extensions beyond April 11, 2021, provided certain conditions are met. Impacts to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Rate Proceedings
Nicor Gassystem are expected to be limited, as the traditional electric operating companies and SEGCO stopped sending coal ash from most of their generating units to unlined ponds in April 2019 and expect to stop sending coal ash from the remaining generating units within the timeframes allowed in the rule.
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 was based on a projected test year for the 12-month period ending September 30,June 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 was $180 million.
On October 2, 2019, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, including $65 million related to the recovery of investments under the Investing in Illinois program, based on a ROE of 9.73% and an equity ratio of 54.2%, which became effective October 8, 2019. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery. The Illinois Commission's order is subject to any rehearing request filed by any party to the proceeding within 30 days of service of the order on such party.
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, which was subsequently revised to $93 million. 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$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
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. Infrastructure expenditures incurred under these programs in the first nine months of 2019 were as follows:
| | | | | | | Utility | Program | Year-to-Date 2019 | | | | (in millions) | | Nicor Gas | Investing in Illinois(*) | $ | 334 |
| | Virginia Natural Gas | Steps to Advance Virginia's Energy (SAVE) | 32 |
| | Total | | $ | 366 |
|
| | (*) | In conjunction with the base rate case order issued by the Illinois Commission on October 2, 2019, Nicor Gas will be recovering the program costs incurred prior to September 30, 2019 through base rates. |
On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its SAVE program, which was approved by the Virginia Commission on September 25, 2019. The extension allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024 and increase its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a potential variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.
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. Southern Company Gas does not expect this new agreement to have a material impact on its financial statements.
Other Matters
Southern Company Gas is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Gas Pipeline Projects
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K and Notes 7 and 9 to the financial statements under
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Southern Company Gas – Equity Method Investments" and "Guarantees," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
In 2014, Southern Company Gas entered into a joint venture, whereby it holds a 5% ownership interest in the Atlantic Coast Pipeline, an interstate pipeline company which will develop and operate a 605-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with expected initial transportation capacity of 1.5 Bcf per day.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. The delays resulting from the permitting issues have impacted the cost and schedule for the project. As a result, total current project cost estimates have increased from between $7.0 billion and $7.8 billion ($350 million and $390 million for Southern Company Gas) to between $7.3 billion and $7.8 billion ($365 million and $390 million for Southern Company Gas), excluding financing costs. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.
Also in 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate a 118-mile natural gas pipeline between New Jersey and Pennsylvania. The expected initial transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly with public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York.
On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal court eminent domain authority over lands in which a state has property rights interests. The joint venture is pursuing appellate and other options and is evaluating further next steps.
The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, which could result in an impairment of one or both of Southern Company Gas' investments and could have a material impact on Southern Company Gas' financial statements.
Natural Gas Storage Facilities
See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana.
As of September 30, 2019, management no longer plans to obtain the core samples during 2020 that are necessary to determine the composition of the sheath surrounding the edge of the salt dome. Core sampling is a requirement of the Louisiana Department of Natural Resources to put the cavern back in service; as a result, the cavern will not return to service by 2021. This change in plan, which affects the future operation of the entire storage facility, resulted in a pre-tax impairment charge of $92 million ($65 million after-tax). Southern Company Gas will continue to monitor the pressure and overall structural integrity of the entire facility pending any future decisions regarding decommissioning.
Southern Company Gas has two other natural gas storage facilities located in California and Texas, which could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Sustained diminished natural gas storage values could trigger impairment of either of these natural gas storage facilities, which have a combined net book value of $328 million at September 30, 2019.
The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from thoseAlabama Power recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. Southern Company Gas' financial condition remained stable at September 30, 2019. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $897 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.
Net cash provided from operating activities totaled $1.0 billion for the first nine months of 2019, an increase of $313 million from the corresponding period in 2018. The increase was primarily due to the impacts of the Southern Company Gas Dispositions and the timing of collection of customer receivables, partially offset by the timing of vendor payments. Net cash used for investing activities totaled $989 million for the first nine months of 2019 primarily due to gross property additions related to utility capital expenditures and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, partially offset by proceeds from the sale of Triton. Net cash used for financing activities totaled $68 million for the first nine months of 2019 primarily due to repayments of commercial paper borrowings and long-term debt and a common stock dividend payment to Southern Company, partially offset by proceeds from the issuance of first mortgage bonds and capital contributions from Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2019 include an increase of $836 million in additional paid-in-capital related to capital contributions from Southern Company, an increase of $657 million in total property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs, a $383 million decrease in notes payable primarily related to net repayments of commercial paper borrowings, a $357 million decrease in securities due within one year, and a $172 million increase in long-term debt due to the issuance of first mortgage bonds. Other significant balance sheet changes include decreases of $465 million and $488 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold, a decrease of $184 million in customer accounts receivable, and a decrease of $158 million in unbilled revenues. Significant balance sheet changes for the first nine months of 2019 also include recording $92 million in operating lease right-of use assets and $91 million in
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
operating lease obligations related to the adoption of ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASU 2016-02.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through September 30, 2020. See "Sources of Capital" herein for additional information.
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; abnormal weather; construction delays (including due to judicial or regulatory action); and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
Southern Company Gas received a $400 million capital contribution from Southern Company in each of July 2019 and August 2019.
As of September 30, 2019, Southern Company Gas' current liabilities exceeded current assets by $52 million. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs.
At September 30, 2019, Southern Company Gas had $59 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2019 were as follows:
| | | | | | | | | | Company | Expires 2024 | | Unused | | | (in millions) | Southern Company Gas Capital(a) | $ | 1,250 |
| | $ | 1,245 |
| | Nicor Gas | 500 |
| | 500 |
| Total(b) | $ | 1,750 |
| | $ | 1,745 |
|
| | (a) | Southern Company Gas guarantees the obligations of Southern Company Gas Capital. |
| | (b) | Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. |
See Note 8 to the consolidated financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
In May 2019, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2019, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.
Southern Company Gas has substantial cash flow from operating activities and access to capital markets, including the commercial paper programs, and financial institutions to meet liquidity needs. Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | Short-Term Debt at September 30, 2019 | | Short-Term Debt During the Period(*) | | | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | | Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) | | Southern Company Gas Capital | $ | 189 |
| | 2.3 | % | | $ | 271 |
| | 2.6 | % | | $ | 435 |
| | Nicor Gas | 78 |
| | 2.1 |
| | 77 |
| | 2.4 |
| | 211 |
| | Total | $ | 267 |
| | 2.2 | % | | $ | 348 |
| | 2.5 | % | | |
| | (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2019. |
Southern Company Gas believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical natural gas purchases and sales, gas transportation and storage, and energy price risk management. The maximum potential collateral requirement under these contracts at September 30, 2019 was approximately $15 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.
On September 12, 2019, S&P upgraded the long-term issuer rating of Nicor Gas to A from A- and the senior secured debt rating of Nicor Gas to A+ from A and maintained the negative rating outlook.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Illinois Commission's October 2, 2019 approval of Nicor Gas' rate case increased its equity ratio from 52% to 54.2%. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for information on an additional requested equity ratio increase included in Atlanta Gas Light's rate case proceeding, which is expected to conclude in December 2019.
Financing Activities
The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of September 30, 2019, the non-principal components totaled $420 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds.
In August 2019, Southern Company Gas Capital repaid at maturity $300 million aggregate principal amount of 5.25% Senior Notes due 2019.
In August 2019, Nicor Gas issued $200 million aggregate principal amount of first mortgage bonds in a private placement. The proceeds will be used for the repayment of short-term debt, capital expenditures, and other corporate purposes. Nicor Gas entered into an agreement to issue an additional $100 million aggregate principal amount of first mortgage bonds on October 30, 2019.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Market Price Risk
Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the third quarter 2019. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas may manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment.
For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | Third Quarter 2019 | Third Quarter 2018 | | Year-to-Date 2019 | Year-to-Date 2018 | | | (in millions) | | Contracts outstanding at beginning of period, assets (liabilities), net | $ | (90 | ) | $ | (90 | ) | | $ | (167 | ) | $ | (106 | ) | | Contracts realized or otherwise settled | 7 |
| 6 |
| | 7 |
| 57 |
| Current period changes(a) | (13 | ) | (34 | ) | | 64 |
| (69 | ) | | Contracts outstanding at the end of period, assets (liabilities), net | $ | (96 | ) | $ | (118 | ) |
| $ | (96 | ) | $ | (118 | ) | | Netting of cash collateral | 166 |
| 189 |
| | 166 |
| 189 |
| Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 70 |
| $ | 71 |
|
| $ | 70 |
| $ | 71 |
|
| | (a) | Current period changes also include the fair value of new contracts entered into during the period, if any. |
| | (b) | Net fair value of derivative contracts outstanding excludes premium and the intrinsic value associated with weather derivatives, which were immaterial at September 30, 2019 and 2018. |
The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | Fair Value Measurements | | | | | September 30, 2019 | | | Total
Fair Value | | Maturity | | | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter | | | (in millions) | Level 1(a) | $ | (114 | ) | | $ | (22 | ) | | $ | (76 | ) | | $ | (16 | ) | Level 2(b) | 13 |
| | (3 | ) | | 17 |
| | (1 | ) | Level 3(c) | 5 |
| | 1 |
| | 7 |
| | (3 | ) | Fair value of contracts outstanding at end of period(d) | $ | (96 | ) | | $ | (24 | ) | | $ | (52 | ) | | $ | (20 | ) |
| | (a) | Valued using NYMEX futures prices. |
| | (b) | Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
| | (c) | Valued using a combination of observable and unobservable inputs. |
| | (d) | Excludes cash collateral of $166 million as well as an immaterial amount of premium and intrinsic value associated with weather derivatives at September 30, 2019. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
| | | | Note | | Page Number | A | | | B | | | C | | | D | | | E | | | F | | | G | | | H | | | I | | | J | | | K | | | L | | | M | | |
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
| | | Registrant | Applicable Notes | Southern Company | A, B, C, D, E, F, G, H, I, J, K, L, M | Alabama Power | A, B, C, D, F, G, H, I, J, K, L | Georgia Power | A, B, C, D, F, G, H, I, J, L | Mississippi Power | A, B, C, D, F, G, H, I, J, L | Southern Power | A, C, D, E, F, G, H, I, J, K, L | Southern Company Gas | A, B, C, D, E, F, G, H, I, J, K, L, M |
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)
(A) INTRODUCTION
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2019 and 2018. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
Recently Adopted Accounting Standards
In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. The registrants adopted the new standard effective January 1, 2019. See Note (L) for additional information and related disclosures.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Goodwill and Other Intangible Assets
Goodwill at September 30, 2019 and December 31, 2018 was as follows: | | | | | | | | | | At September 30, 2019 | At December 31, 2018 | | | (in millions) | | Southern Company | $ | 5,280 |
| $ | 5,315 |
| | Southern Company Gas: | | | | Gas distribution operations | $ | 4,034 |
| $ | 4,034 |
| | Gas marketing services | 981 |
| 981 |
| | Southern Company Gas total | $ | 5,015 |
| $ | 5,015 |
|
Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise. A goodwill impairment charge of $32 million was recorded in the second quarter 2019 in contemplation of the July 22, 2019 sale of PowerSecure's utility infrastructure services business. In the third quarter 2019, impairment charges of $2 million and $3 million were recorded to goodwill and other intangible assets, net, respectively, in contemplation of the sale of PowerSecure's lighting business, which is expected to occur in the fourth quarter 2019. See Note (K) under "Southern Company" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Other intangible assets were as follows:
| | | | | | | | | | | | | | | | | | | | | | | At September 30, 2019 | | At December 31, 2018 | | | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net | | | (in millions) | | (in millions) | | Southern Company | | | | | | | | | Other intangible assets subject to amortization: | | | | | | | | Customer relationships(a) | $ | 211 |
| $ | (110 | ) | $ | 101 |
| | $ | 223 |
| $ | (94 | ) | $ | 129 |
| Trade names(a) | 64 |
| (23 | ) | 41 |
| | 70 |
| (21 | ) | 49 |
| | Storage and transportation contracts | 64 |
| (60 | ) | 4 |
| | 64 |
| (54 | ) | 10 |
| PPA fair value adjustments(b) | 389 |
| (64 | ) | 325 |
| | 405 |
| (61 | ) | 344 |
| | Other | 12 |
| (8 | ) | 4 |
| | 11 |
| (5 | ) | 6 |
| | Total other intangible assets subject to amortization | $ | 740 |
| $ | (265 | ) | $ | 475 |
|
| $ | 773 |
| $ | (235 | ) | $ | 538 |
| | Other intangible assets not subject to amortization: | | | | | | | | | Federal Communications Commission licenses | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
| | Total other intangible assets | $ | 815 |
| $ | (265 | ) | $ | 550 |
| | $ | 848 |
| $ | (235 | ) | $ | 613 |
| | | | | | | | | | | Southern Power | | | | | | | | | Other intangible assets subject to amortization: | | | | | | | | PPA fair value adjustments(b) | $ | 389 |
| $ | (64 | ) | $ | 325 |
| | $ | 405 |
| $ | (61 | ) | $ | 344 |
| | | | | | | | | | | Southern Company Gas | | | | | | | | | Other intangible assets subject to amortization: | | | | | | | | | Gas marketing services | | | | | | | | | Customer relationships | $ | 156 |
| $ | (99 | ) | $ | 57 |
| | $ | 156 |
| $ | (84 | ) | $ | 72 |
| | Trade names | 26 |
| (9 | ) | 17 |
| | 26 |
| (7 | ) | 19 |
| | Wholesale gas services | | | | | | | | | Storage and transportation contracts | 64 |
| (60 | ) | 4 |
| | 64 |
| (54 | ) | 10 |
| | Total other intangible assets subject to amortization | $ | 246 |
| $ | (168 | ) | $ | 78 |
| | $ | 246 |
| $ | (145 | ) | $ | 101 |
|
| | (a) | The decrease in the gross carrying amount during the nine months ended September 30, 2019 primarily reflects the reclassification to held for sale. See Note (K) for additional information. |
| | (b) | The decrease in the gross carrying amount during the nine months ended September 30, 2019 reflects the sale of Plant Nacogdoches, partially offset by additional PPA fair value adjustments related to the acquisition of DSGP. See Note (K) under "Southern Power" for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
| | | | | | | | | | Three Months Ended | Nine Months Ended | | | September 30, 2019 | | | (in millions) | Southern Company(a) | $ | 14 |
| $ | 45 |
| Southern Power(b) | $ | 4 |
| $ | 14 |
| | Southern Company Gas |
|
| | | Gas marketing services | $ | 5 |
| $ | 17 |
| Wholesale gas services(b) | 2 |
| 6 |
| | Southern Company Gas total | $ | 7 |
| $ | 23 |
|
| | (a) | Includes $6 million and $20 million for the three and nine months ended September 30, 2019, respectively, recorded as a reduction to operating revenues. |
| | (b) | Recorded as a reduction to operating revenues. |
Restricted Cash
At December 31, 2018, Georgia Power had restricted cash related to the redemption of certain pollution control revenue bonds in January 2019. See Note (F) under "Financing Activities" for additional information. At both September 30, 2019 and December 31, 2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at September 30, 2019 and/or December 31, 2018:
| | | | | | | | | | | Southern Company | | Southern Company Gas | | | (in millions) | | At September 30, 2019 | | | | | Cash and cash equivalents | $ | 2,931 |
| | $ | 59 |
| | Restricted cash: | | | | | Other accounts and notes receivable | 3 |
| | 3 |
| | Total cash, cash equivalents, and restricted cash | $ | 2,935 |
| (*) | $ | 62 |
|
| | (*) | Total does not add due to rounding. |
| | | | | | | | | | | | | Southern Company | Georgia Power | Southern Company Gas | | | (in millions) | | At December 31, 2018 | | | | | Cash and cash equivalents | $ | 1,396 |
| $ | 4 |
| $ | 64 |
| | Cash and cash equivalents held for sale | 9 |
| — |
| — |
| | Restricted cash: | | | | | Restricted cash | — |
| 108 |
| — |
| | Other accounts and notes receivable | 114 |
| — |
| 6 |
| | Total cash, cash equivalents, and restricted cash | $ | 1,519 |
| $ | 112 |
| $ | 70 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Natural Gas for Sale
Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded an adjustment of $10 million for the nine months ended September 30, 2019 and no material adjustments for the remaining periods reported.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Nicor Gas had 0 inventory decrement at September 30, 2019.
Asset Retirement Obligations
See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding AROs.
Details of the AROs included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power at September 30, 2019 are shown in the following table. There were no material changes in the AROs of Georgia Power or Southern Power during the first nine months of 2019.
| | | | | | | | | | | | | Southern Company | Alabama Power | Mississippi Power | | | (in millions) | | Balance at December 31, 2018 | $ | 9,394 |
| $ | 3,210 |
| $ | 160 |
| | Liabilities incurred | 35 |
| — |
| 1 |
| | Liabilities settled | (223 | ) | (76 | ) | (28 | ) | | Accretion | 299 |
| 107 |
| 5 |
| | Cash flow revisions | 455 |
| 312 |
| 57 |
| | Balance at September 30, 2019 | $ | 9,960 |
| $ | 3,553 |
| $ | 195 |
|
During 2019, Alabama Power recorded increases totaling approximately $312$462 million to its AROs primarily related to the CCR Rule and the related state rule based onprimarily due to management's completion of closure designsa feasibility study and the related cost estimates during the second quarter 2020 for all but one of its ash pond facilities. In the second quarter 2019, Mississippi Power recorded anponds. Alabama Power's increase of approximately $58 million to its AROs related to the CCR Rule, primarilyalso reflects costs associated with the addition of a water treatment system to the design of another ash pond facility at Plant Greene County, which is jointly owned with Alabama Power.pond. The additional estimated
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainagedesign revisions, and dewatering system designs, and increaseschanges in the estimatedexpected volume of ash volumes. The cost estimate forhandling. During the remaining Alabamathird quarter 2020, Georgia Power completed an assessment of its plans to close the ash pond facility will be updated withinponds at all of its generating plants in compliance with the next 12 monthsCCR Rule and the change could be material.related state rule. The related cost estimates were further refined, including updates to long-term post-closure care requirements, market pricing, and timing of future cash outlays. As a result, in September 2020, Georgia Power recorded an increase of approximately $411 million to its AROs related to the CCR Rule and the related state rule. As further analysis is performed and additional details are developed with respect to ash pond closures, theThe traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically update their ARO cost estimates.as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available, and the changes could be material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(B) 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 September 30, 2019 and December 31, 2018 were as follows:
| | | | | | | | | | Regulatory Clause | Balance Sheet Line Item | September 30,
2019 | December 31,
2018 | | | | (in millions) | | Alabama Power | | | | | Rate CNP Compliance | Deferred under recovered regulatory clause revenues | $ | — |
| $ | 42 |
| | | Other regulatory liabilities, deferred | 55 |
| — |
| | Rate CNP PPA | Deferred under recovered regulatory clause revenues | 45 |
| 25 |
| Retail Energy Cost Recovery(*) | Deferred under recovered regulatory clause revenues | — |
| 109 |
| | | Other regulatory liabilities, deferred | 21 |
| — |
| | Natural Disaster Reserve | Other regulatory liabilities, deferred | 23 |
| 20 |
| | Georgia Power | | | | | Fuel Cost Recovery | Receivables – under recovered fuel clause revenues | $ | — |
| $ | 115 |
| | | Other deferred credits and liabilities | 1 |
| — |
| | Mississippi Power | | | | | Fuel Cost Recovery | Over recovered regulatory clause liabilities | $ | 18 |
| $ | 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
Petition for Certificate of Convenience and Necessity
On September 6, 2019, Alabama Power filed a petition for a CCN with the Alabama PSC for authorization to procure additional generating capacity through the turnkey construction of a new combined cycle facility and long-term contracts for the purchase of power from others, both as more fully described below, as well as the acquisition of an existing combined cycle facility in Autauga County, AL (Autauga Combined Cycle Acquisition). In addition, Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. This filing was predicated on the results of Alabama Power's 2019 IRP providedNote (B) to the Alabama PSC, which identified an approximately 2,400-MW resource need for AlabamaCondensed Financial Statements herein under "Georgia Power driven by the need for additional winter reserve capacity. See Note (K) under "Alabama Power" for additional information regarding the Autauga Combined Cycle Acquisition.
The procurement of these resources is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC. The completion of the Autauga Combined Cycle Acquisition is also subject to (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and (ii) approval by the FERC. All regulatory approvals are expected to be obtained by the end of the third quarter 2020.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On May 8, 2019, Alabama Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023.
The capital investment associated with the construction of Plant Barry Unit 8 and the Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.
Alabama Power also intends to procure through long-term PPAs approximately 640 MWs of additional generating capacity, which will consist of approximately 240 MWs of combined cycle generation expected to begin in 2020 and approximately 400 MWs of solar generation coupled with battery energy storage systems (solar/battery systems) expected to begin in 2022 through 2024. The terms of the agreements for the solar/battery systems permit Alabama Power to use the energy and retire the associated renewable energy credits (REC) in service of customers or to sell RECs, separately or bundled with energy.
Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 through its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through Rate RSE during the term of the existing power sales agreement and, on expiration of the agreement, through Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of Rate RSE. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K– Integrated Resource Plan" for additional information.
The ultimate outcome of these matters cannot be determined at this time. Construction Work in Progress Accounting Order
On October 1, 2019, the Alabama PSC acknowledged that Alabama Power would begin certain limited preparatory activities associated with Plant Barry Unit 8 construction to meet the target in-service date by authorizing Alabama Power to record the related costs as CWIP prior to the issuance of an order on the CCN petition. Should a CCN not be granted and Alabama Power does not proceed with the related construction of Plant Barry Unit 8, Alabama Power may transfer those costs and any costs that directly result from the non-issuance of the CCN to a regulatory asset which would be amortized over a five-year period. If the balance of incurred costs reaches 5% of the estimated in-service cost of the total project prior to issuance of an order on the CCN petition, Alabama Power will confer with the Alabama PSC regarding the appropriateness of additional authorization.
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, as modified on September 24, 2019, includes a three-year Alternate Rate Plan with requested rate increases totaling $560 million, $144 million, and $233 million effective January 1, 2020, January 1, 2021, and
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 | $ | 210 |
| $ | — |
| $ | — |
| | CCR AROs | 158 |
| 139 |
| 227 |
| | Environmental Compliance Cost Recovery | 163 |
| — |
| — |
| | Demand-Side Management | 12 |
| 1 |
| 1 |
| | Municipal Franchise Fee | 17 |
| 3 |
| 5 |
| Total(*) | $ | 560 |
| $ | 144 |
| $ | 233 |
|
| | (*) | 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 IRP, 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 IRP (Georgia Power 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 Georgia Power 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), 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. Additionally, approximately $295 million of net capitalized asset retirement costs were reclassified to a regulatory asset.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 September 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 timing of recovery of the related ARO costs will be determined in the Georgia Power 2019 Base Rate Case. The ultimate outcome of these matters cannot be determined at this time.
Also in the Georgia Power 2019 IRP, 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 $157 million at September 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 and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional informationinformation.
Regulatory Matters See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information. Alabama Power Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. Petition for Certificate of Convenience and Necessity On August 14, 2020, the Alabama PSC issued its order regarding Alabama Power's petition for a CCN, which authorized Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which occurred on August 31, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA, which began on September 1, 2020, and (iv) pursue up to approximately 200 MWs of cost-effective demand-side management and distributed energy resource programs. The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs. The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate (RGC) issued by the Alabama PSC in September 2015. The contracts proposed in the CCN petition expired on July 31, 2020. Any future requests for solar/battery systems will be evaluated under the RGC process. Energy Alabama, Gasp, Inc., and the Sierra Club filed petitions for reconsideration and rehearing with the Alabama PSC. Alabama PSC action on these petitions is expected by November 10, 2020. Upon issuance of a written order reflecting such action, affected parties would have 30 days to pursue an appeal through the State of Alabama court system.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Alabama Power expects to recover all approved costs associated with the CCN through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K. The ultimate outcome of these matters cannot be determined at this time. Rate ECR On August 7, 2020, the Alabama PSC issued an order authorizing Alabama Power to reduce its over-collected fuel balance by $100 million and return that amount to customers in the form of bill credits for the billing month of October 2020. Any portion of the $100 million undistributed following the bill credit process will remain in the Rate ECR regulatory liability for the benefit of customers. Rate NDR In the third quarter 2020, Alabama Power recorded $44 million against the NDR for damages incurred to its transmission and distribution facilities from Hurricane Sally. The NDR balance available for storm damages was $51 million as of September 30, 2020. If the balance falls below $50 million, a reserve establishment charge would be activated (and the ongoing reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. Georgia Power Georgia Power's AROs. Additionally,revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC rejectedPSC. Georgia Power currently recovers its costs from the regulated retail business through an alternate rate plan, which includes traditional base tariffs, Demand-Side Management tariffs, the ECCR tariff, and Municipal Franchise Fee tariffs. In addition, financing costs on certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a requestseparate fuel cost recovery tariff.
Rate Plans 2019 ARP In accordance with the terms of the 2019 ARP, on October 1, 2020, Georgia Power filed the following tariff adjustments to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginningbecome effective January 1, 2020 following2021 pending approval by the expiration of a wholesale PPA. Georgia Power may offer such capacity inPSC: •increase traditional base tariffs by approximately $120 million; •increase the wholesale market or to the retail jurisdiction in a future IRP. ECCR tariff by approximately $2 million; •decrease Demand-Side Management tariffs by approximately $15 million; and •increase Municipal Franchise Fee tariffs by approximately $4 million. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact ontime. 2013 ARP In 2019, Georgia Power's or Southern Company's financial statements. Theretail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia Power reduced regulatory assets by approximately $60 million and accrued refunds for retail customers of approximately $60 million. On September 1, 2020, the Georgia PSC also approvedauthorized Georgia Power to issue customers bill credits prior to final review of the 2019 Annual Surveillance Report by the staff of the Georgia PSC. Georgia Power issued the bill credits in October 2020.
Deferral of Incremental COVID-19 Costs On April 7, 2020 and June 2, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in Georgia Power's next base rate case. At September 30, 2020, the incremental costs deferred totaled approximately $38 million. The ultimate outcome of this matter cannot be determined at this time. Integrated Resource Plan On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time. Fuel Cost Recovery On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power further lowered fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023. Mississippi Power Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates. 2019 Base Rate Case On March 17, 2020, the Mississippi PSC approved the Mississippi Power Rate Case Settlement Agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019. Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment. Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) issueestablished common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021. Performance Evaluation Plan On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause. Deferral of Incremental COVID-19 Costs On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 26, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At September 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time. Municipal and Rural Associations Tariff On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020. Southern Company Gas The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. With the exception of Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation, energy efficiency plans, and bad debt. The natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which will mitigate potential increases in bad debt expense as a result of the COVID-19 pandemic. Nicor Gas fully recovers its bad debt expenses, both the gas and non-gas portions, through its purchased gas adjustment mechanism and separate bad debt rider. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms and the non-gas portion of bad debt expense through their base rates in accordance with established benchmarks. Atlanta Gas Light does not have material bad debt expense because its receivables are from Marketers, rather than end-use customers. Its tariff allows it to obtain credit security support from the Marketers in an amount equal to at least two times their estimated highest bill. Rate Proceedings On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of$49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments are expected to be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021. The ultimate outcome of these matters cannot be determined at this time. Deferral of Incremental COVID-19 Costs Atlanta Gas Light On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for proposals (RFP)customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for capacity beginningthe base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its future GRAM filings, which would impact rates starting on January 1, 2022. The ultimate outcome of this matter cannot be determined at this time. Nicor Gas On March 18, 2020, in 2022response to the COVID-19 pandemic, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or 2023penalties. In response to this order, on March 27, 2020, Nicor Gas and other utilities in 2026, 2027, or 2028; (ii) procure upIllinois filed their plans seeking cost recovery and providing more flexible credit and collection plans. On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. Nicor Gas resumed late payment fees on July 27, 2020 and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts through the special purpose rider, which will continue over a 24-month period. In response to an Illinois Commission request, Nicor Gas will continue to voluntarily suspend residential customer disconnections for non-payment through March 31, 2021. At September 30, 2020, Nicor Gas' related regulatory asset was $13 million. Virginia Natural Gas In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which expired on October 5, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At September 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Construction Programs Overview The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See "Nuclear Construction" herein for additional 2,210 MWsinformation. Also see Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power" for information regarding Alabama Power's construction of Plant Barry Unit 8. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See "Southern Power" herein, "Acquisitions and Dispositions – Southern Power" herein, and Note (K) to the Condensed Financial Statements under "Southern Power" herein, as well as Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K, for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable resourcesenergy facilities. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through competitive RFPs;their regulated rates. See "Southern Company Gas" herein for additional information regarding infrastructure improvement programs at the natural gas distribution utilities and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.the PennEast Pipeline construction project. See "Rate Plans"FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding the Georgia Power 2019 Base Rate Case.Registrants' capital requirements for their construction programs. 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 4.4, in which Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4.interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the 2two 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. 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 September 30, 2019(b) | (5.5 | ) | Remaining estimate to complete(a) | $ | 2.9 |
|
| | | | | | | (in billions) | Base project capital cost forecast(a)(b) | $ | 8.4 | | | Construction contingency estimate | 0.1 | | | | Total project capital cost forecast(a)(b) | Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million. |
| 8.5 | | Net investment as of September 30, 2020(b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.(6.9) | | Remaining estimate to complete(a) | $ | 1.6 | |
As(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $240 million, of which $71 million had been accrued through September 30, 2019,2020.
(b) Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $30$188 million of the construction contingency estimate was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program, and start-up; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.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$3.0 billion, of which $2.1$2.5 billion had been incurred through September 30, 2019.2020. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. As of June 30, 2020, assignments of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement, among other factors. As a result of these factors, Georgia Power established $115 million of additional construction contingency as of June 30, 2020 for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery. During the third quarter 2020, approximately $5 million of the construction contingency established in the second quarter 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support. 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. 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. 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, particularly in the installation of electrical and mechanical commodities, 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 aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approvedregulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. To support that strategy,Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values will continueduring 2020. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June through July, and continued to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not achieved at the levels anticipated, contributing to the June 30, 2020 allocation of, and increase significantly throughoutin, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan. To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. Through October 2020, the remainderproject has faced challenges in meeting the July 2020 aggressive site work plan targets including, but not limited to, overall construction and subcontractor labor productivity, which has resulted in a backlog of 2019activities and into 2020. To meetcompletion percentages below the July 2020 aggressive site work plan targets. In addition, while the number of active COVID-19 cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. After considering these increasing monthly targets, existing
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
craftthese extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity must improve and additionalproduction levels, including subcontractors, significantly improving and being sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, (particularlyparticularly electrical and pipefitter craft labor)labor,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates. As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), as well asany of which may require additional supervisionlabor and/or materials; or other issues could arise and other fieldchange the projected schedule and estimated cost. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support resources, mustactivities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be retainedbetween $70 million and deployed.$115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. 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. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On June 15, 2020, the NRC rejected Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. On August 10, 2020, the Atomic Safety and Licensing Board rejected the Blue Ridge Environmental Defense League's (BREDL) May 11, 2020 petition challenging a license amendment request. The staff of the NRC has issued the requested amendment to the combined construction and operating license for Plant Vogtle Unit 3. BREDL appealed the Atomic Safety and Licensing Board decision to the NRC. 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 $11$10 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) 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 thean 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 in 2018, 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'sMEAG Power'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 Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. OnIn January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. OnIn February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'sMEAG Power'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.Sheet (Global Amendments).
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above
NOTES TO THE CONDENSEDMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued) (UNAUDITED)
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 September 30, 2019,2020, Georgia Power had recovered approximately $2.1$2.5 billion of financing costs. Financing costs related to capital costs above $4.418 billion willare being recognized through AFUDC and are expected to be recovered through AFUDC;retail rates over the life of Plant Vogtle Units 3 and 4; 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 JanuaryOn October 1, 2019.2020, Georgia Power expects to file on November 1, 2019filed a request to decrease the NCCR tariff by approximately $65$142 million annually, effective January 1, 2020,2021, pending Georgia PSC approval. 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)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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) operational. The ROE reductions negatively impacted earnings by approximately $100$75 million in 20182019 and are estimated to have negative earnings impacts of approximately $70$145 million, $255 million, and $200 million in 20192020, 2021, and an aggregate of approximately $650 million from 2020 to 2022.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2022, respectively. 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 2two appeals. OnIn January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. OnIn October 29, 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. Georgia Power believesOn April 21, 2020, the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's andFulton County Superior Court granted Georgia Power's resultsmotion to dismiss the two appeals. The petitioners filed a notice of operations, financial condition, and liquidity.appeal of the dismissal on May 20, 2020, which was withdrawn on August 20, 2020. This matter is now concluded. The Georgia PSC has approved nineteen22 VCM reports covering the periodperiods through June 30, 2018,December 31, 2019, including total construction capital costs incurred through that date of $5.4$7.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds)customer refunds). On August 30, 2019, Georgia Power filed its twentieth VCM report concurrently with its twenty-firsttwenty-third VCM report with the Georgia PSC on August 31, 2020, which requestedreflects the capital cost forecast discussed above and requests approval of $1.2 billion$701 million of construction capital costs incurred from JulyJanuary 1, 20182020 through June 30, 2019.2020. In the nineteenth VCM, the Georgia PSC deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filedSee RISK FACTORS in Item 1A herein and in the Westinghouse bankruptcy proceedings. On June 20, 2019, Georgia Power, actingForm 10-K for itselfa discussion of certain risks associated with the licensing, construction, and as agent for the other Vogtle Owners, entered intooperation of nuclear generating units, including potential impacts that could result from a settlement agreement related to the administrative claim filedmajor incident at a nuclear facility anywhere in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power also requested approval of $21.5 million of associated expenditures previously deferred for approval by the Georgia PSC. The remaining $30.1 million deferred for approval was refunded to Georgia Power and credited to the total construction capital costs.world.
The ultimate outcome of these matters cannot be determined at this time. DOE Financing
Southern Power At September 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – DOE Loan Guarantee Borrowings"FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" in Item 87 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings"FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information, including applicable covenants, eventsinformation.
During the nine months ended September 30, 2020, Southern Power completed construction of default, mandatory prepayment events, and conditionsplaced in service the Reading wind facility, continued construction of the Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to borrowing. be between $475 million and $545 million for the facilities under construction. At September 30, 2020, total costs of construction incurred for these projects were $244 million and are included in CWIP. 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 rates 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
NOTES TO THE CONDENSEDMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued) (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected
COD | PPA Counterparties | PPA Contract Period | | Projects Completed During the Nine Months Ended September 30, 2020 | | Reading(a) | Wind | 200 | Osage and Lyon Counties, KS | May 2020 | Royal Caribbean Cruises LTD | 12 years | | Projects Under Construction as of September 30, 2020 | | | Skookumchuck(b) | Wind | 136 | Lewis and Thurston Counties, WA | November 2020 | Puget Sound Energy | 20 years | Garland Solar Storage(c) | Battery energy storage system | 88 | Kern County, CA | Second quarter 2021 | Southern California Edison | 20 years | Tranquillity Solar Storage(c) | Battery energy storage system | 72 | Fresno County, CA | Second quarter 2021 | Southern California Edison | 20 years |
the Mississippi PSC in February(a)In 2018, and reflecting the impactsSouthern Power purchased 100% of the Tax Reform Legislation. Pursuantmembership interests of the Reading facility pursuant to a joint development arrangement. At the MRA settlement agreement, wholesale base rates decreased $3.7time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million annually, effective January 1, 2019.and now owns 100% of the Class B membership interests.
Environmental Compliance Overview Plan
On(b)In October 24, 2019, Southern Power purchased 100% of the Mississippi PSC approved Mississippi Power's July 9, 2019 request formembership interests of the Skookumchuck facility pursuant to a Certificate of Public Convenience and Necessityjoint development arrangement. Southern Power expects to complete certain environmental compliance projects, primarily associated witha tax equity transaction upon commercial operation and retain 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 reflectedClass B membership interests. Shortly after the completed tax equity transaction, Southern Power may sell a noncontrolling interest in Mississippi Power's ARO liabilities. See Note 2these Class B membership interests to another partner. Southern Power would retain the financial statements under "Mississippi Power – Environmental Compliance Overview Plan"controlling ownership interest 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" 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 third quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $10 million ($7 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 $3 million for the remainder of 2019 and $2 million to $7 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 by year-end 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 andtime.
(c)Prior to commercial operation, Southern Company's financial statements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company Gas
Rate Proceedings
Nicor Gas
In November 2018, Nicor Gas filed a general base ratePower may enter into one or more partnerships, in which case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase was 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 impactsit would ultimately own less than 100% of the Tax Reform Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the StaffClass B membership interests, but would retain ownership 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 2 intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase was $180 million.
On October 2, 2019, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, including $65 million related to the recovery of investments under the Investing in Illinois program, based on a ROE of 9.73% and an equity ratio of 54.2%, which became effective October 8, 2019. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery. The Illinois Commission's order is subject to any rehearing request filed by any party to the proceeding within 30 days of service of the order on such party.
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, which was subsequently revised to $93 million. 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.controlling interest. 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 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Company Gas" in various infrastructure programs that update or expand its gas distribution systems to improve reliabilityItem 7 of the Form 10-K for additional information. Infrastructure Replacement Programs and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. Capital Projects 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. Infrastructure expenditures incurred under these programs in the first nine months of 2020 were as follows: | | | | | | | | | | Utility | Program | Year-to-Date 2020 | | | (in millions) | | Nicor Gas | Investing in Illinois | $ | 294 | | | Virginia Natural Gas | Steps to Advance Virginia's Energy (SAVE) | 37 | | | Total | | $ | 331 | |
On April 8,In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to amendimprove resiliency and extend its Stepsincrease the supply of natural gas delivered to Advance Virginia's Energy program, which was approved byenergy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission on September 25, 2019. The extension allowsissued an order requiring Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024
NOTES TO THE CONDENSEDMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued) (UNAUDITED)
and increase its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a potential variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million.
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
Open Access Transmission Tariff
See Note 2 to the financial statements under "FERC Matters "Southern Company Gas – Open Access Transmission Tariff"Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information. Pipeline Construction Projects On June 28, 2019,March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information. On February 20, 2020, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS andtwo-year extension for PennEast Pipeline to complete the traditional electric operating companies agreeingproject by January 19, 2022. In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an OATT rate reduction basedopinion on PennEast Pipeline's petition for a 10.6% ROE, with a retroactive effective datewrit of May 10, 2018, and a five-year moratorium on these partiescertiorari seeking changesits review of the appellate court's decision. Expected project costs related to the OATT formula rate.PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The termsultimate outcome of the OATT settlement agreement will notPennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on the financial statements of any of the traditional electric operating companies or Southern Company. Southern Company Gas
See Note (E) under "Southern Company Gas – Pipelines" and Note 2 to the financial statements under "FERC Matters – Southern Company Gas" in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
(C) CONTINGENCIESfinancial statements.
See NoteNotes 3 and 7 to the financial statements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information. Southern Power's Power Sales Agreements See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information relatingregarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to various lawsuitskeep or resell the renewable energy credits. During the first quarter 2020, Southern Power received $15 million from Pacific Gas & Electric Company (PG&E) in accordance with a November 2019 bankruptcy court order granting payment of certain transmission interconnections. PG&E emerged from bankruptcy on July 1, 2020 and other contingencies.Southern Power's PPAs and transmission interconnection agreements continue in effect unchanged. Tax Matters See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. On March 20, 2020 and April 9, 2020, the Treasury Department and the Internal Revenue Service issued Notices 2020-18 and 2020-23, respectively, providing relief to taxpayers by postponing to July 15, 2020 a variety of tax form filings and payment obligations that were due before July 15, 2020. Associated interest, additions to tax, and penalties for late filing or late payment were also suspended until July 16, 2020. These provisions had a modest positive impact on the Registrants' liquidity. However, Southern Power's expected utilization of tax credits in the first half of 2020 was delayed until July 15, 2020. General Litigation Matters Each registrant is subject to certain claimsThe Registrants are involved in various other matters being litigated and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
regulatory matters that could affect future earnings. The ultimate outcome of such pending or potential litigation or regulatory matters against each registrant Registrant
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein or in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant'sRegistrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential. The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time. Southern Company In January 2017, a securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges thatnames as defendants Southern Company, certain
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismisseddismissing certain claims against certain officers of Southern Company and Mississippi Power and dismisseddismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. On August 22,In the third quarter 2019, the court certified the plaintiffs' proposed class. On September 5, 2019,class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines. On August 15, 2020, the parties reached a settlement. On September 8, 2020, the plaintiffs filed a stipulation of settlement and motion for preliminary approval to resolve the case on a class-wide basis, which the court granted on October 1, 2020. The settlement amount will be paid entirely through existing insurance policies and is not expected to have a material impact on Southern Company's financial statements.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these 2two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On September 25, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. OnIn August 5, 2019, the court granted a motion filed by the plaintiff onin July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust. On September 30, 2020, the plaintiffs filed a status report noting the settlement of the securities class action and informing the court that the parties have scheduled mediation of this case later in the fourth quarter 2020. Southern Company believes these legal challenges have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Georgia Power In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari withone recent appeal, the Georgia Supreme Court which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Court of Appeals and remanded the case toand noted that the trial court for further proceedings.could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, onin February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton Countyand also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. OnAlso in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 23, 2019, the Georgia PSC issued an order that found and concluded that Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal with11, 2020, the Georgia Court of Appeals regardingvacated the Superior Court of Fulton County's February 2019 order.order granting conditional class certification. The Court of Appeals remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power believeseach filed motions for summary judgment on all claims and the plaintiffs' claims have no merit.plaintiffs renewed their motion for class certification. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditionala class certification will be upheld andcertified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The ultimate outcomeplaintiffs seek an unspecified amount of this matter cannot be determined at this time.monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Mississippi Power In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on 2two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In the first quarterMay 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. Ondenied Mississippi Power's and Southern Company's motions to dismiss. In September 27, 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in either of these proceedings could have a material impacteach filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's financial statements and an adverse outcome inmotions for summary judgment. During the third quarter 2020, the plaintiffs reduced their claim for damages to approximately $76 million. On October 12, 2020, the arbitration case could havepanel issued a material impactunanimous award in favor of Mississippi Power on Southern Company's financial statements. The ultimate outcome of these matters cannot be determined at this time.all claims. This matter is now concluded. In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the 3 currentthree then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint onin March 14, 2019. The amended complaint included 4four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power believes this legal challenge has no merit; however, anand the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, the court granted Mississippi Power's motion to dismiss the first amended complaint filed in 2019. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. On July 28, 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which includes the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements. See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information. Other Matters See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" in Item 7 of the Form 10-K for additional information. Southern Company See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through September 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax). If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill. Mississippi Power Kemper County Energy Facility See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information. 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 related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. 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. For year-to-date 2020, Mississippi Power recorded pre-tax (and after-tax) charges to income totaling $2 million primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $3 million for the remainder of 2020 and $10 million to $15 million annually for 2021 through 2025. In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement is expected to be treated as a finance lease for accounting purposes upon commencement.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) On September 3, 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request for property closeout certification under the contract related to the DOE grants received for the Kemper County energy facility, which enables Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. The execution of the agreement had no material impact on Mississippi Power's financial statements. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the $387 million of DOE grants received. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net, with a portion allocated to noncontrolling interests. As a result, Southern Power recognized a $12 million after-tax gain in the second quarter 2019.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $16 million and $23 million as of September 30, 2019 and December 31, 2018, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Southern Company Gas' environmental remediation liability was $278 million and $294 million as of September 30, 2019 and December 31, 2018, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected toit could have a material impact on the financial statements of Southern Company, Georgia Power, or Southern Company Gas.
Nuclear Fuel Disposal Costs
In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On June 12, 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible and no amounts will be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's Alabamaand Mississippi Power's or Georgia Power's net income is expected.financial statements.
Other Matters
Alabama Power
On May 17, 2019, the Alabama Department of Environmental Management (ADEM) issued a proposed administrative order assessing a penalty of $250,000 to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater and/or soils at Plant Gadsden. The order was finalized and Alabama Power paid the penalty on September 16, 2019.
On October 16, 2019, Alabama Power agreed to a consent order regarding a fish kill investigation. The consent order requires Alabama Power to pay approximately $50,000 to ADEM in civil penalties and approximately $172,000 to the Alabama Department of Conservation and Natural Resources in fish restocking costs. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committedagreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019,April 24, 2020, Mississippi Power and Gulf Power provided noticeamended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power thatto notify Gulf Power will retire its share of which generating unit it has selected for 100% ownership. The parties agreed not to select a specific unit by August 1, 2020 and are continuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the generating capacity of Plant Danielunits on January 15, 2024.an individual basis continue to be evaluated by Mississippi Power has the option to purchase Gulf Power'sand any transfer of ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remainswould be subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, includingapproval by the FERC and the Mississippi PSC, andPSC. The ultimate outcome of this matter cannot be determined at this time. See Note (K) under "Southern Company" for information regarding ACCOUNTING POLICIES Application of Critical Accounting Policies and Estimates The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the sale of Gulf Power. Southern Company Gas
See Note 3notes to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on the Registrants' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" in Item 7 of the Form 10-K under "Other Matters – for a complete discussion of the Registrants' critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4 (Southern Company Gas"and Georgia Power) In the second quarter 2018, Georgia Power revised its base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for information on a natural gas storage facility consistingtotal project capital cost forecast of two salt dome caverns$8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in Louisiana. Asrelated customer refunds). Through the second quarter 2020, assignments of September 30, 2019, management no longer plansconstruction contingency to obtain the core samples during 2020 that are necessary to determinebase capital cost forecast exceeded the composition ofamount originally established in the sheath surrounding the edge of the salt dome. Core sampling is a requirement of the Louisiana Department of Natural Resources to put the cavern back in service; assecond quarter 2018 by approximately $34 million. As a result, Georgia Power established $115 million of additional construction contingency as of June 30, 2020.
After considering the cavern will not return to service by 2021. This change in plan, which affectssignificant level of uncertainty that exists regarding the future operation of the entire storage facility, resulted in a pre-tax impairment charge of $92 million ($65 million after-tax). Southern Company Gas will continue to monitor the pressure and overall structural integrity of the entire facility pending any future decisions regarding decommissioning. Southern Company Gas has 2 other natural gas storage facilities located in California and Texas, which could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Sustained diminished natural gas storage values could trigger impairment of eitherrecoverability of these natural gas storage facilities, which have a combined net book value of $328 million at September 30, 2019.
Thecosts since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 and a total pre-tax charge to income of $149 million ($111 million after tax) in the second quarter 2020.
In July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. In October 2020, Southern Nuclear further extended milestone dates from the July 2020 aggressive site work plan. Achievement of these extended milestone dates depends on absenteeism rates continuing to normalize and overall construction productivity and production levels, including subcontractors, significantly improving and being sustained above
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, need to be added and maintained. Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively. The continuing effects of the COVID-19 pandemic and other factors could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. The ultimate impact of these matters on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information. Recently Issued Accounting Standards On March 12, 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which is currently expected to occur on December 31, 2021. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance provides the following optional expedients: (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic. The Registrants currently reference LIBOR for certain debt and hedging arrangements. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While existing effective hedging relationships are expected to continue, the Registrants will continue to evaluate the provisions of ASU 2020–04 and the impacts of transitioning to an alternative rate. The ultimate outcome of the transition cannot be determined at this time, but couldis not expected to have a material impact on the Registrants' financial statements. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note (J) to the Condensed Financial Statements under "Interest Rate Derivatives" herein for additional information. FINANCIAL CONDITION AND LIQUIDITY Overview See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at September 30, 2020. The Registrants have maintained adequate access to capital throughout 2020, including through a period of volatility in the short-term financial markets during the first quarter. As a precautionary measure, in the first quarter 2020, Southern Company'sCompany, Georgia Power, Mississippi Power, and Southern Company Gas'Gas increased their outstanding short-term debt while also increasing cash and cash equivalents by taking actions such as entering into new bank term loans, entering into and funding new committed and uncommitted credit facilities, and funding existing uncommitted credit facilities. During the third quarter 2020, most of these additional borrowings were repaid. No material changes occurred in the terms of the applicable Registrants' bank credit arrangements or their interest expense on short-term debt as a result of these actions. The Registrants have experienced no material counterparty credit losses as a result of the volatility in the financial statements.
NOTES TO THE CONDENSEDMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued) (UNAUDITED)
(D) REVENUE FROM CONTRACTS WITH CUSTOMERS
The registrants generate revenuesAnalysis of Cash Flows
Net cash flows provided from a variety(used for) operating, investing, and financing activities for the nine months ended September 30, 2020 and 2019 are presented in the following table: | | | | | | | | | | | | | | | | | | | | | Net cash provided from
(used for): | Southern Company | Alabama Power | Georgia
Power | Mississippi Power | Southern Power | Southern Company Gas | | (in millions) | | Nine Months Ended September 30, 2020 | | | | | | | | Operating activities | $ | 5,220 | | $ | 1,229 | | $ | 2,125 | | $ | 186 | | $ | 774 | | $ | 1,122 | | | Investing activities | (4,892) | | (1,591) | | (2,526) | | (200) | | 424 | | (973) | | | Financing activities | 1,077 | | 505 | | 867 | | (214) | | (1,060) | | (37) | | | | | | | | | | Nine Months Ended September 30, 2019 | | | | | | | | Operating activities | $ | 4,881 | | $ | 1,471 | | $ | 2,365 | | $ | 242 | | $ | 1,221 | | $ | 1,049 | | | Investing activities | (1,073) | | (1,439) | | (2,793) | | (198) | | 36 | | (989) | | | Financing activities | (2,392) | | 992 | | 765 | | (69) | | (1,070) | | (68) | |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of sources, somesecurities. Southern Company Net cash provided from operating activities increased $0.3 billion for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of which are excluded fromvendor payments as well as lower income tax payments, partially offset by the scopetiming of ASC 606, Revenue from Contracts with Customers (ASC 606), such as leases, derivatives,receivable collections and certain cost recovery mechanisms.customer bill credits issued in 2020 by Alabama Power and Georgia Power. See Note 12 to the financial statements under "Recently Adopted Accounting Standards – Revenue""Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K for additional information oninformation. The net cash used for investing activities for the adoptionnine months ended September 30, 2020 was primarily due to the Subsidiary Registrants' construction programs, partially offset by proceeds from the sale transactions described in Note (K) to the Condensed Financial Statements herein. The net cash provided from financing activities for the nine months ended September 30, 2020 was primarily due to net issuances of ASC 606long-term debt, partially offset by common stock dividend payments and net repayments of short-term bank debt and commercial paper. Alabama Power Net cash provided from operating activities decreased $242 million for revenue from contracts with customersthe nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to payments related to ARO settlements, purchases of materials and supplies, and Rate RSE customer refunds. See Note 12 to the financial statements under "Revenues""Alabama Power – Rate RSE" in Item 8 of the Form 10-K and "Other Taxes"Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to gross property additions. The net cash provided from financing activities for the nine months ended September 30, 2020 was primarily due to capital contributions from Southern Company and a long-term debt issuance, partially offset by common stock dividend payments. Georgia Power Net cash provided from operating activities decreased $240 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to higher income tax payments and customer bill credits issued in 2020 associated with Tax Reform and 2018 earnings in excess of the allowed retail ROE range, partially offset by the timing of vendor payments. See Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information oninformation. The net cash used for investing activities for the revenue policiesnine months ended September 30, 2020 was primarily due to gross property additions, including approximately $1.0 billion related to the construction of the registrants. ForPlant Vogtle Units 3 and 4. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information on revenues accountedconstruction of Plant Vogtle Units 3 and 4. The net cash provided from financing activities for under other accounting guidance, see Notes (J)the nine months ended September 30, 2020 was primarily due to capital contributions from Southern Company, net issuances of senior notes, and (L)borrowings from the FFB for energy-related derivative contractsconstruction of Plant Vogtle Units 3 and lessor revenues, respectively, Note 14, partially offset by common stock dividend payments and net repayment of short-term borrowings. Mississippi Power Net cash provided from operating activities decreased $56 million for the nine months ended September 30, 2020 as compared to the financial statementscorresponding period in 2019 primarily due to the timing of vendor payments, decreased fuel cost recovery, and higher income tax payments. The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to gross property additions. The net cash used for financing activities for the nine months ended September 30, 2020 was primarily due to the repayment of senior notes at maturity, redemption of pollution control revenue bonds, and repayment of short-term borrowings, partially offset by debt issuances and capital contributions from Southern Company. Southern Power Net cash provided from operating activities decreased $447 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to a reduction in the utilization of tax credits in 2020. The net cash provided from investing activities for the nine months ended September 30, 2020 was primarily due to proceeds from the disposition of Plant Mankato, partially offset by the acquisition of the Beech Ridge II wind facility and ongoing construction activities. See Note (K) to the Condensed Financial Statement under "Revenues"Southern Power" herein for additional information. The net cash used for financing activities for the nine months ended September 30, 2020 was primarily due to net repayments of short-term bank debt and commercial paper, the repayment of senior notes at maturity, distributions to non-controlling interests, and common stock dividend payments, partially offset by contributions from non-controlling interests.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Southern Company Gas Net cash provided from operating activities increased $73 million for the nine months ended September 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of vendor payments, partially offset by the timing of customer receivable collections. The net cash used for investing activities for the nine months ended September 30, 2020 was primarily due to construction of transportation and distribution assets recovered through base rates and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method investments, partially offset by proceeds from the sale of interests in Pivotal LNG and Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information. The net cash used for financing activities for the nine months ended September 30, 2020 was primarily due to net repayments of short-term borrowings and common stock dividend payments, partially offset by debt issuances and capital contributions from Southern Company. Significant Balance Sheet Changes Southern Company Significant balance sheet changes for the nine months ended September 30, 2020 included: •an increase of $5.2 billion in long-term debt (including amounts due within one year) related to new issuances; •an increase of $3.3 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs; •a decrease of $1.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper; •an increase of $1.4 billion in cash and cash equivalents primarily related to Southern Company's redemption of $1.0 billion of junior subordinated notes in October 2020; •increases of $0.9 billion and $0.8 billion in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates at Alabama Power and Georgia Power for ash pond facilities; •a decrease of $0.8 billion in assets held for sale related to the completion of Southern Power's sale of Plant Mankato and Southern Company Gas' sale of its interests in Pivotal LNG and Atlantic Coast Pipeline; and •an increase of $0.5 billion in accumulated deferred income taxes related to the utilization of tax credits in 2020. See "Financing Activities" herein and Notes (A) and (K) to the Condensed Financial Statements herein for additional information. Alabama Power Significant balance sheet changes for the nine months ended September 30, 2020 included: •an increase of $960 million in common stockholder's equity primarily due to capital contributions from Southern Company; •an increase of $949 million in total property, plant, and equipment primarily related to the Autauga Combined Cycle Acquisition, construction of distribution and transmission facilities, and the installation of equipment to comply with environmental standards; •an increase of $597 million in long-term debt (including securities due within one year) primarily due to an increase in outstanding senior notes; and •increases of $456 million and $418 million in regulatory assets associated with AROs and AROs, respectively, primarily related to cost estimate updates for certain ash pond facilities. See "Financing Activities – Alabama Power" herein and Notes (A) and (K) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Alabama Power," respectively, herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Georgia Power Significant balance sheet changes for the nine months ended September 30, 2020 included: •an increase of $1.7 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities; •an increase of $1.6 billion in common stockholder's equity primarily due to capital contributions from Southern Company; •an increase of $1.0 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4; and •increases of $468 million and $397 million in AROs and regulatory assets associated with AROs, respectively, primarily due to cost estimate updates for ash pond closures. See "Financing Activities – Georgia Power" herein and Notes (A) and (B) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Georgia Power – Nuclear Construction," respectively, herein for additional information. Mississippi Power Significant balance sheet changes for the nine months ended September 30, 2020 included: •a decrease of $228 million in cash and cash equivalents and a decrease of $187 million in long-term debt (including amounts due within one year) primarily related to the repayment of senior notes at maturity; •an increase of $108 million in common stockholder's equity primarily from net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; and •a decrease of $53 million in deferred credits related to income taxes due to reclassifying certain amounts to other regulatory liabilities, current for the expected flowback of excess deferred income taxes. See "Financing Activities – Mississippi Power" herein for additional information. Southern Power Significant balance sheet changes for the nine months ended September 30, 2020 included: •a decrease of $618 million in assets held for sale (of which $17 million related to current assets) due to completion of the sale of Plant Mankato; •a decrease of $549 million in notes payable due to net repayments of short-term bank debt and commercial paper; •an increase of $330 million in property, plant, and equipment in service and a decrease of $180 million in construction work in progress primarily due to wind facilities acquired or placed in service; •a decrease of $320 million in accumulated deferred income tax assets primarily related to the utilization of tax credits in 2020; and •a decrease of $299 million in securities due within one year primarily related to the maturity of senior notes. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein, "Financing Activities – Southern Power" herein, and Note (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Southern Company Gas Significant balance sheet changes for the nine months ended September 30, 2020 included: •an increase of $789 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investments recovered through replacement programs; •an increase of $616 million in long-term debt (including securities due within one year) due to the issuance of senior notes and mortgage bonds; •a decrease of $500 million in notes payable due to net repayments of short-term borrowings; •an increase of $179 million in common stockholder's equity primarily from net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; •a decrease of $171 million in assets held for sale due to the completed sale of interests in Pivotal LNG and Atlantic Coast Pipeline; •a decrease of $123 million in unbilled revenues due to seasonality; •an increase of $111 million in cash and cash equivalents primarily from long-term debt issuance proceeds; •a decrease of $109 million in customer accounts receivable due to the timing of collections; and •decreases of $100 million and $81 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold. See "Financing Activities – Southern Company Gas" herein and Note (K) to the Condensed Financial Statements herein for additional information. Capital Requirements and Contractual Obligations See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" and "Contractual Obligations" in Item 87 of the Form 10-K for alternative revenue programs at the natural gas distribution utilities, and Note 2 to the financial statements in Item 8a description of the Form 10-K for cost recovery mechanisms.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following tables disaggregate revenue sources for the threeRegistrants' capital requirements and nine months ended September 30, 2019 and 2018:
| | | | | | | | | | | | | | | | For the Three Months Ended September 30, 2019 | For the Three Months Ended September 30, 2018 | For the Nine Months Ended September 30, 2019 | For the Nine Months Ended September 30, 2018 | | | (in millions) | | Southern Company | | | | | | Operating revenues | | | | | Retail electric revenues(a) | | | | | | Residential | $ | 2,056 |
| $ | 2,148 |
| $ | 4,832 |
| $ | 5,266 |
| | Commercial | 1,508 |
| 1,527 |
| 3,859 |
| 4,084 |
| | Industrial | 916 |
| 901 |
| 2,356 |
| 2,471 |
| | Other | 32 |
| 29 |
| 89 |
| 92 |
| Natural gas distribution revenues(b) | 445 |
| 433 |
| 2,169 |
| 2,299 |
| Alternative revenue programs(c) | — |
| 5 |
| — |
| (23 | ) | | Total retail electric and gas distribution revenues | $ | 4,957 |
| $ | 5,043 |
| $ | 13,305 |
| $ | 14,189 |
| Wholesale energy revenues(d)(e) | 477 |
| 521 |
| 1,254 |
| 1,458 |
| Wholesale capacity revenues(e) | 148 |
| 177 |
| 413 |
| 479 |
| Other natural gas revenues(f)(g) | 53 |
| 54 |
| 492 |
| 530 |
| Other revenues(h) | 360 |
| 364 |
| 1,041 |
| 1,502 |
| | Total operating revenues | $ | 5,995 |
| $ | 6,159 |
| $ | 16,505 |
| $ | 18,158 |
|
| | (a) | Retail electric revenues include $8 million, $17 million, $24 million, and $54 million of revenues accounted for as leases for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, and a net increase/(reduction) of $(155) million, $(98) million, $(272) million, and $4 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.
|
| | (b) | Natural gas distribution revenues include $3 million for each of the three months ended September 30, 2019 and 2018 and $11 million for each of the nine months ended September 30, 2019 and 2018 of revenues not accounted for under ASC 606. |
| | (c) | Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period. |
| | (d) | Wholesale energy revenues include $28 million, $63 million, $109 million, and $217 million of revenues accounted for as derivatives for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, primarily related to physical energy sales in the wholesale electricity market.
|
| | (e) | Wholesale energy revenues include $141 million, $130 million, $324 million, and $318 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, and wholesale capacity revenues include $15 million, $31 million, $62 million, and $92 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, related to PPAs accounted for as leases. |
| | (f) | Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.1 billion, $1.6 billion, $4.3 billion, and $4.8 billion for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, of which $0.7 billion, $0.9 billion, $2.7 billion, and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.
|
| | (g) | Other natural gas revenues include $10 million and $37 million for the three and nine months ended September 30, 2019, respectively, of revenues not accounted for under ASC 606, including $8 million and $24 million, respectively, of revenues accounted for as leases. |
| | (h) | Other revenues include $93 million, $92 million, $278 million, and $274 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606, including $33 million, $35 million, $104 million, and $106 million, respectively, accounted for as leases.
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | Alabama Power | Georgia Power | Mississippi Power | | | (in millions) | | For the Three Months Ended September 30, 2019 | | | | | Operating revenues | | | | Retail revenues(a)(b) | | | | | Residential | $ | 796 |
| $ | 1,174 |
| $ | 86 |
| | Commercial | 493 |
| 932 |
| 83 |
| | Industrial | 398 |
| 439 |
| 79 |
| | Other | 7 |
| 22 |
| 3 |
| | Total retail electric revenues | $ | 1,694 |
| $ | 2,567 |
| $ | 251 |
| Wholesale energy revenues(c) | 48 |
| 25 |
| 114 |
| | Wholesale capacity revenues | 25 |
| 14 |
| 1 |
| Other revenues(b)(d) | 74 |
| 149 |
| 4 |
| | Total operating revenues | $ | 1,841 |
| $ | 2,755 |
| $ | 370 |
| | | | | | | For the Three Months Ended September 30, 2018 | | | | | Operating revenues | | | | Retail revenues(a)(b) | | | | | Residential | $ | 721 |
| $ | 1,142 |
| $ | 85 |
| | Commercial | 464 |
| 877 |
| 82 |
| | Industrial | 392 |
| 385 |
| 86 |
| | Other | 7 |
| 21 |
| 1 |
| | Total retail electric revenues | $ | 1,584 |
| $ | 2,425 |
| $ | 254 |
| Wholesale energy revenues(c) | 62 |
| 33 |
| 97 |
| | Wholesale capacity revenues | 26 |
| 14 |
| 1 |
| Other revenues(b)(d) | 68 |
| 121 |
| 6 |
| | Total operating revenues | $ | 1,740 |
| $ | 2,593 |
| $ | 358 |
|
| | (a) | Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net reduction of $(64) million, $(83) million, and $(8) million, respectively, for the three months ended September 30, 2019 and $(12) million, $(47) million, and $(3) million, respectively, for the three months ended September 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. |
| | (b) | Retail revenues and other revenues at Georgia Power include $8 million and $10 million, respectively, for the three months ended September 30, 2019 and $17 million and $34 million, respectively, for the three months ended September 30, 2018 of revenues accounted for as leases. |
| | (c) | Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $3 million, $4 million, and $1 million, respectively, for the three months ended September 30, 2019 and $6 million, $8 million, and $1 million, respectively, for the three months ended September 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. |
| | (d) | Other revenues at Alabama Power and Georgia Power include $36 million and $26 million, respectively, for the three months ended September 30, 2019 and $27 million and $28 million, respectively, for the three months ended September 30, 2018 of revenues not accounted for under ASC 606. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | Alabama Power | Georgia Power | Mississippi Power | | | (in millions) | | For the Nine Months Ended September 30, 2019 | | | | | Operating revenues | | | | Retail revenues(a)(b) | | | | | Residential | $ | 1,923 |
| $ | 2,693 |
| $ | 216 |
| | Commercial | 1,266 |
| 2,372 |
| 221 |
| | Industrial | 1,077 |
| 1,055 |
| 224 |
| | Other | 20 |
| 61 |
| 8 |
| | Total retail electric revenues | $ | 4,286 |
| $ | 6,181 |
| $ | 669 |
| Wholesale energy revenues(c) | 183 |
| 66 |
| 285 |
| | Wholesale capacity revenues | 77 |
| 41 |
| 2 |
| Other revenues(b)(d) | 216 |
| 418 |
| 14 |
| | Total operating revenues | $ | 4,762 |
| $ | 6,706 |
| $ | 970 |
| | | | | | | For the Nine Months Ended September 30, 2018 | | | | | Operating revenues | | | | Retail revenues(a)(b) | | | | | Residential | $ | 1,848 |
| $ | 2,671 |
| $ | 209 |
| | Commercial | 1,238 |
| 2,343 |
| 212 |
| | Industrial | 1,103 |
| 1,036 |
| 233 |
| | Other | 19 |
| 62 |
| 6 |
| | Total retail electric revenues | $ | 4,208 |
| $ | 6,112 |
| $ | 660 |
| Wholesale energy revenues(c) | 234 |
| 99 |
| 272 |
| | Wholesale capacity revenues | 75 |
| 41 |
| 6 |
| Other revenues(b)(d) | 199 |
| 349 |
| 18 |
| | Total operating revenues | $ | 4,716 |
| $ | 6,601 |
| $ | 956 |
|
| | (a) | Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase/(reduction) of $(132) million, $(135) million, and $(5) million, respectively, for the nine months ended September 30, 2019 and $113 million, $(35) million, and $(11) million, respectively, for the nine months ended September 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. |
| | (b) | Retail revenues and other revenues at Georgia Power include $24 million and $33 million, respectively, for the nine months ended September 30, 2019 and $54 million and $100 million, respectively, for the nine months ended September 30, 2018 of revenues accounted for as leases. |
| | (c) | Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $8 million, $12 million, and $2 million, respectively, for the nine months ended September 30, 2019 and $14 million, $21 million, and $3 million, respectively, for the nine months ended September 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. |
| | (d) | Other revenues at Alabama Power and Georgia Power include $95 million and $88 million, respectively, for the nine months ended September 30, 2019 and $79 million and $80 million, respectively, for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | For the Three Months Ended September 30, 2019 | For the Three Months Ended September 30, 2018 | For the Nine Months Ended September 30, 2019 | For the Nine Months Ended September 30, 2018 | | | (in millions) | | Southern Power | | | | | PPA capacity revenues(a) | $ | 131 |
| $ | 168 |
| $ | 384 |
| $ | 450 |
| PPA energy revenues(a) | 339 |
| 336 |
| 857 |
| 892 |
| Non-PPA revenues(b) | 101 |
| 126 |
| 276 |
| 347 |
| | Other revenues | 3 |
| 5 |
| 10 |
| 10 |
| | Total operating revenues | $ | 574 |
| $ | 635 |
| $ | 1,527 |
| $ | 1,699 |
|
| | (a) | PPA capacity revenues include $31 million, $47 million, $111 million, and $141 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, and PPA energy revenues include $151 million, $139 million, $349 million, and $342 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.
|
| | (b) | Non-PPA revenues include $20 million, $47 million, $87 million, and $176 million for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market.
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | For the Three Months Ended September 30, 2019 | For the Three Months Ended September 30, 2018 | For the Nine Months Ended September 30, 2019 | For the Nine Months Ended September 30, 2018 | | | (in millions) | | Southern Company Gas | | | | | | Operating revenues | | | | | Natural gas distribution revenues(a) | | | | | | Residential | $ | 162 |
| $ | 149 |
| $ | 992 |
| $ | 1,082 |
| | Commercial | 42 |
| 45 |
| 277 |
| 313 |
| | Transportation | 204 |
| 203 |
| 673 |
| 708 |
| | Industrial | 3 |
| 4 |
| 25 |
| 28 |
| | Other | 34 |
| 32 |
| 202 |
| 168 |
| Alternative revenue programs(b) | — |
| 5 |
| — |
| (23 | ) | | Total natural gas distribution revenues | $ | 445 |
| $ | 438 |
| $ | 2,169 |
| $ | 2,276 |
| Gas pipeline investments(c) | 8 |
| 8 |
| 24 |
| 24 |
| Wholesale gas services(d) | (4 | ) | (10 | ) | 110 |
| 121 |
| Gas marketing services(e) | 39 |
| 44 |
| 326 |
| 403 |
| | Other revenues | 10 |
| 12 |
| 32 |
| 37 |
| | Total operating revenues | $ | 498 |
| $ | 492 |
| $ | 2,661 |
| $ | 2,861 |
|
| | (a) | Natural gas distribution revenues include $3 million for each of the three months ended September 30, 2019 and 2018 and $11 million for each of the nine months ended September 30, 2019 and 2018 of revenues not accounted for under ASC 606. |
| | (b) | Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period. |
| | (c) | Revenues from gas pipeline investments include $8 million and $24 million for the three and nine months ended September 30, 2019, respectively, accounted for as leases. |
| | (d) | Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.1 billion, $1.6 billion, $4.3 billion, and $4.8 billion for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively, of which $0.7 billion, $0.9 billion, $2.7 billion, and $2.7 billion, respectively, relates to contracts accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.
|
| | (e) | Gas marketing services include $2 million for the three months ended September 30, 2019 and $13 million and $4 million for the nine months ended September 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Contract Balances
contractual obligations. The following table reflectsprovides the closing balancesapplicable Registrants' maturities and announced redemptions of receivables, contract assets,long-term debt through September 30, 2021: | | | | | | | | | | | | | | | | | | | | At September 30, 2020: | Southern Company | Alabama Power | Georgia
Power | | Southern Power | Southern Company Gas | | (in millions) | | Securities due within one year | $ | 4,378 | | $ | 496 | | $ | 531 | | | $ | 525 | | $ | 334 | |
See "Sources of Capital" and contract liabilities"Financing Activities" herein for additional information. In October 2020, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.9 billion for 2021, $1.8 billion for 2022, $1.7 billion for 2023, $1.6 billion for 2024, and $1.6 billion for 2025. These amounts include capital expenditures related to revenues from contractsPlant Barry Unit 8 and contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. These amounts also include estimated capital expenditures to comply with customers as of September 30, 2019environmental laws and December 31, 2018: | | | | | | | | | | | | | | | | | | | | | | | | Receivables | | Contract Assets | | Contract Liabilities | | | September 30, 2019 | December 31, 2018 | | September 30, 2019 | December 31, 2018 | | September 30, 2019 | December 31, 2018 | | | (in millions) | | Southern Company | $ | 2,523 |
| $ | 2,630 |
| | $ | 132 |
| $ | 102 |
| | $ | 58 |
| $ | 32 |
| | Alabama Power | 713 |
| 520 |
| | 2 |
| — |
| | 12 |
| 12 |
| | Georgia Power | 993 |
| 721 |
| | 91 |
| 58 |
| | 15 |
| 7 |
| | Mississippi Power | 94 |
| 100 |
| | — |
| — |
| | 6 |
| — |
| | Southern Power | 132 |
| 118 |
| | — |
| — |
| | 3 |
| 11 |
| | Southern Company Gas | 441 |
| 952 |
| | — |
| — |
| | 1 |
| 2 |
|
As of September 30, 2019 and December 31, 2018, Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion and fixed retail customer bill programs where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over the one-year contract term. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Contract liabilities for Georgia Power and Southern Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements and certain levelized PPAs, respectively. Mississippi Power had contract liabilities for cash collections recognized in advance of revenue for operating agreements associated with a tolling arrangement accounted for as a sales-type lease. Southern Company's unregulated distributed generation business had $31 million and $39 million of contract assets and $23 million and $11 million of contract liabilities at September 30, 2019 and December 31, 2018, respectively, remaining for outstanding performance obligations.
The following table reflects revenue from contracts with customers recognized in the three and nine months ended September 30, 2019 included in the contract liability at December 31, 2018:
| | | | | | | | | | Three Months Ended
September 30,
2019 | Nine Months Ended
September 30,
2019 | | | (in millions) | | Southern Company | $ | 4 |
| $ | 29 |
| | Southern Power | — |
| 11 |
|
Revenues recognized in the three and nine months ended September 30, 2019, which were included in contract liabilities at December 31, 2018, were immaterial for Alabama Power, Georgia Power, and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized when the performance obligations are satisfied during the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Registrants with revenues from contracts with customers related to these performance obligations remaining at September 30, 2019 expect the revenues to be recognized as follows:
| | | | | | | | | | | | | | | | | | | | | | 2019 (remaining) | 2020 | 2021 | 2022 | 2023 | Thereafter | | | (in millions) | | Southern Company | $ | 138 |
| $ | 419 |
| $ | 345 |
| $ | 326 |
| $ | 317 |
| $ | 2,256 |
| | Alabama Power | 6 |
| 23 |
| 27 |
| 23 |
| 22 |
| 140 |
| | Georgia Power | 15 |
| 56 |
| 47 |
| 31 |
| 32 |
| 83 |
| | Southern Power | 61 |
| 309 |
| 291 |
| 290 |
| 283 |
| 2,180 |
|
Revenues expected to be recognized for performance obligations remaining at September 30, 2019 were immaterial for Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
Southern Power
Consolidated Variable Interest Entities
See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Power's consolidated VIEs.
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. In 2018, Southern Power sold noncontrolling interests in SP Solar and SP Wind. Southern Power continues to consolidate each entity, as the primary beneficiary of each VIE, since it controls the most significant activities of each entity, including operating and maintaining their assets. Transfers and sales of the assets in the VIEs are subject to limited partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items andregulations, but do not include any long-term debt.potential compliance costs associated with pending regulation of CO2 emissions from fossil fuel-fired electric generating units. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are approximately $83 million for 2021, $98 million for 2022, $86 million for 2023, $99 million for 2024, and $70 million for 2025. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for information on Alabama Power's construction of Plant Barry Unit 8.
In August 2019, Southern Power completed the acquisition of a majority interest in DSGP and gained control of its most significant activities. As a result Southern Power became the primary beneficiary of this VIE and began accounting for it as a consolidated entity. See Note (K) under "Southern Power" for additional information.
SP Solar
At September 30, 2019, SP Solar had total assets of $6.5 billion, total liabilities of $383 million, and noncontrolling interests of $1.2 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cashsecond quarter 2020 increase in Alabama Power's AROs discussed herein under FUTURE EARNINGS POTENTIAL – "Environmental Matters," Alabama Power's costs through 2025 associated with closure and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenancemonitoring of appropriate operating reserves.
SP Wind
At September 30, 2019, SP Wind had total assets of $2.5 billion, total liabilities of $132 million,ash ponds and noncontrolling interests of $46 million. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the 3 financial investorslandfills in accordance with the limited liability agreement.
Southern Company Gas
See Note 7CCR Rule and the related state rule are currently estimated to the financial statementsbe approximately $263 million for 2020, $247 million for 2021, $301 million for 2022, $330 million for 2023, $326 million for 2024, and $311 million for 2025. These costs are reflected in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2019 and December 31, 2018 and related income from those investments for the three- and nine-month periods ended September 30, 2019 and 2018 were as follows:
| | | | | | | | | Investment Balance | September 30, 2019 | December 31, 2018 | | | (in millions) | SNG(a) | $ | 1,210 |
| $ | 1,261 |
| Atlantic Coast Pipeline(b) | 109 |
| 83 |
| | PennEast Pipeline | 80 |
| 71 |
| Other(c) | 88 |
| 123 |
| | Total | $ | 1,487 |
| $ | 1,538 |
|
| | (a) | Decrease primarily relates to the continued amortization of deferred tax assets established upon acquisition. |
| | (b) | The Atlantic Coast Pipeline has a $3.4 billion revolving credit facility with a stated maturity date of October 2021. Southern Company Gas guarantees 5% of the outstanding borrowings under this facility; this guarantee totaled $85 million as of September 30, 2019. |
| | (c) | Decrease primarily relates to the sale of Triton. |
| | | | | | | | | | | | | | | Earnings from Equity Method Investments | Three Months Ended September 30, 2019 | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2019 | Nine Months Ended September 30, 2018 | | | (in millions) | | SNG | $ | 30 |
| $ | 29 |
| $ | 104 |
| $ | 95 |
| | Atlantic Coast Pipeline | 3 |
| 1 |
| 9 |
| 4 |
| | PennEast Pipeline | 2 |
| 2 |
| 5 |
| 4 |
| Other(*) | — |
| 2 |
| (3 | ) | 5 |
| | Total | $ | 35 |
| $ | 34 |
| $ | 115 |
| $ | 108 |
|
| | (*) | Decrease primarily relates to the sale of Triton. |
SNG
Selected financial information of SNG for the three and nine months ended September 30, 2019 and 2018 is as follows:
| | | | | | | | | | | | | | | Income Statement Information | Three Months Ended September 30, 2019 | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2019 | Nine Months Ended September 30, 2018 | | | (in millions) | | Revenues | $ | 152 |
| $ | 145 |
| $ | 473 |
| $ | 451 |
| | Operating income | 82 |
| 71 |
| 274 |
| 230 |
| | Net income | 60 |
| 58 |
| 208 |
| 190 |
|
Atlantic CoastMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued) ARO liabilities and PennEast Pipelines In 2014, Southern Company Gas entered into a joint venture, whereby it holds a 5% ownership interest in the Atlantic Coast Pipeline, an interstate pipeline company which will develop and operate a 605-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with expected initial transportation capacityare based on closure-in-place for all of 1.5 Bcf per day.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The Atlantic Coast Pipeline has experienced challengesits ash ponds. These anticipated costs are likely to its permits since construction began in 2018. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. The delays resulting from the permitting issues have impacted the cost and schedule for the project. As a result, total current project cost estimates have increased from between $7.0 billion and $7.8 billion ($350 million and $390 million for Southern Company Gas) to between $7.3 billion and $7.8 billion ($365 million and $390 million for Southern Company Gas), excluding financing costs. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.
Also in 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate a 118-mile natural gas pipeline between New Jersey and Pennsylvania. The expected initial transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly with public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York.
On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal court eminent domain authority over lands in which a state has property rights interests. The joint venture is pursuing appellate and other options and is evaluating further next steps.
The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, which could result in an impairment of one or both of Southern Company Gas' investmentschange, and could have a material impact on Southern Company Gas'change materially, as assumptions and Southern Company's financial statements.
Other
On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 milliondetails pertaining to closure are refined and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.
(F) FINANCING
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowingscompliance activities continue. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2019 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $40 million at Mississippi Power). In addition, at September 30, 2019, Alabama Power had approximately $87 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. See Note 8 to the financial statements under "Bank Credit Arrangements"Regulations – Coal Combustion Residuals" in Item 8 of the Form 10-K and "Financing Activities"Note (A) to the Condensed Financial Statements herein for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following table outlinesconstruction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the committed credit arrangements by company as of September 30, 2019: | | | | | | | | | | | | | | | | | | | | | | | | Expires | | | | | Company | 2020 | 2022 | 2024 | | Total | | Unused | Due within One Year | | | (in millions) | Southern Company(a) | $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| $ | — |
| | Alabama Power | 3 |
| 525 |
| 800 |
| | 1,328 |
| | 1,328 |
| 3 |
| | Georgia Power | — |
| — |
| 1,750 |
| | 1,750 |
| | 1,733 |
| — |
| | Mississippi Power | — |
| 150 |
| — |
| | 150 |
| | 150 |
| — |
| Southern Power(b) | — |
| — |
| 600 |
| | 600 |
| | 591 |
| — |
| Southern Company Gas(c) | — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| — |
| | Other | 30 |
| — |
| — |
| | 30 |
| | 30 |
| 30 |
| | Southern Company Consolidated | $ | 33 |
| $ | 675 |
| $ | 6,900 |
| | $ | 7,608 |
| | $ | 7,576 |
| $ | 33 |
|
| | (a) | Represents the Southern Company parent entity. |
| | (b) | Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at September 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement.
|
| | (c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
|
As reflectedlast few years began initial operation in the table above,global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in May 2019, Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein, and Item 1A herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A herein. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, Southern Power's planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects. Sources of Capital Southern Company Alabama Power,intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2024. The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power and Southern Power each amended and restated certain of their multi-year credit arrangements, which, among other things, extendedplans to utilize borrowings from the maturity dates to 2024. Southern Power also decreased its borrowing capacity from $750 million to $600 million. In addition, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion. In June 2019, Mississippi Power entered into a new $50 million credit arrangement that maturesFFB (as discussed further in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022. In September 2019, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022 and increased the borrowing capacity to $525 million. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
DOE Loan Guarantee Borrowings
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The traditional electric operating companies and the natural gas distribution utilities have experienced a reduction in operating cash flows as a result of the temporary suspension of disconnections for non-payment by customers resulting from the COVID-19 pandemic and the related overall economic contraction. To date, this reduction of operating cash flows has not had a material impact on the liquidity of any of the Registrants, and, during the third quarter 2020, most of the temporary measures in place expired. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. The ultimate extent of the negative impact on the Registrants' liquidity depends on resolution of the Heroes Act and the duration of the COVID-19 pandemic and cannot be determined at this time. See Note (B)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) to the Condensed Financial Statements herein for information regarding suspended disconnections for non-payment by the traditional electric operating companies and the natural gas distribution utilities. The amount, type, and timing of any financings in 2020, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for the Subsidiary Registrants), and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information. Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. In June 2020, Southern Power obtained tax equity funding for the Reading wind project and received proceeds of $156 million. In addition, during the first nine months of 2020, Southern Power received tax equity funding totaling $16 million from existing partnerships. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2020, the amount of subsidiary retained earnings restricted to dividend totaled $1.1 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information. The Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. See "Financing Activities" herein for information regarding Georgiaon financing activities that occurred subsequent to September 30, 2020. The following table shows the amount by which current liabilities exceeded current assets at September 30, 2020 for the applicable Registrants: | | | | | | | | | | | | | | | | | | At September 30, 2020 | Southern Company | | Georgia
Power | Mississippi Power | | Southern Company Gas | | (in millions) | | Current liabilities in excess of current assets | $ | 1,176 | | | $ | 612 | | $ | 65 | | | $ | 286 | |
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company. Bank Credit Arrangements At September 30, 2020, the Registrants' unused committed credit arrangements with banks were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | At September 30, 2020 | Southern
Company
parent | Alabama Power | Georgia
Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern
Company | | (in millions) | | Unused committed credit | $ | 1,999 | | $ | 1,328 | | $ | 1,728 | | $ | 250 | | $ | 591 | | $ | 1,745 | | $ | 30 | | $ | 7,671 | |
(a)At September 30, 2020, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $63 million was unused. Southern Power's 2014 loan guarantee agreement. Pursuantsubsidiaries are not parties to its bank credit arrangement or to the loan guarantee program established under Title XVIIletter of credit facilities.
(b)Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of the Energy Policy Actunused credit with banks is allocated to provide liquidity support to the revenue bonds of 2005 (Title XVII Loan Guarantee Program),the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at September 30, 2020 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for 2 multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds).
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835$34 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. AtMississippi Power). In addition, at September 30, 2019,2020, Georgia Power had a totalapproximately $257 million of $3.46 billion of borrowingsfixed rate revenue bonds outstanding under the FFB Credit Facilities.
All borrowings under the FFB Credit Facilitiesthat are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to makebe remarketed within the next 12 months.
See Note 8 to the FFBfinancial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information. Short-term Borrowings The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its guarantee. Georgia Power's reimbursement obligations to the DOEcommercial paper program. Commercial paper and short-term bank term loans are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interestincluded in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loadednotes payable in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property. In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirementsbalance sheets. Details of the Title XVII Loan Guarantee Program, including accuracy of project-related representationsRegistrants' short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Short-term Debt at September 30, 2020 | | Short-term Debt During the Period(*) | | | Amount
Outstanding | | Weighted
Average
Interest
Rate | | Average
Amount
Outstanding | | Weighted
Average
Interest
Rate | | Maximum
Amount
Outstanding | | | (in millions) | | | | (in millions) | | | | (in millions) | | Southern Company | $ | 171 | | | 0.9 | % | | $ | 958 | | | 1.2 | % | | $ | 1,272 | | | Alabama Power | — | | | — | | | 7 | | | 0.2 | | | 80 | | | Georgia Power | — | | | — | | | 347 | | | 1.4 | | | 465 | | | Mississippi Power | — | | | — | | | 1 | | | 0.2 | | | 10 | | | Southern Power | — | | | — | | | 19 | | | 0.3 | | | 114 | | | Southern Company Gas: | | | | | | | | | | | Southern Company Gas Capital | $ | 150 | | | 1.0 | % | | $ | 273 | | | 1.0 | % | | $ | 464 | | | Nicor Gas | — | | | — | | | 21 | | | 0.2 | | | 82 | | | Southern Company Gas Total | $ | 150 | | | 1.0 | % | | $ | 294 | | | 0.9 | % | | |
(*)Average and warranties, delivery of updated project-related information, and evidence of compliance withmaximum amounts are based upon daily balances during the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20,three-month period ended September 30, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
Under the Amended and Restated Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facilities to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
NOTES TO THE CONDENSEDMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL STATEMENTS:CONDITION
AND RESULTS OF OPERATIONS (Continued) (UNAUDITED)
Financing Activities The following table outlines the Registrants' long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2019:2020: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Senior Notes | | Revenue Bonds | | Other Long-Term Debt | | Company | Issuances | | Maturities, Redemptions, and Repurchases | | Issuances/
Remarketings | | Maturities, Redemptions, and
Repurchases | | Issuances | | Redemptions and Maturities(a) | | (in millions) | | Southern Company parent | $ | 1,000 | | | $ | 600 | | | $ | — | | | $ | — | | | $ | 3,000 | | | $ | — | | | Alabama Power | 600 | | | — | | | 87 | | | 87 | | | — | | | — | | | Georgia Power | 1,500 | | | 950 | | | 53 | | | 148 | | | 519 | | | 65 | | | Mississippi Power | — | | | 275 | | | 34 | | | 41 | | | 100 | | | — | | | Southern Power | — | | | 300 | | | — | | | — | | | — | | | — | | | Southern Company Gas | 500 | | | — | | | — | | | — | | | 150 | | | — | | | Other | — | | | — | | | — | | | — | | | — | | | 12 | | Elimination(b) | — | | | — | | | — | | | — | | | — | | | (6) | | | Southern Company | $ | 3,600 | | | $ | 2,125 | | | $ | 174 | | | $ | 276 | | | $ | 3,769 | | | $ | 71 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | Company | Senior Note Issuances | | Senior Note Maturities, Redemptions, and Repurchases | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond
Maturities, Redemptions, and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | | | (in millions) | Southern Company(b) | $ | — |
| | $ | 2,400 |
| | $ | — |
| | $ | — |
| | $ | 1,725 |
| | $ | — |
| | Alabama Power | 600 |
| | 200 |
| | — |
| | — |
| | — |
| | 1 |
| | Georgia Power | 750 |
| | — |
| | 584 |
| | 223 |
| | 835 |
| | 11 |
| | Mississippi Power | — |
| | — |
| | 43 |
| | — |
| | — |
| | — |
| | Southern Company Gas | — |
| | 300 |
| | — |
| | — |
| | 200 |
| | 50 |
| | Other | — |
| | — |
| | — |
| | 25 |
| | — |
| | 14 |
| Elimination(c) | — |
| | — |
| | — |
| | — |
| | — |
| | (7 | ) | | Southern Company Consolidated | $ | 1,350 |
| | $ | 2,900 |
| | $ | 627 |
| | $ | 248 |
| | $ | 2,760 |
| | $ | 69 |
|
| | (a) | Includes reductions in finance lease obligations resulting from cash payments under finance leases. |
| | (b) | Represents the Southern Company parent entity. |
| | (c) | Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements. |
(b)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements. Except as otherwise described herein, Southern Company and its subsidiariesthe Registrants used or will use the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiariesSubsidiary Registrants also used or will use the proceeds for their construction programs. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Southern Company During the first nine months of 2020, Southern Company issued approximately 3.0 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $63 million. In January 2019,2020, Southern Company repaid aissued $1.0 billion aggregate principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080. In March 2020, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time. In April 2020 and September 2020, Southern Company repaid $50 million and $200 million, respectively, of the $250 million borrowed. Also in March 2020, Southern Company entered into a $1.5 billion$75 million short-term floating rate bank loan.loan bearing interest based on one-month LIBOR, which it repaid in September 2020. Also in January 2019, through cash tender offers,In April 2020, Southern Company repurchasedissued $1.0 billion aggregate principal amount of Series 2020A 3.70% Senior Notes due April 30, 2030.
In May 2020, Southern Company redeemed all $600 million aggregate principal amount of its Series 2015A 2.750% Senior Notes due June 15, 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) In September 2020, Southern Company issued $1.25 billion aggregate principal amount of Series 2020B 4.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due January 15, 2051 and retired approximately $522$750 million aggregate principal amount of theSeries 2020C 4.20% Junior Subordinated Notes due October 15, 2060. Subsequent to September 30, 2020, Southern Company redeemed all of its $1.0 billion aggregate principal amount outstanding of its 1.85% SeniorSeries 2015A 6.25% Junior Subordinated Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.October 15, 2075. See "Equity Units" herein for information related to Southern Company's August 2019 issuance of 34.5 million equity units for a total stated amount of $1.725 billion.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In September 2019, Southern Company redeemed all $300March 2020, Alabama Power purchased and held approximately $87 million aggregate principal amount of itsThe Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2017A Floating Rate Senior Notes due September 30,2007-A, which were remarketed to the public in June 2020. Alabama Power
In September 2019,August 2020, Alabama Power issued $600 million aggregate principal amount of Series 2019A 3.45%2020A 1.45% Senior Notes due October 1, 2049.September 15, 2030. Subsequent to September 30, 2020, Alabama Power repaid at maturity $250 million aggregate principal amount of its Series 2010A 3.375% Senior Notes. Georgia Power In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively. In March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:
$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;
approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013; and
$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008.
In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.
$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;
$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and
$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In June 2019, Georgia Power reoffered to the public $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994, which previously had been purchased and held by Georgia Power.
Also in June 2019, Georgia Power entered into 2 short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.
In August 2019, Georgia Power reoffered to the public approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013, which previously had been purchased and held by Georgia Power.
In September 2019,2020, Georgia Power issued $400$700 million aggregate principal amount of Series 2019A 2.20%2020A 2.10% Senior Notes due September 15, 2024July 30, 2023, $500 million aggregate principal amount of Series 2020B 3.70% Senior Notes due January 30, 2050, and $350an additional $300 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.
In February 2020, Georgia Power redeemed all $500 million aggregate principal amount of its Series 2017C 2.00% Senior Notes due September 8, 2020. Also in February 2020, Georgia Power purchased and held approximately $28 million, $49 million, and $18 million aggregate principal amounts of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2006, First Series 2012, and First Series 2013, respectively, which may be remarketed to the public at a later date. In March 2020, Georgia Power repaid at maturity $450 million aggregate principal amount of its Series 2017A 2.00% Senior Notes. Also in March 2020, Georgia Power purchased and subsequently remarketed to the public approximately $53 million of pollution control revenue bonds. Also in March 2020, Georgia Power borrowed $200 million pursuant to a $250 million short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Georgia Power and the bank from time to time. In April 2020, Georgia Power borrowed the remaining $50 million pursuant to this bank credit arrangement. In September 2020, Georgia Power repaid the full $250 million. Also in March 2020, Georgia Power extended one of its $125 million short-term floating rate bank loans to a long-term term loan, which matures in June 2021. In June 2020, Georgia Power extended its other $125 million short-term floating rate bank loan to mature in December 2020. In September 2020, Georgia Power repaid this $125 million bank loan. Also in June 2020, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $519 million at an interest rate of 1.652% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. During the nine months ended September 30, 2020, Georgia Power made principal amortization payments of $55 million under the FFB Credit Facilities. At September 30, 2020, the outstanding principal balance under the FFB Credit Facilities was $4.3 billion. See Note 8 to the financial statements under "Long-Term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Mississippi Power In March 2019,February 2020, Mississippi Power reofferedentered into $60 million and $15 million floating rate bank term loans, which mature in December 2021 and January 2022, respectively, each bearing interest based on one-month LIBOR. In March 2020, Mississippi Power entered into a $125 million revolving credit arrangement that matures in March 2023 and borrowed $40 million (short term) and $25 million (long term) pursuant to the public $43arrangement, each bearing interest based on one-month LIBOR. In May 2020, Mississippi Power repaid the $40 million short-term portion. In March 2020, Mississippi Power repaid at maturity the remaining $275 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes. In April 2020, Mississippi Power purchased and held approximately $11 million, $14 million, and $9 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Bonds, Series 1995 (Mississippi Power Company Project), Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 1998 (Mississippi Power Company Project), and Revenue Bonds, Series 1999 (Mississippi Power Company Project), respectively, which were remarketed to the public in May 2020. Also in April 2020, Mississippi Power redeemed approximately $7 million aggregate principal amount of The Industrial Development Board of the City of Eutaw, Alabama Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.1992 (Mississippi Power Greene County Plant Project) due December 1, 2020.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power In May 2019,February 2020, Southern Power repaid its $100 million short-term floating rate bank loan entered into in December 2019. In June 2020, Southern Power repaid at maturity a $100$300 million aggregate principal amount short-term bank loan.of its Series 2015B 2.375% Senior Notes. Southern Company Gas In March 2020, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, entered into a $150 million short-term floating rate bank loan bearing interest based on one-month LIBOR. Also in March 2020, Southern Company Gas Capital borrowed approximately $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time. In August 2019,2020, Southern Company Gas Capital repaid the outstanding balance. In August 2020, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, issued $500 million aggregate principal amount of Series 2020A 1.75% Senior Notes due January 15, 2031. Also in August 2020, Nicor Gas issued $200$150 million aggregate principal amount of first mortgage bonds in a private placement. Nicor Gasplacement and entered into an agreement to issue an additional $100$175 million aggregate principal amount of first mortgage bonds on October 30, 2019.in November 2020. Equity Units
In August 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net proceeds from the issuance were approximately $1.682 billion. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including investments in Southern Company's subsidiaries.
Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes (Series 2019A RSNs) due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes (together with the Series 2019A RSNs, the RSNs) due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash (Stock Purchase Contract). Southern Company has agreed to remarket the RSNs in 2022, at which time each interest rate on the RSNs will reset at the applicable market rate. Holders may choose to either remarket their RSNs, receive the proceeds, and use those funds to settle the related Stock Purchase Contract or retain the RSNs and use other funds to settle the related Stock Purchase Contract. If the remarketing is unsuccessful, holders will have the right to put their RSNs to Southern Company at a price equal to the principal amount. The Corporate Units carry an annual distribution rate of 6.75% of the stated amount, which is comprised of a quarterly interest payment on the RSNs of 2.70% per year and a quarterly purchase contract adjustment payment of 4.05% per year.
Each Stock Purchase Contract obligates the holder to purchase, and Southern Company to sell, for $50 a number of shares of Southern Company common stock determined based on the applicable market value (as determined under the related Stock Purchase Contract) in accordance with the conversion ratios set forth below (subject to anti-dilution adjustments):
If the applicable market value is equal to or greater than $68.64, 0.7284 shares.
If the applicable market value is less than $68.64 but greater than $57.20, a number of shares equal to $50 divided by the applicable market value.
If the applicable market value is less than or equal to $57.20, 0.8741 shares.
A holder's ownership interest in the RSNs is pledged to Southern Company to secure the holder's obligation under the related Stock Purchase Contract. If a holder of a Stock Purchase Contract chooses at any time to have its RSNs released from the pledge, such holder's obligation under such Stock Purchase Contract must be secured by a U.S. Treasury security equal to the aggregate principal amount of the RSNs. At the time of issuance, the RSNs were recorded on Southern Company's consolidated balance sheet as long-term debt and the present value of the contract adjustment payments of $198 million was recorded as a liability (of which $63 million was classified as current at September 30, 2019), representing the obligation to make contract adjustment payments, with an offsetting reduction to paid-in capital. The difference between the face value and present value of the contract adjustment payments will be accreted to interest expense on the consolidated statements of income over the three-year period ending in 2022. The liability recorded for the contract adjustment payments is considered non-cash and excluded from the consolidated statements of cash flows. To settle the Stock Purchase Contracts, Southern Company will be required to issue a maximum of 30.2 million shares of common stock (subject to anti-dilution adjustments and a make-whole adjustment if certain fundamental changes occur).
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans and the Equity Units. Earnings per share dilution resulting from stock-based compensation plans and the Equity Units issuance is determined under the treasury stock method. See "Equity Units" herein for additional information and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:
| | | | | | | | | | | | Three Months Ended September 30, 2019 | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2019 | Nine Months Ended September 30, 2018 | | | (in millions) | | As reported shares | 1,048 |
| 1,023 |
| 1,043 |
| 1,016 |
| | Effect of stock-based compensation | 9 |
| 6 |
| 8 |
| 5 |
| | Diluted shares | 1,057 |
| 1,029 |
| 1,051 |
| 1,021 |
|
There were 0 stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive for the three and nine months ended September 30, 2019 and an immaterial amount of such awards was not included for the three and nine months ended September 30, 2018.
The Equity Units issued in August 2019 were excluded from the calculation of diluted earnings per share for the three and nine months ended September 30, 2019 as the dilutive stock price threshold was not met.
(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.8 billion as of September 30, 2019 compared to $2.4 billion as of December 31, 2018.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2023. The estimated tax credit utilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Effective Tax Rate
Details of significant changes in the effective tax rate for the applicable registrants are provided herein.
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity and flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs, primarily at Southern Power.
Southern Company's effective tax rate was 30.2% for the nine months ended September 30, 2019 compared to 22.7% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
from the sale of Gulf Power in 2019 and the reductions of tax benefits associated with wind PTCs following Southern Power's 2018 sale of a noncontrolling tax equity interest in its wind projects. The effective tax rate increase was partially offset by the tax impacts related to the Southern Company Gas Dispositions in 2018. See Note (K) for additional information.
Georgia Power
Georgia Power's effective tax rate was 22.6% for the nine months ended September 30, 2019 compared to 25.5% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in state ITCs in 2019 related to the construction of Plant Vogtle Units 3 and 4 and the impact of recording a valuation allowance on certain state tax credit carryforwards in 2018, partially offset by additional benefits recorded in 2018 as a result of the Tax Reform Legislation.
Mississippi Power
Mississippi Power's effective tax rate was 16.3% for the nine months ended September 30, 2019 compared to 20.8% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes as a result of both a settlement agreement reached with wholesale customers under the MRA tariff and a new tolling arrangement accounted for as a sales-type lease. See Note (B) under "Mississippi Power" for additional information on the settlement agreement.
Southern Power
Southern Power's effective tax benefit rate was (13.6)% for the nine months ended September 30, 2019 compared to (220.3)% for the corresponding period in 2018. The effective tax benefit rate decrease primarily resulted from lower wind PTCs following the 2018 sale of a noncontrolling tax equity interest in SP Wind and changes in state apportionment rates following the 2018 reorganization of certain legal entities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.
Southern Company Gas
Southern Company Gas' effective tax rate was 15.0% for the nine months ended September 30, 2019 compared to 61.8% for the corresponding period in 2018. This decrease was primarily related to an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of Triton in 2019, as well as the tax impacts of the Southern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
(H) RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). NaN mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2019. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On each registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2019 and 2018 are presented in the following tables.
| | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2019 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 73 |
| | $ | 17 |
| | $ | 19 |
| | $ | 3 |
| | $ | 2 |
| | $ | 7 |
| | Interest cost | 123 |
| | 28 |
| | 38 |
| | 6 |
| | 1 |
| | 9 |
| | Expected return on plan assets | (222 | ) | | (51 | ) | | (73 | ) | | (10 | ) | | (2 | ) | | (15 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | 1 |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | Net (gain)/loss | 30 |
| | 9 |
| | 11 |
| | 1 |
| | — |
| | 1 |
| | Net periodic pension cost (income) | $ | 5 |
| | $ | 3 |
| | $ | (5 | ) | | $ | — |
| | $ | 1 |
| | $ | 4 |
| | Postretirement Benefits | | Service cost | $ | 5 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | Interest cost | 18 |
| | 4 |
| | 6 |
| | — |
| | — |
| | 2 |
| | Expected return on plan assets | (16 | ) | | (6 | ) | | (7 | ) | | — |
| | — |
| | (1 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | Net (gain)/loss | (1 | ) | | — |
| | 1 |
| | — |
| | — |
| | — |
| | Net periodic postretirement benefit cost | $ | 6 |
| | $ | — |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2019 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 219 |
| | $ | 51 |
| | $ | 56 |
| | $ | 9 |
| | $ | 5 |
| | $ | 19 |
| | Interest cost | 369 |
| | 85 |
| | 116 |
| | 17 |
| | 4 |
| | 27 |
| | Expected return on plan assets | (664 | ) | | (154 | ) | | (219 | ) | | (30 | ) | | (7 | ) | | (45 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| | (2 | ) | | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | Net (gain)/loss | 90 |
| | 27 |
| | 33 |
| | 4 |
| | — |
| | 2 |
| | Net periodic pension cost (income) | $ | 16 |
| | $ | 10 |
| | $ | (13 | ) | | $ | — |
| | $ | 2 |
| | $ | 11 |
| | Postretirement Benefits | | Service cost | $ | 14 |
| | $ | 3 |
| | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | Interest cost | 52 |
| | 12 |
| | 19 |
| | 2 |
| | — |
| | 7 |
| | Expected return on plan assets | (49 | ) | | (19 | ) | | (19 | ) | | (1 | ) | | — |
| | (4 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | 2 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | Net (gain)/loss | (2 | ) | | — |
| | 1 |
| | — |
| | — |
| | (2 | ) | | Net periodic postretirement benefit cost | $ | 17 |
| | $ | (1 | ) | | $ | 5 |
| | $ | 2 |
| | $ | — |
| | $ | 6 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 90 |
|
| $ | 19 |
|
| $ | 22 |
|
| $ | 5 |
|
| $ | 3 |
|
| $ | 8 |
| | Interest cost | 116 |
|
| 26 |
|
| 34 |
|
| 5 |
|
| 1 |
|
| 10 |
| | Expected return on plan assets | (236 | ) |
| (51 | ) |
| (74 | ) |
| (11 | ) |
| (3 | ) |
| (18 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | 1 |
|
| — |
|
| 1 |
|
| — |
|
| — |
|
| (1 | ) | | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | Net (gain)/loss | 53 |
|
| 13 |
|
| 18 |
|
| 3 |
|
| — |
|
| 3 |
| | Net periodic pension cost (income) | $ | 24 |
|
| $ | 7 |
|
| $ | 1 |
|
| $ | 2 |
|
| $ | 1 |
|
| $ | 6 |
| | Postretirement Benefits | | Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | Interest cost | 19 |
| | 5 |
| | 7 |
| | — |
| | — |
| | 2 |
| | Expected return on plan assets | (17 | ) | | (7 | ) | | (6 | ) | | — |
| | — |
| | (1 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | Net (gain)/loss | 3 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | Net periodic postretirement benefit cost | $ | 13 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2018 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas | | | (in millions) | | Pension Plans | | Service cost | $ | 269 |
| | $ | 58 |
| | $ | 65 |
| | $ | 13 |
| | $ | 7 |
| | $ | 24 |
| | Interest cost | 348 |
| | 76 |
| | 104 |
| | 15 |
| | 4 |
| | 29 |
| | Expected return on plan assets | (707 | ) | | (155 | ) | | (222 | ) | | (31 | ) | | (8 | ) | | (53 | ) | | Amortization: | | | | | | | | | | | | | Prior service costs | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| | (2 | ) | | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | Net (gain)/loss | 160 |
| | 40 |
| | 52 |
| | 8 |
| | 1 |
| | 9 |
| | Net periodic pension cost (income) | $ | 73 |
| | $ | 20 |
| | $ | 1 |
| | $ | 5 |
| | $ | 4 |
| | $ | 18 |
| | Postretirement Benefits | | Service cost | $ | 18 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | Interest cost | 56 |
| | 13 |
| | 21 |
| | 2 |
| | — |
| | 7 |
| | Expected return on plan assets | (51 | ) | | (20 | ) | | (19 | ) | | (1 | ) | | — |
| | (5 | ) | | Amortization: | | | | | | | | �� | | | | | Prior service costs | 5 |
| | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | Net (gain)/loss | 10 |
| | 1 |
| | 6 |
| | — |
| | — |
| | — |
| | Net periodic postretirement benefit cost | $ | 38 |
| | $ | 1 |
| | $ | 14 |
| | $ | 2 |
| | $ | 1 |
| | $ | 8 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
As of September 30, 2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | As of September 30, 2019: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | | | (in millions) | | Southern Company | | | | | | | | | | | Assets: | | | | | | | | | | Energy-related derivatives(a) | $ | 297 |
| | $ | 156 |
| | $ | 34 |
| | $ | — |
| | $ | 487 |
| | Interest rate derivatives | — |
| | 2 |
| | — |
| | — |
| | 2 |
| Investments in trusts:(b)(c) | | | | | | | | | | | Domestic equity | 713 |
| | 126 |
| | — |
| | — |
| | 839 |
| | Foreign equity | 61 |
| | 204 |
| | — |
| | — |
| | 265 |
| | U.S. Treasury and government agency securities | — |
| | 301 |
| | — |
| | — |
| | 301 |
| | Municipal bonds | — |
| | 86 |
| | — |
| | — |
| | 86 |
| | Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
| | Corporate bonds | 24 |
| | 306 |
| | — |
| | — |
| | 330 |
| | Mortgage and asset backed securities | — |
| | 82 |
| | — |
| | — |
| | 82 |
| | Private equity | — |
| | — |
| | — |
| | 53 |
| | 53 |
| | Cash and cash equivalents | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | Other | 17 |
| | 6 |
| | — |
| | — |
| | 23 |
| | Cash equivalents | 2,078 |
| | 7 |
| | — |
| | — |
| | 2,085 |
| | Other investments | 9 |
| | 15 |
| | — |
| | — |
| | 24 |
| | Total | $ | 3,200 |
| | $ | 1,307 |
| | $ | 34 |
| | $ | 53 |
| | $ | 4,594 |
| | Liabilities: | | | | | | | | | | Energy-related derivatives(a) | $ | 412 |
| | $ | 227 |
| | $ | 28 |
| | $ | — |
| | $ | 667 |
| | Interest rate derivatives | — |
| | 72 |
| | — |
| | — |
| | 72 |
| | Foreign currency derivatives | — |
| | 32 |
| | — |
| | — |
| | 32 |
| | Contingent consideration | — |
| | — |
| | 21 |
| | — |
| | 21 |
| | Total | $ | 412 |
| | $ | 331 |
| | $ | 49 |
| | $ | — |
| | $ | 792 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | As of September 30, 2019: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | | | (in millions) | | Alabama Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| Nuclear decommissioning trusts:(b) | | | | | | | | |
|
| | Domestic equity | 464 |
| | 114 |
| | — |
| | — |
| | 578 |
| | Foreign equity | 61 |
| | 60 |
| | — |
| | — |
| | 121 |
| | U.S. Treasury and government agency securities | — |
| | 23 |
| | — |
| | — |
| | 23 |
| | Municipal bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | Corporate bonds | 24 |
| | 142 |
| | — |
| | — |
| | 166 |
| | Mortgage and asset backed securities | — |
| | 26 |
| | — |
| | — |
| | 26 |
| | Private equity | — |
| | — |
| | — |
| | 53 |
| | 53 |
| | Other | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | Cash equivalents | 1,136 |
| | 7 |
| | — |
| | — |
| | 1,143 |
| | Other investments |
|
| | 15 |
| | — |
| | — |
| | 15 |
| | Total | $ | 1,690 |
| | $ | 393 |
| | $ | — |
| | $ | 53 |
| | $ | 2,136 |
| | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
| | | | | | | | | | | | | Georgia Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
| Nuclear decommissioning trusts:(b)(c) | | | | | | | | | | | Domestic equity | 248 |
| | 1 |
| | — |
| | — |
| | 249 |
| | Foreign equity | — |
| | 140 |
| | — |
| | — |
| | 140 |
| | U.S. Treasury and government agency securities | — |
| | 277 |
| | — |
| | — |
| | 277 |
| | Municipal bonds | — |
| | 86 |
| | — |
| | — |
| | 86 |
| | Corporate bonds | — |
| | 164 |
| | — |
| | — |
| | 164 |
| | Mortgage and asset backed securities | — |
| | 55 |
| | — |
| | — |
| | 55 |
| | Other | 12 |
| | 6 |
| | — |
| | — |
| | 18 |
| | Cash equivalents | 392 |
| | — |
| | — |
| | — |
| | 392 |
| | Total | $ | 652 |
| | $ | 732 |
| | $ | — |
| | $ | — |
| | $ | 1,384 |
| | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 49 |
| | $ | — |
| | $ | — |
| | $ | 49 |
| | Interest rate derivatives | — |
| | 60 |
| | — |
| | — |
| | 60 |
| | Total | $ | — |
| | $ | 109 |
| | $ | — |
| | $ | — |
| | $ | 109 |
| | | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | As of September 30, 2019: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total | | | (in millions) | | Mississippi Power | | | | | | | | | | | Assets: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | Cash equivalents | 234 |
| | — |
| | — |
| | — |
| | 234 |
| | Total | $ | 234 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 236 |
| | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 24 |
| | $ | — |
| | $ | — |
| | $ | 24 |
| | | | | | | | | | | | | Southern Power | | | | | | | | | | | Assets: | | | | | | | | | | | Cash equivalents | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | Liabilities: | | | | | | | | | | | Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | Foreign currency derivatives | — |
| | 32 |
| | — |
| | — |
| | 32 |
| | Contingent consideration | — |
| | — |
| | 21 |
| | — |
| | 21 |
| | Total | $ | — |
|
| $ | 36 |
|
| $ | 21 |
|
| $ | — |
|
| $ | 57 |
| | | | | | | | | | | | | Southern Company Gas | | | | | | | | | | | Assets: | | | | | | | | | | Energy-related derivatives(a) | $ | 297 |
| | $ | 146 |
| | $ | 34 |
| | $ | — |
| | $ | 477 |
| | Non-qualified deferred compensation trusts: | | | | | | | | | | | Domestic equity | — |
| | 11 |
| | — |
| | — |
| | 11 |
| | Foreign equity | — |
| | 4 |
| | — |
| | — |
| | 4 |
| | Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
| | Cash equivalents | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | Total | $ | 298 |
|
| $ | 177 |
|
| $ | 34 |
|
| $ | — |
|
| $ | 509 |
| | Liabilities: | | | | | | | | | | Energy-related derivatives(a) | $ | 412 |
| | $ | 128 |
| | $ | 28 |
| | $ | — |
| | $ | 568 |
| | Interest rate derivatives | — |
| | 5 |
| | — |
| | — |
| | 5 |
| | Total | $ | 412 |
|
| $ | 133 |
|
| $ | 28 |
|
| $ | — |
|
| $ | 573 |
|
| | (a) | Energy-related derivatives exclude cash collateral of $166 million. |
| | (b) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
| | (c) | Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2019, approximately $50 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
| | | | | | | | | | | | | | | | Three Months Ended September 30, 2019 | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2019 | Nine Months Ended September 30, 2018 | | | (in millions) | | Southern Company | $ | 27 |
| $ | 58 |
| $ | 255 |
| $ | 68 |
| | Alabama Power | 15 |
| 39 |
| 140 |
| 49 |
| | Georgia Power | 12 |
| 19 |
| 115 |
| 19 |
|
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
As of September 30, 2019, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $53 million and unfunded commitments related to the private equity investments totaled $54 million. Private equity funds include funds-of-funds that invest in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
As of September 30, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) | | | (in millions) | | Long-term debt, including securities due within one year: | | | | | | Carrying amount | $ | 45,182 |
| $ | 8,516 |
| $ | 11,787 |
| $ | 1,616 |
| $ | 4,960 |
| $ | 5,755 |
| | Fair value | 49,424 |
| 9,646 |
| 13,001 |
| 1,717 |
| 5,290 |
| 6,489 |
|
| | (*) | The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds. |
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas.
Commodity Contracts with Level 3 Valuation Inputs
As of September 30, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $5 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
| | | | | | | | | | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 | | | (in millions) | | Beginning balance | $ | (10 | ) | $ | — |
| | Transfers to Level 3 | — |
| (33 | ) | | Transfers from Level 3 | 3 |
| 3 |
| | Instruments realized or otherwise settled during period | (2 | ) | (2 | ) | | Changes in fair value | 14 |
| 37 |
| | Ending balance | $ | 5 |
| $ | 5 |
|
Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.
The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.05) to $0.74 per mmBtu). Forward price increases (decreases) as of September 30, 2019 would have resulted in higher (lower) values on a net basis.
(J) DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.
Energy-Related Derivatives
The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
| | • | Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
|
| | • | Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.
|
| | • | Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
|
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.Rating Risk
At September 30, 2019,2020, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows: | | | | | | | | | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date | | | (in millions) | | | | | Southern Company(*) | 475 | | 2023 | | 2029 | | Alabama Power | 89 | | 2022 | | — | | Georgia Power | 184 | | 2023 | | — | | Mississippi Power | 99 | | 2023 | | — | | Southern Power | 9 | | 2020 | | — | Southern Company Gas(*) | 94 | | 2022 | | 2029 |
| | (*) | Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.1 billion mmBtu and short natural gas positions of 4.1 billion mmBtu as of September 30, 2019, which is also included in Southern Company's total volume. |
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 25 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 9 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2020 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At September 30, 2019, the following interest rate derivatives were outstanding:
| | | | | | | | | | | | | | | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value Gain (Loss) at September 30, 2019 | | | (in millions) | | | | | | (in millions) | | Cash Flow Hedges of Forecasted Debt | | | | | | | | Georgia Power | $ | 250 |
| | 3-month LIBOR | 2.23% | March 2025 | | $ | (9 | ) | | Georgia Power | 250 |
| | 3-month LIBOR | 2.40% | March 2030 | | (20 | ) | | Georgia Power | 250 |
| | 3-month LIBOR | 2.48% | February 2044 | | (30 | ) | | Southern Company Gas | 200 |
| | 3-month LIBOR | 1.81% | September 2030 | | (5 | ) | | Fair Value Hedges of Existing Debt | | | | | | | Southern Company(*) | 300 |
| | 2.75% | 3-month LIBOR+0.92% | June 2020 | | (1 | ) | Southern Company(*) | 1,500 |
| | 2.35% | 1-month LIBOR+0.87% | July 2021 | | (5 | ) | | Georgia Power | 200 |
| | 4.25% | 3-month LIBOR+2.46% | December 2019 | | (1 | ) | | Southern Company Consolidated | $ | 2,950 |
| | | | | | $ | (71 | ) |
| | (*) | Represents the Southern Company parent entity. |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2020 total $(21) million for Southern Company and are immaterial for all other registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 2019, the following foreign currency derivatives were outstanding:
| | | | | | | | | | | | | | | | Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value Gain (Loss) at September 30, 2019 | | | (in millions) | | (in millions) | | | (in millions) | | Cash Flow Hedges of Existing Debt | | | | | | | Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (21 | ) | | Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (11 | ) | | Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (32 | ) |
The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2020 are $(24) million.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
| | | | | | | | | | | | | | | | As of September 30, 2019 | As of December 31, 2018 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | | (in millions) | (in millions) | | Southern Company | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 5 |
| $ | 61 |
| $ | 8 |
| $ | 23 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 6 |
| 44 |
| 9 |
| 26 |
| | Assets held for sale, current/Liabilities held for sale, current |
|
|
|
| — |
| 6 |
| | Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 |
| $ | 105 |
| $ | 17 |
| $ | 55 |
| | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | — |
| $ | 8 |
| $ | 3 |
| $ | 7 |
| | Other deferred charges and assets/Other deferred credits and liabilities | — |
| 1 |
| 1 |
| 2 |
| | Interest rate derivatives: | | | | | | Other current assets/Other current liabilities | — |
| 72 |
| — |
| 19 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| — |
| — |
| 30 |
| | Foreign currency derivatives: | | | | | | Other current assets/Other current liabilities | — |
| 24 |
| — |
| 23 |
| | Other deferred charges and assets/Other deferred credits and liabilities | — |
| 8 |
| 75 |
| — |
| | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | 113 |
| $ | 79 |
| $ | 81 |
| | Derivatives not designated as hedging instruments | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 311 |
| $ | 342 |
| $ | 561 |
| $ | 575 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 165 |
| 211 |
| 180 |
| 325 |
| | Total derivatives not designated as hedging instruments | $ | 476 |
| $ | 553 |
| $ | 741 |
| $ | 900 |
| | Gross amounts recognized | $ | 489 |
| $ | 771 |
| $ | 837 |
| $ | 1,036 |
| Gross amounts offset(a) | $ | (348 | ) | $ | (514 | ) | $ | (524 | ) | $ | (801 | ) | Net amounts recognized in the Balance Sheets(b) | $ | 141 |
| $ | 257 |
| $ | 313 |
| $ | 235 |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | As of September 30, 2019 | As of December 31, 2018 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | | (in millions) | (in millions) | | Alabama Power | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 3 |
| $ | 12 |
| $ | 3 |
| $ | 4 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 10 |
| 3 |
| 6 |
| | Total derivatives designated as hedging instruments for regulatory purposes | $ | 5 |
| $ | 22 |
| $ | 6 |
| $ | 10 |
| | Gross amounts recognized | $ | 5 |
| $ | 22 |
| $ | 6 |
| $ | 10 |
| | Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (4 | ) | $ | (4 | ) | | Net amounts recognized in the Balance Sheets | $ | 3 |
| $ | 20 |
| $ | 2 |
| $ | 6 |
| | | | | | | | Georgia Power | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | 1 |
| $ | 27 |
| $ | 2 |
| $ | 8 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 22 |
| 4 |
| 13 |
| | Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 49 |
| $ | 6 |
| $ | 21 |
| | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Interest rate derivatives: | | | | | | Other current assets/Other current liabilities | $ | — |
| $ | 60 |
| $ | — |
| $ | 2 |
| | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | 60 |
| $ | — |
| $ | 2 |
| | Gross amounts recognized | $ | 3 |
| $ | 109 |
| $ | 6 |
| $ | 23 |
| | Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (6 | ) | $ | (6 | ) | | Net amounts recognized in the Balance Sheets | $ | — |
| $ | 106 |
| $ | — |
| $ | 17 |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | As of September 30, 2019 | As of December 31, 2018 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | | (in millions) | (in millions) | | Mississippi Power | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | — |
| $ | 12 |
| $ | 1 |
| $ | 3 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 12 |
| 2 |
| 6 |
| | Total derivatives designated as hedging instruments for regulatory purposes | $ | 2 |
| $ | 24 |
| $ | 3 |
| $ | 9 |
| | Gross amounts recognized | $ | 2 |
| $ | 24 |
| $ | 3 |
| $ | 9 |
| | Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (2 | ) | $ | (2 | ) | | Net amounts recognized in the Balance Sheets | $ | — |
| $ | 22 |
| $ | 1 |
| $ | 7 |
| | | | | | | | Southern Power | | | | | | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Energy-related derivatives: | | | | | | Other current assets/Other current liabilities | $ | — |
| $ | 4 |
| $ | 3 |
| $ | 6 |
| | Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| 2 |
| | Foreign currency derivatives: | | | | | | Other current assets/Other current liabilities | — |
| 24 |
| — |
| 23 |
| | Other deferred charges and assets/Other deferred credits and liabilities | — |
| 8 |
| 75 |
| — |
| | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | 36 |
| $ | 79 |
| $ | 31 |
| | Gross amounts recognized | $ | — |
| $ | 36 |
| $ | 79 |
| $ | 31 |
| | Gross amounts offset | $ | — |
| $ | — |
| $ | (3 | ) | $ | (3 | ) | | Net amounts recognized in the Balance Sheets | $ | — |
| $ | 36 |
| $ | 76 |
| $ | 28 |
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | As of September 30, 2019 | As of December 31, 2018 | | Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | | | (in millions) | (in millions) | | Southern Company Gas | | | | | | Derivatives designated as hedging instruments for regulatory purposes | | | | | | Energy-related derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | $ | 1 |
| $ | 10 |
| $ | 2 |
| $ | 8 |
| | Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| — |
| 1 |
| | Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | 10 |
| $ | 2 |
| $ | 9 |
| | Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | Energy-related derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | $ | — |
| $ | 4 |
| $ | — |
| $ | 1 |
| | Other deferred charges and assets/Other deferred credits and liabilities | — |
| 1 |
| — |
| — |
| | Interest rate derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | — |
| 5 |
| — |
| — |
| | Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | 10 |
| $ | — |
| $ | 1 |
| | Derivatives not designated as hedging instruments | | | | | | Energy-related derivatives: | | | | | | Assets from risk management activities/Liabilities from risk management activities-current | $ | 311 |
| $ | 342 |
| $ | 559 |
| $ | 574 |
| | Other deferred charges and assets/Other deferred credits and liabilities | 165 |
| 211 |
| 180 |
| 325 |
| | Total derivatives not designated as hedging instruments | $ | 476 |
| $ | 553 |
| $ | 739 |
| $ | 899 |
| | Gross amounts of recognized | $ | 477 |
| $ | 573 |
| $ | 741 |
| $ | 909 |
| Gross amounts offset(a) | $ | (341 | ) | $ | (507 | ) | $ | (508 | ) | $ | (785 | ) | Net amounts recognized in the Balance Sheets(b) | $ | 136 |
| $ | 66 |
| $ | 233 |
| $ | 124 |
|
| | (a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $166 million and $277 million as of September 30, 2019 and December 31, 2018, respectively. |
| | (b) | Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million as of December 31, 2018. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | | | | | | | | | | | | | | | | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2019 | Derivative Category and Balance Sheet Location | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas(*) | | | (in millions) | | Energy-related derivatives: | | | | | | | Other regulatory assets, current | $ | (55 | ) | $ | (11 | ) | $ | (27 | ) | $ | (12 | ) | $ | (5 | ) | | Other regulatory assets, deferred | (37 | ) | (8 | ) | (19 | ) | (10 | ) | — |
| | Other regulatory liabilities, current | 6 |
| 3 |
| — |
| — |
| 3 |
| | Total energy-related derivative gains (losses) | $ | (86 | ) | $ | (16 | ) | $ | (46 | ) | $ | (22 | ) | $ | (2 | ) |
| | (*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at September 30, 2019. |
| | | | | | | | | | | | | | | | | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018 | Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | | | (in millions) | | Energy-related derivatives: | | | | | | | Other regulatory assets, current | $ | (19 | ) | $ | (3 | ) | $ | (6 | ) | $ | (2 | ) | $ | (8 | ) | | Other regulatory assets, deferred | (16 | ) | (3 | ) | (9 | ) | (4 | ) | — |
| | Assets held for sale, current | (6 | ) | — |
| — |
| — |
| — |
| | Other regulatory liabilities, current | 1 |
| — |
| — |
| — |
| 1 |
| | Total energy-related derivative gains (losses) | $ | (40 | ) | $ | (6 | ) | $ | (15 | ) | $ | (6 | ) | $ | (7 | ) |
For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
| | | | | | | | | | | | | | | Gain (Loss) Recognized in OCI on Derivative | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | | 2019 | 2018 | 2019 | 2018 | | | (in millions) | (in millions) | | Southern Company | | | | | | Energy-related derivatives | $ | (5 | ) | $ | (5 | ) | $ | (11 | ) | $ | 7 |
| | Interest rate derivatives | (52 | ) | — |
| (88 | ) | (2 | ) | | Foreign currency derivatives | (68 | ) | (10 | ) | (107 | ) | (31 | ) | | Total | $ | (125 | ) | $ | (15 | ) | $ | (206 | ) | $ | (26 | ) | | Georgia Power | | | | | | Interest rate derivatives | $ | (47 | ) | $ | — |
| $ | (83 | ) | $ | — |
| | Total | $ | (47 | ) | $ | — |
| $ | (83 | ) | $ | — |
| | Southern Power | | | | | | Energy-related derivatives | $ | (3 | ) | $ | (5 | ) | $ | (5 | ) | $ | 5 |
| | Foreign currency derivatives | (68 | ) | (10 | ) | (107 | ) | (31 | ) | | Total | $ | (71 | ) | $ | (15 | ) | $ | (112 | ) | $ | (26 | ) |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.
For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows: | | | | | | | | | | | | | | | | | Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | | | | | 2019 | 2018 | 2019 | 2018 | | | | (in millions) | (in millions) | | | Southern Company | | | | | | | Total depreciation and amortization | $ | 760 |
| $ | 787 |
| $ | 2,267 |
| $ | 2,338 |
| | | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | — |
| (5 | ) | 2 |
| | | Total interest expense, net of amounts capitalized | (434 | ) | (458 | ) | (1,294 | ) | (1,386 | ) | | | Gain (loss) on interest rate cash flow hedges(a) | (5 | ) | (5 | ) | (14 | ) | (16 | ) | | | Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (6 | ) | (18 | ) | (18 | ) | | | Gain (loss) on interest rate fair value hedges(b) | 10 |
| (4 | ) | 43 |
| (35 | ) | | | Total other income (expense), net | 61 |
| 57 |
| 239 |
| 195 |
| | | Gain (loss) on foreign currency cash flow hedges(a)(c) | (54 | ) | (9 | ) | (62 | ) | (46 | ) | | | Southern Power | | | | | | | Total depreciation and amortization | $ | 120 |
| $ | 130 |
| $ | 357 |
| $ | 370 |
| | | Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | — |
| (5 | ) | 2 |
| | | Total interest expense, net of amounts capitalized | (43 | ) | (45 | ) | (127 | ) | (138 | ) | | | Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (6 | ) | (18 | ) | (18 | ) | | | Total other income (expense), net | 6 |
| 17 |
| 48 |
| 22 |
| | | Gain (loss) on foreign currency cash flow hedges(a)(c) | (54 | ) | (9 | ) | (62 | ) | (46 | ) |
| | (a) | Reclassified from accumulated OCI into earnings. |
| | (b) | For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income. |
| | (c) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2019 and December 31, 2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
| | | | | | | | | | | | | | |
| Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item | | Balance Sheet Location of Hedged Items | As of September 30, 2019 | As of December 31, 2018 |
| As of September 30, 2019 | As of December 31, 2018 |
| (in millions) | | (in millions) | | Southern Company | | | | | | | Securities due within one year | $ | (500 | ) | $ | (498 | ) | | $ | — |
| $ | 2 |
| | Long-term debt | (2,093 | ) | (2,052 | ) | | (2 | ) | 41 |
| | | | | | | | | Georgia Power | | | | | | | Securities due within one year | $ | (500 | ) | $ | (498 | ) | | $ | — |
| $ | 2 |
|
For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | | | | | | | | | | | | | | | Gain (Loss) | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2019 | 2018 | | 2019 | 2018 | | | | (in millions) | | (in millions) | | Energy-related derivatives: | Natural gas revenues(*) | $ | (2 | ) | $ | (36 | ) | | $ | 81 |
| $ | (79 | ) | | | Cost of natural gas | 2 |
| 2 |
| | 5 |
| 5 |
| | Total derivatives in non-designated hedging relationships | $ | — |
| $ | (34 | ) | | $ | 86 |
| $ | (74 | ) |
| | (*) | Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented. |
For the three and nine months ended September 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas doRegistrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain derivativescontracts that could require collateral, but not accelerated payment, in the event of variousa credit rating changeschange of certain Southern Company subsidiaries. At September 30, 2019, the registrants had 0 collateral posted with derivative counterpartiessubsidiaries to satisfy these arrangements. For the registrants withBBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate derivativesmanagement, and, for Georgia Power, construction of new generation at September 30, 2019, the fair valuePlant Vogtle Units 3 and 4.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) The maximum potential collateral requirements arisingunder these contracts at September 30, 2020 were as follows: | | | | | | | | | | | | | | | | | | | | | | Credit Ratings | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power(*) | Southern Company Gas | | (in millions) | | At BBB and/or Baa2 | $ | 36 | | $ | 1 | | $ | — | | $ | — | | $ | 35 | | $ | — | | | At BBB- and/or Baa3 | 413 | | 2 | | 61 | | 1 | | 351 | | — | | | At BB+ and/or Ba1 or below | 1,935 | | 372 | | 956 | | 315 | | 1,195 | | 9 | |
(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at September 30, 2020. The potential collateral requirement amounts in the credit-risk-related contingent featuresprevious table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that oneeither Alabama Power or more Southern Company power pool participantsGeorgia Power has a credit
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized forAdditionally, a credit rating downgrade could impact the rightability of the Registrants to reclaim cash collateral oraccess capital markets and would be likely to impact the obligationcost at which they do so. On August 27, 2020, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to return cash collateral are not offset against fair value amounts recognized for derivatives executed withBaa1 from Baa2 and revised its rating outlook to stable from positive. On September 25, 2020, Fitch upgraded Mississippi Power's senior unsecured long-term debt rating to A- from BBB+ and revised its rating outlook to stable from positive. Also on September 25, 2020, Fitch revised the same counterparty. Alabamaratings outlook of Southern Company and its subsidiaries (excluding Georgia Power and Southern Power maintain accounts with certain regional transmission organizationsMississippi Power) to facilitate financial derivative transactions. Based onstable from negative.
Market Price Risk Other than the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2019, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers oritems discussed below, there were no material changes to the clearing housesRegistrants' disclosures about market price risk during the third quarter 2020. For an in-depth discussion of certain exchanges to facilitate financial derivative transactions. Based on the valueSouthern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2019, cash collateral heldForm 10-K. Also see "Overview" herein for information on deposit in broker margin accounts was $166 million. The registrants are exposed to losses related to financial instrumentsvolatility in the event of counterparties' nonperformance. The registrants only enter into agreementsfinancial markets that has occurred at certain periods during 2020 resulting from the COVID-19 pandemic and material transactions with counterparties that have investment grade credit ratings by Moody'sNotes (I) and S&P or with counterparties who have posted collateral(J) to cover potential credit exposure. The registrants have also established risk management policies and controlsthe Condensed Financial Statements herein for information relating to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch Ratings Inc. ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.derivative instruments.
Southern Company Gas also utilizes master netting agreements whenever possibleis exposed to mitigatemarket risks, including commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the nettingmarket volatility of natural gas prices. Certain of the positivenatural gas distribution utilities may manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and negative exposures with that counterpartyweather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and a reasonable measureover-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) For the periods presented below, the changes in net fair value of Southern Company Gas' creditderivative contracts were as follows: | | | | | | | | | | | | | | | | | | | Third Quarter 2020 | Third Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 | | (in millions) | | Contracts outstanding at beginning of period, assets (liabilities), net | $ | 26 | | $ | (90) | | | $ | 72 | | $ | (167) | | | Contracts realized or otherwise settled | (8) | | 7 | | | (107) | | 7 | | Current period changes(*) | — | | (13) | | | 53 | | 64 | | | Contracts outstanding at the end of period, assets (liabilities), net | $ | 18 | | $ | (96) | | | $ | 18 | | $ | (96) | | | Netting of cash collateral | 70 | | 166 | | | 70 | | 166 | | | Cash collateral and net fair value of contracts outstanding at end of period | $ | 88 | | $ | 70 | | | $ | 88 | | $ | 70 | |
(*)Current period changes also include the fair value of new contracts entered into during the period, if any. The maturities of Southern Company Gas' derivative contracts at September 30, 2020 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements | | | | September 30, 2020 | | Total
Fair Value | | Maturity | | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter | | (in millions) | Level 1(a) | $ | (33) | | | $ | (14) | | | $ | (35) | | | $ | 16 | | Level 2(b) | 9 | | | 6 | | 1 | | 2 | Level 3(c) | 42 | | | — | | | 11 | | 31 | Fair value of contracts outstanding at end of period(d) | $ | 18 | | | $ | (8) | | | $ | (23) | | | $ | 49 | |
(a)Valued using NYMEX futures prices. (b)Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. (c)Valued using a combination of observable and unobservable inputs. (d)Excludes cash collateral of $70 million.
Item 3. Quantitative and Qualitative Disclosures About Market Risk. During the nine months ended September 30, 2020, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gassee MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein. For an in-depth discussion of each Registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K and Note 1 to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. The registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(K) ACQUISITIONS AND DISPOSITIONS
See Note 15under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K, for additional information.
Southern Company
On January 1, 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to 700 Universe, LLC, a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018.
On July 22, 2019, PowerSecure completed the sale of its utility infrastructure services business for approximately $71 million, subject to customary working capital adjustments. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.
In September 2019, PowerSecure reached an agreement to sell its lighting business for approximately $8 million, subject to customary working capital adjustments. In contemplation of this sale, an impairment charge of $18 million was recorded in the third quarter 2019 related to goodwill, identifiable intangibles, and other assets. The related assets and liabilities were classified as held for sale on Southern Company's balance sheet as of September 30, 2019. The sale is expected to close during the fourth quarter 2019.
Southern Company is negotiating an agreement to sell one of its leveraged lease investments for approximately $20 million. The net investment in the leveraged lease of approximately $6 million was classified as held for sale on Southern Company's balance sheet as of September 30, 2019. The sale is expected to close during the fourth quarter 2019.
The ultimate outcome of these matters cannot be determined at this time. See "Assets Held for Sale" herein for additional information.
Alabama Power
On September 6, 2019, Alabama Power entered into the Autauga Combined Cycle Acquisition, a purchase and sale agreement to acquire all of the equity interests in Tenaska Alabama II Partners, L.P. Tenaska Alabama II Partners, L.P. owns and operates an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The transaction is expected to close by September 1, 2020. As part of the Autauga Combined Cycle Acquisition, Alabama Power will assume an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. The estimated revenues from the power sales agreement are expected to offset the associated costs of operation during the remaining term.
The completion of the Autauga Combined Cycle Acquisition is subject to the satisfaction or waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC, as well as (i)Notes (I) and (J) to the expiration or terminationCondensed Financial Statements herein.
Item 4. Controls and Procedures. (a)Evaluation of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Actdisclosure controls and (ii) approval by the FERC. All regulatory approvals are expected to be obtained byprocedures. As of the end of the third quarter 2020. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
Acquisitions
During the third quarter 2019, Southern Power acquired a controlling interest in the fuel cell generation facility listed below. Acquisition-related costs were expensed as incurred and were not material.
| | | | | | | | | Project Facility | Resource | Seller | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | COD | PPA Remaining Period | DSGP (a)
| Fuel Cell | Bloom Energy | 28 | Delaware | 100% of Class B | N/A(b)
| 15 years |
| | (a) | During the second and third quarters 2019, Southern Power made a total investment of approximately $166 million in DSGP and now holds a controlling interest and consolidates 100% of DSGP's operating results. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility. |
| | (b) | Approximately 18 MWs of the 28-MW facility was repowered between June and August 2019. |
Construction Projects
During the nine months ended September 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of the Wildhorse Mountain and Reading facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the two facilities under construction. At September 30, 2019, total costs of construction incurred for these projects were $337 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
| | | | | | | Project Facility | Resource | Approximate Nameplate Capacity (MW)
| Location | Actual/Expected COD | PPA Contract Period | Projects Completed During the Nine Months Ended September 30, 2019 | Mankato expansion(a)
| Natural Gas | 385 | Mankato, MN | May 2019 | 20 years | Projects Under Construction as of September 30, 2019 | Wildhorse Mountain(b)
| Wind | 100 | Pushmataha County, OK | Fourth quarter 2019 | 20 years | Reading(c)
| Wind | 200 | Osage and Lyon Counties, KS | Second quarter 2020 | 12 years |
| | (a) | Southern Power has an agreement with a subsidiary of Xcel to sell all of its equity interests in Plant Mankato, including the expansion. The transaction is subject to FERC approval and is expected to close by January 20, 2020. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below.
|
| | (b) | In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.
|
| | (c) | In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.
|
Development Projects
Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During 2019, certain wind turbine equipment was sold, resulting in gains totaling approximately $17 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Sales of Natural Gas and Biomass Plants
On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a cash purchase price of approximately $461 million. This sale resulted in an $88 million after-tax gain.
In November 2018, Southern Power entered into an agreement with Northern States Power (a subsidiary of Xcel) to sell all of its equity interests in Plant Mankato for an aggregate purchase price of approximately $650 million, subject to certain state commission approvals. On September 27, 2019, the Minnesota Public Utilities Commission denied approval of the transaction. A newly-formed subsidiary of Xcel has agreed to purchase all of the equity interests in Plant Mankato subject to FERC approval and other customary conditions to closing. The transaction is expected to close by January 20, 2020. If the transaction does not closeperiod covered by this date, either party may terminate the transaction, which would result in the payment of a termination fee to Southern Power of up to $25 million. The ultimate outcome of this matter cannot be determined at this time. The assets and liabilities of Plant Mankato are classified as assets held for sale and liabilities held for saleQuarterly Report on Southern Company's and Southern Power's balance sheets as of September 30, 2019 and December 31, 2018. See "Assets Held for Sale" herein for additional information.
Assets Subject to Lien
Under the terms of the PPAs for Plant Mankato, approximately $545 million of assets, primarily related to property, plant, and equipment, are subject to lien at September 30, 2019.
Assets Held for Sale
As discussed above,Form 10-Q, Southern Company, andAlabama Power, Georgia Power, Mississippi Power, Southern Power each have assets and liabilities held for sale on their balance sheets at September 30, 2019 and December 31, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.
Upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively, Southern Power ceased recognizing depreciation and amortization on the long-lived assets to be sold.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at September 30, 2019 and December 31, 2018:
| | | | | | | | | | Southern Company | Southern Power | | | (in millions) | | At September 30, 2019 | | | | Assets Held for Sale: | | | | Current assets | $ | 17 |
| $ | 12 |
| | Total property, plant, and equipment | 551 |
| 546 |
| | Goodwill and other intangible assets | 40 |
| 40 |
| | Other non-current assets | 40 |
| 14 |
| | Total Assets Held for Sale | $ | 648 |
| $ | 612 |
| | | | | | Liabilities Held for Sale: | | | | Current liabilities | $ | 6 |
| $ | 3 |
| | Other non-current liabilities | 20 |
| — |
| | Total Liabilities Held for Sale | $ | 26 |
| $ | 3 |
| | | | | | At December 31, 2018 | | | | Assets Held for Sale: | | | | Current assets | $ | 393 |
| $ | 8 |
| | Total property, plant, and equipment | 4,583 |
| 536 |
| | Other intangible assets | 40 |
| 40 |
| | Other non-current assets | 727 |
| — |
| | Total Assets Held for Sale | $ | 5,743 |
| $ | 584 |
| | | | | | Liabilities Held for Sale: | | | | Current liabilities | $ | 425 |
| $ | 15 |
| | Long-term debt | 1,286 |
| — |
| | Accumulated deferred income taxes | 618 |
| — |
| | Other non-current liabilities | 932 |
| — |
| | Total Liabilities Held for Sale | $ | 3,261 |
| $ | 15 |
|
Southern Company and Southern Power each concluded that the sale of their assets, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and Plant Nacogdoches represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and nine months ended September 30, 2019 and 2018 is presented below:
| | | | | | | | | | | | | | | | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | | | 2019 | 2018 | 2019 | 2018 | | | (in millions) | | Earnings before income taxes: | | | | | | Gulf Power | $ | — |
| $ | 59 |
| $ | — |
| $ | 146 |
| | Southern Power's Florida Plants | $ | — |
| $ | 18 |
| $ | — |
| $ | 40 |
| Southern Power's Plant Nacogdoches(*) | $ | — |
| $ | 7 |
| $ | 16 |
| $ | 20 |
|
| | (*) | Earnings before income taxes for Plant Nacogdoches for the nine months ended September 30, 2019 represents January 1, 2019 through June 13, 2019 (the divestiture date). |
(L) LEASES
On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.
The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.
Lessee
As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:
| | | | | | | | | | | | | | | | | | | | | | As of September 30, 2019 | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | | (in millions) | | Electric generating units | $ | 988 |
| $ | 125 |
| $ | 1,488 |
| $ | — |
| $ | — |
| $ | — |
| | Real estate/land | 785 |
| 4 |
| 57 |
| 2 |
| 395 |
| 77 |
| | Communication towers | 150 |
| 2 |
| 3 |
| — |
| — |
| 13 |
| | Railcars | 51 |
| 23 |
| 25 |
| 3 |
| — |
| — |
| | Other | 89 |
| 9 |
| 14 |
| 2 |
| — |
| 1 |
| | Total | $ | 2,063 |
| $ | 163 |
| $ | 1,587 |
| $ | 7 |
| $ | 395 |
| $ | 91 |
|
Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas conducted separate evaluations under the supervision and various land leases primarily associated with renewable energy facilities at Southern
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power. The commercial real estate leases have remaining terms of up to 25 years whileeach company's management, including the land leases have remaining terms of up to 47 years, including renewal periods.
Communication towers are leased forChief Executive Officer and the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.
While renewal options exist in manyChief Financial Officer, of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable periodeffectiveness of the leasedesign and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as it is not considered reasonably certainamended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resultingdisclosure controls and procedures are effective.
(b) Changes in an expected lease term at least equal to the expected life of the renewable energy facilities.internal controls over financial reporting. Contracts that Contain a Lease
While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between three and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $625 million at September 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amountsThere have been reviewedno changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and approved by15d-15(f) under the Georgia PSC.
DuringSecurities Exchange Act of 1934, as amended) during the third quarter 2019, Alabama Power entered into additional long-term PPAs totaling approximately 640 MWs of additional generating capacity consisting of combined cycle generation expected to commence in 2020 and solar generation coupled with battery energy storage systems expected to commence in 2022 through 2024. Both the combined cycle PPA and the battery storage system portion of the solar generation PPAs are deemed operating leases. The estimated minimum lease payments for these agreements total $95 million. See Note (B) under "Alabama Power" for additional information.
Short-term Leases
Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.
Residual Value Guarantees
Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of September 30, 2019.
Lease and Nonlease Components
For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Balance sheet amounts recorded for operating and finance leases are as follows:
| | | | | | | | | | | | | | | | | | | | | | As of September 30, 2019 | | | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | | (in millions) | | Operating Leases | | | | | | | | Operating lease ROU assets, net | $ | 1,823 |
| $ | 143 |
| $ | 1,461 |
| $ | 7 |
| $ | 368 |
| $ | 92 |
| | | | | | | | | | Operating lease obligations - current | $ | 229 |
| $ | 49 |
| $ | 143 |
| $ | 2 |
| $ | 22 |
| $ | 14 |
| | Operating lease obligations - non current | 1,606 |
| 109 |
| 1,287 |
| 5 |
| 373 |
| 77 |
| | Total operating lease obligations | $ | 1,835 |
| $ | 158 |
| $ | 1,430 |
| $ | 7 |
| $ | 395 |
| $ | 91 |
| | | | | | | | | | Finance Leases | | | | | | | | Finance lease ROU assets, net | $ | 220 |
| $ | 4 |
| $ | 134 |
| $ | — |
| $ | — |
| $ | — |
| | | | | | | | | | Finance lease obligations - current | $ | 21 |
| $ | 1 |
| $ | 12 |
| $ | — |
| $ | — |
| $ | — |
| | Finance lease obligations - noncurrent | 207 |
| 4 |
| 145 |
| — |
| — |
| — |
| | Total finance lease obligations | $ | 228 |
| $ | 5 |
| $ | 157 |
| $ | — |
| $ | — |
| $ | — |
|
| | (*) | Includes operating lease ROU assets, net and operating lease obligations classified as held for sale. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Lease costs for the three and nine months ended September 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:
| | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | | (in millions) | | For the Three Months Ended September 30, 2019 | | | | | | | Lease cost | | | | | | | | Operating lease cost | $ | 94 |
| $ | 29 |
| $ | 53 |
| $ | 1 |
| $ | 7 |
| $ | 5 |
| | Finance lease cost: | | | | | | | | Amortization of ROU assets | 7 |
| — |
| 4 |
| — |
| — |
| — |
| | Interest on lease obligations | 3 |
| — |
| 4 |
| — |
| — |
| — |
| | Total finance lease cost | 10 |
| — |
| 8 |
| — |
| — |
| — |
| | Short-term lease costs | 9 |
| 4 |
| 5 |
| — |
| — |
| — |
| | Variable lease cost | 33 |
| 4 |
| 26 |
| — |
| 1 |
| — |
| | Total lease cost | $ | 146 |
| $ | 37 |
| $ | 92 |
| $ | 1 |
| $ | 8 |
| $ | 5 |
| | | | | | | | | | For the Nine Months Ended September 30, 2019 | | | | | | | Lease cost | | | | | | | | Operating lease cost | $ | 243 |
| $ | 49 |
| $ | 154 |
| $ | 2 |
| $ | 21 |
| $ | 14 |
| | Finance lease cost: | | | | | | | | Amortization of ROU assets | 21 |
| 1 |
| 11 |
| — |
| — |
| — |
| | Interest on lease obligations | 9 |
| — |
| 14 |
| — |
| — |
| — |
| | Total finance lease cost | 30 |
| 1 |
| 25 |
| — |
| — |
| — |
| | Short-term lease costs | 39 |
| 15 |
| 17 |
| — |
| — |
| — |
| | Variable lease cost | 81 |
| 6 |
| 67 |
| — |
| 3 |
| — |
| | Sublease income | (1 | ) | (1 | ) | — |
| — |
| — |
| — |
| | Total lease cost | $ | 392 |
| $ | 70 |
| $ | 263 |
| $ | 2 |
| $ | 24 |
| $ | 14 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.
Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:
| | | | | | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2019 | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | | (in millions) | | Other information | | | | | | | | Cash paid for amounts included in the measurements of lease obligations: | | | | | | | | Operating cash flows from operating leases | $ | 211 |
| $ | 50 |
| $ | 130 |
| $ | 2 |
| $ | 18 |
| $ | 13 |
| | Operating cash flows from finance leases | 3 |
| 1 |
| 17 |
| — |
| — |
| — |
| | Financing cash flows from finance leases | 24 |
| — |
| 4 |
| — |
| — |
| — |
| | ROU assets obtained in exchange for new operating lease obligations | 76 |
| 7 |
| 18 |
| — |
| — |
| 14 |
| | ROU assets obtained in exchange for new finance lease obligations | 31 |
| 1 |
| 24 |
| — |
| — |
| — |
|
| | | | | | | | | | | | | | | | As of September 30, 2019 | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | Weighted-average remaining lease term in years: | | | | | | | | Operating leases | 14.4 |
| 3.4 |
| 10.4 |
| 6.8 |
| 33.2 |
| 9.6 |
| | Finance leases | 18.9 |
| 12.4 |
| 10.8 |
| N/A |
| N/A |
| N/A |
| | Weighted-average discount rate: | | | | | | | | Operating leases | 4.56 | % | 3.33 | % | 4.46 | % | 3.98 | % | 5.68 | % | 3.73 | % | | Finance leases | 5.07 | % | 3.65 | % | 10.74 | % | N/A |
| N/A |
| N/A |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Maturities of lease liabilities are as follows:
| | | | | | | | | | | | | | | | | | | | | | As of September 30, 2019 | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | | (in millions) | | Maturity Analysis | | | | | | | | Operating leases: | | | | | | | | 2019 (remaining) | $ | 45 |
| $ | 4 |
| $ | 23 |
| $ | 1 |
| $ | 8 |
| $ | 4 |
| | 2020 | 284 |
| 54 |
| 205 |
| 2 |
| 22 |
| 17 |
| | 2021 | 269 |
| 53 |
| 198 |
| 1 |
| 23 |
| 17 |
| | 2022 | 259 |
| 52 |
| 196 |
| 1 |
| 23 |
| 13 |
| | 2023 | 202 |
| 4 |
| 197 |
| 1 |
| 24 |
| 11 |
| | Thereafter | 1,662 |
| 2 |
| 991 |
| 2 |
| 847 |
| 49 |
| | Total | 2,721 |
| 169 |
| 1,810 |
| 8 |
| 947 |
| 111 |
| | Less: Present value discount | 886 |
| 11 |
| 380 |
| 1 |
| 552 |
| 20 |
| | Operating lease obligations | $ | 1,835 |
| $ | 158 |
| $ | 1,430 |
| $ | 7 |
| $ | 395 |
| $ | 91 |
| | Finance leases: | | | | | | | | 2019 (remaining) | $ | 9 |
| $ | — |
| $ | 4 |
| $ | — |
| $ | — |
| $ | — |
| | 2020 | 31 |
| 1 |
| 28 |
| — |
| — |
| — |
| | 2021 | 24 |
| 1 |
| 24 |
| — |
| — |
| — |
| | 2022 | 21 |
| 1 |
| 24 |
| — |
| — |
| — |
| | 2023 | 17 |
| 1 |
| 25 |
| — |
| — |
| — |
| | Thereafter | 259 |
| 1 |
| 161 |
| — |
| — |
| — |
| | Total | 361 |
| 5 |
| 266 |
| — |
| — |
| — |
| | Less: Present value discount | 133 |
| — |
| 109 |
|
|
| — |
| | Finance lease obligations | $ | 228 |
| $ | 5 |
| $ | 157 |
| $ | — |
| $ | — |
| $ | — |
|
Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis.
As of September 30, 2019, Alabama Power and Southern Power have additional operating leases that have not yet commenced, as detailed in the following table:
| | | | | | | Southern Company | Alabama Power | Southern Power | | Operating lease type | PPAs and land | PPAs | Land | | Expected commencement date | 2019-2024 | 2020-2024 | 2019-2022 | | Longest lease term expiration | 28-31 years | 28 years | 31 years | Estimated total obligations (in millions) | $159 | $95 | $64 |
For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9materially affected or are reasonably likely to the financial statements in Item 8 of the Form 10-K.
Lessor
With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to seven years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.
Lease income for the three and nine months ended September 30, 2019 is as follows:
| | | | | | | | | | | | | | | | | | | | | | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | | | (in millions) | | For the Three Months Ended September 30, 2019 | | | | | | | | Lease income - interest income on sales-type leases | $ | 2 |
| $ | — |
| $ | — |
| $ | 2 |
| $ | — |
| $ | — |
| | Lease income - operating leases | 64 |
| 6 |
| 18 |
| — |
| 31 |
| 9 |
| | Variable lease income | 141 |
| — |
| — |
| — |
| 151 |
| — |
| | Total lease income | $ | 207 |
| $ | 6 |
| $ | 18 |
| $ | 2 |
| $ | 182 |
| $ | 9 |
| | | | | | | | | | For the Nine Months Ended September 30, 2019 | | | | | | | | Lease income - interest income on sales-type leases | $ | 7 |
| $ | — |
| $ | — |
| $ | 7 |
| $ | — |
| $ | — |
| | Lease income - operating leases | 216 |
| 19 |
| 57 |
| — |
| 111 |
| 26 |
| | Variable lease income | 324 |
| — |
| — |
| — |
| 349 |
| — |
| | Total lease income | $ | 547 |
| $ | 19 |
| $ | 57 |
| $ | 7 |
| $ | 460 |
| $ | 26 |
|
No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.
Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:
| | | | | | | | | | As of September 30, 2019 | | | Southern Company | Mississippi Power | | | (in millions) | | 2019 (remaining) | $ | 4 |
| $ | 4 |
| | 2020 | 17 |
| 17 |
| | 2021 | 15 |
| 15 |
| | 2022 | 15 |
| 15 |
| | 2023 | 14 |
| 14 |
| | Thereafter | 152 |
| 152 |
| | Total undiscounted cash flows | $ | 217 |
| $ | 217 |
| | Lease receivable | 119 |
| 119 |
| | Difference between undiscounted cash flows and discounted cash flows | $ | 98 |
| $ | 98 |
|
The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:
| | | | | | | | | | | | | | | | | | | As of September 30, 2019 | | | Southern Company | Alabama Power | Georgia Power | Southern Power | Southern Company Gas | | | (in millions) | | 2019 (remaining) | $ | 39 |
| $ | 6 |
| $ | 7 |
| $ | 8 |
| $ | 9 |
| | 2020 | 155 |
| 26 |
| 26 |
| 65 |
| 35 |
| | 2021 | 140 |
| 22 |
| 18 |
| 66 |
| 35 |
| | 2022 | 121 |
| 13 |
| 8 |
| 68 |
| 34 |
| | 2023 | 109 |
| 5 |
| 2 |
| 69 |
| 34 |
| | Thereafter | 1,166 |
| 22 |
| — |
| 350 |
| 497 |
| | Total | $ | 1,730 |
| $ | 94 |
| $ | 61 |
| $ | 626 |
| $ | 644 |
|
Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Mississippi Power are immaterial.
(M) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in 3 Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
materially affect Southern Company's, reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $116 million and $320 million for the three and nine months ended September 30, 2019, respectively, and $134 million and $326 million for the three and nine months ended September 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $9 million and $13 million for the three and nine months ended September 30, 2019, respectively, and $14 million and $22 million for the three and nine months ended September 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $20 million and $53 million for the three and nine months ended September 30, 2019, respectively, and $38 million and $96 million for the three and nine months ended September 30, 2018, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30, 2019 and 2018 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Electric Utilities | | | | | | | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated | | | (in millions) | | Three Months Ended September 30, 2019 | | | | | | | | | Operating revenues | $ | 4,908 |
| $ | 574 |
| $ | (119 | ) | $ | 5,363 |
| $ | 498 |
| $ | 146 |
| $ | (12 | ) | $ | 5,995 |
| Segment net income (loss)(a)(b)(c)(d) | 1,373 |
| 86 |
| — |
| 1,459 |
| (29 | ) | (110 | ) | (4 | ) | 1,316 |
| | Nine Months Ended September 30, 2019 | | | |
|
| | | | | Operating revenues | $ | 12,252 |
| $ | 1,527 |
| $ | (331 | ) | $ | 13,448 |
| $ | 2,661 |
| $ | 514 |
| $ | (118 | ) | $ | 16,505 |
| Segment net income (loss)(a)(b)(c)(d)(e) | 2,719 |
| 316 |
| — |
| 3,035 |
| 347 |
| 931 |
| (15 | ) | 4,298 |
| | At September 30, 2019 | | | | | | | | | | Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 263 |
| $ | — |
| $ | 5,280 |
| | Total assets | 80,493 |
| 14,397 |
| (756 | ) | 94,134 |
| 21,047 |
| 3,569 |
| (1,159 | ) | 117,591 |
| | Three Months Ended September 30, 2018 | | | | | | | | | Operating revenues | $ | 5,014 |
| $ | 635 |
| $ | (140 | ) | $ | 5,509 |
| $ | 492 |
| $ | 202 |
| $ | (44 | ) | $ | 6,159 |
| Segment net income (loss)(a)(b)(e)(f) | 1,148 |
| 92 |
| — |
| 1,240 |
| 46 |
| (119 | ) | (3 | ) | 1,164 |
| | Nine Months Ended September 30, 2018 | | | | | | | | | Operating revenues | $ | 13,117 |
| $ | 1,699 |
| $ | (360 | ) | $ | 14,456 |
| $ | 2,861 |
| $ | 984 |
| $ | (143 | ) | $ | 18,158 |
| Segment net income (loss)(a)(b)(e)(f) | 1,711 |
| 235 |
| — |
| 1,946 |
| 294 |
| (292 | ) | — |
| 1,948 |
| | At December 31, 2018 | | | | | | | | | | Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 298 |
| $ | — |
| $ | 5,315 |
| | Total assets | 79,382 |
| 14,883 |
| (306 | ) | 93,959 |
| 21,448 |
| 3,285 |
| (1,778 | ) | 116,914 |
|
| | (a) | Attributable to Southern Company. |
| | (b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $4 million ($3 million after tax) and $1 million ($1 million after tax) for the three months ended September 30, 2019 and 2018, respectively, and $10 million ($7 million after tax) and $1.1 billion ($0.8 billion after tax) for the nine months ended September 30, 2019 and 2018, respectively. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information.
|
| | (c) | Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the nine months ended September 30, 2019, of which $4 million ($4 million after tax) was recorded in the three months ended September 30, 2019, as well as impairment charges in contemplation of the sales of two of PowerSecure's business units totaling $18 million and $50 million for the three and nine months ended September 30, 2019, respectively. See Note (K) under "Southern Company" for additional information.
|
| | (d) | Segment net income (loss) for Southern Company Gas includes a pre-tax impairment charge of $92 million ($65 million after tax) related to a natural gas storage facility in Louisiana. See Note (C) under "Other Matters – Southern Company Gas" for additional information. |
| | (e) | Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the nine months ended September 30, 2019 and pre-tax impairment charges of $36 million ($27 million after tax) and $155 million ($116 million after tax) for the three and nine months ended September 30, 2018, respectively. See Note (K) under "Southern Power" and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Development Projects" and " – Sale of Natural Gas Plants" for additional information.
|
| | (f) | Segment net income (loss) for Southern Company Gas includes a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax) for the three and nine months ended September 30, 2018, respectively, related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Products and Services
| | | | | | | | | | | | | | | | Electric Utilities' Revenues | | | Retail | Wholesale | Other | Total | | | (in millions) | | Three Months Ended September 30, 2019 | $ | 4,512 |
| $ | 625 |
| $ | 226 |
| $ | 5,363 |
| | Three Months Ended September 30, 2018 | 4,605 |
| 698 |
| 206 |
| 5,509 |
| | Nine Months Ended September 30, 2019 | $ | 11,136 |
| $ | 1,667 |
| $ | 645 |
| $ | 13,448 |
| | Nine Months Ended September 30, 2018 | 11,913 |
| 1,937 |
| 606 |
| 14,456 |
|
| | | | | | | | | | | | | | | | Southern Company Gas' Revenues | | | Gas
Distribution
Operations(a) | Gas
Marketing
Services(b) | Other | Total | | | (in millions) | | Three Months Ended September 30, 2019 | $ | 445 |
| $ | 39 |
| $ | 14 |
| $ | 498 |
| | Three Months Ended September 30, 2018 | 438 |
| 44 |
| 10 |
| 492 |
| | Nine Months Ended September 30, 2019 | $ | 2,169 |
| $ | 326 |
| $ | 166 |
| $ | 2,661 |
| | Nine Months Ended September 30, 2018 | 2,276 |
| 403 |
| 182 |
| 2,861 |
|
| | (a) | Operating revenues for the three gas distribution operations dispositions were $7 million and $245 million for the three and nine months ended September 30, 2018, respectively. |
| | (b) | Operating revenues for Pivotal Home Solutions were $55 million for the nine months ended September 30, 2018, respectively. |
Southern Company Gas
Southern Company Gas manages its business through 4 reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other.
Gas distribution operations is the largest component ofAlabama Power's, Georgia Power's, Mississippi Power's, or Southern Company Gas' businessinternal control over financial reporting.
In July 2020, Southern Power implemented new financial accounting and includes natural gas local distribution utilities that construct, manage,reporting systems. As a result, there were certain changes to processes and maintain intrastate natural gas pipelinesprocedures, which resulted in changes to Southern Power's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and gas distribution facilities15d-15(f) under the Securities Exchange Act of 1934, as amended). These changes include automation of previously manual controls. These changes in 4 states. Gas pipeline investments consists of joint venturesinternal controls were not made in natural gas pipeline investments including a 50% interest in SNG, 2 significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas suppliesresponse to the customers of Southern Company Gas.
Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar Energy Services, LLC.
The all other column includes segments below the quantitative threshold for separate disclosure. This includes Southern Company Gas' storage and fuels operations, its investment in Triton through the completion of its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Note (E) under "Southern Company Gas" for additional information and related disclosures.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Business segment financial data for the three and nine months ended September 30, 2019 and 2018 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Gas Distribution Operations(a) | Gas Pipeline Investments | Wholesale Gas Services(b) | Gas Marketing Services(c)(d) | Total | All Other(e) | Eliminations | Consolidated | | | (in millions) | | Three Months Ended September 30, 2019 | | | | | | | | Operating revenues | $ | 448 |
| $ | 8 |
| $ | (2 | ) | $ | 39 |
| $ | 493 |
| $ | 10 |
| $ | (5 | ) | $ | 498 |
| | Segment net income (loss) | 37 |
| 6 |
| (9 | ) | (4 | ) | 30 |
| (59 | ) | — |
| (29 | ) | | Nine Months Ended September 30, 2019 | | | | | | | | Operating revenues | $ | 2,188 |
| $ | 24 |
| $ | 132 |
| $ | 326 |
| $ | 2,670 |
| $ | 34 |
| $ | (43 | ) | $ | 2,661 |
| | Segment net income (loss) | 228 |
| 63 |
| 61 |
| 54 |
| 406 |
| (59 | ) | — |
| 347 |
| | Total assets at September 30, 2019 | 17,798 |
| 1,743 |
| 657 |
| 1,443 |
| 21,641 |
| 10,429 |
| (11,023 | ) | 21,047 |
| | Three Months Ended September 30, 2018 | | | | | | | | Operating revenues | $ | 441 |
| $ | 8 |
| $ | (8 | ) | $ | 44 |
| $ | 485 |
| $ | 13 |
| $ | (6 | ) | $ | 492 |
| | Segment net income (loss) | 74 |
| 20 |
| (18 | ) | (8 | ) | 68 |
| (22 | ) | — |
| 46 |
| | Nine Months Ended September 30, 2018 | | | | | | | | | Operating revenues | $ | 2,297 |
| $ | 24 |
| $ | 142 |
| $ | 403 |
| $ | 2,866 |
| $ | 39 |
| $ | (44 | ) | $ | 2,861 |
| | Segment net income (loss) | 290 |
| 68 |
| 65 |
| (71 | ) | 352 |
| (58 | ) | — |
| 294 |
| | Total assets at December 31, 2018 | 17,266 |
| 1,763 |
| 1,302 |
| 1,587 |
| 21,918 |
| 11,112 |
| (11,582 | ) | 21,448 |
|
| | (a) | Operating revenues for the 3 gas distribution operations dispositions were $8 million and $245 million for the three and nine months ended September 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
| | (b) | The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. |
| | | | | | | | | | | | | | | | | | | Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues | | | (in millions) | | Three Months Ended September 30, 2019 | $ | 1,138 |
| $ | 72 |
| $ | 1,210 |
| $ | 1,212 |
| $ | (2 | ) | | Three Months Ended September 30, 2018 | 1,573 |
| 82 |
| 1,655 |
| 1,663 |
| (8 | ) | | Nine Months Ended September 30, 2019 | $ | 4,287 |
| $ | 223 |
| $ | 4,510 |
| $ | 4,378 |
| $ | 132 |
| | Nine Months Ended September 30, 2018 | 4,847 |
| 352 |
| 5,199 |
| 5,057 |
| 142 |
|
| | (c) | Operating revenues for Pivotal Home Solutions were $55 million for the nine months ended September 30, 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the sale of Pivotal Home Solutions. |
| | (d) | Segment net income (loss) for gas marketing services includes a loss on disposition of $34 million for the nine months ended September 30, 2018 and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information. |
| | (e) | Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $92 million ($65 million after tax) for the three and nine months ended September 30, 2019 related to a natural gas storage facility in Louisiana. See Note (C) under "Other Matters – Southern Company Gas" for additional information. |
PART II — OTHER INFORMATION Item 1. Legal Proceedings. See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrantsRegistrants are involved. Item 1A. Risk Factors. See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. ThereRegistrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K. The Registrants are subject to risks related to the COVID-19 pandemic, including, but not limited to, disruption to the construction of Plant Vogtle Units 3 and 4 for Southern Company and Georgia Power. COVID-19 has been declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. In response, most jurisdictions, including in the United States, have instituted restrictions on travel, public gatherings, and non-essential business operations. While some jurisdictions, including some in the Southern Company system's service territory, have relaxed these restrictions, many of these restrictions remain and there is no guarantee restrictions will not be reimposed in the future. These restrictions have significantly disrupted economic activity in the service territories of the traditional electric operating companies and the natural gas distribution utilities and caused volatility in capital markets at certain periods during 2020. For example, retail electric revenues have declined slightly compared to 2019, as discussed further in RESULTS OF OPERATIONS – "Southern Company – Retail Electric Revenues" in Item 2 herein. In addition, the traditional electric operating companies and the natural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. The effects of the continued COVID-19 pandemic and related responses could include extended disruptions to supply chains and capital markets, further reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts on the Registrants, including continued reduced demand for energy, particularly from commercial and industrial customers, reduced cash flows and liquidity, impairment of goodwill or long-lived assets, reductions in investments recorded at fair value, and further impairment of the ability of the Registrants to develop, construct, and operate facilities, including electric generation, transmission, and distribution assets, to perform necessary corporate and customer service functions, and to access funds from financial institutions and capital markets. In addition, the COVID-19 pandemic could cause delays or cancellations of regulatory proceedings. Further, the effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again from mid-June
through July. While the number of active cases at the site has declined since July 2020, the COVID-19 pandemic continues to impact productivity and the pace of activity completion. These factors contributed to the June 30, 2020 allocation of, and increase in, construction contingency described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. Item 6. Exhibits. The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements. | | | | | | | | | | | | | | | | | (4) Instruments Describing Rights of Security Holders, Including Indentures | | | | | | | | Southern Company | | | | | | | | (a)1 | - | SixthNinth Supplemental Indenture to theJunior Subordinated Note Indenture dated as of August 16, 2019,September 18, 2020, providing for the issuance of Southern Company'sthe Series 2019A Remarketable2020B 4.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2024. (DesignatedJanuary 15, 2051. (Designated in Form 8-K dated August 13, 2019,September 15, 2020, File No. 1-3526, asExhibit 4.4(a).4.4(a)) | | | | | | | | (a)2 | - | SeventhTenth Supplemental Indenture to theJunior Subordinated Note Indenture dated as of August 16, 2019,September 18, 2020, providing for the issuance of Southern Company'sthe Series 2019B Remarketable2020C 4.20% Junior Subordinated Notes due 2027. (DesignatedOctober 15, 2060. (Designated in Form 8-K dated August 13, 2019,September 15, 2020, File No. 1-3526, as Exhibit 4.4(b).4.4(b)) | | | | | | | | (a)3 | | Purchase Contract and Pledge Agreement, dated as of August 16, 2019, between Southern Company and U.S. Bank National Association, as Purchase Contract Agent, Collateral Agent, Custodial Agent, and Securities Intermediary. (Designated in Form 8-K dated August 13, 2019, File No. 1-3526, as Exhibit 4.9.)Alabama Power | | | | | | | | Alabama Power | | (b) | | | | | | | (b) | - | | | | | | | | | Georgia Power | | | | | | | | (c) | - | | | | | | | | | (c) | - | Sixtieth Supplemental Indenture to Senior Note Indenture dated as of September 10, 2019,August 27, 2020, providing for the issuance of Georgia Power'sthe Series 2019B 2.65%2020A 1.45% Senior Notes due September 15, 2029. (Designated2030. (Designated in Form 8-K dated September 4, 2019,August 24, 2020, File No. 1-6468,1-3164, as Exhibit 4.2(b).4.6) | | | | | | | | Southern Company Gas | | | | | | | | (f)1 | - | | | | | | | | | (f)2 | - | | | | | | | | | (24) Power of Attorney and Resolutions | | | | | | | | Southern Company | | | | | | | | (a) | - | | | | | | |
| | | | | | | | Southern Power | | | | | | | * | (e)1 | - | | | | | | | | * | (e)2 | - | | | | | | | | | Southern Company Gas | | | | | | | * | (f)1 | - | | | | | | |
| | | | | | | | | | | | | | | | * | (f)2 | - | | | | | | | | | (32) Section 906 Certifications | | | | | | | | Southern Company | | | | | | | * | (a) | - | | | | | | | | | Alabama Power | | | | | | | * | (b) | - | | | | | | | | | Georgia Power | | | | | | | * | (c) | - | | | | | | | | | Mississippi Power | | | | | | | * | (d) | - | | | | | | | | | Southern Power | | | | | | | * | (e) | - | | | | | | | | | Southern Company Gas | | | | | | | * | (f) | - | | | | | | | | | (101) Interactive Data Files | | | | | | | * | INS | - | XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. | | * | SCH | - | XBRL Taxonomy Extension Schema Document | | * | CAL | - | XBRL Taxonomy Calculation Linkbase Document | | * | DEF | - | XBRL Definition Linkbase Document | | * | LAB | - | XBRL Taxonomy Label Linkbase Document | | * | PRE | - | XBRL Taxonomy Presentation Linkbase Document | | | | | | | | (104) Cover Page Interactive Data File | | * | | | Formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101. |
THE SOUTHERN COMPANY SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report. | | | | | | | | | | | | | | THE SOUTHERN COMPANY | | | | | | By | | THE SOUTHERN COMPANY | | | | | By | | Thomas A. Fanning | | | Chairman, President, and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | By | | Andrew W. Evans | | | Executive Vice President and Chief Financial Officer | | | (Principal Financial Officer) | | | | | | By | | /s/ Melissa K. Caen | | | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 29, 2019
ALABAMA POWER COMPANY SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report. | | | | | | | | | | | | | | ALABAMA POWER COMPANY | | | | | | By | | ALABAMA POWER COMPANY | | | | | By | | Mark A. Crosswhite | | | | Chairman, President, and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | By | | Philip C. Raymond | | | Executive Vice President, Chief Financial Officer, and Treasurer | | | (Principal Financial Officer) | | | | | | By | | /s/ Melissa K. Caen | | | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 29, 2019
GEORGIA POWER COMPANY SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report. | | | | | | | | | | | | | | GEORGIA POWER COMPANY | | | | | | By | | GEORGIA POWER COMPANY | | | | | By | | W. Paul Bowers | | | Chairman, President, and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | By | | David P. Poroch | | | Executive Vice President, Chief Financial Officer, Treasurer, and ComptrollerTreasurer | | | (Principal Financial Officer) | | | | | | By | | /s/ Melissa K. Caen | | | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 29, 2019
MISSISSIPPI POWER COMPANY SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report. | | | | | | | | | | | | | | MISSISSIPPI POWER COMPANY | | | | | | By | | MISSISSIPPI POWER COMPANY | | | | | By | | Anthony L. Wilson | | | Chairman, President, and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | By | | Moses H. Feagin | | | Senior Vice President, Chief Financial Officer, and Treasurer | | | (Principal Financial Officer) | | | | | | By | | /s/ Melissa K. Caen | | | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 29, 2019
SOUTHERN POWER COMPANY SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report. | | | | | | | | | | | | | | SOUTHERN POWER COMPANY | | | | | | By | | SOUTHERN POWER COMPANYChristopher Cummiskey | | | | | By | | Mark S. Lantrip | | | Chairman and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | By | | Elliott L. Spencer | | | Senior Vice President, Chief Financial Officer, and Treasurer | | | (Principal Financial Officer) | | | | | | By | | /s/ Melissa K. Caen | | | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 29, 2019
SOUTHERN COMPANY GAS SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report. | | | | | | | | | | | | | | SOUTHERN COMPANY GAS | | | | | | By | | SOUTHERN COMPANY GAS | | | | | By | | Kimberly S. Greene | | | Chairman, President, and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | By | | Daniel S. Tucker | | | Executive Vice President, Chief Financial Officer, and Treasurer | | | (Principal Financial Officer) | | | | | | By | | /s/ Melissa K. Caen | | | | (Melissa K. Caen, Attorney-in-fact) | |
Date: October 29, 201928, 2020
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